6560.50

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 86, 87, 89, 90,

94, 98, 600, 1033, 1039, 1042, 1045, 

1048, 1051, 1054, 1065

[EPA-HQ-OAR-2008-0508; FRL-       ]

RIN 2060-A079

Mandatory Reporting of Greenhouse Gases

AGENCY:  Environmental Protection Agency (EPA).

ACTION:  Final Rule. 

SUMMARY:  EPA is promulgating a regulation to require reporting of
greenhouse gas emissions from all sectors of the economy.  The final
rule applies to fossil fuel suppliers and industrial gas suppliers,
direct greenhouse gas emitters and manufacturers of heavy-duty and
off-road vehicles and engines.  The rule does not require control of
greenhouse gases, rather it requires only that sources above certain
threshold levels monitor and report emissions.

DATES:  The final rule is effective on [INSERT THE DATE 60 DAYS AFTER
PUBLICATION IN THE FEDERAL REGISTER].  The incorporation by reference of
certain publications listed in the rule is approved by the Director of
Federal Register as of [INSERT THE DATE 60 DAYS AFTER PUBLICATION IN THE
FEDERAL REGISTER].

ADDRESSES:  EPA has established a docket for this action under Docket ID
No. EPA-HQ-OAR-2008-0508.  All documents in the docket are listed on the
www.regulations.gov webWeb site.  Although listed in the index, some
information is not publicly available, e.g., confidential business
information (CBI) or other information whose disclosure is restricted by
statute.  Certain other material, such as copyrighted material, is not
placed on the Internet and will be publicly available only in hard copy
form.  Publicly available docket materials are available either
electronically through www.regulations.gov or in hard copy at the
EPAEPA’s Docket Center, Public Reading Room, EPA West Building, Room
3334, 1301 Constitution Avenue, NW, Washington, DC 20004.  This Docket
Facility is open from 8:30 a.m. to 4:30 p.m., Monday through Friday,
excluding legal holidays.  The telephone number for the Public Reading
Room is (202) 566-1744, and the telephone number for the Air Docket is
(202) 566-1742.  

FOR FURTHER GENERAL INFORMATION CONTACT:  Carole Cook, Climate Change
Division, Office of Atmospheric Programs (MC-6207J), Environmental
Protection Agency, 1200 Pennsylvania Ave., NW, Washington, DC 20460;
telephone number:  (202) 343-9263; fax number: (202) 343-2342; e-mail
address: GHGReportingRule@epa.gov.  For technical information and
implementation materials, please go to the Web site   HYPERLINK
"http://www.epa.gov/climatechange/emissions/ghgrulemaking.html" 
www.epa.gov/climatechange/emissions/ghgrulemaking.html .  You may also
contact the Greenhouse Gas Reporting Rule Hotline at telephone number:
(877) 444-1188; or e-mail:   HYPERLINK "mailto:ghgmrr@epa.gov" 
ghgmrr@epa.gov .

SUPPLEMENTARY INFORMATION:

Regulated Entities.  The Administrator determined that this action is
subject to the provisions of Clean Air Act (CAA) section 307(d).  See
CAA section 307(d)(1)(V) (the provisions of section 307(d) apply to
“such other actions as the Administrator may determine.”).  The
final rule affects fuel and chemicals suppliers, direct emitters of
greenhouse gases (GHGs) and manufacturers of mobile sources and engines.
 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 manufacturing
facilities.

Cement Production	327310	Portland Cement manufacturing plants.

Ferroalloy Production	331112	Ferroalloys manufacturing facilities.

Glass Production	327211	Flat glass manufacturing facilities.

	327213	Glass container manufacturing facilities.

	327212	Other pressed and blown glass and glassware manufacturing
facilities.

HCFC-22 Production and HFC-23 Destruction	325120	Chlorodifluoromethane
manufacturing facilities.

Hydrogen Production	325120	Hydrogen manufacturing facilities.

Iron and Steel Production	331111	Integrated iron and steel mills, steel
companies, sinter plants, blast furnaces, basic oxygen process furnace
shops.

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.

Nitric Acid Production	325311	Nitric acid manufacturing facilities.

Petrochemical Production	32511	Ethylene dichloride manufacturing
facilities.

	325199	Acrylonitrile, ethylene oxide, methanol manufacturing
facilities.

	325110	Ethylene manufacturing facilities.

	325182	Carbon black manufacturing 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	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 Coal Based Liquids Fuels	211111	Coal liquefaction at mine
sites.

Suppliers of Petroleum Products	324110	Petroleum refineries.

Suppliers of Natural Gas and NGLs 	221210	Natural gas distribution
facilities.

	211112	Natural gas liquid extraction facilities.

Suppliers of Industrial GHGs	325120	Industrial gas manufacturing
facilities.

Suppliers of Carbon Dioxide (CO2)	325120	Industrial gas manufacturing
facilities.

Mobile Sources	333618	Heavy-duty, non-road, aircraft, locomotive, and
marine diesel engine manufacturing.

	336120	Heavy-duty vehicle manufacturing facilities.

	336312	Small non-road, and marine spark-ignition engine manufacturing
facilities.

	336999	Personal watercraft manufacturing facilities.

	336991	Motorcycle manufacturing facilities.



Table 1 of this preamble is not intended to be exhaustive, but rather
provides a guide for readers regarding facilities likely to be affected
by this action.  Table 1 of this preamble lists the types of facilities
that EPA is now aware could be potentially affected by the reporting
requirements.  Other types of facilities and suppliers not 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 manufacturers of heavy-duty
and off-road vehicles and engines.  If you have questions regarding the
applicability of this action to a particular facility, consult the
person listed in the preceding “FOR FURTHER INFORMATION CONTACT”
section. 

Many facilities that are affected by the final rule have GHG emissions
from multiple source categories listed in Table 1 of this preamble. 
Table 2 of this preamble has been developed as a guide to help potential
reporters subject to the mandatory reporting rule identify the source
categories (by subpart) that they may need to (1) consider in their
facility applicability determination, and (2) include in their
reporting.  For each source category, activity, or facility type (e.g.,
electricity generation, aluminum production), Table 2 of this preamble
identifies the subparts that are likely to be relevant.  The table
should only be seen as a guide.  Additional subparts may be relevant for
a given reporter.  Similarly, not all listed subparts are relevant for
all reporters.  

Table 2.  Source Categories and Relevant Subparts 

Source category

(and main applicable subpart)	Other Subparts recommended for review to
determine applicability

General Stationary Fuel Combustion Sources 

	Electricity Generation	General Stationary Fuel Combustion, Suppliers of
CO2

Adipic Acid Production 	General Stationary Fuel Combustion 

Aluminum Production 	General Stationary Fuel Combustion 

Ammonia Manufacturing 	General Stationary Fuel Combustion, Hydrogen,
Nitric Acid, Petroleum Refineries, Suppliers of CO2 

Cement Production	General Stationary Fuel Combustion, Suppliers of CO2

Ferroalloy Production 	General Stationary Fuel Combustion 

Glass Production	General Stationary Fuel Combustion 

HCFC-22 Production and HFC-23 Destruction	General Stationary Fuel
Combustion 

Hydrogen Production	General Stationary Fuel Combustion, Petrochemicals,
Petroleum Refineries, Suppliers of Industrial GHGs, Suppliers of CO2

Iron and Steel Production	General Stationary Fuel Combustion, Suppliers
of CO2

Lead Production	General Stationary Fuel Combustion 

Lime Manufacturing 	General Stationary Fuel Combustion 

Nitric Acid Production 	General Stationary Fuel Combustion, Adipic Acid

Petrochemical Production	General Stationary Fuel Combustion, Ammonia,
Petroleum Refineries

Petroleum Refineries	General Stationary Fuel Combustion, Hydrogen,
Suppliers of Petroleum Products

Phosphoric Acid Production	General Stationary Fuel Combustion 

Pulp and Paper Manufacturing	General Stationary Fuel Combustion 

Silicon Carbide Production	General Stationary Fuel Combustion 

Soda Ash Manufacturing	General Stationary Fuel Combustion 

Titanium Dioxide Production 	General Stationary Fuel Combustion 

Zinc Production	General Stationary Fuel Combustion 

Municipal Solid Waste Landfills	General Stationary Fuel Combustion 

Manure Management	General Stationary Fuel Combustion 

Suppliers of Coal-based Liquid Fuels	Suppliers of Petroleum Products

Suppliers of Petroleum Products	General Stationary Fuel Combustion 

Suppliers of Natural Gas and NGLs	General Stationary Fuel Combustion,
Suppliers of CO2

Suppliers of Industrial GHGs	General Stationary Fuel Combustion,
Hydrogen Production, Suppliers of CO2

Suppliers of Carbon Dioxide (CO2)	General Stationary Fuel Combustion,
Electricity Generation, Ammonia, Cement, Hydrogen, Iron and Steel,
Suppliers of Industrial GHGs

Mobile Sources	General Stationary Fuel Combustion



Judicial Review.

Under section 307(b)(1) of the Clean Air Act (CAA), judicial review of
this final rule is available only by filing a petition for review in the
U.S. Court of Appeals for the District of Columbia Circuit by [INSERT
THE DATE 60 DAYS AFTER PUBLICATION IN THE FEDERAL REGISTER].  Under CAA
section 307(d)(7)(B) of the CAA, only an objection to this final rule
that was raised with reasonable specificity during the period for public
comment can be raised during judicial review.  This section also
provides a mechanism for us to convene a proceeding for reconsideration,
“[i]f the person raising an objection can demonstrate to EPA that it
was impracticable to raise such objection within [the period for public
comment] or if the grounds for such objection arose after the period for
public comment (but within the time specified for judicial review) and
if such objection is of central relevance to the outcome of this
rule.”  Any person seeking to make such a demonstration to us should
submit a Petition for Reconsideration to the Office of the
Administrator, Environmental Protection Agency, Room 3000, Ariel Rios
Building, 1200 Pennsylvania Ave., NW., Washington, DC 20004, with a copy
to the person listed in the preceding FOR FURTHER INFORMATION CONTACT
section, and the Associate General Counsel for the Air and Radiation Law
Office, Office of General Counsel (Mail Code 2344A), Environmental
Protection Agency, 1200 Pennsylvania Ave., NW., Washington, DC 20004. 
Note, under CAA section 307(b)(2) of the CAA, the requirements
established by this final rule may not be challenged separately in any
civil or criminal proceedings brought by EPA to enforce these
requirements.

Acronyms and Abbreviations.  The following acronyms and abbreviations
are used in this document.

A/C	air conditioning

AERR	Air Emissions Reporting Rule

ANPR	Advance Notice of Proposed Rulemaking

ARP	Acid Rain Program

ASME	American Society of Mechanical Engineers

ASTM	American Society for Testing and Materials

BLS	Bureau of Labor Statistics

CAA	Clean Air Act

CAFE	Corporate Average Fuel Economy

CAIR	Clean Air Interstate Rule 

CARB	California Air Resources Board 

CBI	confidential business information

CCAR	California Climate Action Registry

CDX	central data exchange

CCS	carbon capture and sequestration

CEMS	continuous emission monitoring system(s)

CERR	Consolidated Emissions Reporting Rule

cf	cubic feet

CFCs	chlorofluorocarbons

CFR	Code of Federal Regulations

CH4	methane

CHP	combined heat and power

CO2	carbon dioxide

CO2e	CO2-equivalent

COD	chemical oxygen demand

DE	destruction efficiency

DOD	U.S. Department of Defense

DOE	U.S. Department of Energy

DOT	U.S. Department of Transportation

DE	destruction efficiency

DRE	destruction or removal efficiency

EAF	electric arc furnace

ECOS	Environmental Council of the States

EGUs	electric generating units

EIA	Energy Information Administration

EISA	Energy Independence and Security Act of 2007

EO	Executive Order

EOR	enhanced oil recovery

EPA	U.S. Environmental Protection Agency

EU	European Union 

FTP	Federal Test Procedure

FY2008	fiscal year 2008

GHG	greenhouse gas

GWP	global warming potential

HCFC-22	chlorodifluoromethane (or CHClF2)

HCFCs	hydrochlorofluorocarbons

HCl	hydrogen chloride

HFC-23	trifluoromethane (or CHF3)

HFCs	hydrofluorocarbons

HFEs	hydrofluorinated ethers

HHV	higher heating value

ICR	information collection request

IPCC	Intergovernmental Panel on Climate Change

ISO	International Organization for Standardization

kg	kilograms

LandGEM	Landfill Gas Emissions Model

LCD	liquid crystal display

LDCs	local natural gas distribution companies

LEDs	light emitting diodes

LNG	liquefied natural gas

LPG	liquified petroleum gas

MEMS	microelectricomechanical system

LMP	lime manufacturing plants

mmBtu/hr	millions British thermal units per hour

MMTCO2e	million metric tons carbon dioxide equivalent 

MSHA	Mine Safety and Health Administration

MSW	municipal solid waste

MW	megawatts

MY	mileage year

N2O	nitrous oxide

NAAQS	national ambient air quality standard

NACAA	National Association of Clean Air Agencies

NAICS	North American Industry Classification System

NEI	National Emissions Inventory

NESHAP	national emission standards for hazardous air pollutants

NF3	nitrogen trifluoride 

NGLs	natural gas liquids

NIOSH	National Institute for Occupational Safety and Health

NSPS	new source performance standards

NSR	New Source Review

NTTAA	National Technology Transfer and Advancement Act of 1995

O3	ozone

ODS	ozone-depleting substance(s)

OMB	Office of Management and Budget

ORIS	Office of Regulatory Information Systems 

PFCs	perfluorocarbons

PIN	personal identification number

POTWs	publicly owned treatment works

PSD	Prevention of Significant Deterioration

PV	photovoltaic

QA	quality assurance

QA/QC	quality assurance/quality control

QAPP	quality assurance performance plan

R&D	research and development 

RFA	Regulatory Flexibility Act

RFS	Renewable Fuel Standard

RGGI	Regional Greenhouse Gas Initiative

RICE	reciprocating internal combustion engine

RIA	regulatory impact analysis

SAE	Society of Automotive Engineers

SAR	IPCC Second Assessment Report

SBREFA	Small Business Regulatory Enforcement Fairness Act

scf	standard cubic feet 

SF6	sulfur hexafluoride

SFTP	Supplemental Federal Test Procedure

SI	international system of units

SIP	State Implementation Plan

SOP	standard operating procedure

SSM	startup, shutdown, and malfunction

TCR	The Climate Registry

TOC	total organic carbon

TRI	Toxic Release Inventory

TSCA	Toxics Substances Control Act 

TSD	technical support document

U.S.	United States

UIC	underground injection control

UMRA	Unfunded Mandates Reform Act of 1995

UNFCCC	United Nations Framework Convention on Climate Change

USDA	U.S. Department of Agriculture

USGS	U.S. Geological Survey 

VMT	vehicle miles traveled 

VOC	volatile organic compound(s)

WBCSD	World Business Council for Sustainable Development

WCI	Western Climate Initiative

WRI	World Resources Institute

XML	eXtensible Markup Language

TABLE OF CONTENTS 

I.  Background

A.  Organization of this Preamble 

B.  Background on the Final Rule 

C.  Legal Authority 

D.  How does this rule relate to EPA and U.S. government climate change
efforts?

E.  How does this rule relate to State and regional programs?

II.	General Requirements of the Rule 

A.  Summary of the General Requirements of the Final Rule

B.  Summary of the Major Changes Since Proposal

C.  Summary of Comments and Responses on GHGs to Report

D.  Summary of Comments and Responses on Source Categories to Report

E.  Summary of Comments and Responses on Thresholds

F.  Summary of Comments and Responses on Level of Reporting

G.  Summary of Comments and Responses on Initial Reporting Year and Best
Available Monitoring Methods

H.  Summary of Comments and Responses on Frequency of Reporting and
Provisions to Cease Reporting

I.  Summary of Comments and Responses on General Content of the Annual
GHG Report

J.  Summary of Comments and Responses on Submittal Date and Making
Corrections to Annual Reports

K.  Summary of Comments and Responses on De minimis Reporting

L.  Summary of Comments and Responses on General Monitoring Requirements


M.  Summary of Comments and Responses on General Recordkeeping
Requirements

N.  Summary of Comments and Responses on Emissions Verification Approach

O.  Summary of Comments and Responses on the Role of States and
Relationship of this Rule to Other Programs

P.  Summary of Comments and Responses on Other General Rule Requirements

Q.  Summary of Comments and Responses on Statutory Authority 

R.  Summary of Comments and Responses on CBI

S.  Summary of Comments and Responses on Other Legal Issues 

III.  Reporting and Recordkeeping Requirements for Specific Source
Categories

A.  Overview 

B.  Electricity Purchases 

C.  General Stationary Fuel Combustion Sources

D.  Electricity Generation

E.  Adipic Acid Production

F.  Aluminum Production

G.  Ammonia Manufacturing

H.  Cement Production

I.  Electronics Manufacturing

J.  Ethanol Production

K.  Ferroalloy Production

L.  Fluorinated GHG Production

M.  Food Processing

N.  Glass Production

O.  HCFC-22 Production and HFC-23 Destruction

P.  Hydrogen Production

Q.  Iron and Steel Production

R.  Lead Production

S.  Lime Manufacturing

T.  Magnesium Production

U.  Miscellaneous Uses of Carbonates

V.  Nitric Acid Production

W.  Oil and Natural Gas Systems

X.  Petrochemical Production

Y.  Petroleum Refineries

Z.  Phosphoric Acid Production

AA.  Pulp and Paper Manufacturing

BB.  Silicon Carbide Production

CC.  Soda Ash Manufacturing

DD.  Sulfur Hexafluoride (SF6) from Electrical Equipment

EE.  Titanium Dioxide Production

FF.  Underground Coal Mines

GG.  Zinc Production

HH.  Municipal Solid Waste Landfills

II.  Wastewater Treatment

JJ.  Manure Management

KK.  Suppliers of Coal

LL.  Suppliers of Coal-based Liquid Fuels

MM.  Suppliers of Petroleum Products

NN.  Suppliers of Natural Gas and Natural Gas Liquids

OO.  Suppliers of Industrial GHGs

PP.  Suppliers of Carbon Dioxide (CO2)

IV.  Mobile Sources

A. Summary of Requirements of the Final Rule

B. Summary of Changes Since Proposal

C. Summary of Comments and Responses

V.  Collection, Management, and Dissemination of GHG Emissions Data

A.  Summary of Data Collection, Management and Dissemination for the
Final Rule

B.  Summary of Comments and Responses on Collection, Management, and
Dissemination of GHG Emissions Data

VI. Compliance and Enforcement 

A.  Compliance and Enforcement Summary 

B.  Summary of Public Comments and Responses on Compliance and
Enforcement

VII. Economic Impacts of the Rule

A.  How were compliance costs estimated?

B.  What are the costs of the rule?

C.  What are the economic impacts of the rule?

D.  What are the impacts of the rule on small businesses?

E.  What are the benefits of the rule for society?

VIII.  Statutory and Executive Order Reviews  

A.  Executive Order 12866: Regulatory Planning and Review

B.  Paperwork Reduction Act

C.  Regulatory Flexibility Act (RFA)

D.  Unfunded Mandates Reform Act (UMRA)

E.  Executive Order 13132: Federalism

F.  Executive Order 13175: Consultation and Coordination with Indian
Tribal Governments

G.  Executive Order 13045: Protection of Children from Environmental
Health Risks and Safety Risks

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

I.  National Technology Transfer and Advancement Act

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

K.  Congressional Review Act

I.  Background

A.  Organization of This Preamble

 This preamble is broken into several large sections, as detailed above
in the Table of Contents.  The paragraphs below describe the layout of
the preamble and provide a brief summary of each section.   

The first section of this preamble contains the basic background
information about the origin of this rule, our legal authority, and how
this proposal relates to other Federal, State, and regional efforts to
address emissions of GHGs.  

The second section of this preamble summarizes the general provisions of
the final GHG reporting rule and identifies the major changes since
proposal.  It also provides a brief summary of public comments and
responses on key design elements such as: (i) source categories
included, (ii) the level of reporting, (iii) applicability thresholds,
(iv) selection of reporting and monitoring methods, (v) emissions
verification, (vi) frequency of reporting and (vii) duration of
reporting.  It also addresses some of the legal comments on the
statutory authority for the rule and the relationship of this rule to
other CAA programs. 

The third section of this preamble contains separate subsections
addressing each individual source category of the proposed rule.  Each
source category section contains a summary of specific requirements of
the rule for that source category, identifies major changes since
proposal, and briefly discusses public comments and EPA responses
specific to the source category.  For example, comments on EPA’s
general approach for selecting monitoring methods are discussed in
Section II of this preamble, whereas, comments on specific monitoring
methods for individual source categories are discussed in Section III of
this preamble.  The fourth section of this preamble summarizes rule
requirements and addresses public comments pertaining to mobile sources.


The fifth section of this preamble explains how EPA plans to collect,
manage and disseminate the data, while the sixth section describes the
approach to compliance and enforcement.  In both sections key public
comments are summarized and responses are presented.  

The seventh section provides the summary of the cost impacts, economic
impacts, and benefits of the final rule and discusses comments on the
regulatory impacts analyses. Finally, the last section discusses the
various statutory and executive order requirements applicable to this
rulemaking.

B.  Background on the Final Rule

The fiscal year 2008 (FY2008) Consolidated Appropriations Act, signed on
December 26, 2007, authorized funding for EPA to “develop and publish
a draft rule not later than 9nine months after the date of enactment of
[the] Act, and a final rule not later than 18 months after the date of
enactment of [the] Act, to require mandatory reporting of GHGgreenhouse
gas emissions above appropriate thresholds in all sectors of the economy
of the United States.”  Consolidated Appropriations Act, 2008, Pub. L.
No.110-161, 121 Stat 1844, 2128 (2008). 

The accompanying joint explanatory statement directed EPA to "use its
existing authority under the Clean Air Act" to develop a mandatory GHG
reporting rule.  "The Agency is further directed to include in its rule
reporting of emissions resulting from upstream production and downstream
sources, to the extent that the Administrator deems it appropriate.” 
EPA interpreted that language to confirm that it was appropriate for the
Agency to exercise its CAA authority to develop this rulemaking.  The
joint explanatory statement further states that “[t]he Administrator
shall determine appropriate thresholds of emissions above which
reporting is required, and how frequently reports shall be submitted to
EPA.  The Administrator shall have discretion to use existing reporting
requirements for electric generating units (EGUs)” under section 821
of the 1990 CAA Amendments.

On April 10, 2009 (74 FR 16448), EPA proposed the GHG reporting rule. 
EPA held two public hearings, and received approximately 16,800 written
public comments.  The public comment period ended on June 9, 2009.  

In addition to the public hearings, EPA had an open door policy, similar
to the outreach conducted during the development of the proposal.  As a
result, EPA has met with over 4,000 people and 135 groups since proposal
signature (March 10, 2009).  Details of these meetings are available in
the docket (EPA-HQ-OAR-2008-0508).

EPA developed this final rule and included reporting of GHGs from the
facilities that we determined appropriately responded to the direction
in the FY2008 Consolidated Appropriations Act (e.g., capturing
approximately 85 percent of U.S. GHG emissions through reporting by
direct emitters as well as suppliers of fossil fuels and industrial
gases and manufacturers of heavy-duty and off-road vehicles and
engines).  There are, however, many additional types of data and
reporting that the Agency deems important and necessary to address an
issue as large and complex as climate change (e.g.., indirect emissions,
electricity use).  In that sense, one could view this final rule as
narrowly focused on certain sources of emissions and upstream suppliers.
 As described in Sections I.C and D of this preamble as well as in the
comment response sections, there are several existing programs at the
Federal, Regionalregional and State levels that also collect valuable
information to inform and implement policies necessary to address
climate change.  Many  of these programs are focused on cost-effectively
reducing GHG emissions through improvements in energy efficiency and by
other means.  These programs are an essential component of the
Nation’s climate policy, and the targeted nature of this mandatory
reporting programrule should not be interpreted to mean that the data
EPA collects through this program are the only data necessary to support
the full range of climate policies and programs.  

Today’s rule requires the reporting of the GHG emissions that could
result from the combustion or use of fossil fuel or industrial gas that
is produced or imported from upstream sources such as fuel suppliers, as
well as reporting of GHG emissions directly emitted from facilities
(downstream sources) through their processes and/or from fuel
combustion, as appropriate.  Vehicle and engine manufacturers are also
required to report emissions rate data on the heavy-duty and off-road
engines they produce.  The rule also establishes appropriate thresholds
and frequency for reporting.  

The rule requires reporting of annual emissions of carbon dioxide (CO2),
methane (CH4), nitrous oxide (N2O), sulfur hexafluoride (SF6),
hydrofluorocarbons (HFCs), perfluorochemicalsperfluorocarbons (PFCs),
and other fluorinated gases (e.g., nitrogen trifluoride (NF3) and
hydrofluorinated ethers (HFEs)).  It also includes provisions to ensure
the accuracy of emissions data through monitoring, recordkeeping and
verification requirements.  The rule applies to certain downstream
facilities that emit GHGs (primarily large facilities emitting 25,000
metric tons per yearor more of CO2 equivalent (CO2e) GHG emissions or
moreper year) and to most upstream suppliers of fossil fuels and
industrial GHGs, as well as to manufacturers of vehicles and engines. 
Reporting is at the facility level, except certain suppliers and vehicle
and engine manufacturers report at the corporate level.

C.  Legal Authority

As proposed, EPA is promulgating this rule under its existing CAA
authority, specifically authorities provided in CAA sections 114 and 208
of the CAA.  As discussed further below and in the comment response
document (EPA-HQ-OAR-2008-0508-XXXX),“Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to Public Comments, Legal Issues”, we
are not citing the FY 2008 Consolidated Appropriations Act as the
statutory basis for this action.  While that law required that EPA spend
no less than $3.5 million on a rule requiring the mandatory reporting of
GHG emissions, it is the CAA, not the Appropriations Act, that EPA is
citing as the authority to gather the information required by this rule.
 

Clean Air Act sectionsSections 114 and 208 of the CAA provide EPA broad
authority to require the information mandated by this rule because such
data will inform and are relevant to EPA’s carrying out a wide variety
of CAA provisions.  As discussed in the proposed rule, CAA section
114(a)(1) of the CAA authorizes the Administrator to require emissions
sources, persons subject to the CAA, 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 (except for a
provision of title II with respect to manufacturers of new motor
vehicles or new motor vehicle engines).  Section 208 of the CAA provides
EPA with similar broad authority regarding the manufacturers of new
motor vehicles or new motor vehicle engines, and other persons subject
to the requirements of parts A and C of title II.  We note that while
climate change legislation approved by the U.S. House of
Representatives, and pending in the U.S. Senate, would provide EPA
additional authority for a GHG registry similar to today’s rule, and
would do so for purposes of that pending legislation, this final rule is
authorized by, and the information being gathered by the rule is
relevant to implementing, the existing CAA.  We expect, however, that
the information collected by this final rule will also prove useful to
legislative efforts to address GHG emissions. 

As discussed in the proposal, emissions from direct emitters should
inform decisions about whether and how to use CAA section 111 to
establish new source performance standards (NSPS) for various source
categories emitting GHGs, including whether there are any additional
categories of sources that should be listed under CAA section 111(b). 
Similarly, the information required of manufacturers of mobile sources
should support decisions regarding treatment of those sources under CAA
sections 202, 213 or 231 of the CAA.  In addition, the information from
fuel suppliers would be relevant in analyzing whether to proceed, and
particular options for how to proceed, under CAA section 211(c)
regarding fuels, or to inform action concerning downstream sources under
a variety of Title I or Title II provisions.  The data overall also
would inform EPA’s implementation of CAA section 103(g) of the CAA
regarding improvements in non-regulatory strategies and technologies for
preventing or reducing air pollutants (e.g.., EPA’s voluntary GHG
reduction programs such as the non-CO2 partnership programs and Energy
StarENERGY STAR, described below in Section I.D of this preamble and
Section II of the proposal preamble (74 FR 16448, April 10, 2009)).

D.  How does this rule relate to EPA and U.S. government climate change
efforts?

This reporting rule is one specific action EPA has taken, consistent
with the Congressional request contained in the FY2008 Consolidated
Appropriations Act, to collect GHG emissions data.  EPA has recently
announced a number of climate change related actions, including proposed
findings that GHG emissions from new motor vehicles and engines
contribute to air pollution which may reasonably be anticipated to
endanger public health and welfare (74 FR 18886, April 24, 2009,
“Proposed Endangerment and Cause or Contribute Findings for Greenhouse
Gases Under Section 202(a) of the Clean Air Act”), and an intent to
regulate light duty vehicles, jointly published with U.S. Department of
Transportation (DOT) (74 FR 24007, May 22, 2009, “Notice of Upcoming
Joint Rulemaking To Establish Vehicle GHG Emissions and CAFE
Standards”). The Administrator has also announced her reconsideration
of the memo entitled “EPA’s Interpretation of Regulations that
Determine Pollutants Covered By Federal Prevention of Significant
Deterioration (PSD) Permit Program” (73 FR 80300, December 31, 2008),
and granted  California’s request for a waiver for its GHG vehicle
standard (74 FR 32744, July 8, 2009).  These are all separate actions. 
Some actions , some of which are related to EPA’s response to the U.S.
Supreme Court’s decision in Massachusetts v. EPA. 127 S. Ct. 1438
(2007), while others are additional EPA actions to address climate
change.).  This rulemaking does not indicate EPA has made any final
decisions on pending actions.  In fact the mandatory GHG reporting
program will provide EPA, other government agencies, and outside
stakeholders with economy-wide data on facility-level (and in some cases
corporate-level) GHG emissions, which should assist in future policy
development.  

Accurate and timely information on GHG emissions is essential for
informing many future climate change policy decisions.  Although
additional data collection (e.g., for other source categories or to
support additional policy or program needs) will no doubt be required as
the development of climate policies evolves, the data collected in this
rule will provide useful information for a variety of polices.  Through
data collected under this rule, EPA, States and the public will gain a
better understanding of the relative emissions of specific industries
across the nation and the distribution of emissions from individual
facilities within those industries.  The facility-specific data will
also improve our understanding of the factors that influence GHG
emission rates and actions that facilities could in the future or
already take to reduce emissions.  In addition, the data collected on
some source categories could also potentially help inform the design of,
including under traditional and more flexible programs (e.g., offsets,
set-asides, or other incentives). 

UsingAs discussed in more detail in “Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to Public Comments, Legal Issues” and
elsewhere, EPA is promulgating this rule to gather GHG information to
assist EPA in assessing how to address GHG emissions and climate change
under the Clean Air Act.  However, we expect that the information will
prove useful for other purposes as well.  For example, using the rich
data set provided by this rulemaking, EPA, States and the public will be
able to track emission trends from industries and facilities within
industries over time, particularly in response to policies and potential
regulations.  The data collected by this rule will also improve the U.S.
government’s ability to formulate climate policies, and to assess
which industries might be affected, and how these industries might be
affected by potential policies.  Finally, EPA’s experience with other
reporting programs is that such programs raise awareness of emissions
among reporters and other stakeholders, and thus contribute to efforts
to identify and implement emission reduction opportunities.  These data
can also be coupled with efforts at the local, State and Federal levels
to assist corporations and facilities in determining their GHG
footprints and identifying opportunities to reduce emissions (e.g.,
through energy audits or other forms of assistance). 

This GHG reporting program supplements and complements, rather than
duplicates, existing U.S. government programs (e.g., climate policy and
research programs).  For example, EPA anticipates that facility-level
GHG emissions data will lead to improvements in the quality of the
Inventory of U.S. Greenhouse Gas Emissions and Sinks (Inventory), which
EPA prepares annually, with input from several other agencies, and
submits to the Secretariat of the United Nations Framework Convention on
Climate Change (UNFCCC).

A number of EPA voluntary partnership programs include a GHG emissions
and/or reductions reporting component (e.g., Climate Leaders, the
Natural Gas STAR program, Energy Star).  This mandatory reporting
program has broader coverage of U.S. GHG emissions than most voluntary
programs, which typically focus on a specific industry and/or goal
(e.g., reduction of CH4 emissions or development of corporate
inventories).  It will improve EPA’s understanding of emissions from
facilities not currently included in these programs and increase the
coverage of these industries.  That said, we expect ongoing and
potential new voluntary programs to continue to play an important role
in achieving low-cost reductions in GHG emissions.

In addition to the EPA EPA’s programs mentioned above, U.S. Department
of Energy (DOE) EIA implements a voluntary GHG registry under section
1605(b) of the Energy Policy Act, which is further discussed in Section
II of the proposal preamble (74 FR 16458, April 10, 2009).  Under
EIA’s “1605(b) program,” reporters can choose to prepare an
entity-wide GHG inventory and identify specific GHG reductions made by
the entity.  EPA’s mandatory GHG reporting rule covers a much broader
set of reporters, primarily at the facility rather than entity-level,
but this reporting rule is not designed with the specific intent of
reporting of emission reductions, as is the 1605(b) program.

For additional information about these programs, please see Sections I
and II of the preamble to the proposed GHG reporting rule (74 FR 16454,
April 10, 2009).

E.  How does this rule relate to other State and Regional Programs? 

There are several existing State and Regional regional GHG reporting
and/or reduction programs, summarized in Section II of the proposal
preamble (74 FR 16457, April 10, 2009).  These are important programs
that not only led the way in reporting of GHG emissions before the
Federal government acted but also assist in quantifying the GHG
reductions achieved by various reduction policies.  Many of these
programs collect different or additional data as compared to this rule. 
For example, State programs may establish lower thresholds for reporting
or request information on areas not addressed in the EPA EPA’s
reporting rule (e.g., electricity use or emission related to other
indirect sources).  States collecting additional information have
determined that these data are necessary to implement their specific
climate policies and programs.  EPA agrees that State and regional
programs are crucial, to achieving emissions reductions, and this rule
does not pre-empt any other programs.

EPA’s GHG reporting rule is a specific single action that was
specifically developed in response to the Appropriations Act, and
therefore is targeted to accomplish the purpose of the language of the
Appropriations Act and serve EPA’s purposes under the CAA.  As State
experience has demonstrated, we recognize that in order to address the
breadth of climate change issues there will likely be a need to collect
additional data from sources subject to this rule as well as other
sources.  The timing and nature of these additional needs will be
dependent on the types of programs and actions the Agency has underway
or may develop and implement in response to  future policy developments
and/or new requests from Congress.  Addressing climate change will
require a suite of policies and programs and this reporting rule is just
one effort to collect information to inform those policies.  

EPA is committed to working with State and regional programs to
coordinate implementation of reporting programs, reduce burden on
reporters, provide timely access to verified emissions data, establish
mechanisms to efficiently share data, and harmonize data systems to the
extent possible.  See Section II.O of this preamble for a summary of
public comments and responses on the role of States and the relationship
of this GHG reporting rule to other programs.  See Section VI.B of this
preamble for a summary of comments and responses on State delegation of
rule implementation and enforcement.  As mentioned above, for additional
information about existing State and regional programs please see
Section II of the proposal preamble (74 FR 16457, April 10, 2009) and
the docket EPA-HQ-OAR-2008-0508.

II.  General Requirements of the Rule 

The rule requires reporting of annual emissions of CO2, CH4, N2O, SF6,
HFCs, PFCs, and other fluorinated gases (as defined in 40 CFR part 98,
subpart A).) in metric tons.  The final 40 CFR part 98 applies to
certain downstream facilities that emit GHGs, and to certain upstream
suppliers of fossil fuels and industrial GHGs.  For suppliers, the GHG
emissions reported are the emissions that would result from combustion
or use of the products supplied.  The rule also includes provisions to
ensure the accuracy of emissions data through monitoring, recordkeeping
and verification requirements.  Reporting is at the facility level,
except that certain suppliers of fossil fuels and industrial gases would
report at the corporate level.

In addition, GHG reporting by manufacturers of heavy-duty and off-road
vehicles and engines is required, by incorporating new requirements into
the existing reporting requirements for motor vehicles and engine
manufacturers in 40 CFR parts 86, 87, 89, 90, 94, 1033, 1039, 1042,
1045, 1048, 1051, 1054, and 1065.  A summary of the reporting
requirements for manufacturers of motor vehicles and engines is
contained in Section IV of this preamble.  A discussion of public
comments and responses that pertain to motor vehicles is also contained
in Section IV of this preamble. and in the “Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to Public Comments, Motor Vehicle and
Engine Manufacturers.”

The remainder of this section summarizes the general provisions of 40
CFR part 98, identifies changes since the proposed rule, and summarizes
key public comments and responses on the general requirements of the
rule.

A.  Summary of the General Requirements of the Final Rule

1. 	Applicability

Reporters must submit annual GHG reports for the following facilities
and supply operations. 

Any facility that contains any of the source categories source category
(as defined in 40 CFR part 98, subparts C through JJ) that is listed
below in any calendar year starting in 2010.  For these facilities, the
annual GHG report covers all sources in any source category source
categories and GHGs for which calculation methodologies are provided in
40 CFR part 98, subparts C through JJ.

Electricity generating facilities that are subject to the Acid Rain
Program (ARP) or otherwise required to monitor and report CO2 mass
emissions year-round according tothrough 40 CFR part 75 of this chapter.

Adipic acid production.

Aluminum production. 

Ammonia manufacturing.

Cement production.

HCFC-22 production.

HFC-23 destruction processes that are not col-located with a HCFC-22
production facility and that destroy more than 2.14 metric tons of
HFC-23 per year.

Lime manufacturing.

Nitric acid production.

Petrochemical production.

Petroleum refineries.

Phosphoric acid production.

Silicon carbide production.

Soda ash production.

Titanium dioxide production.

Municipal solid waste (MSW) landfills that generate CH4 in amounts
equivalent to 25,000 metric tons CO2e or more per year, as determined
according to 40 CFR part 98, subpart HH.  

Manure management systems that emit CH4 and N20 (combined) in amounts
equivalent to 25,000 metric tons CO2e or more per year, as determined
according to 40 CFR part 98, subpart JJ.

Any facility that contains any of the source categoriescategory (as
defined in 40 CFR part 98, subparts C through JJ) that is listed below
and that emits 25,000 metric tons CO2e or more per year in combined
emissions from stationary fuel combustion units, miscellaneous use of
carbonates and all of the source categories listed in this paragraph in
any calendar year starting in 2010.  For these facilities, the annual
GHG report coversmust cover all source categories located at the
facilityand GHGs for which calculation methodologies are provided in 40
CFR part 98, subparts C through JJ.

Ferroalloy Production.

Glass Production.

Hydrogen Production.

Iron and Steel Production.

Lead Production.

Pulp and Paper Manufacturing.

Zinc Production.

Any facility that in any calendar year starting in 2010 meets all three
of the conditions listed in this paragraph.  For these facilities, the
annual GHG report covers emissions from stationary fuel combustion
units.sources only.  For 2010 only, the facilities can submit an
abbreviated GHG report according to 40 CFR 98.3(d). 

The facility does not meet the requirements described in the above two
paragraphs;

The aggregate maximum rated heat input capacity of the stationary fuel
combustion units at the facility is 30 million British thermal units per
hour (mmBtu/hr) or greater; and

The facility emits 25,000 metric tons CO2e or more per year from all
stationary fuel combustion sources.

Any supplier (as defined in 40 CFR part 98, subparts LL through PP) of
any of the products as listed below in any calendar year starting in
2010.  For these suppliers, the annual GHG report covers all applicable
products for which calculation methodologies are provided in 40 CFR part
98, subparts KK through PP.

Coal-based liquid fuels: All producers of coal-based to-liquid fuels,;
importers and exporters of coal-based to-liquid fuels with annual bulk
imports or annual bulk exports that are equivalent to 25,000 metric tons
CO2e or more per year. 

Petroleum products: All producers of petroleum products,refiners that
distill crude oil; importers and exporters of petroleum products with
annual bulk imports or annaul bulk annual exports that are equivalent to
25,000 metric tons CO2e or more per year.  

Natural gas and natural gas liquids (NGLs): All natural gas
fractionators and all local natural gas distribution companies (LDCs). 

Industrial GHGs:  All producers of industrial GHGs; importers of
industrial GHGs with annual bulk imports of N2O, fluorinated GHGs, and
CO2 that in combination  are equivalent to 25,000 metric tons CO2e or
more per year; exporters of industrial GHGs with annual bulk imports or
exports of N2O, fluorinated GHGs, and CO2 that in combination  are
equivalent to 25,000 metric tons CO2e or more per year.

CO2: All producers of CO2; importers of CO2 with annual bulk imports of
N2O, fluorinated GHGs, and CO2 that in combination are equivalent to
25,000 metric tons CO2e or more per year; exporters of CO2 with annual
bulk imports or exports of N2O, fluorinated GHGs, and CO2 that in
combination are equivalent to 25,000 metric tons CO2e or more per year.

Research and development activities (as defined in 40 CFR 98.6) are not
considered to be part of any source category subject to the rule.

It is important to note that the applicability criteria apply to a
facility’s annual emissions or a supplier’s annual quantity of
product supplied.  For example, while a facility’s emissions may be
below 25,000 metric tons CO2e in January, if the cumulative emissions
for the calendar year are 25,000 metric tons CO2e or more at the end of
December, the rule applies and the reporter must submit an annual GHG
report for that facility.  Therefore, it is in a facilityfacility’s or
supplier’s interest to collect the GHG data required by the rule if
they think they will meet or exceed the applicability criteria in 40 CFR
98.2 by the end of the year.  EPA plans to have tools and guidance
available to assist potential reporters in assessing whether the rule
applies to their facilities or supply operations.

2.  Schedule for Reporting

Reporters must begin collecting data on January 1, 2010.  The first
annual GHG report is due on March 31, 2011, for GHGs emitted or products
supplied during 2010.  For a portion of 2010, the rule allows reporters
to use best available monitoring methods for parameters that cannot
reasonably be measured according to the monitoring and quality
assurance/quality control (QA/QC) requirements of the relevant subpart
as described in Sections II.A.3 and II.G of this preamble.  

Reports are submitted annually.  For EGUs that are subject to the ARP
continue, reporters must continue to report CO2 mass emissions
quarterly, as required by the ARP, in addition to providing annual GHG
reports under this rule.  Reporters must submit GHG data on an ongoing,
annual basis.  The snapshot of information provided by a one-time
information collection request (ICR) would not provide the type of
ongoing information which could inform the variety of potential CAA
policy options being evaluated for addressing climate change.  

Once subject to this reporting rule, reporters must continue to submit
GHG reports annually.  A reporter can cease reporting if the required
annual GHG reports demonstrate that reported GHG emissions ofare either
(1) less than 25,000 metric tons of CO2e per year for 5five consecutive
years and theor (2) less than 15,000 metric tons of CO2e per year for
three consecutive years.  The reporter notifiesmust notify EPA that they
intend to cease reporting and explains the reasons for the reduction in
emissions.  This provision applies to all facilities and suppliers
subject to the rule, regardless of their applicability category (i.e.,
whether rule applicability was initially triggered by an “all-in”
source category or a source category with a 25,000 metric tons CO2e
threshold).  The reporter must keep records for all 5five consecutive
years in which emissions were less than 25,000 metric tons per year, or
all three consecutive years in which emissions were less than 15,000
metric tons per year, as appropriate.  If GHG emissions (or quantities
in products supplied) subsequently increase to 25,000 metric tons CO2e
in any calendar year, the reporter must again begin annual reporting. 
The rule also contains a provision to allow facilities and suppliers to
notify EPA and stop reporting if they close all GHG-emitting processes
and operations covered by the rule. 

If reporters discover or are notified by EPA of errors in an annual GHG
report, they must submit a revised GHG report within 45 days.

3.  What has to be included in the annual GHG report?  

Reporters must include the following information in each annual GHG
report:

Facility name or supplier name (as appropriate) and physical street
address including the city, stateState, and zip code.

Year and months covered by the report, and date of report submittal.

For facilities that directly emit GHG:

Annual total facility emissions (excluding biogenic CO2), expressed in
metric tons of CO2e per year, aggregated for all GHG from all source
categories in 40 CFR part 98, subparts C through JJ that are located at
the facility. 

Annual emissions of biogenic CO2 (i.e., CO2 from combustion of biomass)
aggregated for all applicable source categories in subparts C through JJ
located at the facility.

Annual GHG emissions for each of the source categories located at the
facility, by gas. Gases are: CO2 (excluding biogenic CO2), biogenic CO2,
CH4, N2O, and each fluorinated GHG.

Within each source category, emissions broken out at the level specified
in the respective subpart (e.g., some source categories require
reporting is required for each individual unit for some source
categories and for each process line for other source categories).  

Additional data specified in the applicable subparts for each source
category.  This includes activity data (e.g., fuel use, feedstock
inputs) that were used to generate the emissions data and additional
data to support QA/QC and emissions verification.    

CO2 emissions from the combustion of biomass, aggregated at the facility
level.

Total annual mass of CO2 captured in metric tons.

Total pounds of synthetic fertilizer produced through nitric acid or
ammonia production and total nitrogen contained in that fertilizer.

For suppliers: 

Annual quantities of each GHG that would be emitted from combustion or
use of the products supplied, imported, or exported during the year. 
Report this for each applicable supply category in 40 CFR part 98
subparts KK through PP, by gas.  Also report the total quantity,
expressed in metric tons of CO2e, aggregated for all GHGs from all
applicable supply categories.

Additional data specified in the applicable subparts for each supply
category.  This includes data used to calculate GHG quantities or needed
to support QA/QC and verification.  

A written explanation if the reporter changes GHG calculation
methodologies during the reporting period. 

If best available monitoring methods were used for part of calendar year
2010, a brief description of the methods used.

Each data element for which a missing data procedure was used according
to the procedures of an applicable subpart and the total number of hours
in the year that a missing data procedure was used for each data
element.

A signed and dated certification statement provided by the designated
representativeDesignated Representative of the owner or operator.

Note that in some cases, the same facility is subject to the rule
requirements for direct emitters as well as for suppliers.  For example,
petroleum refineries are suppliers of petroleum products (40 CFR part
98, subpart NN) and also directly emit GHGs from petroleum refining (40
CFR part 98, subpart Y), general stationary fuel combustion (40 CFR part
98, subpart C), and possibly other source categories located at a
refinery.  In such cases, reporters must report the information in both
the facility and supplier bullets listed above.

EPA will protect any information claimed as CBI in accordance with
regulations in 40 CFR part 2, subpart B.  However, note that in general,
emission data collected under CAA sections 114 and 208 shall be
available to the public and cannot be consideredwithheld as CBI. 

Special Provisions for Reporting Year 2010.  During January 1, 2010
through March 31, 2010, reporters may use best available monitoring
methods for any parameter (e.g., fuel use, daily carbon content of
feedstock by process line) that cannot reasonably be measured according
to the monitoring and QA/QC requirements of a relevant subpart.  The
reporter must still use the calculation proceduresmethodologies and
equations in the “Calculating GHG Emissions” sections of each
relevant subpart, but may use the best available monitoring method for
any parameter for which it is not reasonably feasible to acquire,
install, and operate a required piece of monitoring equipment by January
1, 2010.  Starting no later than April 1, 2010, the reporter must begin
following all applicable monitoring and QA/QC requirements of this part,
unless they submit a request to EPA showing that it is not reasonably
feasible to acquire, install, and operate a required piece of monitoring
equipment by April 1, 2010, and EPA approves the request.  EPA will not
approve use of best available methods beyond December 31, 2010.  Best
available monitoring methods include any of the following methods:

Monitoring methods currently used by the facility that do not meet the
specifications of a relevant subpart.

Supplier data.

Engineering calculations.

Other company data.

Abbreviated GHG Report for Facilities Containing Only General Stationary
Fuel Combustion Sources.  In lieu of a full annual GHG report, reporters
may submit an abbreviated GHG report for 2010 emissions from existing
facilities that were in operation as of January 1, 2010, and are
required to report only their stationary combustion source emissions per
40 CFR 98.2(a)(3).  The abbreviated report contains total facility GHG
emissions aggregated for all stationary combustion units calculated
according to any of the methods in 40 CFR 98.33(a) and expressed in
metric tons of CO2, CH4, N2O, and CO2e.  While the breakdown of
emissions by individual combustion units and the activity data used to
calculate the emissions do not need to be reported as part of the
abbreviated GHG report, the calculation variables used in the selected
method aremust be reported.  For calendar year 2011, all reporters must
submit the full annual GHG report containing all required information.

4.  How is the report submitted? 

The reports must be submitted electronically, in a format to be
specified by the Administrator after publication of the final rule.  To
the extent practicable, we plan to adapt existing EPA facility reporting
programs to accept GHG emissions data.  We are developing a new
electronic data reporting system for source categories or suppliers for
which it is not feasible to use EPA existing EPA reporting mechanisms.

Each report must contain a signed certification by a Designated
Representative of the facility.  On behalf of the owners and operators,
the Designated Representative must certify under penalty of law that the
report has been prepared in accordance with the requirements of 40 CFR
part 98 and that the information contained in the report is true and
accurate.

5.  What records must be retained? 

Each reporter must also retain and make available to EPA upon request
the following records for three years in an electronic or hard-copy
format as appropriate:

A list of all units, operations, processes and activities for which GHG
emissions are calculated.

The data used to calculate the GHG emissions for each unit, operation,
process, and activity, categorized by fuel or material type.  These data
include, but are not limited to:

The GHG emissions calculations and methods used.

Analytical results for the development of site-specific emissions
factors.

The results of all required analyses for high heat value, carbon
content, or other required fuel or feedstock parameters.

Any facility operating data or process information used for the GHG
emissions calculations.

The results of all required certification and QA tests of CEMS and fuel
flow meters if applicable.

The annual GHG reports. 

Missing data computations.  For each missing data event, also retain a
record of the duration of the event, actions taken to restore
malfunctioning monitoring equipment, the cause of the event, and the
actions taken to prevent or minimize occurrence in the future. 

A written GHG monitoring plan containing the information specified in 40
CFR 98.3(g)(5).

The results of all required certification and quality assurance (QA)
tests of CEMS, fuel flow meters, and other instrumentation used to
provide data for the GHGs reported.

Maintenance records for all CEMS, flow meters, and other instrumentation
used to provide data for the GHGs reported.

Any other data specified in any applicable subpart of 40 CFR part 98. 
Examples of such data could include the results of sampling and analysis
procedures required by the subparts (e.g., fuel heat content, carbon
content of raw materials, and flow rate) and other data used to
calculate emissions.

B.  Summary of the Major Changes Since Proposal

EPA received approximately 16,800 public comments on the proposed
rulemaking.  As mentioned earlier in this preamble, we had two public
hearings and conducted an unprecedented level of outreach between
signature of the proposal and the close of the public comment period. 
Below are the major changes to the program since the proposal.  The
rationale for these and any other significant changes can be found in
this preamble or in the comment response documents:“Mandatory
Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments.”

Reduced the number of source categories included in the final rule as we
further consider comments and options on several categories.

Added a mechanism in 40 CFR 98.2 to allow facilities and suppliers that
report less than 25,000 metric tons of CO2e for 5five consecutive years,
or less than 15,000 metric tons for 3 consecutive years, to cease annual
reporting to EPA.

Added a mechanism in 40 CFR 98.2 to allow facilities and suppliers that
stop operating all GHG-emitting processes and operations covered by the
rule to cease annual reporting to EPA.

Added a provision in 40 CFR 98.3 for submittal of revised annual GHG
reports to correct errors.

Added provisions in 40 CFR 98.3 to allow use of best available
monitoring methods for part of calendar year 2010.

Added, in 40 CFR 98.3, calibration requirements for monitoring
instruments including an accuracy specification of plus or minus 5five
percent for flow meters.

Excluded R&D activities from reporting under 40 CFR part 98 by adding an
exclusion in 40 CFR 98.2.

Revised the requirements of the Designated Representative in 40 CFR 98.4
to align them with those in 40 CFR part 75 (ARP regulations).

Changed record retention to 3three years instead of 5five years for most
records (40 CFR 98.3).

In the recordkeeping section (40 CFR 98.3), clarified the contents of
the monitoring plan (called the quality assurance performance plan
(QAPP) at proposal).

Edited references to the stationary fuel combustion subpart to improve
consistency and edited the CEMS language in several subparts for
consistency and to clarify when CEMS are used and under what
circumstances upgrades are needed.  

Revised several definitions in 40 CFR part 98, subpart A to address
comments.

In several subparts of 40 CFR part 98, moved some of the data elements
listed in the recordkeeping section of the proposed rule to the
reporting section.  In general, these changes were made to provide
sufficient data for EPA to verify the reported emissions using the
verification approach described in Section II.N of this preamble. 
Specific changes and reasons for them are summarized in the relevant
source category sections within Section III of this preamble.  

C.  Summary of Comments and Responses on GHGs to Report

 This section contains a brief summary of major comments and responses
on the issue of which GHGs to report.  A large number of comments were
received covering numerous topics.  Responses to significant comments
received can be found in the comment response documents
(EPA-HQ-OAR-2008-0508-XXX).“Mandatory Greenhouse Gas Reporting Rule:
EPA’s Response to Public Comments, Selection of Reporting Thresholds,
Greenhouse Gases, and De Minimis Provisions.”  Reponses to comments on
fluorinated gases can be found in “Mandatory Greenhouse Gas Reporting
Rule: EPA’s Response to Public Comments, Suppliers of Industrial
GHGs.”

Comment: Many commenters supported reporting of the GHGs included in the
proposed rule: CO2, CH4, N2O, HFCs, PFCs, SF6, and other fluorinated
compounds.  Many commenters noted that IPCC and national inventories
focus on these gases, and that they are directly emitted by human
activities, long-lived in the atmosphere, and contribute to global
climate change.  A few of these also stated that collection of data on
these gases is useful for future GHG policy development.  While some
commenters suggested collecting data on fewer gases or requiring
reporting of additional gases, most agreed with the proposed list.

Some commenters raised concerns that the proposed definition of
fluorinated GHGs was broad and included compounds for which global
warming potentials (GWPs) were not currently available.

Response: The final rule requires reporting of the same gases as the
proposed rule.  These are the most abundantly emitted GHGs that result
from human activity.  They are not currently controlled by mandatory
Federal programs and, with the exception of the CO2 emissions data
reported by EGUs subject to the ARP, data on their emissions are also
not reported under mandatory Federal programs.  CO2 is  the most
abundant GHG directly emitted by human activities, and is a significant
driver of climate change.  The global anthropogenic combined heating
effect of CH4, N2O, HFCs, PFCs, SF6, and the other fluorinated compounds
are also significant:  about 40 percent as large as the CO2 heating
effect according to the Fourth Assessment Report of the IPCC. 

The IPCC focuses on CO2, CH4, N2O, HFCs, PFCs, and SF6 for both
scientific assessments and emissions inventory purposes because these
are long-lived, well-mixed GHGs not controlled by the Montreal Protocol
as Substances that Deplete the Ozone (O3) Layer.  These GHGs are
directly emitted by human activities, are reported annually in EPA’s
Inventory of U.S. Greenhouse Gas Emissions and Sinks, and are a major
focus of the climate change research and policy communities.  The IPCC
also included methods for accounting for emissions from several
specified fluorinated gases in the 2006 IPCC Guidelines for National
Greenhouse Gas Inventories.  These gases include fluorinated ethers,
which are used in electronics, in anesthetics, and as heat transfer
fluids.  These fluorinated compounds are long-lived in the atmosphere
and have high GWPs, like the HFCs, PFCs, and SF6.  In many cases these
fluorinated gases are used in growing industries (e.g., electronics) or
as substitutes for HFCs.  As such, EPA is requiring reporting of these
gases to ensure that the Agency has an accurate understanding of the
emissions and uses of these gases, particularly as those uses expand. 

There are other GHGs and aerosols that have climatic warming effects
that we are not including in this rule:  water vapor,
chlorofluorocarbons (CFCs, ), hydrochlorofluorocarbons (HCFCs), halons,
tropospheric O3, and black carbon.  The reasons why we are not requiring
reporting of these gases and aerosols under this rule are contained in
Section IV.A of the preamble to the proposed rule (74 FR 16464, April
10, 2009) and in the comment response document.“Mandatory Greenhouse
Gas Reporting Rule: EPA’s Response to Public Comments, Selection of
Reporting Thresholds, Greenhouse Gases, and De Minimis Provisions.”

In response to comments, the definition of fluorinated gases to report
has been changed.  See Section III.OO of this preamble (Suppliers of
Industrial GHGs) for the response to comments on fluorinated gases to be
reported. 

D.  Summary of Comments and Responses on Source Categories to Report

This section contains a brief summary of major comments and responses on
which source categories must report.  A large number of comments were
received covering numerous topics.  Responses to significant comments
received can be found in the comment response documents
(EPA-HQ-OAR-2008-0508-XXX).“Mandatory Greenhouse Gas Reporting Rule:
EPA’s Response to Public Comments, Selection of Source Categories to
Report and Level of Reporting.”

1.  Reduction in number of source categories included in the final rule

Comment: While many commenters agreed with the source categories
selected for inclusion in the proposed rule, some commenters objected to
the inclusion of specific source categories.  Some also expressed
concern that there might not be sufficient time for EPA to consider and
address public comments and finalize the rules by fall 2009 for
particular source categories.

Response: In today’s notice EPA is promulgating subparts that required
reporting for most of the source categories included in the proposed
rule.  For these categories, EPA fully considered and addressed the
public comments, and has determined that the source categories should be
included in the rule for reasons stated in Section IV.B of the preamble
for the proposed rule (74 FR 16465, April 10, 2009)), the “Mandatory
Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments:
EPA’s Response to Public Comments, Selection of Source Categories to
Report and Level of Reporting”, and the relevant comment response
documents.volumes for each of the individual source categories. 
However, at this time EPA is not going final with the following subparts
as we further evaluate public comments and other considerations:

Electronics manufacturing

Ethanol production

Fluorinated GHG production

Food processing

Magnesium production

Oil and natural gas systems

SF6 from electrical equipment

Underground coal mines

Industrial landfills

Wastewater treatment

Suppliers of coal

We plan to further review public comments and other information before
finalizing these subparts.  Additional discussion of our reasons for not
finalizing these particular source categories at this time can be found
in the individual subsections in Section III of this preamble.

2.  Scope of source categories covered

Comment: Several commenters suggested that the scope of reporting and
the source categories covered should be broader.  Some indicated that
the rule should require reporting of net rather than gross emissions,
including reporting of offset projects.  In particularaddition, some of
the comments suggested requiring reporting of emissions and
sequestration from forestry practices. 

Response: EPA selected the source categories required to report under
the rule after considering the language of the Appropriations Act, the
accompanying explanatory statement, the CAA, and EPA’s experience in
developing the U.S. GHG Inventory.  The Appropriations Act referred to
reporting “in all sectors of the economy,” and the explanatory
statement directed EPA to include “emissions from upstream production
and downstream sources to the extent the Administrator deems it
appropriate.”  EPA interpreted this to mean direct emissions from
facilities over a certain threshold as well as the emissions associated
with fuel or industrial gases when completely combusted or used, but not
necessarily project-based reductions or sequestration.  Calculation and
reporting of net emissions (emissions at a facility less any
sequestration occurring at the facility) are therefore was determined to
be outside of the scope of this rule.  

In selecting source categories, EPA considered all anthropogenic sources
of GHG emissions (those produced as a result of human activities)
included in the U.S. GHG Inventory and reviewed the 2006 IPCC Guidelines
for National Greenhouse Gas Inventories and existing voluntary and
regulatory GHG reporting programs for additional source categories that
might be relevant.  EPA systematically reviewed the list of source
categories developed from the U.S. GHG Inventory and the IPCC guidance
to ensure the inclusion of those that emit the most significant amounts
of GHG emissions while minimizing the number of reporters.  Some sources
were deemed inappropriate for inclusion in this rule for a variety of
reasons including the current ability to monitor and verify the
emissions or products with sufficient accuracy and consistency.  For
further discussions of sources included and excluded please see Section
IV.B of the preamble to the the proposed rule (74 FR 16465).  In total,
the rule is estimated to cover approximately 85 percent of U.S. GHG
emissions.

With respect to emissions and sequestration from agricultural sources
and other land uses, the rule does not require reporting of emissions or
sequestration associated with deforestation, carbon storage in living
biomass or harvested wood products.  These categories were excluded
because currently available, practical reporting methods to calculate
facility-level emissions for these sources can be difficult to implement
and can yield uncertain results.  Currently, there are no direct GHG
emission measurement methods available except for research methods that
are very expensive and require sophisticated equipment.  Limited
modeling-based methods have been developed for voluntary GHG reporting
protocols which use general emission factors, and large-scale models
have been developed to produce comprehensive national-level emissions
estimates, such as those reported in the U.S. GHG Inventory report.  To
calculate emissions or sequestration using emission factor or carbon
stock exchange approaches, it would be necessary for landowners to
report on management practices and a variety of data inputs.  The
activity data collection and emission factor development necessary for
emissions calculations at the scale of individual reporters can be
complex and costly.  Due to the current lack of reasonably accurate
facility-level emissions/stock change factors and the ability to
accurately measure all facility-level calculation variables at a
reasonable cost to reporters, the reporting of emissions and
sequestration associated with deforestation and carbon sequestration
from forestry practices was excluded as a source category.

While this reporting rule does not require reporting by facilities or
suppliers in every source category, the U.S. GHG Inventory does provide
national estimates of emissions from all U.S. anthropogenic GHG sources.
 It In the case of land-based emissions, this includes all emissions by
sources and removals by sinks on lands that are managed.  The Inventory
is prepared annually by EPA, in collaboration with other Federal
agencies, and is an impartial, policy-neutral report that tracks annual
greenhouse gasGHG emissions at the national level and presents
historical emissions from 1990 to 2007.  The Inventory also calculates
carbon dioxide emissions that are removed from the atmosphere by
“sinks,” such as through the uptake of carbon by forests,
vegetation, and soils.

Offsets projects are of interest to many stakeholders because they could
be an important component of a potential future cap and trade system. 
Some commenters requested EPA to include accounting methods for offsets
in this reporting rule.  We believe that this issue is beyond the scope
of this rulemaking and the Congressional request that initiated it. 
However, EPA will continue to monitor policy needs and developments in
the future and is prepared to initiate additional reporting efforts at
the appropriate time. 

3.  Reporting by both upstream and downstream sources

Comment:  Some commenters were concerned that requiring reporting by
both fuel and industrial GHG suppliers (upstream sources) and direct
emitters (downstream sources) results in double counting of GHG
emissions and could lead to overestimation of emissions.  Some
commenters thought reporting by both upstream and downstream sources was
duplicative, confusing, unnecessary, or burdensome and recommended the
rule be revised to eliminate double reporting.  Other commenters agreed
with EPA’s proposed selection of source categories to report and that
reporting by upstream sources and downstream sources is needed to inform
development of GHG policies and programs.

Response: This rule responds to a specific request from Congress to
collect data on GHG emissions from both upstream production and
downstream sources, as appropriate.  The rule requires reporting by
facilities that directly emit GHGs above the selected threshold as a
result of combustion of fuel or industrial processes (downstream
sources).  The majority of these reporters are large facilities in the
electricity generation and industrial sectors.  The rule also requires
upstream suppliers of fossil fuels and industrial GHGs to report the GHG
emissions that could be emitted from combustion or use of the quantity
of fuels or industrial gases supplied into the economy.  In many cases,
the fossil fuels and industrial GHGs supplied by producers and importers
are used and ultimately emitted by a large number of small sources.  To
cover these direct emissions would require reporting by hundreds or
thousands of small facilities.  To avoid this impact, the rule does not
include all of those emitters but instead requires reporting by the
suppliers of industrial gases and suppliers of fossil fuels.  

The data collected under this rule are consistent with the
appropriations language and provide valuable information to EPA and
stakeholders in the development of climate change policy and programs. 
Potential policies such as low carbon fuel standards can only be applied
upstream, whereas end-use emission standards can only be applied
downstream.  Data from upstream and downstream sources would be
necessary to formulate and assess the impacts of such potential
policies.  Eliminating reporting by either upstream sources or
downstream sources would not satisfy EPA’s data needs and policy
objectives of this rule.

EPA acknowledges that there is inherent double reporting of emissions in
a program that includes both upstream and downstream sources.  However,
as discussed in Sections I.D and IV.B of the preamble to the proposed
rule (74 FR 16448, April 10, 2009) EPA does not intend to use emissions
data collected by this rule as a replacement for the national emission
estimates found in the annual Inventory of GHG emissions.  

E.  Summary of Comments and Responses on Thresholds

This section contains a brief summary of major comments and responses on
EPA’s approach and rationale for selection of reporting thresholds. 
See sections III.C through PP of this preamble for summaries of comments
and responses on specific threshold analyses for the individual source
categories contained in 40 CFR part 98, subparts C through PP.  A large
number of comments were received covering numerous topics.  Responses to
significant comments received can be found in the comment response
documents (EPA-HQ-OAR-2008-0508-XXX).“Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to Public Comments, Selection of
Reporting Thresholds, Greenhouse Gases, and De Minimis Provisions.”

Comment:  Many commenters supported the proposed threshold of 25,000
metric tons of CO2e per calendar year.  These commenters generally
agreed that the 25,000 metric ton threshold level achieves a reasonable
balance between the percentage of national emissions covered and the
number of reporters, resulting in a sufficiently comprehensive dataset
while minimizing the impact on small facilities.  Some also commented
that this threshold is consistent with other existing GHG programs or
likely future programs.  Some commenters supported a 100,000 metric ton
CO2e threshold because they believe this level covers an appropriate
percentage of national GHG emissions while easing the reporting burden
on industry.  Some commenters supported an emission threshold of 10,000
metric tons CO2e to enable collection of emissions data for smaller
sources. Some of these commenters also noted that a 10,000 metric ton
CO2e threshold is more appropriate in order to monitor leakage of
emissions to smaller sources (since 25,000 metric tons of CO2e is a
likely threshold for future emissions reductions mandates).  Some
commenters suggested quantitative evaluation of intermediate threshold
options in addition to the four evaluated by EPA (1,000; 10,000; 25,000;
and 100,000); several of these suggested EPA analyze a threshold of
50,000 metric tons CO2e to reduce the number of reporting facilities.

Response: As described in the preamble to the proposed rule (74 FR
16448, April 10, 2009), EPA considered four threshold levels, as well as
capacity-based thresholds where appropriate, and we proposed a threshold
of 25,000 metric tons of CO2e for many source categories with , and
capacity-based or “all in” thresholds for other categories. 
(Although the thresholds were expressed in different ways, most
corresponded to, or were consistent with, an annual facility-wide
emission level of 25,000 metric tons of CO2e.)  Based on comments
received, we reexamined the threshold analyses both in general and for
each industry, taking into account additional data provided, and we
considered whether there were reasons to develop different thresholds in
specific industry sectors.  The specific elements of these analyses are
discussed in the relevant source category discussions in this preamble
and the accompanying comment response documents.“Mandatory Greenhouse
Gas Reporting Rule: EPA’s Response to Public Comments” volumes for
each source category.  At the general level, we also considered
non-quantitative factors, such as consistency with State and other
programs (the majority have established thresholds for GHG reporting at
25,000 metric tons or lower, such as 10,000 or 5,000 metric tons), and
the need to select a threshold level that best satisfies the objective
of the reporting rule to collect a national data set that is
sufficiently comprehensive for use in analyzing potentiala range of GHG
policies and developing future CAA programs.  

From these analyses, we concluded that a 25,000 metric ton threshold
suited the needs of the reporting program by providing comprehensive
coverage of emissions with a reasonable number of reporters, thereby
creating the robust data set necessary for the quantitative analyses of
the range of likely GHG policies, programs and that regulations.
Moreover, the 25,000 metric ton threshold covers similarly sized sources
as covered by many current CAA programs (e.g., NSPS applies PM emissions
limits to oil-fired and coal-fired units larger than 30 mmBtu per hour).
 And, as mentioned previously, this level is consistent with (or higher
than) the majority of other GHG reporting programs.  Furthermore, having
a uniform threshold was an equitable approach because like facilities
could be compared across sectors and no one industry would be
disproportionately affected or subjected to a lower or higher threshold.
 A uniform threshold is also essential for evaluating potential policies
and programs that could have a single emissions threshold across source
categories (e.g., PSD), and simplifies the applicability determination
for facilities that emit GHGs from more than one source category under
the rule.  

As discussed in sectionSection IV.C of the preamble to the proposed rule
(74 FR 16448, April 10, 2009), we considered four potential thresholds
(the range of 1,000 to 100,000 metric tons of CO2e) and through thatfrom
our analysis and the comments we concluded we had enough information to
select an appropriate threshold for the final rule and that detailed
quantitative analyses of additional intermediate thresholds would not
change EPA’s decision.  For example, in reviewing our threshold
analyses, we determined that the intermediate options between 25,000 and
100,000 metric tons would not provide an alternative threshold that
substantially reduced the number of the reporters relative to other
options considered or substantially improved the cost effectiveness. 
(See “Review of Threshold Analyses” memorandum in docket
EPA-HQ-OAR-2008-0508.)  Based on our analysis for the proposal analysis
on the data available, we saw that the majority of the affected
facilities or suppliers had emissions either considerably above or below
25,000 metric tons CO2e per year.  (As previously explained, supplier
GHG quantities represent the emissions that could be released when the
products they supply are combusted or used.)  The selected threshold
took into account our finding that while a threshold other than 25,000
metric tons of CO2e might appear to achieve an appropriate balance
between the number of facilities and emissions covered for a limited
number of source categories, there are several additional reasons for
selecting the threshold of 25,000 metric tons of CO2e per year.

The lower threshold alternatives that we considered were 1,000 metric
tons of CO2e per year, and 10,000 metric tons of CO2e per year.  At
proposal, we explained that we did not select either of these thresholds
because although both broaden national emissions coverage, they do so by
disproportionately increasing the number of affected facilities.  With
the data available at proposal and from the comment period, we remain
convinced that the 1,000 metric ton CO2e/year threshold would increase
the number of reporters by an order of magnitude, thus changing the
focus of the program from large to small emitters and imposing reporting
costs on tens of thousands of small businesses that in total would
amount to less than 10 percent of national GHG emissions.  Our analysis
indicates that a 10,000 metric ton CO2e/yr threshold would approximately
double the number of reporters, but would only increase national
emissions coverage by 1one percent.  (See the Regulatory Impacts
Analysis for the final rule for the estimated number of facilities and
GHG emissions covered by the alternative thresholds examined.)  While
some proposals (e.g., WCI and Waxman-MarkeyH.R. 2454, American Clean
Energy and Security Act) contain a 10,000 metric ton threshold for
reporting, EPA concluded for policy evaluation purposes, the 25,000
metric ton threshold more effectively targets large industrial emitters
and suppliers, covers approximately 85 percent of U.S. emissions, and
minimizes the burden on smaller facilities.

We also reviewed the 100,000 metric tons of CO2e per year as an
alternative threshold but concluded that it fails to satisfy key
objectives.  It may excludeexcludes a number of emitters in certain
source categories such that the emissions data would not adequately
cover key sectors of the economy.  At 100,000 metric tons CO2e per year,
reporting for severalsome large industry sectors would be rather
significantly fragmented, resulting in an incomplete understanding of
direct emissions from that sector.  We concluded that this threshold
would not sufficiently cover the types of facilities that are typically
regulated under the CAA and would be inadequate for the intended use of
analyzing potential policies and developing future CAA programs. 

Based on our review, EPA has determined that the selected 25,000 metric
ton CO2e threshold will cover many of the types of facilities and
suppliers typically regulated under the CAA, while appropriately
balancing emission coverage and burden.  At this threshold, EPA will be
able to evaluate the effects of a number of options and policies that
could address GHG emissions without placing an undue burden on a large
number of smaller facilities and sources.  In addition, thatthis
threshold level is largely consistent with many of the existing GHG
reporting programs and different legislative proposals in Congress. 
Furthermore, many industry stakeholders that EPA met with and the
majority of public commenters, representing a wide variety of
stakeholders, expressed support for a 25,000 metric ton CO2e threshold,
agreeing with the Agency’s assessment of coverage.

F.  Summary of Comments and Responses on Level of Reporting

This section contains a brief summary of major comments and responses on
the level of reporting.  A large number of comments were received
covering numerous topics.  Responses to significant comments received
can be found in the comment response documents
(EPA-HQ-OAR-2008-0508-XXX).“Mandatory Greenhouse Gas Reporting Rule:
EPA’s Response to Public Comments, Selection of Source Categories to
Report and Level of Reporting.”

Comment:  Many commenters supported facility-level reporting rather than
corporate-level reporting.  The reasons they gave included:
facility-level reporting is consistent with most air rules and
permitting programs, environmental managers are used to facility-level
reporting, facility-level data would be needed to implement likely
future regulatory programs such as a cap and trade program, this
approach is simpler to implement and minimizes administrative burden, a
facility’s corporate status can change during the year, and tying data
to physical sources makes emissions easier to track and monitor over
time.  On the other hand, several commenters favored corporate-level
reporting.  The reasons they gave included: the effect of GHG emissions
is global, therefore the location where the GHGs are emitted is not
important; various other GHG programs require corporate-level reporting
and have mechanisms for handling ownership changes; the overall carbon
footprint of a corporation is important; a company’s entire emissions
should be reported, not just those facilities that are above a
threshold; and facility-level data is are more likely to be CBI. 

Response:  In response to comments, EPA reviewed our initial views
outlined in Sections IV.D and V or of the proposal preamble (74 FR
16448, April 10, 2009) in light of our data needs under the CAA, our
interpretation of the Congressional request, and the feedback received. 
Based on these considerations, we determined that the final rule will
retain the same reporting level as the proposed rule.  Facility-level
reporting is required, with the exception of some supplier source
categories (e.g., importers of fuels or industrial GHGs or manufacturers
of motor vehicles and engines).  If a facility is covered by the rule,
the reporter must report the facility’s GHG emissions from all source
categories for which the rule contains GHG emission methods.  The total
emissions for the facility are reported, as well as emissions broken out
by source category within the facility.  Subparts for some source
categories specify further breakout of emissions by process line or
unit.  

We retained this approach because the purpose of this rule is to collect
data from suppliers and from facilities with direct GHG emissions above
selected thresholds for use in analyzing, developing, and implementing
potential future CAA GHG policies and programs.  Facility-level data are
needed to support analyses of some types of potential GHG reduction
programs, such as cap and trade programs and NSPS.  The data collected
from facility-level reporting under this rule will improve the U.S.
government’sour ability to formulate a set of climate change policy
options and to assess which facilities and industries would be affected
by the options and how they would be affected.  Facility(Note, we expect
that similarly, facility-level data will also be useful to States, the
public, and other stakeholders to formulate State and regional programs
and track emission trends over time..)  Reporting by individual
facilities is also consistent with most existing air regulatory such as
ARP, NSPS and national emission standards for hazardous air pollutants
(NESHAP), and permitting programs.  Many facility environmental managers
are already experienced with facility-level emissions reporting under
such programs and can likewise submit reports under the mandatory GHG
reporting rule.  

Corporate-level reporting was not selected because corporate reporting
without facility-specific details would not provide sufficient data to
assess many potential CAA GHG policies and programs.  EPA understands
that some corporate-level GHG reporting programs have mechanisms to
establish reporting responsibilities under complex and changing
ownership situations, but we find corporate-level reporting overly
complex for this rulemaking given that facility level data are needed,
and it is simpler to place reporting responsibility directly on
individual facilities.  We note that while EPA requires facility-level
reporting, it is up to the facility owners and operators to select the
designated representative who will submit the report for a facility, and
reporters can also establish any internal corporate review processes
they deem appropriate.  

While EPA agrees with the commenters who indicated that information on
corporate carbon footprints is useful for various purposes, collection
of such information is outside the scope of this rulemaking.  WeWith
that said, we are exploring options for adding additional data elements
to the reports, such as name of parent company and NAICS code(s), to
allow easier aggregation of facility-level data to the corporate level
under this program.  EPA expects to subject any additional requests to
notice and comment rulemaking.  In any event, we expect that the
facility-level data collected under this rule will be useful for
programs that request or require corporate reporting.  But, as explained
in Sections I.D and I.E of this preamble, this reporting rule is one
action to respond to a specific request from Congress.  Various other
Federal and State programs are collecting and will continue to collect
corporate-level data on direct and indirect emissions, energy
efficiency, and other data as part of a broad array of climate change
initiatives.  

For the response to the commenters’ concern about CBI, see Section
II.R of this preamble.

G.  Summary of Comments and Responses on Initial Reporting Year and Best
Available Monitoring Methods

This section contains a brief summary of major comments and responses on
the initial reporting year.  A large number of comments were received
covering numerous topics.  Responses to significant comments received
can be found in “Mandatory Greenhouse Gas Reporting Rule: EPA’s
Response to Public Comments, Initial Year of Reporting, Duration of the
comment response documents (EPA-HQ-OAR-2008-0508-XXX).Reporting Program,
and Provisions to Cease Reporting.”

Comment: The proposed rule included reporting of calendar year 2010
emissions in March 2011, which would require reporters to collect data
starting on January 1, 2010.  The preamble to the proposed rule also
discussed options of allowing reporting of best available data for 2010,
or delaying reporting by one year (64 FR 16471, April 10, 2009).  Many
industries with source categories covered by the proposed rule commented
that a data collection start date of January 1, 2010, does not provide
sufficient time to review the final rule, purchase and install required
monitoring equipment, train staff, and develop internal electronic data
management and recordkeeping systems needed to comply with the rule. 
Many indicated that they do not currently have all the meters and
monitoring equipment required by the rule.  Most of these commenters
strongly stated that calendar year 2011 should be the first reporting
year.  Many of them also stated that if EPA decides data collection must
begin in 2010, a best available data approach should be allowed for
calculating and reporting 2010 emissions.  

Conversely, Congressional inquiries and a large number of public
commenters including States, NGOs, and the general public, emphasized
that data collection must start in 2010 because time is of the essence
for developing and implementing GHG policies and programs.  These
commenters urged EPA to require reporting of calendar year 2010 GHG
emissions and not to delay data collection until calendar year 2011.  

Some of the commenters made suggestions about the types of data and
methods that could be allowed if EPA chose to use a best available data
approach for 2010. 

Response: EPA carefully reviewed input from all commenters with the goal
of balancing the urgent need for data against the legitimate concerns
raised regarding timing.  As a result, we have revised the approach for
the final rule.  The final rule requires data collection for calendar
year 2010, but has been changed since proposal to allow use of best
available monitoring methods for the first quarter of 2010.  

Schedule.  EPA decided to require reporting of calendar year 2010
emissions because the data are crucial to the timely development of
future GHG policy and regulatory programs.  In the Appropriation Act,
Congress requested EPA to develop this reporting program on an expedited
schedule, and Congressional inquiries along with public comments
reinforce that data collection for calendar year 2010 is a priority. 
Delaying data collection until calendar year 2011 would mean the data
would not be received until 2012, which would likely be too late for
many ongoing GHG policy and program development needs.  

However, EPA understands that because the final rule is not being
promulgated until fall of 2009, facilities that do not already have the
monitoring systems required by the rule in place might not have time to
install and begin operating them by January 1, 2010.  Under the schedule
in the Appropriations Act, the final rule would have been signed at the
end of June 2009, which would have allowed approximately 6six months to
prepare for data collection in January 2010.  Given the delay in
promulgating the rule, there is less time between signature of the rule
and a January 1, 2010 start date.  In light of this fact, and the
industry comments indicating that facilities do not currently have all
of the required monitoring systems, EPA has decided to provide
flexibility by establishing a best available monitoring methods option
for the first quarter of calendar year 2010.  This approach will provide
time comparable to what would have occurred had EPA met the schedule in
the Congressional request.  We will post the rule on the EPAEPA’s Web
site soon after signature, allowing reporters to see the final
requirements and begin compliance planning even before the rule is
published in the Federal Register.  

For the time period of January 1 through March 31, 2010, the rule allows
use of best available monitoring methods for parameters that cannot
reasonably be measured according to the monitoring and QA/QC
requirements of the relevant subpart.  Starting no later than April 1,
2010, the reporter must begin following all applicable monitoring and
QA/QC requirements of this part, unless they submit an extension request
showing that it is not reasonably feasible to acquire, install, and
operate a required piece of monitoring equipment by the specified date
and EPA approves the request.  EPA may approve such requests for a set
time period, but will not approve the use of best available methods
beyond December 31, 2010.  See the paragraph heading “Extension
Request Process” near the end of this response for further details.

EPA has concluded that the time period allowed under this schedule
(including the provision for facility-specific requests) will allow
facilities that do not currently have the required monitoring systems
sufficient time to begin implementing the monitoring methods required by
the rule.  In general, the required monitors, such as flow meters, are
widely available and are not time consuming to install.  By allowing the
additional time, many facilities may also be able to install the
equipment during other planned (or unplanned) process unit downtime,
thus avoiding process interruptions. 

Definition of Best Available Monitoring Methods.  In determining methods
that would be allowed under a best available monitoring methods
approach, EPA considered the goal of collecting consistent data to
provide information of sufficient quality to inform policy and program
development, while recognizing that not all facilities may be able to
implement the full monitoring methods required by the rule by January
2010.  We reviewed the public comments as well as the California Air
Resources Board (CARB) mandatory reporting rule, and we considered
options falling between full flexibility to use any method and the full
requirements of the EPAEPA’s mandatory reporting rule.  

The least stringent approach would be to allow facilities to calculate
GHG emissions using any data, methods, calculation procedures, or
emission factors they choose during the best available monitoring period
and submit minimal supporting data.  This approach would provide maximum
flexibility to industry, but EPA did not select this approach because
the usefulness of the collected data would be questionable given that it
would be obtained using inconsistent methods and it could not be
verified with sufficient confidence.  Instead, EPA developed a hybrid
approach that falls between full flexibility and implementation of full
monitoring requirements in January 2010.  Under the final rule, during
January 1, 2010, through March 31, 2010, reporters may use best
available monitoring methods for any parameter (e.g., fuel use, daily
carbon content of feedstock by process line) if that parameter cannot
reasonably be measured following the monitoring and QA/QC requirements
of a relevant subpart.  The reporter must use the calculation procedures
and equations in the “Calculating GHG Emissions” sections of each
relevant subpart, but may use the best available monitoring method for
any parameter for which it is not reasonably feasible to acquire,
install, and operate a required piece of monitoring equipment by January
1, 2010.  Best available monitoring methods include the following: 

Monitoring methods currently used by the facility that do not meet the
specifications of a relevant subpart.

Supplier data.

Engineering calculations.

Other company data.

Reporters must submit an annual GHG report for 2010.  This calendar year
2010 report (submitted March 31, 2011) includes the same information as
in subsequent years, but also requires brief descriptions of each best
available monitoring method used, the parameter measured using that
method, and the time period during which the method was used. 

EPA selected this approach because it is responsive to commenters’
concerns that monitoring equipment cannot be installed by January 1,
2010, while also ensuring timely submission of more consistent and
verifiable data than the alternatives.  We have concluded that the data
w/ill be more consistent because all reporters will use the same basic
emissions calculation equations that are in the rule, with best
available inputs, rather than the wide range of calculation methods that
would likely be used under a full flexibility approach.  Furthermore,
the selected approach requires reporting of sufficient information for
EPA to verify the emissions data.  We have therefore determined that
this approach for collection and reporting of the calendar year 2010
data will fulfill the objectives of this reporting rule.

It should also be noted that, like the proposed rule, the final rule
allows facilities that must report only emissions from general
stationary fuel combustion equipment (and do not have other covered
source categories) to determine calendar year 2010 emissions using any
of the methods (tiers) in 40 CFR part 98, subpart C, and submit an
abbreviated GHG report.  Full reporting starts with calendar year 2011. 
This allows such facilities, which are less likely to have experience
with emissions monitoring and reporting, an extra year to begin full
reporting using all the procedures required by the rule. 

Extension Request Process.  We expect that the vast majority of
facilities will begin complying with the full monitoring requirements of
the rule no later than April 1, 2010, and will not require or be granted
an extension.  However, EPA is providing facilities with specific
circumstances an opportunity to request an extension in the use of best
available monitoring methods.  EPA will review extension requests to
determine whether they should be approved.  We envision that extensions
will apply primarily to situations when needed monitoring
instrumentation could not be obtained within the timeframe despite good
faith efforts by the facility, or when installation of monitoring
instrumentation would require a process unit shutdown that could not
feasibly be scheduled prior to April 1, 2010.  

Timing.  Reporters must submit extension requests to EPA no later than
30 days after the effective data of the GHG reporting rule.  EPA intends
to review each submitted request and may approve or disapprove the
requests.  EPA may approve the request for a specified time period, but
will not approve the use of best available methods beyond December 31,
2010.  If EPA disapproves an extension request, then the reporter is
required to implement the full monitoring methods required by the rule
by April 1, 2010. 

Content of Request.  Requests must contain the following information:

A list of specific item of monitoring instrumentation for which the
request is being made and the locations where each piece of monitoring
instrumentation will be installed.

Identification of the specific rule requirements (by rule subpart,
section, and paragraph numbers) for which the instrumentation is needed.
 

A detailed description of the reasons why the needed equipment could not
be obtained and installed before April 1, 2010.

If the reason for the extension is that the equipment cannot be
purchased and delivered by April 1, 2010, include supporting
documentation such as the date the monitoring equipment was ordered,
investigation of alternative suppliers and the dates by which
alternative vendors promised delivery, backorder notices or unexpected
delays, descriptions of actions taken to expedite delivery, and the
current expected date of delivery.

If the reason for the extension is that the equipment cannot be
installed without a process unit shutdown, include supporting
documentation demonstrating that it is not possible to isolate the
equipment, piping, or line and install the monitoring instrument without
a full process unit shutdown.  Also include the date of the most recent
process unit shutdown, the frequency of shutdowns for this process unit,
and the date of the next planned shutdown during which the monitoring
equipment can be installed.  If there has been a shutdown or if there is
a planned process unit shutdown between promulgation of this rule and
April 1, 2010, include a justification of why the equipment could not be
obtained and installed during that shutdown.

A description of the specific actions the facility will take to obtain
and install the equipment as soon as reasonably feasible and the
expected date by which the equipment will be installed and operating. 

Approval Criteria.  EPA will approve a request if it contains all of the
information required by the rule and if it demonstrates to the
Administrator’s satisfaction that it is not reasonably feasible to
acquire, install, and operate a required piece of monitoring equipment
by April 1, 2010.  

For example, EPA is likely to approve a request for an extension if the
documentation provided by the reporter shows that they ordered
monitoring equipment in a timely manner, attempted to find a supplier
who could deliver it in time, and could not control the fact that the
equipment was not received for installation prior to April 1, 2010.  

If a reporter requests an extension because equipment cannot be
installed without a process unit shutdown, EPA is likely to approve such
a request if the documentation clearly demonstrates why it is not
feasible to install the equipment without a process unit shutdown, shows
there is not a planned shutdown (and has not been a shutdown) prior to
April 1, 2010, during which the monitoring instrument could be
installed.  There are many locations where monitors can be installed
without a process unit shutdown, because there is often some redundancy
in process or combustion equipment or in the piping that conveys fuels,
raw materials and products.  For example, many facilities have multiple
combustion units and fuel feed lines such that when one combustion unit
is not operating they can obtain the needed steam, heat, or emissions
destruction by using other combustion devices.  Some facilities have
multiple process lines that can operate independently, so one line can
be temporarily shut down to install monitors while the facility
continues to make the same product in other process lines to maintain
production goals.  If a monitor needs to be installed in a section of
piping or ductwork, it can be possible in some cases to isolate a line
without shutting down the process unit (depending on the process
configuration, mode of operation, storage capacity, etc.).  If the line
or equipment location where a monitor needs to be installed can be
temporarily isolated and the monitor can be installed without a full
process unit shutdown, it is less likely EPA will approve an extension
request.  

While there might be other unique facility-specific situations for which
an extension might be granted, EPA expects few of these.  There have
been several changes to the rule since proposal that would reduce the
need for extensions.  For example, fewer source categories are included
in the final rule; changes have been made to the monitoring requirements
of some rule subparts to allow more flexibility in monitoring methods;
and provisions have been added to the general stationary fuel
combustion, petroleum refineries, and petrochemical productions subparts
allowing facilities additional time to perform some monitor
calibrations.  These changes address many of the specific situations
about which commenters raised concerns.

It is highly unlikely we would approve extension requests for parameters
that are measured by periodic sampling and analyses.  Facilities should
be able to make arrangements to collect periodic samples and send them
off-site for analyses (if they don’t have on-site analytical
capabilities) without the need for an extension.  Similarly, extensions
for design of electronic recordkeeping systems seem unnecessary.  Many
facilities already have electronic recordkeeping systems that can be
altered to keep the records needed for this rule.  Furthermore,
reporters can keep the specified records in any type of hard copy or
electronic format they choose, as long as it is in a form suitable for
expeditious inspection and review.  

H.  Summary of Comments and Responses on Frequency of Reporting and
Provisions to Cease Reporting

This section contains a brief summary of major comments and responses on
the frequency of reporting and on whether reporters should be allowed to
stop submitting annual reports if emissions are reduced below a
threshold level.  A large number of comments were received covering
numerous topics.  Responses to significant comments received can be
found in “Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to
Public Comments, Initial Year of Reporting, Duration of the comment
response documents (EPA-HQ-OAR-2008-0508-XXX).Reporting Program, and
Provisions to Cease Reporting” and “Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to Public Comments, Subpart A:
Applicability and Reporting Schedule.”

1.  Provisions to cease reporting if emissions decrease

Comment:  The majority of public commenters favored annual reporting as
opposed to more or less frequent reporting.  Many commenters, especially
industrial facilities required to report under the rule, objected to the
“once in always in” reporting approach in the proposed rule and
requested a mechanism to stop reporting if emissions fall below the
25,000 metric tons CO2e per year annual threshold. Others suggested a
level different from 25,000 metric tons CO2e per year to cease
reporting.   Some commented that the lack of such a mechanism is a
disincentive to reduce facility emissions.  Conversely, other commenters
supported the proposed once in always in approach in order to create a
consistent, long term data set covering the same population of
facilities over time that could be used to track trends and understand
factors that influence emission levels. 

Response:  After reviewing the comments, EPA has not changed the
frequency of reporting since the proposed rule.  Affected facilities and
suppliers must submit annual GHG reports.  Facilities with ARP units
that report CO2 emissions data to EPA on a quarterly basis would
continue to submit quarterly reports as required by 40 CFR part 75, in
addition to providing the annual GHG reports.  We have determined that
annual reporting is sufficient for policy and regulatory development. 
It is also consistent with other existing mandatory and voluntary GHG
reporting programs at the State and Federal levels (e.g., The Climate
Registry (TCR), several individual State mandatory GHG reporting rules,
EPA voluntary partnership programs, the DOE voluntary GHG registry).  

In response to comments on “once in, always in”,,” however, EPA
has added a provisionprovisions to allow facilities and suppliers to
stop submitting annual reports under certain conditions.  This applies
These provisions apply to facilities and suppliers regardless of their
applicability threshold as it is based on the annual report.  If

Under the first provision, if any facility’s annual GHG reports
demonstrate emissions of less than 25,000 metric tons of CO2e per year
for 5five consecutive years, they can cease submitting annual reports. 
Similarly, if any supplier’s annual reports demonstrate that the
products supplied equate to less than 25,000 metric tons of CO2e per
year for 5five consecutive years, they can cease submitting annual
reports.  Before

Under the second provision, if any facility’s or supplier’s annual
GHG reports demonstrate emissions of less than 15,000 metric tons CO2e
per year for three consecutive years, they can cease submitting annual
reports.

In either case, before they can stop reporting, the facility or supplier
must submit a notification to EPA that announces the cessation of
reporting and explains the reasons for the reduction in emissions so EPA
can understand the reason for the decrease in emissions to help aid in
evaluating emission reduction options across the industry.  

If emissions subsequently increase to 25,000 metric tons of CO2e or more
in any calendar year, the facility or supplier must again begin annual
reporting.  Importantly, although a source may not know its emissions
(or quantities supplied) exceeded the reporting threshold until later in
the year, the requirements of the rule apply as of January 1, unless the
increase is a result of a physical or operational change covered by 40
CFR 98.3(b).  Thus sources close to the threshold should consider
monitoring their emissions according to requirements of 40 CFR part 98
if they determine there is a chance they will meet or exceed the
threshold.  EPA is developing  tools and guidance to assist facilities
and suppliers in assessing whether the requirements of the rule apply to
them.

EPA concluded that adding the provisionprovisions to allow cessation of
reporting balances the need for a complete dataset with the burden of
continued annual reporting by facilities where there has been a change
that has consistently reduced emissions (or supplier quantities) below
25,000 metric tons CO2e.  This approach rewards actions taken to reduce
emissions and reduces the reporting burden.  It is consistent with other
reporting programs, such as the CARB mandatory reporting rule and the
WCI program, both of which have mechanisms to allow facilities to cease
reporting if their emissions are below a specified threshold for
multiple consecutive years.  

For the first provision, EPA selected 25,000 metric tons CO2e per year
because it is the same as the general applicability threshold for this
rule.  We selected a 5-year period, instead of a shorter time frame,
because it allows facilities or suppliers reporters that consistently
report less than 25,000 metric tons CO2e to stop reporting, but avoids
the situation where a facility or supplier near this level would be
constantly moving in and out of the reporting program due to small
variations from one year to the next.  Because this reporting rule is
based on actual rather than potential emissions, such a situation would
make tracking of facilities and analyses of trends difficult.  EPA
considered whether the threshold to cease reporting should be lower than
25,000 metric tons CO2e per year to provide a buffer or continue
collecting useful data on facilities that fall below 25,000 metric tons
but might still be covered by potential CAA programs and policies. 
However, we determined that for this reporting rule it is most
appropriate and straightforward that the threshold to cease reporting be
the same as the general applicability threshold for this rule. 
Furthermore, it is difficult to predict what future policies and
programs will be implemented, and needs for such programs can be
addressed at a future date.

The second provision (cease reporting if emissions were below 15,000
metric tons for three consecutive years) was added to reduce the
duration of reporting for facilities and suppliers that reduce emissions
to well below 25,000 metric tons.  In such cases, a 5-year period is
longer than necessary to demonstrate that annual emissions will remain
below 25,000 metric tons per year.  If emissions are less than 15,000
metric tons for three consecutive years, it is unlikely that annual
variation in emissions would cause the facility or supplier to exceed
the threshold of 25,000 metric tons per year.  The shorter time period
provides an incentive for facilities that significantly reduce their GHG
emissions. 

2.  Provisions to cease reporting due to closures

Comment:  Several commenters suggested that EPA add a provision to allow
closed facilities, or facilities or suppliers that stop operating their
GHG-emitting processes, to cease annual reporting.

Response:  In response to comments, EPA has added a mechanism to allow
facilities or suppliers that close all of their GHG-emitting processes
or operations covered by the rule to cease annual reporting.  The
reporter must submit an annual report covering the calendar year during
which the closure occurs.  The reporter must also notify EPA that they
intend to cease reporting and must certify that all GHG-emitting
processes and operations for which there are methods in the rule have
been closed.  EPA agrees that it does not make sense for closed
facilities or facilities that close all of their GHG-emitting processes
to continue reporting indefinitely or for the 5-year period needed to
demonstrate that emissions are less than 25,000 metric tons CO2e per
year (or the 3-year period needed to demonstrate emissions are less than
15,000 metric tons CO2e per year).  However, notification is required so
that we can track facilities and understand why facilities stop
reporting.  If a facility or supplier that was once subject to the
reporting rule and ceased reporting under this provision restarts any of
the GHG-emitting processes or operations formerly reported, then they
must resume annual reporting regardless of whether they exceed the
thresholds in 40 CFR 98.2(a) when they restart.  This provision is
important so that EPA can consistently track emissions from facilities
covered by the rule.  If after the restart, annual reports show
emissions of less than 25,000 metric tons CO2e per year for 5five
consecutive calendar years or less than 15,000 metric tons CO2e per year
for three consecutive years, then the facility could be exempt under the
separate mechanism discussed in Section II.H.1 of this preamble.

It is important to note that the provision to stop reporting is not
intended to apply to seasonal or longer temporary cessation of
operation.  The mechanism is intended for long-term closure situations. 
It should also be noted that in order to use this provision to cease
reporting, a facility or supplier must close all of their processes and
operations that are required to report emissions.  For example, consider
a facility that is required to report process emissions from one or more
source categories covered by 40 CFR part 98 and general stationary fuel
combustion source emissions.  If the facility closes some of the process
units subject to the rule but continues to operate other process units
covered by the rule or continues to operate stationary fuel combustion
sources, then they must continue to submit annual reports until the
required annual GHG reports demonstrate emissions of less than 25,000
metric tons of CO2e per year for 5five consecutive yearsyears (or less
than 15,000 metric tons of CO2e per year for three consecutive years)
and the facility qualifies for the separate provisions to stop reporting
discussed in Section II.H.1 of this preamble.  

I.  Summary of Comments and Responses on General Content of the Annual
GHG Report

This section contains a brief summary of major comments and responses on
the emissions information to be reported under the general provisions
(40 CFR part 98, subpart A).  See sections III.C through PP of this
preamble for summaries of comments and responses on specific reporting
requirements for the individual source categories contained in 40 CFR
part 98, subparts C through PP.  A large number of comments on emission
information to report under the general provisions were received
covering numerous topics.  Responses to significant comments received
can be found in “Mandatory Greenhouse Gas Reporting Rule: EPA’s
Response to Public Comments, Subpart A: Content of the comment response
documents (EPA-HQ-OAR-2008-0508-XXX).Annual Report, the Abbreviated
Emission Report, Recordkeeping, and Monitoring Plan.”

Comment:  EPA received a variety of comments on the general content of
the annual GHG reports.  Some commenters objected to the level of detail
required in the annual GHG reports.  Some suggested reporting only
facility-level emissions and keeping as records more detailed emissions
breakouts (e.g., by source category, process line, or unit) and activity
data used to calculate emissions.  Other commenters supported the
proposed general reporting requirements. 

 Response:  After reviewing the comments, we have not made any major
changes in the general content of the annual GHG reports since proposal.
 The final rule requires facilities to report emissions from all source
categories at the facility for which methods are defined in the rule. 
The General Provisions (40 CFR part 98, subpart A) require facilities to
report total annual GHG emissions in metric tons CO2e and to separately
present annual mass emissions of each individual GHG emitted from each
source category at the facility.  Reporting of CO2e allows a comparison
of total GHG emissions across facilities in varying categories which
emit different GHGs.  Knowledge of both individual gases emitted and
total CO2e emissions maintains transparency, is valuable for future
policy and regulatory development, and will help EPA quantify the
relative contribution of each gas to a source category’s emissions and
maintain transparency.  

Individual rule subparts for each source category, rather than the
General Provisions, identify the specific data elements to be reported
for that source category.  Comments received on the need for specific
data elements are described and responded to in Section III of this
preamble and in the comment response documents for the relevant
subparts.source category volumes of the “Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to Public Comments”.  Where
appropriate, the final rule has been modified based on those comments. 
In general, reporting of such data is are required primarily to enable
emissions verification and ensure the consistency and accuracy of data
collected under this rule.  The information is also needed to support
analyses of GHG emissions for future CAA policy and program development.
 Besides total facility emissions, it benefits policy makers to
understand: (1) the specific sources of emissions and the amounts
emitted by each unit/process to effectively interpret the data, and (2)
the effect of different processes, fuels, and feedstocks on emissions. 
Many of these data are already routinely monitored and recorded by
facilities for business reasons.  Further discussion of the selection of
general reporting requirements is contained in Section IV.G of the
proposal preamble (74 FR 16472, April 10, 2009).  Other responses to
comments on the reporting requirements in 40 CFR Part 98, Subpart A, and
discussion of some clarifications made to the rule, are contained in the
comment response document for“Mandatory Greenhouse Gas Reporting Rule:
EPA’s Response to Public Comments, Subpart A, General Provisions:
Applicability and Reporting Schedule”, “Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to Public Comments, Subpart A: Content
of the Annual Report, the Abbreviated Emission Report, Recordkeeping,
and Monitoring Plan”, and “Mandatory Greenhouse Gas Reporting Rule:
EPA’s Response to Public Comments, Subpart A: Definitions,
Incorporation by Reference, and Other Subpart A Comments”.   

J.  Summary of Comments and Responses on Submittal Date and  Making
Corrections to Annual Reports

1.  Submittal Date for Annual Report

Comment: Several commenters requested that EPA change the annual
submittal date for GHG reports from March 31 to a later date, such as
April 30 or June 30.  Several commenters stated that March 31 does not
provide adequate time for data collection, aggregation and
disaggregation, GHG calculations, QA, management review, and
certification, and explained that this is a complex process for large
industrial sites that have many individual GHG emission sources.  Some
of these commenters indicated that unexpected issues can arise during
GHG emissions calculations and QA that take time to resolve.  Some of
these commenters suggested a date of June 30 to align this mandatory
reporting rule with the submittal dates for other reporting programs
such as California Climate Action Registry (CCAR), TCR, Climate Leaders,
and Toxic Release Inventory (TRI).  Some commented that the same
personnel who will prepare the GHG reports are also involved in
preparing other EPA mandated reports and that completing multiple
reporting activities in the first quarter is a large workload.  Other
commenters favored the March 31 reporting data so that the data could be
disseminated and available for use by policy makers, EPA, States, and
the public in a timely fashion.

Response: After reviewing and addressing both general comments and
comments received on this issue for specific source categories, and
considering the need to balance prompt reporting with the burden on
reporters, EPA has determined that the reporting deadline of March 31
allows a sufficient amount of time for compiling, reviewing, certifying,
and submitting annual GHG reports.  The March deadline will ensure
timely collection of the data necessary to inform decisions regarding
future GHG policy and program development.  Since the data needed to
calculate emissions and prepare the report must be collected on an
ongoing basis throughput the year, reporters can begin to compile the
data for the report and initiate QA activities during the year as the
data are collected.  Reporters would then only have to compile the most
recently collected information, complete the final calculations, and
review and certify the annual report after the reporting period has
ended.  Because the reports required by the rule rely on well-defined
calculation methodologies, EPA determined that three months is a
sufficient amount of time to complete the report.  Moreover, as
discussed in Section III of this preamble for the specific subparts, we
have made several changes to reporting requirements that will ease
burden and further facilitate reporting by March 31. In addition, EPA
intends to provide outreach and training on rule requirements and an
electronic reporting system that will help expedite report submission.  

The March 31 reporting deadline is also consistent with the reporting
deadline implemented in 2005 for reporting GHG emissions under the EU
Emissions Trading System and is longer than the deadlines allowed for
reporting under many other CAA programs.  For example, many NESHAPs and
NSPSs, including those for large complex industrial facilities such as
chemical plants and refineries, require reports of excess emissions and
monitoring system performance to be submitted within 30 calendar days of
the end of each compliance period.  The ARP and Regional Greenhouse Gas
Initiative (RGGI) programs, which are established emission cap and trade
programs that rely on the same types of data many sources will have to
submit under the GHG reporting rule, require facilities to submit their
quarterly emissions reports within 30-days of the end of each quarter.  

2.  Making Corrections to Annual Reports

Comment: Several commenters representing multiple stakeholders suggested
the rule should include provisions to submit revised annual reports. 
Many commented that even with good-faith efforts to follow all the
monitoring and reporting requirements, there will likely be
unintentional errors that are not discovered by the reporter or by EPA
until after an annual report is submitted.  Some commenters added that
given the stringency of the self-certification provisions and potential
penalties involved, reporters need a way to submit corrected data, and
some provided examples of other reporting rules that include provisions
to submit revised reports.      

Response: EPA has addressed this comment in the final rule.  We have
added a provision in 40 CFR 98.3 that requires the reporters to submit a
revised GHG 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.  We agree that it is important for facilities to
correct errors, regardless of whether they are discovered by the
reporter or by EPA.  In order to ensure accurate data for future GHG
policies and programs, known errors should be corrected.  Furthermore,
adding a requirement to submit corrected reports is consistent with
other EPA reporting programs, such as ARP and TRI, as well as State and
other GHG programs.  EPA intends to review the annual GHG reports
submitted under this rule by performing electronic data QA checks and a
range of other emission verification activities.  When we find reporting
errors (as we have in ARP and other reporting programs), we will notify
reporters of errors and require them to submit revised reports.  The
time period of 45 days was selected to allow reporters time to retrieve
any needed data, perform revised calculations, and resubmit the report. 
Because data for the calendar year covered by the report has already
been collected and must be retained according to the rule, it should be
readily available for any reanalyses needed to correct a reporting
error.  Given that facilities are allowed 3three months from the end of
a reporting period to submit the annual report, revising a report to
address a known error would logically require less time and EPA
concluded that 45 days is sufficient.  

K.  Summary of Comments and Responses on De minimis Reporting

Comment:  Some commenters suggested that de minimis cutoffs or
simplified methods for de minimis sources should be provided to be
consistent with other programs, such as the California mandatory GHG
reporting rule.  The commenters argued that it makes sense to focus
effort on the significant emissions sources at a facility, rather than
spending a lot of effort to precisely calculate emissions from sources
that are a small percent of a facility’s total emissions.

Response:  EPA considered public comments on de minimis reporting, both
general comments and those received on individual source categories, in
addition to the analyses of de minimis provisions we conducted at
proposal of the rule.  Based on these considerations, we concluded that
de minimis provisions are not necessary for this rule.  

As discussed in the preamble to the proposal (74 FR 16448, April 10,
2009), many existing reporting programs require corporate level
reporting of all emissions, including emissions from numerous remote
facilities and small onsite equipment (e.g., lawn mowers).  Other
reporting programs require reporting at the facility level but require
reporting of emissions from all types of emission sources.  These
reporting programs recognize that it may not be possible or efficient to
specify the reporting methods for every source that must be reported and
include de minimis provisions to reduce the reporting burden.  The de
minimis provisions included in these programs either allow the reporter
to exclude a portion of their emissions (e.g., the DOE 1605(b) voluntary
reporting program allows up to 3three percent of facility-level
emissions to be excluded) or allow simplified calculation methods for
small sources.  

Since reporters must determine the de minimis emissions even when
reporting is not required, the trend for both mandatory and voluntary
reporting programs is to require reporting of all emissions but allow
simplified calculation methods for small sources of emissions.  Hence,
the de minimis provisions included in many existing reporting programs
are designed to avoid potentially unreasonable reporting burdens where
the reporting rule does not provide simplified calculation methods for
smaller emissions sources. . For example, TCR allows reporters to use
simplified calculation methods of their own design for calculating up to
5five percent of their emissions.  Some programs recognize that a small
percentage of emissions may still represent a large mass of emissions. 
For this reason, some existing reporting programs include a cap on the
mass of de minimis emissions.  For example, both the California
mandatory reporting rule and EU Emissions Trading System cap de minimis
emissions at 20,000 metric tons CO2e/year cap.  For additional
information on the treatment of de minimis in existing GHG reporting
programs, please refer to the “Reporting Methods for Small Emission
Points (De Minimis Reporting)” (EPA–HQ–OAR–2008–0508–0048).

In contrast to such existing programs, this rule already avoids
burdensome reporting requirements for smaller emissions sources in two
ways.  First, the rule excludes small facilities through the application
of the 25,000 metric tons of CO2e threshold.  As described earlier in
this preamble, that threshold appropriately balances the number and size
of reporter with the coverage of emissions.  The source categories
included in the rule are typically for larger sources of emissions. 
Second, reporters must report only the emissions from sources for which
calculation methods are provided in the rule.  Calculation methods are
generally not included for smaller sources of emissions (e.g., coal
piles on industrial sites, mobile sources, lawn equipment).  In some
cases, where a source category includes relatively small sources, the
rule provides simplified emissions calculation methods for those
sources.  For example, reporters may use a default emission factor and
heat rate to calculate emissions from small stationary combustion units,
rather than the fuel measurements required for larger stationary
combustion units.  Given that this rule has taken steps to avoid
burdensome calculations, we have concluded that de minimis reporting
cutoffs are not necessary.  

Furthermore, de minimis cutoffs would compromise the quality of the data
collected.  The goal of this rule is to collect accurate and consistent
data of sufficient quality to inform future CAA policy and regulatory
decisions.  Allowing sources to report up to 20,000 metric tons CO2e
emissions annually using their own simplified calculation methods (as
allowed under some programs) would impact the usefulness of the data. 
The reported emissions would not be comparable across a given industry
because the calculation methods, accuracy and reliability of a portion
of the reported emissions would vary substantially from one reporter to
another.

In response to comments, we have made several changes to this rule that
further reduce any need for a de minimis reporting provision.  As
discussed in Section III of this preamble for individual source
categories, we have revised monitoring and reporting requirements to
allow simpler GHG calculation methods for many combustion units and
other source categories.  These changes reduce the reporting burden for
various types of small emission sources.  Also, as noted earlier in
Section II.D of this preamble, there are a number of source categories
that are not being finalized at this time.  A few of them (e.g.,
industrial landfills and wastewater) represent the type of emission
sources that commenters referenced as de minimis at some facilities. 
EPA is taking some additional time with these sources categories, which
affects commenters in two ways:  1) until EPA promulgates a final rule
for these source categories, these  emissions would not be included in a
facility’s annual report and 2) EPA can further consider the comments
and evaluate our options with respect to the methods for these source
categories to ensure the methods adequately address our need for high
quality data as well as recognize the commenters’ requests for
additional flexibility for smaller sources.

L.  Summary of Comments and Responses on General Monitoring Approach

This section contains a brief summary of major comments and responses on
general monitoring requirements.  See sections III.C through PP of this
preamble for summaries of comments and responses on specific monitoring
requirements for the individual source categories contained in 40 CFR
part 98, subparts C through PP.  A large number of comments were
received on general monitoring requirements covering numerous topics. 
Responses to significant comments received can be found in “Mandatory
Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments,
General Montoring Approach, the comment response documents
(EPA-HQ-OAR-2008-0508-XXX).Need for Detailed Reporting, and Other
General Rationale Comments.”

Comment:  Many commenters favored the general monitoring approach
contained in the proposed rule, which is a combination of direct
emissions measurement and facility-specific calculations.  These
commenters agreed that the selected approach results in high quality
data and strikes a reasonable balance between data accuracy and cost. 
Other commenters believed that the approach contained in the proposed
rule is overly stringent and costly.  They contended that since the data
are not being used to demonstrate compliance with a cap and trade
program or other regulation with emission limits or emissions reduction
requirements, a lower level of accuracy is acceptable, simpler
monitoring approaches should be allowed, and/or facilities should have
flexibility to choose monitoring methods.  Some commenters requested
clarification on whether there were accuracy requirements or performance
standards for flow monitoring equipment, outside of the accuracy
requirements already required for CEMS.  Some commenters requested
clarification on whether upgrades to CEMS were needed under various
circumstances.  Some requested additional time for upgrading CEMS or
installing and calibrating other equipment such as flow meters. 

Response: After reviewing the comments in light of the analysis
presented in Section IV.H of the preamble to the proposed rule (74 FR
16474, April 10, 2009), EPA decided not to change the general monitoring
approach from the proposal.  In general, the rule requires direct
measurement of emissions from certain units that already are required to
collect and report data using CEMS under other programs (e.g., ARP,
NSPS, NESHAP, State Implementation Plans (SIPs)).  In some cases, this
may require upgrading existing CEMS that currently monitor criteria
pollutants to also monitor CO2 or add a volumetric flow meter.  For
facilities with units that do not have CEMS installed, reporters have
the choice to either install and operate CEMS to directly measure
emissions or to use facility-specific GHG calculation methods.  The
measurement and calculation methods for each source category are
specified in each subpart.  As policies and programs evolve and/or
particular calculation or monitoring equipment improves EPA will
evaluate whether or not to update the methodologies in this rule.

The data collected by the rule are expected to be used in analyzing and
developing a range of potential CAA GHG policies and programs.  A
consistent and accurate data set is crucial to serve this intended
purpose.  Therefore, the selected monitoring approach that combines
direct measurement and facility-specific calculations is warranted even
though the rule does not contain any emissions limits or emissions
reduction requirements.  EPA remains convinced that this approach
strikes an appropriate balance between data accuracy and cost.  It makes
use of existing data and methodologies to the extent feasible, and
avoids the cost of installing and operating CEMS at numerous facilities.
 It is consistent with the types of methods contained in other GHG
reporting programs (e.g., the California mandatory reporting rule, WCI,
RGGI, TCR, and Climate Leaders).  Because this option specifies methods
for each source category, it will result in data that are comparable
across facilities.  

EPA chose not to adopt simplified calculation methods as a general
monitoring approach (e.g., using default emission factors) because the
data would be less accurate than under the selected option and would not
make use of site-specific data that many facilities already have
available and refined calculation approaches that many facilities are
already using.  EPA is not allowing reporters full flexibility to use
any method because the accuracy and reliability of the data would be
unknown.  Because consistent methods would not be used under such an
approach, the reported data would not be comparable across similar
facilities.  

While the general approach is unchanged, it is important to note that
EPA has made changes to the General Provisions and to the specific
monitoring requirements for particular source categories in response to
public comments on the proposal.  EPA has added to the General
Provisions (40 CFR part 98, subpart A) an accuracy specification of plus
or minus 5five percent for the calibration of flow meters used to
collect data for the emissions calculations under this rule.  It
provides procedures for calculating calibration error, including
specific procedures for orifice, nozzle, and venturi flow meters.  Given
the comments that were submitted regarding concerns on the timing of
performing meter calibration, EPA is providing flexibility to reporters
subject to certain operational limitations.  For example, facilities
that operate continuously may postpone calibration until the next
scheduled maintenance outage to avoid operational disruptions. 

Individual rule subparts for each source category, rather than the
General Provisions, contain the specific monitoring methods for that
source category.  Comments received on the specific methods are
described and responded to in Section III of this preamble and in the
comment response documents for the relevant subparts.source category
volumes of “Mandatory Greenhouse Gas Reporting Rule: EPA’s Response
to Public Comments.”  Where appropriate, the final rule has been
modified based on those comments.  For example, since proposal, in
response to public comments, EPA has made changes to individual subparts
of 40 CFR part 98 to clarify when CEMS and CEMS upgrades are required
and has made other changes to reduce the monitoring burden.  Interested
parties are encouraged to review the relevant sections of the preamble
and rule.  Furthermore, some subparts for which significant monitoring
approach comments were received are not included in the final rule and
will be consideredfinalized later as explained in Section II.D of this
preamble.  These changes to the rule address monitoring approach
concerns raised by some commenters. 

Comment: Some commenters expressed concern that duplicative reporting
would occur if the rule was interpreted to require a reporter to submit
data on general stationary fuel combustion emissions at a facility both
under 40 CFR part 98, subpart C and also under one of the other source
category subparts that applies to the same facility.  Some of them
indicated that language used in the source category subparts to
reference subpart C was not sufficiently clear and consistent.  Other
commenters indicated the proposed rule was not clear about whether CEMS
can be used to report combustion emissions, process CO2 emissions, or
combined emissions.  

Response: EPA reviewed each subpart in light of these comments and
acknowledges that the proposed rule language referencing 40 CFR part 98
subpart C and the language discussing the of CEMS was inconsistent
between subparts and was not always clear.  EPA has revised the final
rule to clarify our intent.  

As indicated by the commenters, many manufacturing facilities are
subject to one of the source category subparts and also to the general
stationary fuel combustion subpart.  For most facilities, emissions from
stationary fuel combustion sources (e.g., boilers or engines) are
emitted from separate equipment and through separate stacks/emission
points than process GHG emissions covered by 40 CFR part 98, subparts E
through GG.  We have edited the rule to make it clear that in such
cases, the reporter would report stationary fuel combustion emissions
under 40 CFR part 98, subpart C, and they would report process GHG
emissions under each applicable source category subpart.  

We have further clarified those source category subparts that require
reporting of process CO2 emissions.  We have made it clear that the
reporter can elect to monitor and report process CO2 emissions by
either: (1) installing and operating CEMS and following the Tier 4
methodology in 40 CFR part 98, subpart C, or (2) using the source
category-specific monitoring and calculation procedure specified in the
subpart.  In either case, process CO2 emissions would be reported under
the source category subpart.  The source category subparts have also
been revised to specify that if process CO2 emissions are comingled with
and emitted through the same stack as emissions from combustion units or
process equipment required to use CEMS, than the reporter must use the
CEMS and follow the Tier 4 methodology to report combined emissions from
the common stack under the specified subpart.  This approach makes sense
for comingled emissions because CEMS accurately measure total stack CO2
emissions and the reporter would not be able to accurately separate the
fraction of the CO2 emissions that came from the combustion units and
process emission points that are comingled in the same stack.

Source categories with direct-fired equipment (e.g., kilns, furnaces)
present a special situation.  Examples include cement production, glass
production, lead production, lime manufacturing, and soda ash
manufacturing.  In direct-fired units, fuel combustion emissions and
process emissions are both generated within the kiln or furnace and are
always emitted together.  If CEMS are used on such units, the CEMS will
always be measuring combined combustion and process emissions.  The
language regarding CO2 reporting and use of CEMS for these source
categories has been clarified and harmonized to reflect this situation. 


For kilns or furnaces in these source categories that have CEMS in place
and meet specified conditions, the reporter must use the CEMS and follow
Tier 4 methodology to determine combined process and combustion CO2
emissions.  The combined emissions are reported under the relevant
source category subpart (e.g., for cement production, combined
combustion and process emissions from a kiln with a CEMS would be
reported under 40 CFR part 98, subpart H, Cement Production). 

For other kilns or furnaces in these source categories, the reporter has
the choice to (1) install and operate CEMS to measure combined process
and combustion CO2 emissions, or (2) calculate process CO2 emissions
using the source category-specific monitoring and calculation procedures
contained in the subpart.  If reporters don’t have CEMS and choose the
source category-specific calculation approach, then they report process
CO2 emissions under the relevant source category subpart, and report
combustion emissions under 40 CFR part 98, subpart C (general stationary
fuel combustion).

See the sections for the relevant source categories in Section III of
this preamble for summary and discussion of the specific monitoring and
reporting requirements for each source category.

M.  Summary of Comments and Responses on General Recordkeeping
Requirements

This section contains a brief summary of major comments and responses on
the general recordkeeping requirements contained in the general
provisions (40 CRRCFR part 98, subpart A).  See sections III.C through
PP of this preamble for summaries of comments and responses on specific
recordkeeping requirements for the individual source categories
contained in 40 CFR part 98, subparts C through PP.  A large number of
comments were received on general recordkeeping requirements covering
numerous topics.  Responses to significant comments received can be
found in “Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to
Public Comments, Subpart A, Content of the comment response documents
(EPA-HQ-OAR-2008-508-XXX).Annual Report, the Abbreviated Emission
Report, Recordkeeping, and the Monitoring Plan” and in the individual
source category volumes of “Mandatory Greenhouse Gas Reporting Rule:
EPA’s Response to Public Comments.”

1.  Record Retention

Comment:  Several commenters suggested that EPA require retention of
records for 3three years rather than the 5five years specified in the
proposed rule.  Some of these commenters stated that 3three years is
consistent with ARP, which is a comparable program that requires
electronic reporting of similar, detailed data.  Many contended that
retaining the large amount of data required by this rule for 5five years
rather than 3three years is overly burdensome and is not necessary. 
They indicated that 3three years of records is sufficient to allow
verification of annual GHG reports.  A smaller number of commenters
supported record retention for 5five years, which is consistent with
permitting and other programs.  

Response:  In response to public comments, EPA has changed the record
retention requirement in the final rule from 5five years to 3three
years.  We agree that a 3-year time period is sufficient to allow for
EPA audit and review of records needed to verify the emissions data
submitted in annual reports.  Changing the record retention duration
to 3three years will reduce the recordkeeping burden for many facilities
reporting under this rule.  As stated by various commenters, a 3-year
record retention requirement would be consistent with the
recordkeeping provisions of the ARP and other Federal reporting
programs, including the TRI rules and the DOE Energy Information
Administration'sAdministration’s 1605(b) Voluntary Reporting of GHG
Emission and Reductions program. 

2.  Monitoring Plan

Comment:  We received several comments on the QAPP recordkeeping
requirement in proposed 40 CFR 98.3(g).  Some had questions about the
content and level of detail required in the QAPP, and indicated it would
be a costly and burdensome requirement.  Others stated that the QAPP
would be duplicative of their facility SOPs or documentation kept under
ARP or other programs.  Some commenters indicated that the list of items
to report in 40 CFR 98.3(g) was repetitive because a few of the items
listed separately would typically be contained in a QAPP.

Response: The final rule requires a “monitoring plan.”  The
“QAPP” terminology in the proposed rule caused confusion because
“QAPP” is used in a variety of other contexts, has various
connotations to different readers, and caused readers to presume
requirements EPA did not intend.  The final rule specifies monitoring
plan contents such as: 

Identification of persons responsible for collecting emissions data.

Explanation of the processes and methods used to collect the necessary
data for the GHG emissions calculation.

Description of the procedures that are used for QA, maintenance, and
repair of all CEMS, flow meters, and other instrumentation used to
provide data for the GHG emissions reported under 40 CFR part 98.

The first two items in this list were formerly listed as separate line
items in the recordkeeping requirements, but would logically be a part
of the monitoring plan, so were consolidated under the monitoring plan
to avoid repetition. 

The monitoring plan paragraph in the final rule explicitly states that
the monitoring plan can rely on references to existing corporate
documents.  Such documents include SOPs, QA programs under Appendix F to
40 CFR part 60 or Appendix B to 40 CFR part 75, and other documents
provided that the information required by the monitoring plan is clearly
recognizable.  The provision allowing the monitoring plan to refer to
such documents avoids duplicative effort and addresses the
commmenters’ concerns that monitoring plan information is already
contained in other documents. 

The final rule also contains a provision to update the monitoring plan. 
Reporters would need their monitoring plan to be up to date in order to
ensure that facility or supplier personnel follow the right monitoring
and QA procedures and that the reporter meets the requirements of the
reporting rule.  Likewise, EPA needs to be able to view an up-to-date
monitoring plan during facility audits.  Updates to the plan would be
needed if, for example, the facility makes a process change, changes
monitoring instrumentation or QA procedures, or improves procedures for
maintenance and repair of monitoring systems to reduce the frequency of
monitoring equipment downtime. 

N.  Summary of Comments and Responses on Emissions Verification Approach

This section contains a brief summary of major comments and responses on
emissions verification of the GHG reports.  A large number of comments
were received covering numerous topics.  Responses to significant
comments received can be found in the comment response documents
(EPA-HQ-OAR-2008-0508-XXX).“Mandatory Greenhouse Gas Reporting Rule:
EPA’s Response to Public Comments, Approach to Verfication and Missing
Data.”

Comment: The majority of Many commenters, including most facilities and
suppliers required to report under the rule and several other
stakeholders, supported EPA’s proposal to require self-certification
with EPA verification of GHG reports.  These commenters provided a
variety of reasons.  Many supported EPA emissions verification because
the alternative of third party verification would be more costly to
reporters.  Several also commented that EPA emissions verification would
provide a consistent and transparent data set.  

Some otherOther commenters suggested that EPA require third party
verification of GHG reports, and they provided a variety of reasons.  A
few noted that third party verification is consistent with other GHG
reporting systems (e.g., the European Emissions Trading Scheme, The
Climate Registry, the California mandatory GHG reporting rule, and other
stateState programs).  Many stated that third party emissions
verification will improve the quality of the data submittals and told us
that third party verification led to the correction of inaccuracies in
GHG emission reports submitted under other programs.  Some of the
commenters questioned whether EPA would have the time to conduct
verification, given the number of reports and volume of supporting data
that must be submitted.  Others were concerned that EPA verification
requires submittal of detailed supporting data and contended that some
of these supporting data would be CBI. 

A smaller number of commenters favored self-certification without
independent emissions verification.  They believed the designated
representative provisions in the rule would cause reporters to take
self-certification seriously and ensure the emissions they report are
correct.  Some also stated that independent verification is not needed
for a reporting program that does not require emissions reductions.  

Response:  In selecting the approach to emissions verification, EPA
reviewed all of the comments, as well as emissions verification
requirements and procedures under a number of existing EPA regulatory
programs and domestic and international GHG reporting programs.  Based
on this review, EPA considered three alternatives: (1)
self-certification without independent verification, (2)
self-certification with third party verification, and (3)
self-certification with EPA verification.  For this particular program,
EPA is not changing the verification approach from the proposal and is
requiring self-certification with EPA emissions verification.  We
decided to retain this verification approach because it provides greater
assurance of accuracy and impartiality than self-certification without
verification, and has a number of advantages over third party
verification for this type of Federal program.  Our objective with
emissions verification in this program is to ensure collection and
dissemination of high-quality data while providing the reporters a
“level playing field” in terms of requirements and process.  

To enable effective review of the large volume of data reported, the
rule requires reporters to submit data electronically in a standard
format through a centralized data system.  EPA is developing this system
and intends to make it available to reporters, along with training and
instructional materials, before the reporting deadlines.  To the extent
possible, EPA will leverage existing reporting systems and work with
other State and regional programs and systems to develop a reporting
scheme that minimizes the burden on reporters.    

In implementing the emissions verification under this rule, EPA
envisions a two step process.  First, we will conduct an initial
centralized review of the data which will be largely automated.  EPA
intends to build into the data system an electronic data QA program for
use by reporters and EPA to help assure the completeness and accuracy of
data.  In addition, to verify reported data and ensure consistency, EPA
may review facility-level monitoring plans and procedures, and will
perform detailed, automated checks on data utilizing recent and
historical data submittals, comparison against like facilities and/or
other electronic audit tools where appropriate.  Second, EPA intends to
follow-up with facilities should potential errors, discrepancies, or
questions arise through the review of reported data and conduct on-site
audits of selected facilities.  The on-site audits may be conducted by
private verifiers contracted by EPA or by Federal, State or local
personnel, as appropriate.  We plan to coordinate closely with the
States to develop an efficient approach toward on-site auditing that can
meet the needs of multiple programs.  We do not anticipate conducting
on-site audits of every facility every year.  

EPA decided to finalize the rule with EPA emissions verification for
several reasons.  First, we determined that the combination of
comprehensive electronic review and a flexible and adaptive program of
on-site auditing will enable us to effectively target verification
resources while also providing the necessary consistency and quality in
the data.  Utilizing the national data set developed under this rule
will provide unique resources for the review of reports.  A centralized
emissions verification system provides greater ability for EPA to
identify trends and outliers in data and thus assist with targeted
follow-up review, and our approach can evolve over time as we gain
experience with GHG reporting.  This approach also provides opportunity
to work closely with and leverage both the experience and ongoing
activities of States and others already engaged in similar and different
types of GHG reporting.

Our emissions verification approach in this rule is consistent with
other EPA emission reporting programs and follows a model similar to the
ARP which is a highly successful emissions cap and trade program that
consistently produces credible, high-quality data.  Facilities regulated
under ARP must have a Designated Representative sign data reports to
self-certify that the reported data are accurate.  Then, facilities and
EPA use a series of electronic tools to ensure proper data collection
and reporting, including establishing a monitoring plan, calibrating
equipment to certain specifications, frequent testing and data
submittal.  Similar to what we are intending with this program, EPA
conducts site audits on those facilities targeted during the electronic
review as having been outliers or had anomalies in their reported data. 
These audits are done by EPA personnel, States and/or contractors to
EPA.  We support these audits by providing a field audit manual to both
government and private auditors as well as additional training to State
and Federal auditors.

Second, this approach is the best way to address the many comments we
received on the importance of obtaining 2010 data and making the data
widely available.  EPA has determined that this verification approach
will enable us to make data available more quickly than under a third
party verification approach.  We will be able to share a complete data
set promptly upon completion of the electronic review (subject to
relevant CBI concerns, please see the discussion of our plans to address
CBI and emissions data in Section II.S of this preamble and the
associated“Mandatory Greenhouse Gas Reporting Rule: EPA’s Response
to Public Comments document [docket #]))., Legal Issues”).  We
determined that the third party verification approach could take from
3three to 6six months after initial data submission, and EPA would still
need to review and perform consistency checks after the third party
verification was complete.

In addition, developing the third party verification apporachapproach
would require EPA to establish and develop emissions verification
protocols and a system to qualify and accredit the third party
verifiers, and to develop and administer a process to ensure that
verifiers hired by reporting facilities do not have conflicts of
interest.  Such a program could require EPA to review numerous
individual conflict of interest screening determinations made each time
a reporter hires a third party verifier.  Even if EPA were to partner
with an existing program or organization to accredit verifiers, EPA
would still need to develop the criteria and systems described above to
implement this rule and ensure high quality emissions verification given
the unique reporting requirements of this rule.  These efforts would
slow down implementation of the rule and sharing of data. 

Finally, we agree with many of the commenters regarding their concerns
about the cost of third party verification.  Given the information
currently available to us, under a third party verification approach we
would have required that each facility verify its submission each year. 
As a national reporting program with a substantially larger number of
reporters than existing State programs, we determined that the costs to
the reporters of third party verification would have been substantial. 
By finalizing self-certification with EPA emissions verification for
this rule, it also ensures a lower cost burden for reporters. 

EPA’s decision to use self certification with EPA emissions
verification was made in the context of the specific scope of this
rulemaking, the types of data to be collected, and the intended uses of
the emissions data.  For other types of programs (e.g., offsets,
corporate footprinting, energy efficiency) other verification approaches
may be more suitable.  We recognize that many GHG reporting and
reduction programs developed by the States and Regions are broader in
scope and for this and other reasons, the use of third party verifiers
is an appropriate way to verify the data they collect.  EPA’s decision
in this rulemaking does not pre-empt State GHG reporting programs or any
other programs from requiring third party verification.  More
importantly, the selection of EPA emissions verification for this rule
is not intended to suggest that third party verification cannot result
in accurate, high quality data.   

EPA received a smaller number of comments in support of
self-certification without emissions verification.  While recognizing
that this approach would place a low burden on both reporters and the
government, it also has major disadvantages.  Without any verification
of submitted reports, there is far greater potential for inconsistent
and inaccurate data and this will result in less confidence at EPA and
with public stakeholders in the data.  These disadvantages would make
the data collected under this option less useful for informing decisions
on climate policy and supporting the development of potential future
policies and regulations.

Comment:  Commenters asked what role State and local regulatory agencies
will have in verification of reported emissions data.  Some suggested
that State and local agencies should assist with emissions verification
because they already have detailed knowledge of the facilities in their
areas.  Some indicated that States would need resources to play a role
in verification and other rule implementation activities. 

Response:  While EPA is responsible for emissions verification as
explained in the previous response, EPA will likely enlist State
assistance, when it is available, during the implementation phase of the
final rule.  (However, State and local agencies will not be required to
provide EPA any assistance with verification or implementation
activities, given State and local agency resource constraints and
priorities.)  For example, in concert with their routine inspection and
other compliance and enforcement activities for other CAA programs,
State and local agencies could, as resources allow, assist with
educating facilities and assuring compliance at facilities subject to
this rule.  

Assistance from State and local agencies could include such activities
as identifying the facilities for on-site audits or conducting audits
where appropriate.  This type of assistance from State and local
governments has been valuable in other programs.  State and local air
pollution control agencies routinely interact as part of other
regulatory programs with many of the sources that would report under
this rule.  States have knowledge of specific facilities and sources
that would be required to report under this rule.  In addition, many
States have already implemented or are in the process of implementing
GHG reporting and reduction programs.  Therefore, some State and local
agencies willcould serve an important role in communicating the
requirements of the rule and providing compliance assistance.  

O.  Summary of Comments and Responses on the Role of States and
Relationship of this Rule to Other Programs

This section contains a brief summary of major comments and responses. 
A large number of comments on the relationship between this rule and
other programs were received covering numerous topics.  Responses to
significant comments received can be found in the comment response
documents (EPA-HQ-OAR-2008-0508-XXX).“Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to Public Comments, Relationship to
Other GHG Reporting Programs” and “Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to Public Comments, Legal Issues.”

Comment:  Several commenters requested that EPA make it clear that
States can collect additional GHG data under State rules and GHG
programs and are not limited to collecting only the data in this Federal
mandatory reporting rule.  Other commenters requested that this rule
pre-empt or supersede State GHG reporting rules.

Response:  EPA reaffirms that States can collect additional data under
State rules and GHG programs, and that this rule does not pre-empt or
replace State reporting programs.  This rule has been developed in
response to a specific request from Congress (in the Appropriations Act)
and is narrower and more targeted than many existing State programs that
are coupled with GHG emission reduction programs.  As EPA stated in
Section II of the proposal preamble (74 FR 16457, April 10, 2009) and
Section I.E of this preamble, many State programs are broader in scope,
in a more advanced state of development, and have different policy
objectives than this rulemaking.  These are important programs that not
only led the way in reporting of GHG emissions before the Federal
government acted but also have catalyzed important GHG reductions.

EPA supports and recognizes the success and necessity of State programs
as a vital component in achieving GHG emissions reductions, particularly
those focused on energy efficiency improvements.  It is appropriate that
State and Regionalregional GHG reporting and reduction programs have 
different scopes or implementation schedules, and that they require
reporting of different information than this rule for various
program-specific reasons.  For example, some State programs might
require reporting of electricity purchases and other data to provide
information for energy efficiency programs; they may require or allow
reporting of a variety of indirect emissions to gather data to help
facilities reduce their carbon footprint; they may require or allow
reporting of emissions such as from fleet vehicles to encourage fleet
operators to take steps to reduce emissions; or they may be  developing
or implementing GHG reduction rules including cap and trade programs,
and require specific information on emissions and offsets to implement
those programs.  State programs already have, or may evolve to include,
additional monitoring and reporting requirements than those included in
this rule.  Many States are actively collecting additional data they
need for their programs and policies, and this reporting rule does not
pre-empt State programs.

Comment:  Some commenters were concerned that the Federal GHG reporting
rule will result in duplicative reporting for facilities that are also
reporting GHG emissions under State rules or voluntary GHG reporting
programs.  Some requested that to reduce burden, facilities should be
required to submit data only once, and not have to submit different data
to multiple different programs.  Some commenters strongly recommended
that the electronic data systems used by this reporting rule and other
programs need to be consistent and allow data exchange between this rule
and TCR, State rules, National Emissions Inventory (NEI), ARP, or other
programs.  Many commenters supported submittal of all data directly to
EPA, while others favored delegation of data collection to State
agencies to encourage consistency between State and Federal data
collection efforts.

Response:  EPA carefully considered the issue of state State delegation,
particularly in light of the leadership and experience of several
statesStates in developing GHG reporting and reduction programs, and
also in the context of the pressing need for a national reporting
program and the strong emphasis placed by the vast majority of the
commenters on this rule for EPA to ensure that data collection begins on
January 1, 2010 and that data are reported early in 2011.  We determined
that developing a program to delegate to statesStates would take
additional time and would not be available for 2010 reporting, and we
also determined that a significant number of statesStates would likely
not request delegation, which would increase the complexity of
assembling a consistent national data set.  For these reasons, we
determined that the most effective way to achieve nationwide GHG
reporting of 2010 data was for reporters to submit data directly to EPA,
as proposed.  Additional reasons for selection of this data flow
approach are described in the response on emissions verification in
Section II.N of this preamble, the responses on collection, management,
and dissemination of GHG emissions data in Section V of this preamble,
and the responses on compliance and enforcement in Section VI of this
preamble.  

While EPA is not formally delegating rule implementation and enforcement
to States, we are committed to working in partnership to address the
issues expressed in their comments on interaction between State and
Federal reporting programs.  Design and implementation of electronic
systems for data systems has been an area of particular focus in
determining how to ease reporting burdens and facilitate use of the many
different types of data collected by State and Federal reporting
programs by all levels of government.

EPA is committed to working with States to develop electronic reporting
tools that can both collect and share data in an efficient and timely
manner.  At this time, EPA is in the process of developing the reporting
format and tools and therefore has not specified the exact reporting
format, other than it will be electronic, in order to maintain
flexibility to modify the reporting format and tools in a timely manner.
 To the extent possible, EPA will work with existing reporting programs
and systems to develop a reporting scheme that minimizes the burden on
sources.  

EPA recognizes the need to develop reporting tools that can support
reporting across programs that collect different types of data, and we
intend to coordinate with States and other organizations to explore
development of shared web-based tools that can simplify and expedite
reporting.  We recognize that State and Regionalregional programs may be
collecting additional GHG information beyond what is required in this
rule.  For example, many of these programs collect emissions data on
fleet vehicles, indirect emissions data for utility purchase, and other
data not required by the Federal rule.  Moreover, our rule requires
reporting of additional data necessary for emissions verification, which
is likely more expansive than what many existing State and regional
programs are collecting.  For example this rule requires reporting of
emissions at the process or unit level for many source categories,
rather than the company or facility level as allowed by various other
mandatory and voluntary reporting programs.  We will also collect
detailed monitoring data and activity data used to calculate emissions,
which will enable emissions verification.  We are interested in working
with others to determine the extent to which shared tools can be
designed to facilitate reporting across multiple programs, consistent
with obligations regarding CBI. 

 EPA carefully reviewed Federal, State, and international voluntary and
mandatory programs during development of the reporting rule and
attempted to be consistent with the GHG protocols and requirements
within these rules, to the extent feasible given the differing scopes
and policy objectives.  (See Section II of the preamble for the proposed
rule (74 FR 16457, April 10, 2009), the Review of Existing Programs
memorandum (EPA-HQ-OAR-2008-0508-052), and the memorandum summarizing
State mandatory rules (EPA-HQ-OAR-2008-0508-056054).)  EPA has worked
with and will continue to coordinate closely with other Federal, State,
and regional programs to facilitate data exchange when designing the
data reporting systems that will be used for the rule and planning
implementation activities.  We will work with the States, TCR, and
others on data exchange standards to ease sharing of data between
systems, consistent with CBI obligations.  And finally, we see
substantial opportunities for EPA and States to cooperate on strategic
efforts to identify uses of the data collected under this rule and work
together on a broad array of climate change issues.

P.  Summary of Comments and Responses on Other General Rule Requirements

This section contains a brief summary of major comments and responses on
other general rule requirements.  A large number of other general
comments were received covering numerous topics.  Responses to
significant comments received can be found in the comment response
documents (EPA-HQ-OAR-2008-508-XXX)“Mandatory Greenhouse Gas Reporting
Rule: EPA’s Response to Public Comments” volumes on subpart A.

1.  Research and Development 

Comment:  Commenters representing institutions and industries subject to
the reporting rule requested an exclusion for R&D activities.  They
noted that the aluminum production and glass production subparts of the
proposed rule excluded R&D process units, but requested that R&D be
excluded from the rule as a whole, not only from the two subparts.  Some
also commented that the exclusion should encompass R&D activities other
than R&D process units, including bench scale laboratory research and
pilot plants.  Commenters pointed out that many other EPA air rules
exclude R&D and they explained that R&D activities are small-scale,
emissions change frequently as the focus and scope of the R&D activity
changes, reliable information on CO2e emissions during any particular
phase of the research might not be available, and quantifying R&D
emissions would impose a high burden relative to the quantity of
emissions.

Response:  In response to these public comments, EPA has added an R&D
exclusion in 40 CFR 98.2(a)(5) stating that R&D activities are not
considered to be part of any source category defined in 40 CFR part 98. 
Because R&D activities are not included in any source category, their
GHG emissions are not reported.  EPA agreed with the commenters that R&D
process units and laboratory R&D for new processes, technologies, or
products should be excluded.  It is not reasonable to calculate GHG
emissions from processes and activities that continually change as the
research focus changes and have highly variable inputs and operating
conditions due to their R&D nature.  Also, emissions from R&D are
expected to be small.  Therefore, the final rule defines R&D as
activities conducted in process units or at laboratory bench scale
settings whose purpose is to conduct R&D for new processes,
technologies, or products, and whose purpose is not for the manufacture
of products for commercial sale, except in a de minimis manner.  

We point out that the exclusion applies to each individual R&D activity
that meets the R&D definition, not to an entire facility as a whole. 
For example, a facility that has some commercial process units and some
R&D process units can exclude only the R&D process units.  A facility
that meets the applicability criteria in 40 CFR part 98, subpart A and
contains general stationary combustion sources must report emissions
from the combustion units, even if the steam, heat, or electricity
generated by a combustion unit is used in an R&D process unit. 
Laboratory activities are excluded only if they are for R&D purposes. 
Laboratory analyses activities conducted for commercial purposes,
process operating purposes, or to comply with a rule would not be
excluded. 

We decided not to include pilot plants in the definition of R&D.  Pilot
plants that meet the rule applicability criteria must report their GHG
emissions.  Pilot plants tend to be relatively large in scale compared
to the excluded R&D activities.  Because pilot plants are designed to
prove the viability of a particular process or technology rather than to
research a wide range of processes and products, their operations and
emissions are more consistent than the excluded R&D activities.  Pilot
plants also tend to be operated for relatively long periods of time and
in some cases are converted to commercial facilities.  For these
reasons, EPA views the data as more useful and has not applied the R&D
exclusion to pilot plants.

2.  Determining Applicability 

Comment:  Some commenters were concerned that the GHG reporting rule
will virtually require every commercial and industrial facility to
collect fuel usage data and perform relatively complex calculations, and
in some cases modeling, in strict accordance with the prescribed
monitoring methodologies and emissions calculation procedures, to
determine if they are subject to the rule.  The commenters added that
this will be burdensome, especially for small sources that will just be
documenting that the calculated GHG emissions from the facility are well
below the reporting threshold.  They also indicated that recordkeeping
would be needed to show that facilities are below the reporting
threshold, and anticipated that the rule will be nearly as burdensome on
facilities that do not have to report, as on those that must report. 
Many of the commenters asked that EPA provide more simplesimplified
source category thresholds to determine applicability, like the 30
mmBtu/hr aggregate maximum rated heat input capacity for stationary fuel
combustion units, to reduce the burden on the majority of facilities
making applicability determinations. 

Response:  We disagree that the initial applicability determination
process is burdensome.  While the rule requires reporters who are
subject to the rule to determine applicability using the calculation
procedures required in the rule, the rule does not contain any
requirements for facilities that are not subject to the rule. 
Therefore, the rule does not necessarily require monitoring in 2010 to
determine applicability.  To determine applicability, anyone who
believes their facility might be subject to the rule could start by
calculating emissions using the relevant equations provided in each
applicable subpart along with the available data from company records
and the likely operating scenario for the reporting year that would lead
to worst case GHG emissions.  For example, for the input parameters
needed for the equations, use the 2010 production goals from the
company’s business plan, company records, process knowledge,
engineering judgment, and vendor data (e.g., vendor information could be
used to estimate the carbon content of feedstocks, using the highest
likely carbon content of those feedstocks.)  EPA expects that for most
facilities, emissions calculated in this manner are likely to be
significantly above or below the 25,000 metric ton CO2e per year
threshold, such that most potential reporters can determine their
applicability to the rule solely using the available data.

For those facilities with estimated emissions that are near the 25,000
tons/year threshold using available data, the company will have to make
the decision on whether to install monitoring equipment to calculate
emissions during the 2010 reporting year for purposes of determining
applicability and/or reporting emissions.  It is in a facility’s
interest to collect the GHG data required by the rule if they think they
will meet or exceed the applicability criteria in 40 CFR 98.2 by the end
of the year.  EPA anticipates that relatively few potential reporters
will face uncertainty in making this decision.

Given the large number of industrial and commercial facilities
potentially subject to the rule due to stationary fuel combustion
emissions, EPA has provided atin 40 CFR 98.2(b)(2) simplified procedures
for calculating emissions from fuel combustion.  These facilities may
first assess applicability based on the aggregate heat input capacity of
all their fuel combustion units.  Facilities Per 40 CFR 98.2(a)(3),
facilities with an aggregate maximum rated heat input capacity of less
than 30 mmBtu/hour are automatically not covered under the rule, because
emissions of CO2e will be less than 25,000 metric tons of CO2e per year
in all cases.  If a facility is not below the 30 mmBTU/hour cutoff, the
next logical step to determine applicability is to use any of the four
calculation methods provided in subpart C, as allowed by 40 CFR 98.2(b).
 The simplest of the four methods requires determination of only one
parameter – annual fuel use.  Most companies already record fuel use,
and can use this to calculate emissions and determine applicability. 

To assist facilities in determining applicability, EPA plans to provide
implementation guidance with simplified means to determine
applicability.  For combustion sources, EPA plans to publish tables that
will specify by fuel type both an annual fuel assumptionconsumption
level and maximum heat input capacity that correlates with emissions of
25,000 metric tons per year of CO2e.  For non-combustion source
categories with a 25,000 metric ton CO2e threshold, EPA plans to publish
guidance, as feasible, on equipment capacities, production levels, or
other parameters that correlate with emissions of 25,000 metric tons per
year of CO2e.  The capacity and production levels provided in these
tables would be based on worst-case assumptions, but would allow
facilities to quickly and easily determine if they need to develop more
precise estimates or plan to implement monitoring in 2010.

Q.  Summary of Comments and Responses on Statutory Authority 

This section contains a brief summary of some major comments and
responses.  A large number of comments on statutory authority were
received covering numerous topics.  This section will highlight only two
of the key categories of comments.  Additional discussion on these
comments and others can be found in the comment response documents.

Responses to significant comments received can be found in the comment
response documents (EPA-HQ-OAR-2008-508-XXX).“Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to Public Comments, Legal Issues”.

Comment: EPA received numerous comments on whether the Clean Air ActCAA
or the FY 2008 Consolidated Appropriations Act authorized the rule. 
Some commenters argued that EPA was required to issue the reporting rule
under the authority created by the Appropriations Act, not the CAA. 
Others argued that the Appropriation Act could not create new authority,
and therefore either (1) EPA had to rely on the CAA, or (2) EPA was not
authorized to issue the rule at all.  

Response:  As noted above, EPA is relying on the authority provided in
the CAA, not the Appropriations Act, for this final rule.  While the
Appropriations Act required that EPA spend a certain amount of money on
a rule requiring mandatory reporting of GHG emissions, the authority to
gather such information already existed in the CAA.  Indeed, EPA could
have promulgated this rule in the absence of the Appropriations Act. 
Thus, the comments about the inability of an appropriations law to
create new legal authority are inapposite to this rulemaking. 

Comment:  Commenters opined on whether the statute in question (either
the Appropriations Act or the CAA) contained sufficient authority for
various elements of the rule, ranging from broad issues like the scope
and duration of the rule as a whole, to more specific issues related to
particular source categories covered, and specific monitoring,
recordkeeping and reporting requirements.

Several commenters argued that the appropriations language contained
limitations on the scope of the rule EPA could promulgate, regardless of
the underlying authority for the rule.  For example, some commenters
contended that because the appropriations were for a single fiscal year,
EPA was authorized to promulgate only a one-time data collection. 
Others argued that the Appropriations Act authorized the collection
solely of GHG emissions, and not any of the additional data elements
related to verification of emissions data.  

As for the CAA, some commenters questioned whether section 114
authorized a broad reporting rule, as opposed to the targeted 114
information requests used by EPA in the past.  Many commenters
questioned whether EPA had adequately linked the requirements of the
reporting rule to particular provisions of the CAA that EPA was carrying
out.  Others questioned EPA’s general ability to gather information
about GHGs before it had made an endangerment finding and/or regulated
GHGs under the CAA.  

Not all comments were negative.  Some commenters supported EPA’s
interpretation of the CAA, and agreed that it authorized the proposed
reporting rule. 

Response:  We disagree that the language in the Appropriations Act
limited EPA’s authority for this rule.  First, the fact that
appropriations are for a single fiscal year does not mean that the
action taken pursuant to that appropriations cannot last longer than one
year.  First, the Environmental Programs and Management (EP&M) funds
Congress appropriated for the GHG reporting rule are available for two
fiscal years as are the funds EPA historically has used for most other
Agency rules. The fact that the appropriations EPA uses to develop rules
are available for specified fiscal years does not mean that the
effectiveness of the rules is limited by the same period of time that
the funds are available. Moreover, as noted above, EPA is issuing this
rule under the authority of the CAA, and indeed EPA could have issued
this rule absent the direct instruction from Congress to spend at least
a certain amount of money on a mandatory GHG reporting rule.  Thus, we
do not agree that the appropriations language limited EPA’s ability to
collect the information under this rule, either in duration or scope of
the information requested. 

Regarding the scope of the rule, while it is true that EPA has used
section 114 in a more targeted fashion in the past, there is nothing in
the CAA that so limits our ability.  EPA is undertaking a comprehensive
evaluation of greenhouse gasesGHGs under the CAA and hence, is issuing a
comprehensive reporting rule.  

Moreover, as noted above, CAA sections 114 and 208 of the CAA authorize
EPA to gather the information under this rule, which will prove useful
to EPA in carrying out numerous provisions of the CAA.  This final rule
imposes requirements on direct sources of GHG emissions.  These sources
are clearly persons from whom the Administrator may gather information
under CAA section 114, as long as that information is for purposes of
carrying out any provision of the CAA.  As discussed further in the
response“Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to
comments document,Public Comments, Selection of Source Categories to
Report and Level of Reporting” and “Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to Public Comments, Legal Issues,”
the information provided by direct emitters will prove invaluable to the
Agency in several areas, including the evaluation of the appropriate
action to take under section 111 regarding NSPS, and the investigation
into non-regulatory strategies to encourage pollution prevention
pursuant to section 103(g).  For example, the Agency currently has
pending before it a court remand, comments in an ongoing rulemaking, a
petition for reconsideration, notices of intent to sue and litigation
regarding EPA’s treatment of GHGs under section 111.

The requirements applicable to manufacturers of mobile sources are
authorized by section 208 because they will help inform various options
regarding the regulation of these sources under title II of the CAA. 
The Agency currently has pending before it several petitions requesting
that the Agency regulate emissions from a variety of mobile sources,
including motor vehicles, aircraft, nonroad engines and marine engines.

Finally, the final rule also gathers information from upstream suppliers
of industrial GHGs and fossil fuels (except for suppliers of coal).  The
information gathered from suppliers of fossil fuels, in particular
petroleum products, is relevant to an evaluation of possible regulation
of fuels under title II of the CAA, as well as for potential efforts to
address GHG emissions at downstream sources.  Information from suppliers
of industrial greenhouse gasesGHGs is relevant to understanding the
quantities and types of gases being supplied to the economy, in
particular those that could be emitted downstream which will aid in
evaluating action under CAA section 111 as well as various sections of
title VI (e.g., 609 and 612) that address substitutes to ozone depleting
substances (ODS).  Additional discussion on this issue is available in
the response to comments document.“Mandatory Greenhouse Gas Reporting
Rule: EPA’s Response to Public Comments, Selection of Source
Categories to Report and Level of Reporting” and in “Mandatory
Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments,
Legal Issues.”  

Finally, we disagree with commenters who argue that we cannot use CAA
sections 114 of 208 of the CAA to gather information on a pollutant
until we have issued an endangerment finding for that pollutant, or
actually decided to regulate it under the CAA.  The statute is not so
inflexible.   For example, the information collected under sections 114
and 208 could inform the contribution element of endangerment
determinations (e.g., whether emissions from the relevant sector
contribute to air pollution which may reasonably be anticipated to
endanger public health or welfare).  Similarly, information gathered
under these sections could inform decisions on whether to regulate a
pollutant or source category.  Commenters’ interpretation would
prevent EPA from gathering information that could be critical to key
decisions until after those decisions are made.  EPA does not agree
with, and will not adopt, such an interpretation.   

Thus, as discussed in more detail above and in the response to comments
document, the CAA provides“Mandatory Greenhouse Gas Reporting Rule:
EPA’s Response to Public Comments, Legal Issues,”  EPA has adequate
authority forto issue this final rule.

R.  Summary of Comments and Responses on CBI 

This section contains a brief summary of major comments and responses on
CBI issues.  A large number of comments were received covering numerous
topics.  Responses to significant comments received can be found in the
comment response documents (EPA-HQ-OAR-2008-508-XXX).“Mandatory
Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments,
Legal Issues.”

Comment:  EPA received numerous comments addressing the issue of CBI. 
Industry commenters generally expressed concern that much of the
information reported under this rule would be CBI (e.g., production and
process data).  Many commenters also presented arguments regarding why
certain information would not be “emissions data” under the CAA. 
Among the various recommendations were that the final rule (i) not
require the reporting of such information at all, (ii) require only that
the source maintain such information on site, but not report it to EPA,
and/or (iii) clearly state that some classes of information are CBI. 
Some commenters expressed concern about EPA’s ability to maintain the
confidentiality of CBI, and thus suggested that EPA should provide
further detail regarding how we will protect CBI from disclosure.  The
agricultural industry expressed particular concerns about making
information about the location of facilities public due to concerns
about biosecurity and other potential threats.  Other commenters favored
the wide dissemination of information, and argued that the information
gathered under this rule should be “emissions data” and hence not
protected as CBI.

Response:  As discussed in sectionSection II.N of this preamble, EPA is
finalizing its proposal that EPA verify the information collected by
this rule.  Data regarding inputs into emissions calculations and
monitoring are critical elements of that verification process.  Because
EPA will routinely need this data in order to verify the information
collected under this rule, we are not adopting the recommendation that
sources maintain such information on site and only provide it during an
inspection or when otherwise specifically requested.  

EPA also recognizes the importance of this issue to both reporters and
the public.  EPA’s public information regulations contain a definition
of “emissions data” at 40 CFR 2.301, and EPA has discussed in an
earlier Federal Register notice what data elements constitute emissions
data that cannot be considered CBI withheld as CBI (56 FR 7042–7043,
February 21, 1991).  We further recognize that while determinations
about whether information claimed as CBI meets the definition of CBI, as
well as whether it meets the definition of emissions data, are usually
made on a case-by-case basis, such an approach would be cumbersome given
the scope of this rule and the potential inconsistencies across
reporters and source categories and the compelling need to make data
that are not CBI, or are emissions data, available to the public.  For
this reasons, EPA intends to undertake an effort similar to what was
done in 1991 for the data elements collected in this rule.  Through a
notice and comment process, we will establish those data elements that
are “emissions data” and therefore will not be afforded the
protections of CBI.  As part of that exercise, in response to requests
provided in comments, we may identify classes of information that are
not emissions data, and are CBI.  EPA plans to initiate this effort
later this year, or in early 2010.  We will consider the comments
received on this issue as part of that notice and comment process.

As stated in the proposed rule, EPA will protect any information claimed
as CBI in accordance with regulations in 40 CFR part 2, subpart B.  As
we noted previously however, in general the CAA prohibits the
treatementtreatment of emission data collected under CAA sections 114
and 208 as CBI.  

S.  Summary of Comments and Responses on Other Legal Issues 

This section contains a brief summary of major comments and responses on
other legal issues.  A large number of other legal issue comments were
received covering numerous topics.  Responses to significant comments
received can be found in the comment response document on legal issues
(EPA-HQ-OAR-2008-508-XXX).“Mandatory Greenhouse Gas Reporting Rule:
EPA’s Response to Public Comments, Legal Issues.”

Comment:  We received numerous comments on EPA’s statements in the
proposed rule that a final rule requiring the monitoring and reporting
of GHG emissions would not render greenhouse gasesGHGs “regulated NSR
pollutants” for purposes ofunder the PSD program.CAA.  See ‘‘,
e.g., "EPA’s Interpretation of Regulations that Determine Pollutants
Covered By Federal Prevention of Significant Deterioration (PSD) Permit
Program’’" (Dec. 18, 2008).) (“PSD Interpretive Memo).  Some
agreed, while others took issue with the position in the December 2008
memorandum.  

Response:  As we noted in the proposal, EPA is reconsidering the
December 2008 memorandumPSD Interpretive Memo and will be seeking public
comment on the issues raised in it. [UPDATE AS NEEDED]  That proceeding,
not this rulemaking, is the appropriate venue for submitting comments on
the substantive issue of whether monitoring regulations under the CAA
should trigger the PSD program.make GHGs subject to regulation.  At this
time however, the December 2008 memorandumPSD Interpretive Memo reflects
EPA’s current position, and hence, this final rule does not make GHGs
“regulated NSR pollutants” for the purposes of the PSD program.
subject to regulation under the CAA. 

Comment:  EPA also received numerous comments about whether the
requirements imposed by this rule are “applicable requirements”
under the title V operating permit program.  The majority of the
comments took the position that the current definitions of “applicable
requirement” at 40 CFR 70.2 and 71.2 do not include a rule such as
this, promulgated under CAA section 114(a)(1) and 208 of the CAA. 
Commenters requested that EPA confirm their interpretation of the
regulations.

Response:  As currently written, the definition of "applicable
requirement" in 40 CFR 70.2 and 71.2 does not include a monitoring rule
such as today'stoday’s action, which is promulgated under CAA sections
114(a)(1) and 208.  

III. Reporting and Recordkeeping Requirements for Specific Source
Categories

A.  Overview

Once a reporter has determined that theirits facility or supply
operation meets any of the reporting rule applicability criteria in 40
CFR 98.2(a), theythe reporter must calculate and report GHG emissions or
alternate information as required (e.g., suppliers report quantities
supplied and the quantity of CO2e that could be emitted when the
products they supply are combusted or used).  The applicability
threshold determination is separately assessed for suppliers (fossil
fuel suppliers and industrial GHG suppliers) and downstream source
categories (facilities with direct GHG emissions).  

The required GHG information must be reported for all source categories
at the facility for which there are measurement methods provided.  For
suppliers (facilities or corporations) that trigger only the
applicability criteria for upstream fossil fuel or industrial GHG supply
(40 CFR part 98, subparts KK through PP), reporters need only follow the
methods and report the information specified in those respective
subparts.  For downstream facilities that contain exclusively direct
emitting source categories covered in 40 CFR part 98, subparts C through
JJ, and are not suppliers, reporters must monitor and report GHG
emissions the methods presented in each applicable subpart.  Some
reporters will need to report under multiple subparts because multiple
source categories are collocated at their facility.  For example, a
facility with petrochemical production processes (described in
sectionSection III.X of the preamble), should also review
sectionsSections III.C (general stationary fuel combustion), III.G
(ammonia manufacturing) and III.Y (petroleum refineries) of this
preamble.  In some cases, such as petroleum refineries that supply
petroleum products and also meet applicability criteria for direct
emissions from the refinery, reporters will have to report on both
supply operations and direct facility emissions.  

Table 2 of this preamble (in the “Supplementary Information” section
of this preamble) provides a cross walk to aid facilities and suppliers
in identifying potentially relevant source categories.  The cross-walk
table should only be seen as a guide as to the types of source
categories that may be present in any given facility and therefore the
methodological guidance in Section III of this preamble that should be
reviewed.  Additional source categories (beyond those listed in Table 2
of this preamble) may be relevant to a given reporter.  Similarly, not
all listed source categories will be relevant to all reporters.  

Consistent with the requirements in the 40 CFR part 98, subpart A,
reporters must report GHG emissions from all source categories located
at their facility including stationary combustion 40 CFR part 98,
subpart C) and process emissions (e.g., from adipic acid production,
iron and steel production, and other source categories in 40 CFR
subparts C through JJ), as well as the required data for any supplier
source categories (KK through PP).  The methods presented typically
account for normal operating conditions, as well as startup, shutdown,
or malfunction (SSM), where significant (e.g., HCFC-22 production and
oil and gas systems).  Although SSM is not specifically addressed for
many source categories, emissions calculation methodologies relying on
CEMS or mass balance approaches would capture these different operating
conditions. 

For many facilities, calculating facility-wide emissions will simply
involve adding GHG emissions from combustion sources calculated under
Section III.C of this preamble (General Stationary Fuel Combustion
Sources) and process GHG emissions calculated under the applicable the
source category subpart(s).  The rule also clarifies reporting for more
complex situations, such as where combustion and process emissions are
comingled.  See sectionSection II.L of this preamble for a response to
comments on the general monitoring and reporting approach for facilities
with both combustion and process emissions.  See sections III.C through
PP of this preamble for discussion of the specific monitoring and
reporting requirements for each source category.

B.  Electricity Purchases 

1.  Summary of the Final Rule

The final rule does not require facilities to report their electricity
purchases or indirect emissions from electricity consumption.

2.  Summary of Major Changes Since Proposal 

There have been no changes since proposal.  The proposed rule did not
require reporting of electricity purchases and neither does the final
rule.  

3.  Summary of Comments and Responses 

The proposal preamble (74 FR 16479, April 10, 2009) requested comments
on the value of collecting information on electricity purchases under
this rule.  It also outlined three options for reporting and requested
comments on these options:

Option 1: Do not require any reporting on electricity purchases or
associated indirect emissions from purchased electricity as part of this
rule.

Option 2: Require reporting of purchased electricity from all facilities
that are already required to report their GHG emissions under this rule.

Option 3: Require reporting of indirect emissions from purchased
electricity for facilities that exceed a prescribed total facility
emission threshold (including indirect emissions from the purchased
electricity).  Reporting under this option could be either in terms of
electricity purchases or calculated CO2e emission based on purchased
electricity.  

This section containsWhile EPA is not including reporting requirements
for electricity purchases in the final rule at this time, below we have
provided a brief summary of major comments and our initial responses.  A
large number of comments on electricity purchases were received covering
two main topics: those in favor of collecting data on electricity
purchases and those against itAs EPA considers next steps, we will be
reviewing the public comments and other relevant information.  

In Favor of Collecting Data on Electricity Purchases

Comment: Commenters in favor of collecting data on purchased electricity
stated that collection of this data, in conjunction with data on direct
emissions from facilities, will present a more comprehensive picture of
emissions nationwide.  They argued that collection of this data will
also serve to spur investment in energy efficiency and renewable energy
since companies will want to improve their emissions numbers once the
information is made public.  Several commenters noted that while this
reporting should occur, it should happen at the corporate level, rather
than at the facility level.  Others stated that the collection should
begin at a later time, perhaps in a second phase of this rule.

Response: While EPA is not collecting data on electricity purchases in
this rule, we understand that acquiring such data may be important in
the future.  Therefore, we are exploring options for possible future
data collection on electricity purchases and indirect emissions, and the
uses of such data.  Such a future data collection on indirect emissions
would complement EPA’s interest in spurring investment in energy
efficiency and renewable energy.  Energy efficiency is a low cost, vital
first step toward reducing greenhouse gasGHG emissions.  To this end,
EPA has in place several programs in which corporations and individual
facilities can participate to reduce their contribution to greenhouse
gasGHG emissions through increased energy efficiency of buildings and
industry.  These include EPA’s ENERGY STAR and Climate Leaders
programs.

EPA has been working for more than a decade through the ENERGY STAR
program to help companies reduce their energy use through cost-effective
energy efficiency investments and practices.  ENERGY STAR provides
nonresidential building owners and operators and energy intensive
industries with a wide variety of tools and resources to assist in their
efforts to reduce building energy use.  These include an online energy
benchmarking and tracking tool called Portfolio Manager, Guidelines for
Energy Management, technical resources to assist in assessing building
upgrades, and many others.  

Through the Climate Leaders Program, EPA works corporate-wide with
companies to develop comprehensive climate change strategies.  Partner
companies commit to reducing their impact on the global environment by
completing a corporate-wide inventory of their greenhouse gasGHG
emissions based on a quality management system, setting aggressive
reduction goals to be achieved over 5 to 10 years, and annually
reporting their progress to EPA.  Through program participation,
companies create a credible record or audit of their accomplishments and
receive EPA recognition as corporate environmental leaders.  

In addition to these programs that support greenhouse gasGHG emissions
reductions in both the private and public sectors, EPA’s Climate and
Energy State and Local Program assists governments in their clean energy
efforts by providing technical assistance, analytical tools, and
outreach support.  While EPA assists States in this way, we also have
much to learn from their efforts.  Throughout the country, States are
engaged in activities on energy efficiency, energy auditing, and some
collect data on electricity purchases for use in inventories and in
energy efficiency programming.

Since the goal of today’s rule is to collect data on emissions from
downstream direct emitters and upstream production, the collection of
indirect emissions will not be included at this time.  In exploring the
possibility of collecting data on electricity purchases nationwide, EPA
will be looking to the States as examples.  While facility level
collection is a possibility, collection from other sources, such as load
serving entities will also be explored.  Moreover, the collection of
indirect emissions data from the types of facilities covered by this
rule (e.g., facilities and suppliers with emissions over 25,000 metric
tons of CO2e) would not provide the complete picture or focus on the
types of facilities that likely have large indirect emissions.  Reports
from additional facilities could be required in any future data
collection.

Against Collecting Data on Electricity Purchases

Comment:  Many commenters were against the collection of data on
purchased electricity for several reasons.  Primarily they felt it would
constitute double counting if electricity data is are collected from
electric utilities and EPA also collects the same data from facilities
and adds it together.  Others stated that collecting information on
electricity purchases was outside the scope of the rule, that it is not
useful information in attempting to quantify emissions, that it would be
burdensome for facilities, and that it is CBI that companies are not
able to share with EPA.  Those commenters suggested instead the data
should come from utilities, as EPA proposed.

Response:  The final rule does not require facilities to report their
electricity purchases or indirect emissions from electricity
consumption.  While EPA is not collecting data on electricity purchases
in this rule, we understand that acquiring such data may be important in
the future.  Therefore, we are exploring options for possible future
data collection on electricity purchases and indirect emissions, and the
uses of such data.  In the event that a future data collection effort is
pursued, EPA will consider the issues raised by these commenters with
regard to the most effective source for this data, and methods to reduce
burden on reporting entities.

With regard to, double reporting and/or double counting of the same
data, the data collected under this rule is consistent with the
appropriations language, and provides valuable information to EPA and
stakeholders in the development of climate change policy and programs. 
Policies such as low carbon fuel standards can only be applied upstream,
whereas end use emission standards can only be applied downstream.  Data
from upstream and downstream sources would be necessary to formulate and
assess the impacts of such potential policies.  Eliminating reporting by
either upstream or downstream sources would not satisfy EPA’s data
needs and policy objectives of this rule.  Any future rule makings to
collect data on electricity purchases and indirect emissions will follow
a similar approach in order to inform policy decisions.

With regard to CBI, as stated in the proposed rule, and will be stated
in any subsequent rule making process, EPA will protect any information
claimed as CBI in accordance with regulations in 40 CFR part 2, subpart
B.  As we noted previously, however, in general emissions data collected
under CAA sections 114 and 208 cannot be considered CBI.  

EPAWith regard to CBI, EPA recognizes the importance of this issue to
both reporters and the public.  EPA’s public information regulations
contain a definition of “emissions data” at 40 CFR 2.301.  Although
determinations about whether information claimed as CBI meets the
definition of CBI, as well as whether it meets the definition of
emissions data, are usually made on a case-by-case basis,, and EPA has
issued guidancediscussed in an earlier Federal Register notice on what
data elements constitute emissions data that cannot be considered CBI
(956 FR 7042-7043, February 21, 1991).   

  As explained in Section II.R. of this preamble, EPA intends to
undertake a similar effort regarding the data elements collected in this
rule, and any subsequent rules.  Through a notice and comment process,
we will establish those data elements that are “emissions data” and
therefore will not be afforded the protections of CBI.  

C.  General Stationary Fuel Combustion Sources

1.  Summary of the Final Rule 

Source Category Definition.  Stationary fuel combustion sources are
devices that combust any solid, liquid, or gaseous fuel to:

Produce electricity, steam, useful heat, or energy for industrial,
commercial, or institutional use; or

Reduce the volume of waste by removing combustible matter. 

These devices include, but are not limited to, boilers, combustion
turbines, engines, incinerators, and process heaters. 

Portable equipment, emergency generators, and emergency equipment are
excluded from this source category.  Stationary combustion devices that
combust hazardous waste must report emissions only from the co-firing of
any fuels that are covered by 40 CFR part 98, subpart C.  Flares are
also excluded from subpart 40 CFR part 98, subpart C.  Flare emissions
must be reported only if required by the provisions of another subpart
of part 98.

Reporters must submit annual GHG reports for stationary fuels combustion
units if the facility meets the applicability criteria in the General
Provisions (40 CFR 98.2) as summarized in Section II.A of this preamble.

EGUs that are subject to the ARP and other EGUs that are required to
monitor and report to EPA CO2 mass emissions year-round according to 40
CFR part 75, are covered under 40 CFR part 98, subpart D (Electricity
Generation).

GHGs to Report.  For stationary fuel combustion, report: 

CO2, CH4, and N2O emissions from each stationary fuel combustion unit. 
For each unit, CO2, CH4, and N2O emissions must be reported for each
fuel combusted (including biomass).  Reporters can aggregate emissions
from multiple units in certain cases.  

Facility-level CO2 emissions from combustion of biomass (in addition to
unit-level reporting).

GHG Emissions Calculation and Monitoring.  Reporters must use the
following methodologies to calculate emissions:

Calculating CO2 Emissions from Combustion:  Calculate CO2 emissions
using one of four methodological tiers, subject to certain restrictions
based on unit size, type of fuel burned, and other factors.  For each
Tier, CO2  mass emissions are determined as follows:

Tier 1: Use annual fuel consumption (from company records) together with
fuel-specific default high heat values and default CO2 emission factors.

Tier 2: Use annual fuel consumption (from company records) together with
measured fuel-specific high heat values and default CO2 emission
factors.

Tier 3: Use annual fuel consumption, either from company records (for
solid fuels) or directly measured with fuel flow meters (for liquid and
gaseous fuels) together with periodic measurements of fuel carbon
content.

Tier 4: Use CEMS.  Use Tier 4 only for combustion units that have
certain types of existing CEMS in place and that meet several other
specific criteria, such as fuel type and hours of operation.  Sources
that have all of the necessary CEMS installed and certified by January
1, 2010 are required to use Tier 4 in 2010.  However, for sources that
need additional time to upgrade their CEMS, the use of CEMS can begin on
January 1, 2011; and a lower tier calculation methodology may be used in
2010.

As an alternative to any of the four tier methods, the rule provides
that units that report to EPA year-round heat input data under 40 CRF
part 75 can calculate CO2 mass emissions using part 75 calculation
methods.

Calculating CO2 Emissions From Sorbent Use.  For fluidized bed boilers
that use sorbent injection and units equipped with wet flue gas
desulfurization systems, calculate CO2 emissions from sorbent use using
methods provided in the rule, except when CO2 emissions are measured
with CEMS. 

Calculating CO2 Emissions From Biomass Fuel Combustion.  Calculate CO2
emissions from biomass combustion for only the specific types of biomass
that are listed in the rule.  UseThe approach used for most units is to
use a default high heat value and default CO2 emission factor to
estimate emissions.  Use methods provided in the rule for For
determining the biomass fraction of CO2 emissions from units that burn
municipal solid wasteMSW or mixed fuels, and from units that co-fire
biomass with fossil fuels and measure CO2 emissions using CEMS, use the
specific methods provided in the rule.

Calculating N2O and CH4 Emissions From Combustion.  Calculate N2O and
CH4 emissions only for units that are required to report CO2 emissions
under this subpart and only for fuels for which default emission factors
are provided in 40 CFR part 98, subpart C.  

Fuel Sampling and Analysis.  The Tier 2 and Tier 3 calculation
methodologies require periodic measurements of fuel heating value and
carbon content.  The minimum required frequency of these measurements is
daily, weekly, monthly, quarterly, or semiannually, depending on the
type of fuel combusted and other factors. 

Data Reporting.  In addition to the information required to be reported
by the General Provisions (40 CFR 98.3(c)) and summarized in Section
II.A of this preamble, reporters must submit additional data that is are
needed for EPA verification of the reported GHG emissions from
stationary combustion.  The specific data to be reported are found in 40
CFR part 98, subpart C.

Recordkeeping.  In addition to the records required by the General
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this
preamble, reporters must keep records of additional data used to
calculate GHG emissions.  These records are described in 40 CFR part 98,
subpart C.

2.  Summary of Major Changes Since Proposal

The major changes since proposal are identified in the following list. 
The rationale for these and any other significant changes can be found
below or in the comment response document for“Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to Public Comments, Subpart C: General
Stationary Fuel Combustion. Sources.”

A number of exemptionsExemptions to GHG emissions reporting have been
added for certain unconventional types of fuel.  For units using Tiers 1
or 2, youReporters are not required to calculate GHG emissions if EPA
has not provided default values.  For units using Tier 3, youonly for
fuels that are listed in Table C-1 of subpart C, except that units
larger than 250 mmBtu/hr, also must calculate GHG emissions only for
theany other fuels that provide, on average, at least 10% percent of the
annual heat input to the unit.

The use of the Tier 2 calculation method for CO2 emissions has been
expanded to include units greater than 250 mmBtu/hr that combust only
pipeline natural gas and/or distillate oil.

Two new alternative methods have been added, allowing sources that
monitor and report heat input according to 40 CFR part 75, but are not
required to report CO2 mass emissions, to use established Part 75 CO2
emissions calculation methods to meet the 40 CFR part 98 reporting
requirements.

A definition of “company records”, as it pertains to quantifying
fuel consumption in Tiers 1, 2, and 3, has been added to 40 CFR 98.6.

The required fuel sampling frequency in Tiers 2 and 3 has been reduced
for many fuels, particularly those that are homogeneous or that are
delivered in shipments or lots. 

Averaging of fuel sampling results is allowed for many fuels when the
frequency of sampling and analysis is less than the minimum monthly
frequency.

The rule has been clarified to affirm that the use of fuel sampling
results provided by the fuel supplier is permissible, and that the use
of fuel billing records to quantify fuel consumption is also allowed. 

Additional deadline extensions for calibrating the fuel flow meters are
provided in certain situations.

The use of Tier 4 has been clarified; i.e., all of the conditions listed
in 40 CFR 98.33(b)(54)(ii) and all of the conditions listed in 40 CFR
98.33(b)(54)(iii) must be met before Tier 4 is required.

Units that must upgrade their existing CEMS to meet Tier 4 requirements
may use either Tier 2 or Tier 3 in 2010.

The methods for calculating CH4 and N2O emissions have been clarified.

An expanded list of default emission factors are provided for certain
solid, gaseous, and liquid biomass fuels.

The use of steam production and combustion unit efficiency to calculate
CO2 emissions is extended to other solid fuels in addition to municipal
solid waste (MSW).  These parameters may also be used to quantify the
amount of biomass combusted in a unit.

The use of American Society for Testing and Materials (ASTM) Methods
D7459-08 and D6866-06a to determine CO2 emissions from combustion of
mixed biomass fuels has been expanded to include the combustion of other
biomass fuels besides municipal solid wastein addition to those mixed
with  MSW.  

The missing data provisions have been made more flexible.

The limit of 250 mmBtu/hr total heat input for aggregating units into
groups for reporting purposes has been lifted.

The reporting of combined units served by a common supply line, or
common pipe configuration, has been clarified.

The amount of required unit-level data and emissions verification
information has been reduced for some of the measurement Tiers. 

3.  Summary of Comments and Responses 

This section contains a brief summary of major comments and responses. 
Many comments on general stationary fuel combustion were received
covering numerous topics.  Responses to significant comments received
can be found in the comment response document for general stationary
fuel combustion in the docket (EPA-HQ-OAR-2008-508-XXX).Responses to
significant comments received can be found in “Mandatory Greenhouse
Gas Reporting Rule: EPA’s Response to Public Comments, Subpart C:
General Stationary Fuel Combustion Sources.”

Definition of Source Category

Comment:  Several commenters asked EPA to clarify whether sources such
as flares, hazardous waste incinerators, thermal oxidizers, pollution
control devices, fume incinerators, burnout furnaces, and small
equipment such as stoves and space heaters are included in the
stationary combustion source category.  Others suggested that EPA should
consider requiring that only the GHG emissions from combustion of
traditional fossil fuels (if any) in these types of sources be reported.

Comments were also received on the proposed language for excluding
emergency generators and the associated definitions. 

Response:  The final rule retains the broad definition of a stationary
fuel combustion source, which is any device that combusts fuel.  Fuel is
defined very broadly to mean any combustible material.  However, in
evaluating public comments, we agree that in some cases the reporting of
GHG emissions is unreasonable given the cost of monitoring and the
relative level of GHG emissions.  Monitoring can be particularly
burdensome for vents with highly variable gas characteristics (e.g.,
carbon content and heat value).  Accordingly, the final rule expands the
list of combustion sources and fuels that are exempted from GHG
emissions reporting under 40 CFR part 98, subpart C, as summarized
below:

Flares are exempted from 40 CFR part 98, subpart C.  However, flares at
some facilities might be covered by other subparts of the rule.  

Stationary combustion units that combust hazardous waste, as defined in
40 CFR 261.3, are also exempted.  These units would report only the
emissions from combustion of any fuels covered by subpart C that are
co-fired with hazardous wastes.

UnitsFor calculations at the unit level, units less than 250 mmBtu/hour
heat input are required to report GHG emissions only for fuels for which
EPA has provided default emission factors in the rule.  

Units larger than 250 mmBtu/hour heat input GHG that combust
miscellaneous, non-traditional fuels such as refinery gas, process gas,
vent gases, waste liquids, and others must report only if CEMS are used
or if these fuels contribute 10 percent or more of the annual unit heat
input to the unit.  With this exclusion, we have concluded that devices
such as thermal oxidizers, pollution control devices, fume incinerators,
burnout furnaces, and other such equipment would report only GHG
emissions from the firing of supplemental fossil fuels.

In response to comments on the exclusion of emergency generators, EPA
removed proposed language that would have required emergency generators
to be identified as such in the facility’s State or local air permit
in order to qualify for an exemption.  We also added language to exclude
other emergency equipment.  See Section III.D of this preamble for the
response to the comments on exclusion of emergency generators from 40
CFR part 98, subparts C and D.  See the comment response document for
subpart“Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to
Public Comments, Subpart A: Definitions, Incorporation by Reference, and
Other Subpart A Comments” for responses to comments on definitions,
including changes to the emergency generator definition and the addition
of a definition for emergency equipment.

Comment:  Multiple commenters asked EPA to institute a “de minimis”
provision in the rule to exclude stationary combustion sources other
than the largest units at a facility. 

Response:  The final rule contains no de minimis exclusions.  However,
to simplify reporting, the rule allows small units to be aggregated and
reported as a single emissions value, if certain conditions apply.  The
final rule has expanded the availability of this provision.  The
proposed rule limited the aggregation of any one group to a combined
maximum capacity of 250 mmBtu/hour heat input.  The final rule removes
this limit and allows grouping of any units that individually are less
than 250 mmBtu/hour heat input.  EPA has also clarified the use of the
common pipe metering option, so that all stationary combustion units at
a facility using the same fuel that is metered through a common supply
line may report a single emissions value under this rule.  In addition,
the changes listed above in Section III.C.2 of this preamble will
simplify emissions calculations for many combustion units.

Method for Calculating GHG Emissions

Comment:  EPA received numerous comments on the proposed GHG calculation
methods for stationary combustion sources.  Most of the comments
centered on the use of the four-tiered approach for calculating CO2
emissions.  Several commenters requested that EPA remove the 250
mmBtu/hr unit size restriction on the use of Tier 1 and 2 calculation
methods, especially for the combustion of relatively homogeneous fuels
such as natural gas and fuel oil.  Objections were raised to the
specified frequency of fuel sampling under Tiers 2 and 3, as being
excessive and unnecessary.  Two commenters recommended that annual
sampling be allowed for natural gas and fuel oil.  A number of
commenters asked the Agency to allow averaging of fuel sampling results
(to simplify the CO2 emissions calculations) and to affirm that the use
of fuel sampling results provided by the fuel supplier is permissible. 
Others sought confirmation that fuel billing meters could be used to
quantify fuel usage.  Multiple commenters asked EPA to clarify who must
use the Tier 4 calculation method, which requires the use of continuous
emission monitoring systems (CEMS) to measure stack gas flow rate and
CO2 concentration.  A number of comments were received requesting that
sources currently monitoring and reporting heat input data under 40 CFR
Part 75, but not reporting CO2 mass emissions, be allowed to implement
established Part 75 CO2 emissions calculation methods in lieu of using
Tiers 1 through 4.  Finally, EPA received diverse comments on the
proposed calculation method for CH4 and N2O emissions.  Several
commenters recommended that these emissions either not be reported at
all, or that emissions reporting should be excluded for certain fuel
types.  Others asked for flexibility in determining the appropriate
emission factors for CH4 and N2O.  Some suggested that the use of
operator-defined emission factors or factors from other GHG registries
should be allowed.         

Response:  The final rule significantly expands the use of Tier 1 and
Tier 2 calculation methodologies.  All units rated at 250 mmBtu/hr or
less are allowed to use the Tier 1 or Tier 2 calculation methodologies,
depending on fuel sampling provisions at either the facility or by the
supplier of the fuel.  In addition, units rated at over 250 mmBtu/hr
that combust pipeline quality natural gas and distillate oil are allowed
to use the Tier 2 calculation methodology, because of the homogeneous
nature and low variability in the characteristics of these fuels. 
However, the 250 mmBtu/hr unit size cutoff remains for units that
combust residual oil, other gaseous fuels, and solid fossil fuel.

The mandatory monthly fuel sampling and analysis requirements for
traditional fossil fuels have been dropped from Tiers 2 and 3.  EPA
agrees with the commenters that for a homogeneous fuel such as pipeline
natural gas, monthly sampling is not necessary.  Therefore, 40 CFR 98.34
has been revised to require that natural gas be sampled semiannually. 
For other fuels such as oil and coal, which are delivered in shipments
or lots, requiring monthly sampling may be impractical, because new fuel
lots or deliveries may not be received on a monthly basis.  For fuel oil
and coal, a representative sample is required for each fuel lot, i.e.,
for each shipment or delivery.  For other liquid fuels and biogas,
quarterly sampling is required.  For solid fuels other than coal,
excluding municipal solid wasteMSW, weekly composite sampling with
monthly analysis is required.  For gaseous fuels other than natural gas
and biogas, the daily sampling requirement has been retained, but only
for facilities with existing equipment in place that is capable of
providing the data.  Otherwise, weekly sampling is required if such
equipment for daily sampling is not installed.   

The final rule clarifies that fuel sampling and analysis data provided
by the supplier may be used in the emission calculations, and that fuel
billing meters may be used to quantify fuel consumption.  To simplify
the emission calculations in Tiers 2 and 3, arithmetic averaging of
HHVhigher heating value  and carbon content data over the reporting year
is permitted if these data are collected less frequently than monthly
(see Equation C-2b in 40 CFR 98.33).  However, regardless of the
sampling frequency required by the rule, reporters must use the results
of all available valid fuel analyses in the emissions calculations.    

Today’s rule clarifies the applicability of the Tier 4 methodology. 
Many commenters were unsure whether only one or all six of the
conditions listed in proposed 40 CFR 98.33(b)(4)(ii) and all three of
the conditions listed in proposed 40 CFR 98.33(b)(4)(iii) must be met to
trigger the requirement to use CEMS.  EPA’s intent has always been
that a source must meet all conditions listed in those sections to
require the use of Tier 4.  This has been made clear in the final rule
text.  

The final rule adds two alternative methods that can be used as an
alternativealternatives to any of the four tier calculation methods. 
These alternative methods apply to sources that are currently required
to monitor and report heat input data according to 40 CFR part 75, but
are not required to report CO2 mass emissions.  Many units subject to
the Clean Air Interstate Regulation (CAIR) are in this category.  These
alternative methods allow these sources to use their 40 CFR part 75 heat
input data together with one of the CO2 emissions calculation
methodologies in part 75 to meet 40 CFR part 98 CO2 emissions reporting
requirements.  For instance, sources monitoring hourly heat input
according to Appendix D of 40 CFR part 75 may use Equation G-4 in
Appendix G of 40 CFR part 75 to calculate CO2 emissions.  Similarly, low
mass emitting sources monitoring heat input under 40 CFR 75.19 may use
Equation LM-11 in 40 CFR 75.19 to calculate CO2 emissions.  Sources
using 40 CFR part 75 flow rate and CO2 CEMS to continuously monitor heat
input may use the CEMS measurements together with an appropriate
equation from Appendix F of 40 CFR part 75 to determine CO2 mass
emissions.   

The methodology for calculating CH4 and N2O emissions has been clarified
in the final rule.  Reporting of these emissions is required only for
the fuels listed in Table C-2 of 40 CFR part 98, subpart C.  Further,
reporting of CH4 and N2O emissions is required only for units that are
required to report CO2 emissions under 40 CFR part 98, subpart C and
only for fuels for which default emission factors are provided in
subpart C.  The emission factors in Table C-2 of 40 CFR part 98, subpart
C are both fuel-specific and heat input-based.  Therefore, when more
than one type of fuel is combusted in a unit, direct measurements or
engineering estimates of the annual heat input from each fuel are needed
to calculate the CH4 and N2O emissions.  Consequently, when CEMS (which
are not fuel-specific) are used to monitor the CO2 emissions and heat
input for a multi-fuel unit, the total heat input measured by the CEMS
must be apportioned to each fuel type.  The owner or operator should use
the best available information (e.g., fuel feed rates, high heat values)
to do the necessary heat input apportionment.  To provide greater
consistency in reporting, EPA has chosen to retain the requirements for
using the default factors in Table C-2 of 40 CFR part 98, subpart C,
rather than allow reporters to select their own emission factors. 

Procedures for Estimating Missing Data

Comment:  EPA received several requests to modify the proposed missing
data substitution procedures in 40 CFR part 98, subpart C.  One
commenter recommended that a minimum data capture requirement should be
specified rather than requiring the use of substitute data to fill in
missing data gaps.  Another commenter suggested that only the
“before” value be used for data substitution, rather than the
average of the quality-assured values before and after the missing data
period.  Others favored using emission factors or the “best available
estimates” for all parameters, rather than following a prescriptive
missing data algorithm.  Finally, several commenters asserted that 40
CFO part 75 missing data procedures for CO2 are too conservative (i.e.,
may overestimate emissions significantly) and seem to be contrary to the
objectives of 40 CFR part 98.

Response:  The final rule provides additional flexibility to the missing
data provisions of 40 CFR part 98, subpart C.  The rule requires the use
of “before and after” average values for only three parameters (fuel
HHV, carbon content, and molecular weight).  If the “after” value is
not yet available when the GHG emissions report is due, the “before”
value may be used for missing data substitution.  For all other
parameters, the reporter can substitute data values that are based on
the best available estimates, based on all available process
information.  

EPA does not agree with the commenters who believe that the 40 CFR part
75 CO2 missing data procedures are too conservative and contrary to 40
CFR part 98 program objectives.  Nearly all 40 CFR part 75 sources
maintain very high monitor data availability (95% percent or better) and
use very little substitute data.  Only when the data availability drops
below 80% percent (which very seldom occurs) are the substitute data
values significantly higher than the true CO2 concentrations. 
Therefore, sources that monitor CO2 emissions according to 40 CFR part
75 should continue to use the standard part 75 missing data provisions,
and no adjustments to those substitute data values are deemed necessary
for 40 CFR part 98 reporting purposes.       

Data Reporting Requirements

Comment:  A number of commenters objected to the amount of unit-level
data and emissions verification information that is required to be
reported electronically under 40 CFR 98.36 as “burdensome”,
“unnecessary,” and “excessive”..”  The commenters recommended
that the auxiliary information should instead be kept on file and made
available to EPA upon request.  Several commenters recommended that EPA
remove the 250 mmBtu/hr limit on the cumulative heat input capacity of
units that can be aggregated into groups for reporting purposes.  Other
commenters asserted that EPA should consider the 40 CFR part 75
emissions data submitted under the Acid Rain ProgramARP to be sufficient
to satisfy 40 CFR part 98 requirements, and that there is no need to
submit the same data twice.        

Response:  EPA does not agree with the assertion that the amount of
unit-level data to be reported is excessive, burdensome, or unnecessary.
 For this mandatory GHG emissions reporting rule, two approaches to
emissions data verification were considered, EPA verification and
third-party verification.  The Agency decided on EPA emissions
verification.  To verify GHG emissions estimates, EPA needs supporting
data that are reported at the same level as the emissions are
calculated.  Because the rule requires that emissions be calculated at
the unit level, it is imperative for EPA to obtain unit level
verification data, particularly given the variety of requirements for
estimating fuel combustion emissions under 40 CFR part 98, subpart C. 
Subpart C provides four different methods of estimating CO2 emissions. 
The four methods require measurement of different parameters to estimate
emissions, and the use of the methods is conditioned on a variety of
operating factors.  In addition, facilities use fuel combustion units of
a variety of different sizes, types, and fuel firing scenarios.  Under
these circumstances, EPA could not verify that the correct methods were
selected or applied correctly without unit-level data.  If unit-level
data were not submitted or were aggregated at a gross level, EPA could
not reasonably verify the accuracy of reported facility-wide GHG
emissions data, because EPA could not evaluate the relationship between
unit capacity, fuel characteristics, fuel consumption, and emissions. 
However, as explained below, in the final rule EPA has made a number of
significant adjustments to the data reporting requirements to clarify
requirements and to reduce the reporting burden. 

First, for units that use Tiers 1, 2 and 3 to calculate CO2 mass
emissions, the cumulative 250 mmBtu/hr heat input capacity limit on the
aggregation of units into groups has been dropped.  Rather, the 250
mmBtu/hr restriction applies only to the individual units in a group. 
Therefore, for reporting purposes, individual units with maximum rated
heat input capacities of 250 mmBtu/hr or less may be aggregated without
limit into a single group, provided that the Tier 4 methodology is not
required for any of the units, and all units in the group use the same
calculation methodology for any common fuels that they combust.  Units
with maximum rated heat inputs greater than 250 mmBtu/hr using Tiers 1,
2, and 3 must report as individual units, unless they burn the same type
of fuel and the fuel is provided by a common pipe or supply line.  In
that case, the owner or operator may opt to aggregate emission for all
units fed by the common fuel line.  Units using Tier 4 must report as
individual units unless they share a monitored common stack.

Second, the rule requires minimal data to be reported for units that
monitor and report emissions and heat input data according to 40 CFR
part 75.  This includes Units that meet these criteria include units
that are subject to the ARP, and potentially units that are subject to
CAIR, and other programs.  The final rule clarifies that 40 CFR part 75
sources must report 40 CFR part 98 GHG emissions data under the exact
same unit, stack, or pipe ID numbers that are used for electronic
reporting in the part 75 programs (e.g., 1, 2, CT5, CS001, MS1A, CP001,
etc.).  Even though most 40 CFR part 75 sources report CO2 mass
emissions data to EPA year-round, these data alone are not sufficient to
satisfy the Part 98 reporting requirements for the following reasons. 
The emissions reports required under 40 CFR part 98 are facility-wide
reports that require GHG emissions from all stationary combustion units
at the facility, whether or not the units are subject to a 40 CFR part
75 program.  Many electricity generating facilities have both ARP units
and non-ARP units on site.  Further, the CO2 emissions data reported
under 40 CFR part 75 are in units of short tons; Part 98 requires
reporting in metric tons.  Finally, 40 CFR part 98 also requires CH4 and
N2O emissions to be reported, neither of which are reported under any 40
CFR part 75 program.

Third, the required verification data have been clarified and, in some
cases, differ substantively from the proposed rule.  No additional
verification information is required for sources that monitor and report
emissions and heat input data using 40 CFR part 75.  This includes
sources that elect to use the new alternative calculation methodologies
for units monitoring heat input year round according to 40 CFR part 75
programs.  For sources using Tiers 1, 2, 3, and 4, the final rule
streamlines some of the reporting.  Sources using Tier 3 are required to
report only monthly averages of fuel carbon content and molecular weight
rather than the proposed requirement to submit the results of each
individual determination.  Sources that use Tier 4 are required to
report quarterly cumulative CO2 mass emissions, rather than daily CO2
emissions, as proposed.  Also, to address concerns raised by some of the
commenters, certain data elements need only be retained on file and
provided to EPA upon request.  These data elements include the methods
used for fuel sampling and analysis, the methods used to calibrate fuel
flow meters, the dates and results of fuel flow meter calibrations, and
the dates and results of CEMS certification tests and on-going quality
assuranceQA tests of the CEMS.

D.  Electricity Generation 

1.  Summary of the Final Rule 

Source Category Definition.  This source category consists of EGUs that
are subject to the ARP and any other EGUs that are required to monitor
and report to EPA CO2 mass emissions year-round according to 40 CFR part
75.  All other EGUs are part of the general stationary fuel combustion
source category and report under 40 CFR part 98 subpart C, if the
facility meets the reporting rule applicability criteria.  This source
category excludes portable equipment, emergency generators, and
emergency equipment. 

Reporters must submit annual GHG reports for facilities that meet the
applicability criteria in the General Provisions (40 CFR 98.2)
summarized in Section II.A of this preamble.

GHGs to Report.  Report annual CO2, N2O, and CH4 mass emissions from
each EGU. 

GHG Emissions Calculation and Monitoring.  For EGUs subject to the ARP
and other EGUs that are required to montitor monitor and report to EPA
CO2 mass emissions year-round according to 40 CFR part 75, the reporter
must continue to monitor CO2 emissions according to 40 CFR part 75.  The
cumulative CO2 mass emissions reported in the fourth quarter electronic
data reports must be converted from short tons to metric tons, for 40
CFR part 98 reporting purposes.  The N2O and CH4 emissions must be
calculated using fuel-specific default emission factors and heat input
measurements in accordance with 40 CFR 98.33(c) in subpart C (General
Stationary Fuel Combustion Sources).

Data Reporting.  In addition to the information required to be reported
by the General Provisions (40 CFR 98.3(c)) and summarized in Section
II.A of this preamble, reporters must submit unit-level data and other
information that are used to verify the reported GHG emissions.  The
additional data and information to be reported for this source category
are specified in 40 CFR 98.46.

Recordkeeping.  In addition to the records required by the General
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this
preamble, reporters must keep records of additional data used to
calculate GHG emissions.  The specific records that must be retained for
this source category are identified in 40 CFR 98.47.

2.  Summary of Major Changes Since Proposal 

The major changes since proposal are identified in the following list. 
The rationale for these and any other significant changes can be found
below or in the comment response document for“Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to Public Comments, Subpart D:
Electricity Generation.”

The source category has been more precisely defined and includes only
EGUs subject to the ARP and any other EGUs that are required to monitor
and report to EPA CO2 mass emissions year-round according to 40 CFR part
75.

The proposed emergency generator exclusion language no longer requires
that emergency generators be identified as such in State or local air
permits.

A CO2 calculation methology was provided for units that are not in the
ARP, but report CO2 mass emissions year-round using 40 CFR part 75
methodologies.

3.  Summary of Comments and Responses 

Definition of Source Category

Comment:  Several commenters were concerned that covering non-ARP EGUs
in both subparts C and D of proposed 40 CFR part 98 was confusing and
repetitive.  Several commenters stated that the definition of an EGU is
too inclusive and recommended that EPA revise it.  The commenters were
concerned that any unit, regardless of electrical output, could be
identified as an EGU and place a facility in the electricity generation
source category.  One commenter suggested that a 25 megawatts (MW)
threshold should be added to the EGU definition in 40 CFR 98.6 and to 40
CFR part 98, subpart D.  A multitude of commenters objected to the
language in proposed 40 CFR 98.40 requiring emergency generators to be
designated as such in a State or local air permit, in order for the
generators to be exempted from GHG emissions reporting.  Many of these
same commenters recommended changes to the definition of “emergency
generator” in 40 CFR 98.6, suggesting that the term “generator”
should be replaced with the term “reciprocating internal combustion
engine (RICE)”, to be consistent with 40 CFR 63.6675, subpart ZZZZ.
Others recommended that EPA should also exempt emergency equipment such
as fire pumps, fans, etc. from GHG emissions reporting. 

Response: The electricity generation source category definition in
subpart D (40 CFR 98.40) has been modified based on the comments
received.  The final rule limits the source category to EGUs that are
subject to ARP and to other EGUs that monitor and report to EPA CO2 mass
emissions year-round according to 40 CFR part 75.  The final subpart D
does not cover any other EGUs.  The GHG emissions from other EGUs are
covered under subpart C (General Stationary Fuel Combustion). 

The definition of an “emergency generator” in 40 CFR 98.6, the final
rule has been changed to clarify that it includes both reciprocating
internal combustion enginesRICE and turbines.  EPA has also added a
definition of “emergency equipment” to 40 CFR 98.6, and exempts such
equipment from GHG emissions reporting under both 40 CFR part 98,
subparts C and D. 

The proposed requirements in 40 CFR part 98, subparts C and D for
emergency generators to be identified as such in State and local air
permits in order to be exempt from GHG emissions reporting has been
revised.  There is considerable variation from State to State regarding
the regulation of emergency generators, including whether or not permits
are required.  Some States specifically exempt emergency generators from
permitting requirements.  Other statesStates use a permit by rule
approach for emergency units.  In view of this, the Agency has revised
the wording of the exclusion for emergency generators to allow for
situations where they are not specifically identified in a facility’s
permit. 

Method for Calculating GHG Emissions

Comment: Several commenters suggested that for units that are not in the
Acid Rain ProgramARP but are required by other regulatory programs to
report Partpart 75 emissions and heat input data, EPA should expand the
four-tiered calculation method for CO2 mass emissions in §40 CFR
98.33(a) to allow the use of CO2 emissions calculation methods based on
Appendices D and G of Partpart 75.

Response: The electricity generation source category definition has been
narrowed to only include EGUs that are subject to ARP and to other EGUs
that monitor and report to EPA CO2 mass emissions year-round according
to 40 CFR part 75 (e.g., RGGI units).  The final subpart D provides a
CO2 calculation methodology for such EGUs that are not in the ARP, but
report to EPA CO2 mass emissions year-round using part 75 methodologies.
 For the purposes of part 98, the CO2 emissions from these units are
calculated and reported using the same methods as part 75.

Other units that are not in the ARP but report data under part 75,
subpart C are now covered by 40 CFR part 98, subpart C instead of
subpart D, and subpart C has been revised to allow the use of part 75
calculation methodologies.  The response to the comment on these units
is contained in Section III.C of this preamble (General Stationary Fuel
Combustion Sources).

E.  Adipic Acid Production 

1.  Summary of the Final Rule 

Source Category Definition.  The adipic acid production source category
consists of all processes that use oxidation to produce adipic acid. 

Reporters must submit annual GHG reports for facilities that meet the
applicability criteria in the General Provisions (40 CFR 98.2)
summarized in Section II.A of this preamble.

GHGs to Report.  Report N2O process emissions from adipic acid
production. 

In addition, report GHG emissions for other source categories at the
facility for which calculation methods are provided in the rule, as
applicable.  For example, report CO2, N2O, and CH4 emissions from each
stationary combustion unit on site under 40 CFR part 98, subpart C
(General Stationary Fuel Combustion Sources). 

GHG Emissions Calculation and Monitoring.  CalculateUnless an
alternative method of determining N2O emissions is requested, calculate
N2O process emissions from adipic acid production by multiplying a
facility-specific emission factor by the annual adipic acid production
level.  Determine the facility-specific emission factor by an annual
performance test to measure N2O emissions from the waste gas stream of
each oxidation process and the production rate recorded during the test.

When N2O abatement devices (such as nonselective catalytic reduction)
are used, adjust the N2O process emissions for the amount of N2O removed
using athe destruction factor efficiency for the control device and the
fraction of annual production for which the control device is operating.
 The destruction factor is the destruction efficiency can be specified
by the abatement device manufacturer.  This fact or can also be
determined using process knowledge or another performance test.

Data Reporting.  In addition to the information required to be reported
by the General Provisions (40 CFR 98.3(c)) and summarized in Section
II.A of this preamble, reporters must submit additional data that are
used to calculate GHG emissions.  A list of the specific data to be
reported for this source category is contained in 40 CFR part 98,
subpart E.

Recordkeeping.  In addition to the records required by the General
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this
preamble, reporters must keep records of additional data used to
calculate GHG emissions.  A list of specific records that must be
retained for this source category is included in 40 CFR part 98, subpart
E.

2.  Summary of Major Changes Since Proposal

The major changes since proposal are identified in the following list. 
The rationale for these and any other significant changes can be found
belowin this section or in the comment response document for“Mandatory
Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments,
Subpart E: Adipic Acid Production.”

The re-testing trigger was eliminated.changed.  Performance testing is
only required annually to determine the N2O emissions factor is required
annually, whenever the ratio of cyclohexanone to cyclohexanol is
changed, and when new abatement equipment is installed.

Equation E-2 was edited to correct a calculation error and to allow
multiple types of abatement technologies. 

40 CFR 98.56 was reorganized and updated to improve the data reporting
requirements as needed for the emissions verification process.  Some
data elements were moved from section40 CFR 98.57 to section40 CFR
98.56, and some data elements that a reporter must already use to
calculate GHGs as specified in section40 CFR 98.53 were added to
section40 CFR 98.56 for clarity.

3.  Summary of Comments and Responses 

This section contains a brief summary of major comments and responses. 
Several comments on adipic acid production were received covering
numerous topics.  Responses to significant comments received can be
found in the comment response document for adipic acid production in the
docket (EPA-HQ-OAR-2008-508-XXX).Responses to significant comments
received can be found in “Mandatory Greenhouse Gas Reporting Rule:
EPA’s Response to Public Comments, Subpart E: Adipic Acid
Production.”

GHGs to report 

Comment:  Multiple commenters asked that the language in section40 CFR
98.52(b) be clarified to include emissions under 40 CFR part 98, subpart
E only from units that are 100% percent dedicated to adipic acid
production to avoid double counting of combustion emissions. 

Response:  We reviewed this issue but decided not to make any changes to
40 CFR part 98, subpart E.  We do not foresee a potential for double
counting of combustion emissions at the facility because all combustion
unit emissions at adipic acid facilities are to be reported under 40 CFR
part 98, subpart C.  Subpart40 CFR part 98, subpart E provides methods
for reporting only the process N2O emissions.  Also see Section III.C of
this preamble for responses to comments related to Subpart40 CFR part
98, subpart C (General Stationary Combustion). 

Selection of Proposed GHG Emissions Calculations and Monitoring Methods

Comment:  One commenter stated that emissions of N2O do not correlate
with the production of adipic acid at their facility.  A portion of the
process off gas, which contains N2O, is sold to an offsite facility via
dedicated piping.  The amount sold depends on customer needs and the
amount is metered.  The commenter asked that the language in the final
rule address this issue. 

Response:  We agree that any N2O emitted from the production of adipic
acid that is sold or transferred offsite shouldis not covered in the
proposed rule.  The final rule has been changed to require this amount
of N2O to be reported.  Allowing for this additional reporting
requirement ensures that the reported N2O emissions attributed to the
adipic acid facility are accurate.  Reporting of the N2O sold or
transferred offsite will help EPA improve methodologies for reporting of
GHG emissions. 

Method for Calculating GHG Emissions

Comment:  Multiple commenters asked that the requirement to repeat the
annual performance test be removed.  In the proposal, re-testing was
triggered whenever the adipic acid production rate changed by more than
10 percent.  Commenters asserted that production depends on demand for
adipic acid and often varies by 15 percent.

Response:  Upon review, we decided to eliminate re-testing.  We believe
that annual determination of the N2O emissions factor is sufficient to
accurately calculate N2O emissions as long as the production equipment 
remains consistent over the year-long period (i.e. no new abatement
technology).

Comment:  Multiple commenters asked that alternative methods be allowed
for calculating N2O emissions from adipic acid production.  Specifically
the commenters asked that EPA allow the use of N2O and flow CEMS to
directly measure N2O emissions and use the performance test to evaluate
the CEMS accuracy.  The commenters also asked that EPA allow the use of
existing process flow meters and process N2O analyzers to determine the
amount of N2O sent to control devices and use the performance test to
measure control device destruction efficiency.

Response:  We agree that there are other means of determining
site-specific N2O emissions.  The final rule has been changed to allow
alternative test methods.  Any alternative must be approved by the
Administrator before being used to comply with this rule.  An
implementation plan that details how the alternative method will be
implemented must be included in the request for the alternative method.
Until the method is approved facilities must use the alternatives
proposed in the rule for a performance test.  As one commenter noted, at
minimum the performance test will help to QA/QC alternative methods
currently used to monitor N2O emissions (such as N2O CEMS).

EPA understands the need to further evaluate and establish alternative
comparable methods for sources to use in accurately calculating N2O
emissions from adipic production and will address in future rulemakings
or amendments to rulemaking.  

The final rule does allow the use of existing process flow meters and
process knowledge in the determination of parameters used in the
calculation of N2O emissions, such as the destruction factor of N2O
abatement technologies.  These parameters are This parameter is often
based on site-specific knowledge and operations.  We believe that using
existing methods can also reduce the potential cost impacts of this
rulemaking and that it is in the best interest of the facilities that
production rates and destruction factors process parameters be
accurately measured.  

Comment:  One commenter asked that Equation E-2 be edited to follow the
summation format used in the IPCC Tier 2 methodology.  The current
format does not allow for multiple abatement technologies (including no
abatement).

Response:  We agree with the commenter.  The equation in the proposed
rule contained an error and did not allow for multiple abatement
technologies.  The final rule contains a corrected version of the
equation.

F.  Aluminum Production

1.  Summary of the Final Rule 

Source Category Definition.  The aluminum production source category
consists of facilities that manufacture primary aluminum using the
Hall-Héroult manufacturing process.  The primary aluminum manufacturing
process consists of the following operations:

Electrolysis in prebake and Søderberg cells.

Anode baking for prebake cells.

Reporters must submit annual GHG reports for facilities that meet the
applicability criteria in the General Provisions (40 CFR 98.2)
summarized in Section II.A of this preamble.

GHGs to Report.  For aluminum production, report:

Perfluoromethane (CF4) emissions and perfluoroethane (C2F6) emissions
from anode effects in all prebake and Søderberg electrolysis cells
combined.

CO2 emissions from anode consumption during electrolysis in all prebake
and Søderberg cells.

All CO2 emissions from anode baking.

In addition, report GHG emissions for other source categories at the
facility for which calculation methods are provided in the rule, as
applicable.  For example, report CO2, N2O, and CH4 emissions from each
stationary combustion unit on site under 40 CFR part 98, subpart C
(General Stationary Fuel Combustion Sources).  

GHG Emissions Calculation and Monitoring.  Reporters  must calculate
process emissions using the following methods:

CF4 from anode effects:  Calculate annual CF4 emissions based on the
frequency and duration of anode effects in the aluminum electrolytic
reduction process for each prebake and Søderberg electrolysis cell
using the following parameters:

Anode effect minutes (AEM) per cell-day calculated monthly.

Aluminum metal production calculated monthly.

A slope coefficient relating CF4 emissions to anode effect minutes per
cell-day and aluminum production.  The slope coefficient is specific to
each smelter and must be measured in accordance with the protocol
specified in the rule at least once every 10 years.

Facilities are allowed to use historic smelter-specific slope
coefficients for the first three years of reporting under the rule. 
Historic measurements include all those made under the EPAEPA’s
Voluntary Aluminum Industry Partnership or at facilities owned or
operated by companies participating in the Voluntary Aluminum Industry
Partnership.  Facilities without historic measurements are required to
complete measurements by the end of first year of reporting.

Facilities which operate at less than 0.2 anode effect minutes per cell
day or, when overvoltage is recorded, operate with less than 1.4mV
overvoltage, can use either smelter-specific measured slope coefficients
or the technology-specific (Tier 2)default coefficients from Volume III,
Chapter 4, Section 4.4 Metal Industry Emissions of the 2006 IPCC
Guidelines for National Greenhouse Gas Inventories as specified in the
rule.

C2F6 from anode effects: Calculate annual C2F6 emissions from anode
effects from each prebake and Søderberg electrolysis cell using the
calculated CF4 emissions and the mass ratio of C2F6 to CF4 emissions, as
determined during the same test during which the slope coefficient is
determined.

Process CO2 emissions – general approaches.  Most reporters can elect
to calculate and report process CO2 emissions from anode consumption
during electrolysis and from anode baking by either (1) installing and
operating CEMS and following the Tier 4 methodology (in 40 CFR part 98,
subpart C) or (2) using the calculation procedures specified below.

However, if process CO2 emissions from anode consumption during
electrolysis or anode baking are emitted through the same stack as a
combustion unit or process equipment that uses a CEMS and follows Tier 4
methodology to report CO2 emissions, then the CEMS must be used to
measure and report combined CO2 emissions from that stack, instead of
using the calculation procedures specified below.  

CO2 emissions from anode consumption in prebake cells: Calculate annual
CO2 emissions at the facility level using a mass balance equation based
on measurements of the following parameters:

Net prebaked anode consumption rate per metric ton of aluminum metal
produced.

Ash and sulfur contents of the anodes. 

Total mass of aluminum metal produced per year for all prebake cells.  

CO2 emissions from Søderberg cells: Calculate CO2 emissions from paste
consumption in Søderberg cells using a mass balance equation at the
facility level based on the following parameters:

Paste consumption rate per metric ton of aluminum metal produced and the
total mass of aluminum metal produced per year for all Søderberg cells.


Emissions of cyclohexane-soluble matter per metric ton of aluminum
produced.

Binder content of the anode paste.

Sulfur, ash, and hydrogen contents of the coal tar pitch used as the
binder in the anode paste.

Sulfur and ash contents of the calcined coke used in the anode paste.

Carbon in the skimmed dust from the cell, per metric ton of aluminum
produced.

CO2 emissions from anode baking of prebake cells: Calculate CO2
emissions at the facility level separately for pitch volatiles
combustion and for bake furnace packing material.

To calculate CO2 emissions from the pitch volatiles, use a mass balance
equation based on the following parameters:

Initial weight of the green anodes.

Mass of hydrogen in the green anodes.

Mass of the baked anodes.

Mass of waste tar collected.

To calculate CO2 emissions from bake furnace packing material, use a
mass balance equation based on the following parameters:  

Packing coke consumption rate per metric ton of baked anode production. 

Sulfur and ash contents of the packing coke.

The variables used to calculate CO2 emissions from anode and paste
consumption (e.g., sulfur, ash, and hydrogen contents) can be determined
for each facility, or the source can use default values from the 2006
IPCC Guidelines for National Greenhouse Gas Inventories as specified in
40 CFR 98.64.	

Data Reporting.  In addition to the information required to be reported
by the General Provisions (40 CFR 98.3(c)) and summarized in Section
II.A of this preamble, reporters must submit additional data that are
used to calculate GHG emissions.  A list of the specific data to be
reported for this source category is contained in 40 CFR part 98,
subpart F.

Recordkeeping.  In addition to the records required by the General
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this
preamble, reporters must keep records of additional data used to
calculate GHG emissions.  A list of specific records that must be
retained for this source category is included in 40 CFR part 98, subpart
F.

2.  Summary of Major Changes Since Proposal

The major changes since proposal are identified in the following list. 
The rationale for these and any other significant changes can be found
below or in the comment response document for“Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to Public Comments, Subpart F: Aluminum
Production.”

A new subsection was added in 40 CFR 98.63 providing a new equation (Eq.
F-1) to sum monthly PFC emission values into annual PFC emission value.

The equation for CO2 emissions from Søderberg cells (paste consumption)
was corrected.

Language was updated to request reporting of all CO2 emissions from
on-site anode baking. 

Language was updated to request reporting of smelter-specific slope
coefficients (plural).

A new equation was added in §40 CFR 98.63 (Eq. F-3) to calculate CF4
emissions from overvoltage; and updated language in subsequent sections
to accommodate the overvoltage method.

Language was added to permit facilities that operate with low anode
effect minutes or low overvoltages to use IPCC Tier 2 default slope
factors.

3.  Summary of Comments and Responses 

This section contains a brief summary of major comments and responses. 
Three comments on aluminum production were received covering numerous
topics.  Responses to significant comments received can be found in the
comment response document for aluminum production in the docket
(EPA-HQ-OAR-2008-0508-0005).Responses to significant comments received
can be found in “Mandatory Greenhouse Gas Reporting Rule: EPA’s
Response to Public Comments, Subpart F: Aluminum Production.”

Comment:  Several commenters suggested that smelters should be permitted
to use International AluminiumAluminum Institute default slope
coefficients which are based on global technology-specific averages to
calculate PFC emissions, especially at high performance facilities.

Response:  The use of smelter-specific slope coefficients as required in
the rule leads to significantly more precise PFC emission calculations
than the use of default slope coefficients (95% percent confidence
interval of ±15 compared to ±50 percent).  For a typical U.S. smelter
emitting 175,000 metric tons of CO2-eq in PFCs, these errors result in
absolute uncertainties of ±88,000 MTCO2e and ±26,000 MTCO2e,
respectively.  The reduction in uncertainty associated with moving from
default to smelter-specific slope coefficients, 62,000 MTCO2e, is as
large as the emissions from many of the sources that would be subject to
the rule.  However, for “high performance” facilities, which are
defined by the 2006 IPCC Guidelines as those at or below 0.2 anode
effect minutes per cell day or less than 1.4 mV overvoltage, the IPCC
analysis indicates that impact of moving from a Tier 2 to a Tier 3 slope
coefficient would not result in a significant improvement in PFC
emissions.  Therefore, EPA agrees that high performance facilities
should be allowed to use technology specific (Tier 2) default values
from Volume III, Chapter 4, Section 4.4 Metal Industry Emissions of the
2006 IPCC Guidelines for National GrenhouseGreenhouse Gas Inventories. 
These values are identical to the Aluminium“Aluminum Sector Greenhouse
Gas Protocol (Addendum to the WRI/WBCSD Greenhouse Gas Protocol)),”
October, 2006 default coefficients.  

Comment:  Several commenters argued the requirement to re-measure
smelter-specific slope coefficients every 3three years is expensive and
unnecessary.

Response:  While the cost to require smelter-specific slope coefficients
is significantly greater than the cost to use default slope
coefficients, the benefit of reduced uncertainty is considerable, as
noted above.  The costs that would be incurred by smelters measuring
slope factors are discussed in the Regulatory Impact Analysis (RIA) for
thisthe proposed rulemaking (EPA-HQ-OAR-2008-0508-002).

Of the currently operating U.S. smelters, all but one has measured a
smelter specific coefficient at least once; and at least three used the
2003 EPA/IAI protocol for measuring smelter-specific slope coefficients.

The USEPA/IAI Protocol for Measurement of Tetrafluoromethane and
Hexafluoroethane from Primary Aluminum Production establishes guidelines
to ensure that measurements of smelter-specific slope-coefficients are
consistent and accurate (e.g., representative of typical smelter
operating conditions and emission rates). The Protocol currently
recommends that smelter operators re-measure their slope coefficients at
least every three years, and more frequently if they adopt changes to
process control algorithms or observe changes to typical anode effect
duration.  Specifically, the Protocol recommends that operators repeat
measurements of slope coefficients for CF4 and C2F6 if one or more of
the following apply: (1) thirty-six months have passed since the last
measurements (i.e. triennial measurements are recommended); (2) a change
occurs in the control algorithm that affects the mix of types of anode
effects or the nature of the anode effect termination routine; and, (3)
changes occur in the distribution of duration of anode effects (e.g.
when the percentage of manual kills changes or if, over time, the number
of anode effects decreases and results in a fewer number of longer anode
effects).

Changes to process control algorithms or to the typical duration of
anode effects can change the relationship between anode effect minutes,
production, and emissions, that is, they can change slope coefficients. 
In addition, more subtle changes can also change slope coefficients over
time.  According to industry experts, the rate of these more subtle
changes has not been sufficiently studied to specify a frequency for
re-measurement nor have there been a sufficient number of facilities
that have been measured repeatedly to document the benefit of the
additional incremental cost of measurement once every three years.

During the past few years, multiple U.S. smelters have adopted changes
to their production process which are likely to have changed their slope
coefficients. These include the adoption of slotted anodes and
improvements to process control algorithms.  Although some U.S. smelters
have recently updated their measurements of smelter-specific
coefficients, others may not have.

In view of these recent process changes, EPA is requiring smelters that
have not already measured their slope factors under the “2008
USEPA/IAI Protocol for Measurement of Tetrafluoromethane and
Hexafluoroethane from Primary Aluminum Production,” to do so in time
for the 2013 reporting year.  EPA believes that this will ensure that
slope factors are appropriately updated while providing sufficient
lead-time for smelters to perform the measurements without encountering
excessive costs or logistical barriers.  However, after this initial
update, EPA agrees that every three years is burdensome, therefore,
further updates are required only every ten years unless there are major
technological or process changes at a facility such as changes to the
control algorithm that affect the mix of types of anode effects or the
nature of the anode effect termination routine; or changes occur in the
distribution of duration of anode effects (e.g. when the percentage of
manual kills changes or if, over time, the number of anode effects
decreases and results in a fewer number of longer anode effects).

Comment:  Several commenters suggested that the rule should include the
overvoltage measurement method, which is specific to use with Pechiney
technology, in case one or more U.S. smelters decide to adopt this
technology in the future.

Response:  The Overvoltage Method relates PFC emissions to an
overvoltage coefficient, anode effect overvoltage, current efficiency,
and aluminum production. The overvoltage method was developed for
smelters using the Pechiney technology.  While it is EPA’s
understanding that no U.S. smelters have used the Pechiney technology
for at least a decade, if one or more U.S. smelters decide to adopt this
internationally accepted technology in the future they would be expected
to use the overvoltage method which follow the established guidelines in
the “USEPA/IAI Protocol for Measurement of Tetrafluoromethane and
Hexafluoroethane from Primary Aluminum Production.”

G.  Ammonia Manufacturing

1.  Summary of the Final Rule 

Source Category Definition.  The ammonia manufacturing source category
consists of process units in which ammonia is manufactured from a
fossil-based feedstock via steam reforming of the hydrocarbon.  It also
includes ammonia manufacturing processes in which ammonia is
manufactured through the gasification of solid and liquid raw material.

Reporters must submit annual GHG reports for facilities that meet the
applicability criteria in the General Provisions (40 CFR 98.2)
summarized in Section II.A of this preamble.

GHGs to Report.  For ammonia manufacturing, report the following
emissions:

CO2 process emissions from steam reforming of a hydrocarbon or the
gasification of solid and liquid raw material, reported for each ammonia
manufacturing process unit following the requirements of this part.

CO2, CH4, and N2O emissions from each stationary combustion unit. 
Report these emissions under 40 CFR 98, subpart C (General Stationary
Fuel Combustion Sources) by following the requirements of 40 CFR part
98, subpart C.

For CO2 collected and transferred off site, report these emissions under
40 CFR part 98, subpart PP (Suppliers of CO2) following the requirements
of 40 CFR part 98, subpart PP.

In addition, report GHG emissions for any other source categories at the
facility for which calculation methods are provided in other subparts of
the rule, as applicable.

GHG Emissions Calculation and Monitoring.  FacilitiesReporters must use
one of two methods to calculate CO2 process emissions, as appropriate:

Most reporters can elect to calculate and report process CO2 emissions
from each ammonia manufacturing process unit by either (1) installing
and operating CEMS and following the Tier 4 methodology (in 40 CFR part
98, subpart C) or (2) using the calculation procedures contained in the
rule and summarized below.

However, if process CO2 emissions from an ammonia manufacturing process
unit are emitted through the same stack as CO2 emissions from a
combustion unit or process equipment that uses a CEMS and follows Tier 4
methodology to report CO2 emissions, then the CEMS must be used to
measure and report combined emissions from that stack, instead of using
the calculation procedures described below.

To calculate process CO2 emissions, use the equations provided in 40 CFR
part 98, subpart G for solid, liquid, and gaseous feedstock and the
following measurements:

Continuous measurement of gaseous or liquid feedstock consumed using a
flowmeter, or monthly aggregate of solid feedstock consumed.

Carbon content of the feedstock (required to be measured monthly using
supplier data or analysis using the appropriate test methods).  If
supplier data isare used, facilities must QA/QC the supplier analysis on
an annual basis using the appropriate test methods.

Data Reporting.  In addition to the information required to be reported
by the General Provisions (40 CFR 98.3(c)) and summarized in Section
II.A of this preamble, reporters must submit additional data that are
used to calculate GHG emissions.  A list of the specific data to be
reported for this source category is contained in 40 CFR part 98,
subpart G.

Recordkeeping.  In addition to the records required by the General
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this
preamble, reporters must keep records of additional data used to
calculate GHG emissions.  A list of specific records that must be
retained for this source category is included in 40 CFR part 98, subpart
G.

2.  Summary of Major Changes Since Proposal 

The major changes since proposal are identified in the following list. 
The rationale for these and any other significant changes can be found
below or in the comment response document for Ammonia“Mandatory
Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments,
Subpart G: Amonia Manufacturing.”

Monitoring and QA/QC requirements were revised to allow for obtaining
carbon content of feedstock used in ammonia manufacturing from the
feedstock supplier.  Facilities that obtain monthly carbon content
information from their supplier are required to QA/QC supplier
information through annual sampling and analysis of the feedstock.

Missing data procedures were added under section 40 CFR 98.75 for
parameters that facilities must measure such as feedstock consumption,
the quantity of the waste recycle stream, and the monthly carbon content
of both the feedstock consumption and waste recycle stream quantity.

Reporting requirements were added for the quantity of urea produced and
the emissions associated with waste recycle streams commonly found at
ammonia manufacturing facilities.

40 CFR 98.76 was reorganized and updated to improve the emissions data
verification process.  Some data elements were moved from section40 CFR
98.77 to section40 CFR 98.76, and some data elements that a reporter
must already use to calculate GHGs as specified in section40 CFR 98.73
were added to section40 CFR 98.76 for clarity.

3.  Summary of Comments and Responses 

This section contains a brief summary of major comments and responses. 
Several comments on ammonia manufacturing were received covering
numerous topics. Several of these comments were directed at the
requirements for 40 CFR part 98, subpart C (General Stationary Fuel
Combustion Sources in subpart C), and responses to those comments are
provided in theSection III.C of this preamble section III.C.  Responses
to significant comments received can be found in the comment response
document for ammonia manufacturing in the docket
(EPA-HQ-OAR-2008-508-XXX)..  Responses to significant comments received
can be found in “Mandatory Greenhouse Gas Reporting Rule: EPA’s
Response to Public Comments, Subpart G: Ammonia Manufacturing.”

Method for Calculating GHG Emissions

Comment:  Several commenters asked EPA to clarify that ammonia
production units must use Tier 4 calculation only if all of the
conditions under proposed 40 CFR section 98.33(b)(5)(ii)(A) through (F)
apply to the unit and only where the ammonia manufacturing unit already
has installed a stack gas volumetric flow rate monitor and a CO2
concentration monitor.

Response:  We agree with the comment and have modified the text under 40
CFR 98.73(a) and (b) to state that if a facility operates and maintains
CEMS that meet the requirements of §40 CFR 98.33(b)(54)(ii) or (iii),
then process or combined process and combustion CO2 emissions shall be
calculated and reported under this subpart by following the Tier 4
Calculation Methodology specified in §40 CFR 98.33(a)(4) and all
associated requirements for Tier 4 in 40 CFR part 98, subpart C (General
Stationary Fuel Combustion Sources).   If CEMS are not used to determine
CO2 emissions from ammonia processing units, then facilities must
calculate and report process CO2 emissions under this subpart by using
equations provided in section40 CFR 98.73(b)(1) through (b)(4).  CO2
combustion emissions from ammonia processing units must be reported
under 40 CFR part 98, subpart C (General Stationary Fuel Combustion
Sources).  For additional clarification on the requirements on use of
CEMS see 40 CFR part 98, subpart C (General Stationary Fuel Combustion
Sources in subpart C), and Section III.C of this preamble. 

Comment:  One commenter noted that most ammonia facilities utilize
natural gas combustion combined with approximately 5five percent recycle
flow of gas containing methane from the process.  The carbon content of
the recycle stream is already accounted for when measuring the feedstock
flow rate and carbon content to the process.  EPA should allow ammonia
manufacturers to exclude this recycle stream in calculating combustion
emissions, as the carbon in the recycle stream would be double counted.

Response:  We agreed with commenters that it is important to account for
use of the waste process stream in the case that it is recycled since
carbon in the recycle stream isn'tis not actually emitted.  In response
to this comment we have added reporting requirements for quantifying
emissions associated with the recycle stream.  This will help EPA
improve methodologies for calculating emissions from ammonia
manufacturing in the future. 

Monitoring and QA/QC Requirements

Comment:  Several commenters stated that monthly carbon content sampling
and analysis requirement is overly burdensome.  Some commenters asked
that EPA allow the use of a default value for carbon content while one
commenter suggested use of carbon content data generated by the
feedstock supplier.

Response:  We agreed with commenters that flexibility should be added to
the rule to allow for use of supplier data. This information is readily
available from the feedstock supplier in most cases.  The most common
feedstock for ammonia production is pipeline quality natural gas.
Supplier data on carbon contents of feedstock will have sufficient or
comparable accuracy for the purposes of calculating CO2 emissions.  We
modified the monitoring and QA/QC procedures in the rule to allow use of
carbon content data obtained from the feedstock supplier(s).  Facilities
that obtain monthly carbon content information from their supplier are
required to QA/QC supplier information through annual sampling and
analysis of the feedstocks consumed.  

Procedures for Missing Data

Comment:  Two commenters suggested that the proposed procedures for
calculating emissions in the event of missing feedstock data would yield
significant overstatements of GHG emissions.  As proposed, if feedstock
supply rate data isare missing for a specific day or days (e.g., if a
meter malfunctions during unit operation), the reporting entity must use
the lesser of the maximum supply rate that the production unit is
capable of processing or the maximum supply rate that the meter can
measure. If this substitution is applied to the feedstock for reformers
used in ammonia production, either of these proposed approaches would
likely result in significant over reporting of carbon emissions.  The
commenter proposed two alternatives that a reporting facility could use:
either (1) substitute an estimated value for feedstock supply rate,
based on the arithmetic average of the previous thirty days of available
feedstock supply rate data; or (2) utilize missing data estimating
procedures similar to the procedure proposed under §40 CFR 98.35(b)(2),
based upon all available process data.  These approaches would result in
much more accurate estimates of emissions derived from the true
historical operation of a specific ammonia manufacturing source.

Response:  We agreed with commenters that the proposed missing data
procedures would overestimate emissions when applied.  While some of
feedstock should be readily available and collected as a part of normal
business practices, circumstances could arise where data could be
missing.  We added procedures consistent with the commenter’s second
recommendation, referencing the proposed missing data procedures in
98.35(b)(2).  Ammonia facilities with missing data on feedstock supply
rate must provide the best available estimate from all available process
data.  Facilities must document and keep records of missing data
procedures applied.  We find that these revised procedures will provide
accurate information for the purposes of this rulemaking.  

Data to be Reported

Comment:  One commenter noted that the CO2 produced through ammonia
manufacturing can be utilized and that much of it is in the manufacture
of urea.  The commenter stated that EPA makes unsubstantiated
assumptions that all CO2 in urea will be released into the atmosphere.
The commenter asked EPA not to tie emissions from applied urea, or
emissions that result from urea once the product has been sold, to the
producing industry.

Response:  We added reporting requirements for annual urea production
under 40 CFR 98.76.  Information on urea production will help us improve
our understanding of the quantity of CO2 consumed from ammonia
production that is used in the manufacture of urea.  We know from the US
GHG inventory and subsequent conversations with ammonia producers that
on average it takes 0.733 tons of CO2 to produce one ton of urea.  We
have also requested that producers report, if known, the uses of the
urea sold.  Collecting information on urea production and its uses will
help EPA to improve methodologies for calculating emissions from ammonia
manufacturersmanufacturing, urea production, and urea consumption in the
future.  

H.  Cement Production

1.  Summary of the Final Rule 

Source Category Definition.  The cement production source category
consists of each kiln and each inline kiln/raw mill at any Portland
cement manufacturing facility, including alkali bypasses and kilns and
inline kilns/raw mills that burn hazardous waste.

Reporters must submit annual GHG reports for facilities that meet the
applicability criteria in the General Provisions (40 CFR 98.2)
summarized in Section II.A of this preamble.

GHGs to Report.  For cement production, report the following emissions:

CO2 process emissions from calcination, reported for each kiln.

CO2 combustion emissions from each kiln.

N2O, and CH4 emissions from fuel combustion at each kiln under 40 CFR
part 98, subpart C (General Stationary Fuel Combustion Sources) using
the methodologies in subpart C.

CO2, N2O, and CH4 emissions from each stationary combustion unit other
than kilns under 40 CFR part 98, subpart C (General Stationary Fuel
Combustion Sources).

In addition, report GHG emissions for any other source categories for
which calculation methods are provided in other subparts of the rule, as
applicable.

GHG Emissions Calculation and Monitoring.  For CO2 emissions from kilns,
reporters must select one of two methods, as appropriate:

For kilns with certain types of CEMS in place, reporters must use the
CEMS and follow the Tier 4 methodology (in 40 CFR part 98, subpart C) to
measure and report under the Cement Production subpart (40 CFR part 98,
subpart H) combined calcination and fuel combustion CO2 emissions. 

For other kilns, the reporter can elect to either (1) install or operate
a CEMS and follow the Tier 4 methodology to measure and report combined
calcination and fuel combustion CO2 emissions or (2) calculate process
CO2 emissions as the sum of clinker emissions and emissions from raw
materials.  If using approach (2):

Calculate clinker emissions monthly from each kiln using monthly clinker
production (required to be measured); a kiln-specific, monthly clinker
emission factor calculated from the monthly CaO and MgO content of the
clinker (required to be measured); quarterly cement kiln dust not
recycled to the kiln (required to be measured); and a quarterly
kiln-specific fractionfactor of calcined material in the cement kiln
dust not recycled to the kiln (measured or default values can be used). 

Calculate raw material emissions annually from the annual consumption of
raw materials and the organic carbon content in the raw material
(measured annually for each type of raw material, or a default value of
0.2 percent may be used).

Report process CO2 emissions from each kiln under 40 CFR part 98,
subpart H (Cement Production), and report combustion CO2 emissions from
each kiln under 40 CFR part 98, subpart C (General Stationary Fuel
Combustion Sources).

Data Reporting.  In addition to the information required to be reported
by the General Provisions (40 CFR 98.3(c)) and summarized in Section
II.A of this preamble, reporters must submit additional data that are
used to calculate GHG emissions.  A list of the specific data to be
reported for this source category is contained in 40 CFR part 98,
Subpart H (Cement Production).

Recordkeeping.  In addition to the records required by the General
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this
preamble, reporters must keep records of additional data used to
calculate GHG emissions.  A list of specific records that must be
retained for this source category is included in 40 CFR part 98, subpart
H (Cement Production).

2.  Summary of Major Changes Since Proposal 

The major changes since proposal are identified in the following list. 
The rationale for these and any other significant changes can be found
below or in the comment response document for“Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to Public Comments, Subpart H: Cement
Production.”

The CO2CO2 calculation equations in §40 CFR 98.83 were revised to
account for non-carbonate sources of calcium and magnesium in the kiln
feed and uncalcined carbonates in the product.

Methods for monitoring CaO and MgO in clinker and CKD were changed from
XRF to ASTM c114-07, Standard Test Methods for Chemical Analysis of
Hydraulic Cement.

40 CFR 98.84 was revised to clarify required monitoring frequency and to
allow for alternative monitoring methods for raw materials and CKD.

Missing data procedures were added to 40 CFR 98.85 for parameters
reporters must measure, clinker, CKD not recycled to the kiln, raw
material consumption, carbonate contents of clinker and CKD, and
non-calcined content of clinker and CKD, and organic carbon content of
raw materials.

Requirements in sections 40 CFR 98.81 through 40 CFR 98.87 were revised
to clarify which requirements apply to reporters who elect to report CO2
emissions using CEMS. 

40 CFR 98.86 was reorganized and updated to improve the emissions
verification process.  Some data elements were moved from 40 CFR 98.87
to 40 CFR 98.86, and some data elements that a reporter must already use
to calculate GHGs as specified in 40 CFR 98.83 were added to 40 CFR
98.86 for clarity.

3.  Summary of Comments and Responses 

This section contains a brief summary of major comments and responses. 
We received several comments on cement production covering a number of
topics.  Many of these comments were directed at the requirements for 40
CFR part 98, subpart C (General Stationary Fuel Combustion Sources in
subpart C), and responses to those comments are provided in Section
III.C of this preamble dealing with that source category.  Also see
Section II.N of this preamble for the response to comments on the
emissions verification approach.

Responses to significant comments received related to process emissions
from cement production can be found in the comment response document for
cement production in the docket (EPA-HQ-OAR-2008-508-XXX).“Mandatory
Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments,
Subpart H: Cement Production.”

Selection of Threshold

Comment:  One commenter suggested that EPA could reduce the burden
presented by the Proposed Rule by reducing the number of facilities
required to report (i.e., raise the reporting thresholds).  The
commenter further noted that by requiring GHG reporting for all cement
plants, regardless of the magnitude of the plant’s emissions, EPA
removes an incentive for those plants to reduce GHG emissions to get
below a threshold in order to avoid the burden of monitoring and
reporting.

Response:  In considering the comment, we acknowledge the potential
benefit of a reporting threshold providing cement plants with incentive
to reduce their GHG emissions. The “once in, always in” provision
has been removed.  The final rule now contains a provisionprovisions to
cease reporting if annual reports demonstrate emissions less than 25,000
metric tons CO2e per yearspecified levels for 5 consecutivemultiple
years.  This provision appliesThese provisions apply to all reporting
facilities.  See Section II.H of this preamble for the response on
provisions to cease reporting.  See Section II.D of this preamble for
the response on selection of source categories to report.  

In developing the Proposed Rule, we considered emission-based thresholds
of 1,000 metric tons CO2e, 10,000 metric tons CO2e, 25,000 metric tons
CO2e, and 100,000 metric tons CO2e.  All of these emission thresholds
covered more than 99.9 percent of CO2e emissions from cement facilities.
 Only one plant out of 107 in the dataset would be excluded by the
highest considered thresholds of 100,000 metric tons CO2e.  Therefore,
we determined that it was appropriate to include all cement production
facilities in the reporting requirements. 

Method for Calculating GHG Emissions 

Comment:  Two commenters stated that the cement industry already has an
established, proven protocol for calculating and reporting GHG
emissions, and requested that EPA use the existing cementCement CO2
protocolProtocol as the basis for the Proposed Rule.  Commenters further
stated that the cementCement CO2 protocolProtocol already provides many
of the benefits that EPA ascribes to the Proposed Rule, including
uniformity of reported data from one facility to another; availability
of verifiable data to provide to the public, investors, and others; and
other suggested benefits.

Both commenters stated that EPA needs to revise its clinker-based
calculation to account for any non-carbonated CaO or MgO in the raw
materials.

Response:  In developing the proposed Rule, we considered many domestic
and international GHG monitoring guidelines and protocols, including the
Cement Sustainability Initiative Protocol referenced in the cement
industry’s comments.  We combined elements of the cementCement CO2
protocolProtocol with elements of other protocols including the 2006
IPCC Guidelines, U.S. Inventory, DOE 1605(b), CARB mandatory GHG
emissions reporting program, EPA’s Climate Leaders program, and the EU
Emissions Trading System to develop two proposed methods for quantifying
GHG emissions from cement manufacturing.  These proposed methods include
the use of CEMS to directly measure emissions and the use of calculation
methods to determine emissions.

While finalizing today’s rule, we revisited the cementCement CO2
protocolProtocol and compared its requirements to our requirements.  We
feel that the rule closely mirrors the GHG calculation methods and
requirements of the Cement CO2 Protocol with some minor differences. 
For example, our rule requires cement plants to use plant-specific
emission factors to calculate CO2 emissions and does not allow the use
of default emission factors.  As stated in the proposal, we have
determined that applying default emission factors to clinker production
is more appropriate for national-level emissions estimates than
facility-specific estimates, where data are readily available to develop
site-specific emission factors.  Default approaches would not provide
site-specific calculation of emissions that reflect differences in
inputs, operating conditions, fuel combustion efficiency, variability in
fuels, and other differences among facilities.  Further, it is our
understanding that facilities analyze data relevant for site-specific
determinations such as the carbonate contents of their raw materials to
the kiln and products on a frequent basis, either on a daily basis or
every time there is a change in the raw material mix.  Using data from
direct measurements will provide a more accurate representation of site
specific emissions rates.

We also note that the Cement CO2 Protocol does not specify measurement
methods.  Our rule specifies methods for measuring CaO, MgO, and clinker
weight.  We selected these methods to be consistent with measurement
techniques that are common within the cement industry.  Prescribing
standardized measurement procedures ensures the uniformity and
consistency in the results and quality of data reported that the
commenters agree is important for comparability of emissions.

We also used the Cement CO2 Protocol as a model for revising our
equations in 40 CFR 98.83 to account for non-carbonate sources of
calcium and magnesium that may be present in the kiln feed.

Monitoring and QA/QC Requirements

Comment:  One commenter expressed concern that 40 CFR 98.84(e) and (f)
seem to require continuous, direct weight measurement of CKD discarded
and raw materials used, by category of material.  The commenter stated
that most cement plants do not have that capability, and that the
Proposed Ruleproposed rule does not clearly state whether installation
of additional measurement equipment will be required if not already
installed. 

One industry representative further recommended that EPA add truck
weight scales as an acceptable option for raw material weight
measurement to address certain limited cases in which this method may be
more appropriate to use. In addition, the commenter recommended that EPA
allow CKD samples to be taken either as CKD exits the kiln or from bulk
storage. 

Response:  We revised the text in §40 CFR 98.84(e) and (f) to more
clearly state that CKD quantities are required to be measured on a
quarterly basis and raw material quantities are required to be measured
on a monthly basis.  Furthermore, the Proposed Rule was never intended
to require installation of new monitoring equipment for this purpose. 
We agree with the commenter that continuous, direct weight measurement
of these materials and installation of additional measurement equipment
would be unnecessary.  The proposed Rulerule clearly stated that the
quantity of CKD produced and raw materials consumed must be determined
using the same plant instruments that the cement plant currently uses
for accounting purposes.  Moreover, because the quantities of raw
materials and CKD do not greatly impact the CO2 calculation, we added
further clarification to this section to allow cement plants to use
potentially less accurate, but commonly used, methods of measurement,
such as truck weigh scales, to determine quantities of CKD and raw
materials.  We also added clarification to §40 CFR 98.84 to allow
facilities to collect CKD samples either as CKD exits the kiln or from
bulk storage.

Data Reporting Requirements

Comment:  Two commenters asserted that EPA needs to provide clarifying
language within Subpart 40 CFR part 98, subpart H (Cement Production) to
define which requirements apply to facilities using CEMS to monitor CO2
emissions.  One commenter noted that the Proposed Rule, as written,
appears to require cement plants using CEMS to collect maintain, and
report process data related to calculating CO2 process emissions for
kilns pursuant to proposed §40 CFR 98.84- through 98.87.  This
commenter claimed that requiring plants to collect and report such
process data is are redundant if the facility is continuously monitoring
CO2 emissions.  Another commenter recommended that EPA state within
Subpart40 CFR part 98, subpart H (Cement Production) that all of the
requirements detailed in the subpart do not apply to cement kilns using
Tier 4 (CEMS) method.

Response:  We agree with the comment that reporters who are using CEMS
to monitor CO2 do not need to collect, report, and maintain all of the
process data required in proposed 40 CFR 98.84 through 98.87.  However,
we determined that some of the process data are necessary for emissions
verification purposes, and therefore, facilitiesplants using CEMS are
not completely excluded from the requirements in Subpart40 CFR part 98,
subpart H. (Cement Production).  We added clarifying language throughout
the Subpart to clearly state which requirements will apply to facilities
that use CEMS to measure CO2 emissions.  Specifically, we created
separate lists of reporting requirements and recordkeeping requirements
that for cement plants using CEMS.

Comment:  One commenter noted that the data reporting requirements for
cement plants, set forth in proposed 40 CFR 98.86, are expressed in
different terms that those used for the specified procedures for
calculating emissions.  For example, the commenter stated that it is
unclear what emission sources go into the “site-specific emission
factor (metric tons CO2/metric ton clinker produced)” required to be
reported under proposed section §40 CFR 98.86(h), and how that factor
would be calculated. 

Response:  We agree with the commenter that there were inconsistencies
between sections §40 CFR 98.83 and §98.86.  We updated reporting
requirements in §40 CFR 98.86 to be consistent with the terms used in
the emission calculation procedures in §40 CFR 98.83 and provide
clarification in §40 CFR 98.83 for terms if needed.  As a result, some
calculations that are performed on a kiln-specific basis, such as CO2
emission factors, will be required to be reported on a kiln-specific
basis in §40 CFR 98.86.  Also see the Section II.N of this preamble for
the response to comments on the emissions verification approach.

I.  Electronics Manufacturing

At this time EPA is not going final with the electronics manufacturing
subpart.  As we consider next steps, we will be reviewing the public
comments and other relevant information.  

The Agency received a number of lengthy, detailed comments regarding the
electronics manufacturing subpart.  Commenters generally opposed the
proposed reporting requirements and stated the proposal required
excessive detail.  For example, commenters asserted that they currently
do not collect the data required to report using an IPCC Tier 3 approach
and that to collect such data would entail significant burden and
capital costs.  In most cases, commenters provided alternative
approaches to each of the reporting requirements proposed by EPA.

 Commenters also requested clarification from EPA on a number of the
proposed reporting provisions.

Based on careful review of comments received on the proposal preamble,
rule, and technical support documents (TSDs) under proposed 40 CFR part
98, subpart I, EPA will perform additional analysis and evaluate a range
of data collection procedures and methodologies.  EPA’s goal is to
optimize methods of data collection to ensure data accuracy while
considering industry burden.  

J.  Ethanol Production

At this time, EPA is not finalizing the Ethanol Production Subpart.  The
sources of GHG emissions at ethanol production facilities that were to
be reported under the proposed rule were stationary fuel combustion,
onsite landfills, and onsite wastewater treatment.  EPA has decided not
to finalize the portion of 40 CFR part 98, subpart HH (Landfills) that
addresses industrial landfills nor 40 CFR part 98, subpart II
(Wastewater Treatment).  Stationary fuel combustion sources at ethanol
production facilities are subject to the requirements of 40 CFR part 98,
subpart C if general stationary fuel combustion emissions exceed the
25,000 metric tons CO2e threshold. 

 As EPA considers next steps, we will be reviewing the public comments
and other relevant information.  Based on careful review of comments
received on the proposal preamble, rule and technical support
documentsTSDs under proposed 40 CFR part 98, subparts J, HH, and II, EPA
will perform additional analysis and consider alternatives to data
collection procedures and methodologies contained in those subparts.  

K.  Ferroalloy Production

1.  Summary of the Final Rule 

Source Category Definition.  The ferroalloy production source category
consists of facilities that use pyrometallurgical techniques to produce
any of the following metals: ferrochromium, ferromanganese,
ferromolybdenum, ferronickel, ferrosilicon, ferrotitanium,
ferrotungsten, ferrovanadium, silicomanganese, or silicon metal. 

Reporters must submit annual GHG reports for facilities that meet the
applicability criteria in the General Provisions (40 CFR 98.2)
summarized in Section II.A of this preamble.

GHGs to Report.  For ferroalloy production, report the following
emissions. 

Annual process CO2 emissions from each EAF used for production of any
ferroalloy listed in the source category definition.  

Annual process CH4 emissions for those EAFs used for the production of
silicon metal, ferrosilicon 65 percent, ferrosilicon 75 percent, or
ferrosilicon 90 percent.  

CO2, N2O, and CH4 emissions from each stationary combustion unit on site
under 40 CFR part 98, subpart C (General Stationary Fuel Combustion
Sources).  

In addition, report emissions from any other source categories for which
calculation methodologies are specified in the rule, as applicable.

GHG Emissions Calculation and Monitoring.  To calculate process CO2
emissions from EAFs, reporters can use one of two methods, as
appropriate:

Most reporters can elect to calculate and report process CO2 emissions
from each EAF by either (1) installing and operating a CEMS and
following the Tier 4 methodology (in 40 CFR part 98, subpart C) or (2)
using the carbon mass balance calculation procedure specified in the
rule and summarized below.

However, if CO2 process emissions from an EAF are emitted through the
same stack as CO2 emissions from a combustion unit or process equipment
that uses a CEMS and follows Tier 4 methodology to report CO2 emissions,
then the CEMS must be used to measure and report combined emissions from
that stack, instead of using the carbon mass balance calculation
procedure described below.

If using the carbon mass balance procedure, perform a once per year
calculation using equations in the rule and: 

Recorded monthly production data, and 

The average carbon content for each EAF input and output material
determined by either using material supplier information or by annual
analysis of representative samples of the material.

For those EAF’s for which the reporter must report annual CH4
emissions, annual ferroalloy production data are used with an applicable
emissions factor provided in the rule. 

Data Reporting.  In addition to the information required to be reported
by the General Provisions (40 CFR 98.3(c)) and summarized in Section
II.A of this preamble, reporters must submit additional data that are
used to calculate GHG emissions.  A list of the specific data to be
reported for this source category is contained in 40 CFR part 98,
subpart K.

Recordkeeping.  In addition to the records required by the General
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this
preamble, reporters must keep records of additional data used to
calculate GHG emissions.  A list of specific records that must be
retained for this source category is included in 40 CFR part 98, subpart
K.

2.  Summary of Major Changes Since Proposal 

The major changes to the rule since proposal for ferroalloy production
facilities were revisions to the carbon mass balance calculation
procedure for calculating process CO2 emissions from EAFs.  These
changes reduce the reporting burden and are consistent with revisions
made to other similar industries.  The rationale for these and any other
significant changes can be found below or in the comment response
document for“Mandatory Greenhouse Gas Reporting Rule: EPA’s Response
to Public Comments, Subpart K: Ferroalloy Production.  Changes
include:.”  

Frequency of performing the carbon mass balance calculations was revised
to be required on an annual basis instead of the proposed monthly basis.

Frequency of material carbon content sampling and analysis of each EAF
input and output material used for the material balance was revised to
be performed by annual analysis of representative samples of the
material instead of the proposed monthly basis.

Materials contributing less than 1 one percent of the total carbon into
or out of the EAF do not need to be included carbon mass balance
calculations.

40 CFR 98.116 and 98.117 were reorganized and updated to improve the
emissions verification process.  Some data elements were moved from
section40 CFR 98.117 to section40 CFR 98.116, and some data elements
that a reporter must already use to calculate GHG'sGHGs as specified in
section40 CFR 98.173 were added to section40 CFR 98.116 for clarity. 
See the Section II.N of this preamble for the response to comments on
the emissions verification approach.

3.  Summary of Comments and Responses 

This section contains a brief summary of major comments and responses. 
Other comments on ferroalloy production were received covering various
topics.  Responses to significant comments received can be found in the
comment response document for ferroalloy production in the docket
(EPA-HQ-OAR-2008-508-XXX).Responses to significant comments received can
be found in “Mandatory Greenhouse Gas Reporting Rule: EPA’s Response
to Public Comments, Subpart K: Ferroalloy Production.”

Comment:  One comment was received on the proposed rule specific to
ferroalloy production facilities.  The commenter requested that EPA
allow ferroalloy production facilities to use alternative methods for
determining EAF process CO2 emissions other than those proposed, and
specifically a protocol for silicon metal production facilities
developed for use by the Chicago Climate Exchange.  This smelting
protocol was developed a protocol for calculating the CO2 emissions from
based on the World Resources Institute (WRI aluminium) aluminum smelting
protocol.

Response:  We reviewed the WRI aluminum smelting protocol, which was
publicly available and did not have a access towe tried to obtain a copy
of the specific protocol that the commenter mentions to fully evaluate
whether it is an appropriate alternative.  However, we never received it
in the long run.  The commenter did not provide additional or more
specific recommendations beyond the reference to improve or revise the
proposed methodology.  At this time, given insufficient information, we
have decided not to include additional alternative methods in the final
rule for ferroalloy production facilities. As we stated at proposal, the
selected methodology was based on review of several existing
methodologies used by the 2006 IPCC Guidelines for National Greenhouse
Gas Inventories, Canadian Mandatory Greenhouse Gas Reporting Program,
the Australian National Greenhouse Gas Reporting Program, and EU
Emissions Trading System. 

However, we have revised the frequency of sampling and analysis of
carbon contents for carbon containing input and output materials monthly
to annual consistent with revisions made in response to comments for
similar production processes (e.g. emissions from metal production). 
These revisions reduce the reporting burden for ferroalloy production
facilities.  We understand that the carbon content of material inputs
and outputs does not vary widely at a given facility for the significant
process inputs that contain carbon, and we continue to account for
variations due to changes in production rate, which is likely a more
significant source of variability.  The response to the comment can be
found in the comment response document for ferroalloy production in the
docket (EPA-HQ-OAR-2008-508-XXX).The response to the comment can be
found in “Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to
Public Comments, Subpart K: Ferroalloy Production.”

L.  Fluorinated GHG Production

At this time EPA is not going final with the subpart for emissions from
fluorinated GHG production.  As we consider next steps, we will be
reviewing the public comments and other relevant information.  

The Agency received a number of lengthy, detailed comments regarding the
fluorinated GHG production subpart.  Commenters generally opposed the
proposed reporting requirements. Several commenters stated that
facilities could not meet the proposed accuracy, precision, and
frequency requirements using existing equipment and practices.  These
commenters stated that they would need to expend significant funds
(millions of dollars in some cases) and time to install Coriolis
flowmeters in multiple streams and to implement daily sampling protocols
to analyze the contents of these streams.  Some commenters stated that
even after such equipment was installed, the proposed mass-balance
approach was likely to be inaccurate, particularly for batch processes. 
In most cases, commenters provided alternative approaches, such as
emission-factor based approaches, to the proposed mass-balance approach.

Based on careful review of comments received on the proposal preamble,
rule, and technical support documentsTSDs under proposed 40 CFR part 98,
subpart L, EPA will perform additional analysis and evaluate a range of
data collection procedures and methodologies.  EPA’s goal is to
optimize methods of data collection to ensure data accuracy while
considering industry burden.  

M.  Food Processing

At this time, EPA is not going final with the Food Processing Subpart. 
The sources of GHG emissions at food processing facilities that were to
be reported under the proposed rule were stationary fuel combustion,
onsite landfills, and onsite wastewater treatment.  EPA has decided not
to finalize the portion of 40 CFR part 98, subpart HH (Landfills) that
addresses industrial landfills nor 40 CFR part 98, subpart II
(Wastewater Treatment).  Note, however, that Stationary fuel combustion
sources at food processing facilities are subject to the requirements of
40 CFR part 98, subpart C if general stationary fuel combustion
emissions exceed the 25,000 metric ton CO2e threshold.  As EPA considers
next steps, we will be reviewing the public comments and other relevant
information. 

Based on careful review of comments received on the proposal preamble,
rule and technical support documentsTSDs under proposed 40 CFR part 98,
subparts M, HH, and II, EPA will perform additional analysis and
consider alternatives to data collection procedures and methodologies
contained in those subparts.  

N.  Glass Production 

1.  Summary of the Final Rule 

Source Category Definition.  The glass production source category
consists of facilities that manufacture glass (including flat,
container, pressed, or blown glass) or wool fiberglass using one or more
continuous glass melting furnaces.  Experimental furnaces and research
and development process units are excluded. 

Reporters must submit annual GHG reports for facilities that meet the
applicability criteria in the General Provisions (40 CFR 98.2)
summarized in Section II.A of this preamble.

GHGs to Report.  For glass production facilities, report the following
emissions:

CO2 process emissions from each continuous glass melting furnace.

CO2 combustion emissions from each continuous glass melting furnace, 

CH4 and N2O emissions from fuel combustion at each continuous glass
melting furnace under 40 CFR part 98, subpart C (General Stationary
Combustion Sources) using the methodologies in subpart C.

CO2, CH4, and N2O emissions and from each onsite stationary fuel
combustion unit other than continuous glass melting furnaces under 40
CFR part 98, subpart C (General Stationary Combustion Sources).

In addition, report GHG emissions for any other source categories at the
facility for which calculation methods are provided in other subparts of
the rule, as applicable.

GHG Emissions Calculation and Monitoring.  For CO2 process emissions
from glass melting furnaces, reporters must use one of two methods, as
appropriate:

For glass melting furnaces with certain types of CEMS in place,
reporters must use the CEMS and follow the Tier 4 methodology (in 40 CFR
part 98, subpart C) to measure and report under the glass production
subpart (40 CFR part 98, subpart N) combined process and combustion CO2
emissions.

For other glass melting furnaces, the reporter can elect to either (1)
install and operate a CEMS and follorfollow the Tier 4 methodology to
measure and report combined process and combustion CO2 emissions or (2)
calculate process CO2 emissions for each furnace using an emission
factor and process data.  If using approach (2), multiply a default
emission factor appropriate for the carbonate raw material by:

the annual mass of carbonate-based raw material charged to the furnace
(required to be measured); and 

the mass-fraction of carbonate in the raw material (based on data
supplied by the raw material supplier and verified by an annual
measurement). 

Under approach (2), report process CO2 emissions from each glass melting
furnace under 40 CFR part 98, subpart N (Glass Production), and report
combustion CO2 emissions from each glass furnace under 40 CFR part 98,
subpart C (General Stationary Fuel Combustion Sources).

Data Reporting.  In addition to the information required to be reported
by the General Provisions (40 CFR 98.3(c)) and summarized in Section
II.A of this preamble, reporters must submit additional data that are
used to calculate GHG emissions.  A list of the specific data to be
reported for this source category is contained in 40 CFR part 98,
subpart N.

Recordkeeping.  In addition to the records required by the General
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this
preamble, reporters must keep records of additional data used to
calculate GHG emissions.  A list of specific records that must be
retained for this source category is included in 40 CFR part 98, subpart
N.

2.  Summary of Major Changes Since Proposal

The major changes since proposal are identified in the following list. 
The rationale for these and any other significant changes can be found
below or in the comment response document for“Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to Public Comments, Subpart N: Glass
Production..” 

The definition of the term "glass produced" was added to the
defintionsdefinitions in 40 CFR part 98, subpart A.

40 CFR 98.146 was reorganized and updated to improve the emissions
verification process.  Some data elements were moved from section40 CFR
98.147 to section40 CFR 98.146, and some data elements that a reporter
must already use to calculate GHG'sGHGs as specified in section40 CFR
98.143 were added to section40 CFR 98.146 for clarity. 

3.  Summary of Comments and Responses 

This section contains a brief summary of major comments and responses. 
Several comments on glass production were received covering numerous
topics.  Responses to significant comments received can be found in the
comment response document for glass production in the docket
(EPA-HQ-OAR-2008-508-XXX).Responses to significant comments received can
be found in “Mandatory Greenhouse Gas Reporting Rule: EPA’s Response
to Public Comments, Subpart N: Glass Production.”

Definition of Source Category

Comment:  One commenter stated that EPA should exempt from the rule all
fiber glass and rock and slag wool insulation facilities within the
glass production source category because glass production facilities
subject to the proposed rule are a miniscule portion of the total
national emissions of CO2e, and amount to less than 0.1% percent of
total GHG emissions in the U.S. and the subset of fiber glass and rock
and slag wool insulation facilities is an even smaller portion.  The
commenter stated that there is virtually no benefit to having the glass
production source category subject to the proposed rule, and any benefit
is outweighed by the burden imposed on these facilities.  The commenter
also pointed out the importance of the fiber glass and rock and slag
wool insulation industry’s products in meeting the nation’s energy
needs and reducing greenhouse gasGHG emissions.  Exempting the industry
from the proposed rule’s reporting requirements will help the industry
focus more of its scarce resources on producing insulation.

Response:  We recognize that the glass manufacturing industry is
comprised of a wide range of facilities, many of which are small in size
and have relatively low levels of emissions.  However, the data we have
collected on the industry indicate that there are several large glass
manufacturing plants with significant GHG emissions.  These plants
include some that produce glass fiber, flat glass, and container glass,
as well as other types of pressed and blown glass products.  As a
result, we do not agree with the commenter that fiber glass and other
types of insulation facilities should be exempt from reporting. 
However, we tried to reduce the burden on the glass manufacturing
industry by incorporating into the proposed rule a 25,000 metric ton
CO2e threshold, which should preclude small facilities from having to
report GHGs.  We have retained thisThis threshold remains in the final
rule.  Thus, any small fiber glass and rock and slag wool insulation
facilities with insignificantlow GHG emissions will fall under the
threshold and will be exempt from reporting.  To further minimize the
burden on the industry, we have tried to limit recordkeeping and
reporting requirements to the types of data that glass production
facilities already collect as part of normal business operations.

Commenters may also be interested in reviewing Section II.H of this
preamble for the response on provisions to cease reporting.  The final
rule contains a provisionprovisions to cease reporting if annual reports
demonstrate emissions less than 25,000 metric tons CO2e per
yearspecified levels for 5 consecutivemultiple years.

Selection of Threshold

Comment:  One commenter remarked that EPA should raise the threshold for
reporting for fiberglass and rock and slag wool insulation entities. 
Doing so would reduce the number of entities reporting with only a
minimal impact on the amount of emissions covered.  The commenter stated
that EPA’s analysis did not address reasonable alternative thresholds
between 25,000 and 100,000 metric tons.

Response:  When evaluating potential thresholds for reporting GHG
emissions, we considered several thresholds between 1,000 and 100,000
mtmetric tons CO2e.  We selected the 25,000 mtmetric tons CO2e threshold
for reporting GHG emissions in order to achieve a balance between
quantifying the majority of the emissions and minimizing the number of
facilities impacted.  For example, at a 1,000 metric tons CO2e
threshold, 98 percent of emissions would be covered, with about 58
percent of facilities being required to report.  Compared to the 100,000
mtmetric tons CO2e threshold, the proposed 25,000 mtmetric tons CO2e
threshold achieves reporting of 11 times more emissions while requiring
less than 15 percent of the facilities to report.  Compared to the
10,000 metric tons CO2e threshold, the 25,000 mtmetric tons CO2e
threshold captures more than half of those emissions, but only requires
a third of the facilities in the industry to report.  This threshold
offers significant coverage of the GHG emissions while impacting a
relatively small portion of the industry.  Although a threshold of
50,000 mtmetric tons CO2e would greatly reduce the number of facilities
reporting, it would capture less than 20 percent of total emissions for
the industry.  We believe the proposed threshold of 25,000 mtmetric tons
CO2e represents the best option for ensuring that the majority of
emissions are reported without imposing an unreasonable burden on the
industry.

Section II.E of this preamble discussescontains a general discussion of
the selection of the 25,000 metric tons CO2e threshold and the
alternative thresholds considered.

Method for Calculating GHG Emissions

Comment:  One commenter fully supports EPA'sEPA’s proposed rule for
measuring, calculating, monitoring, and reporting emissions from the
glass melting process.  They agree that 40 CFR part 98, subpart N
represents a good balance between site reporting burden, cost, and data
accuracy and consistency.  Specifically, the commenter supports using
raw-material emissions factors and usage rates, as proposed, to
calculate emissions from glass production in lieu of requiring
installing CEMs on sources that another regulation does not currently
require to be installed.

Response:  We acknowledge this support for the proposal and appreciate
these comments.  We have retained the proposed calculation methodology
in the final rule.

Data Reporting Requirements

Comment:  One commenter stated that, at various places in the preamble
and proposed rule, EPA uses the phrase “glass produced,” but has not
defined this phrase in the rule.  The commenter noted that the phrase
could be interpreted to mean either glass melted or glass product
produced.  The commenter assumed that the phrase refers to the amount of
glass melted, but requested clarification.

Response:  We agree that the term glass produced is subject to
interpretation.  We have added a definition of the term to 40 CFR part
98, subpart A of the final rule.  “Glass produced” means the weight
of glass exiting a glass melting furnace.

Comment:  One commenter remarked that some of the information that would
have to be reported under the proposed rule, such as annual quantity of
glass produced, is considered to be company confidential and could be
used by competitors to back-calculate product formulas.  The commenter
requested that EPA remove these reporting requirements from the rule and
instead, require that the data be retained by the facility and made
available for review by EPA.  Should EPA require the reporting of all of
this information in the final rule, the commenter requests that EPA
explicitly state in the final rule and confirm in the preamble to the
final rule that all information provided under Subpart40 CFR part 98,
subpart N, other than the annual process emissions of CO2, is considered
confidential information and would not be considered “emission data”
under this reporting rule.  The commenter requests that a new paragraph
(e) be added to proposed Section40 CFR 98.146 that reads:  “No
information required to be reported by this section, other than the
information required by Section40 CFR 98.146(a), is considered to be
emission data under 40 CFR Section 2.301(a)(2)(i) and (ii).”

Response:  We acknowledge the commenter’s concerns.  However, the
quantity of glass produced is an important variable for EPA to verify
whether reported emissions are within a reasonable range and therefore
is a required reporting parameter under Subpart40 CFR part 98, subpart
N.

We have reviewed CBI comments received across the rule (both general and
subpart-specific comments) and our response is discussed in Section II.R
of this preamble and in the comment response document for legal
issues.“Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to
Public Comments, Legal Issues.” 

O.  HCFC-22 Production and HFC-23 Destruction 

1.  Summary of the Final Rule 

Source Category Definition.  This source category consists of:

Processes that produce HCFC-22 (chlorodifluoromethane or CHClF2) using
chloroform and hydrogen fluoride. 

HFC-23 destruction processes located at HCFC-22 production facilities. 

HFC-23 destruction processes that destroy more than 2.14 metric tons of
HFC-23 per year and that are not located at HCFC-22 production
facilities.

Reporters must submit annual GHG reports for facilities that meet the
applicability criteria in the General Provisions (40 CFR 98.2)
summarized in Section II.A of this preamble.

GHGs to Report.  For facilities that produce HCFC-22 or that destroy
HFC-23, report the following emissions:

HFC-23 emissions from all HCFC-22 production processes at the facility.

HFC-23 emissions from each destruction process. 

In addition, report GHG emissions for other source categories at the
facility for which calculation methods are provided in the rule, as
applicable.  For example, report CO2, N2O, and CH4 emissions from each
stationary combustion unit on site by following the requirements of 40
CFR part 98, subpart C (General Stationary Fuel Combustion Sources). 

GHG Emissions Calculation and Monitoring.  Reporters must calculate
HFC-23 emissions as follows:

For HCFC-22 production processes that do not use a thermal oxidizer or
that have a thermal oxidizer that is not connected to the production
equipment, calculate annual HFC-23 emissions at the facility level using
a mass balance equation and the following information: annual HFC-23
generated, the annual HFC-23 sent off site for sale, the annual HFC-23
sent off site for destruction, the annual increase in the HFC-23
inventory, and the annual HFC-23 destroyed on site (calculated by
multiplying the mass of HFC-23 fed to the destruction device by the
destruction efficiency). 

For HCFC-22 production processes with a thermal oxidizer that is
connected to the production equipment, calculate annual HFC-23 emissions
at the facility level by summing the following emissions: 

Annual HFC-23 emissions from equipment leaks (calculated using default
emission factors and the measured number of leaks in valves, pump seals,
compressor seals, pressure relief valves, connectors, and open-ended
lines).

Annual HFC-23 emissions from process vents (calculated for each vent
using the HFC-23 emission rate from the most recent emission test and
the ratio of the actual production rate and the production rate during
the emission test).

Annual HFC-23 from the thermal oxidizer (calculated by subtracting the
amount of HFC-23 destroyed by the destruction device from the measured
mass of HFC-23 fed to the destruction device). 

For other HFC-23 destruction processes, calculate HFC-23 emissions based
on the mass of HFC-23 fed to the destruction device and the destruction
efficiency.

For the destruction efficiency, conduct a performance test or use the
destruction efficiency determined during a previous performance test. 
To confirm the destruction efficiency, measure the fluorinated GHG
concentration at the outlet to the destruction device annually. 

Data Reporting.  In addition to the information required to be reported
by the General Provisions (40 CFR 98.3(c)) and summarized in Section
II.A of this preamble, reporters must submit additional data that are
used to calculate GHG emissions.  A list of the specific data to be
reported for this source category is contained in 40 CFR part 98,
subpart O.

Recordkeeping.  In addition to the records required by the General
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this
preamble, reporters must keep records of additional data used to
calculate GHG emissions.  A list of specific records that must be
retained for this source category is included in 40 CFR part 98, subpart
O.

2.  Summary of Major Changes Since Proposal 

The major changes since proposal are identified in the following list. 
The rationale for these and any other significant changes can be found
below or in the comment response document for“Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to Public Comments, Subpart O: HCFC-22
productionProduction and HFC-23 destruction:Destruction.”  

The minimum required frequency of mass flow and concentration
measurements has been decreased from daily to weekly.

The required frequency of emissions tests at process vents has been
decreased to once every five years.  A test is also required after a
significant change is made to the process.  

The required annual measurements at the outlet of the thermal oxidizer
now omit measurements of mass flow.  Three samples are required to be
taken; the average of these is compared to the concentration at the
outlet of the oxidizer that was measured during the initial performance
test that established the destruction efficiency (DE).

A term has been added to the mass-balance equation for HCFC-22
production facilities that do not have a thermal oxidizer that is
directly connected to the HCFC-22 production equipment.  This term
accounts for increases in the inventory of stored HFC-23 that can occur
during the year.

EPA has added an additional method for estimating missing mass flow data
in the event that a secondary mass measurement for that stream is not
available.  

The option for reporters to develop their own methods for estimating
missing data if they believe that the prescribed method will over- or
under-estimate the data has been removed.  

Some reporting requirements have been added to be consistent with the
changes to the calculations and monitoring sections and to permit
verification of emissions calculations.

EPA decreased the minimum frequency of gas flow and concentration
measurements from daily to weekly because EPA’s research indicates
that HFC-23 concentrations are not likely to vary significantly over a
one week period.  This change also makes the required measurement
frequency more consistent with current industry practice.

As noted above, EPA removed the option for reporters to develop their
own methods for estimating missing data if they believe that the
prescribed method will over- or underestimate the data.  EPA removed
this option for two reasons.  First, the proposed provision lacked clear
guidance on when alternative methods should be used (e.g., on the size
of an underestimate that would justify use of an alternative method) and
on how they should be developed.  Second, the proposed provision was
redundant with the new provision that permits reporters to estimate
missing data using a related parameter and the historical relationship
between the related parameter and the missing parameter.  This new
option provides reporters with flexibility in substituting for missing
data in the event that a secondary mass measurement is not available,
but sets out general guidance on how to select the substitute data.

3.  Summary of Comments and Responses 

This section contains a brief summary of major comments and responses. 
A number of comments on HCFC-22 production and HFC-23 destruction were
received covering numerous topics.  Responses to significant comments
received can be found in the comment response document for“Mandatory
Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments,
Subpart O: HCFC-22 productionProduction and HFC-23 destruction in the
docket (EPA-HQ-OAR-2008-508-XXX).Destruction.”

Monitoring and QA/QC Requirements

Comment:  EPA received a comment that the requirement to annually
conduct emissions tests at process vents is overly burdensome and
unnecessary because it is unlikely that the emissions rate would deviate
from an initial process vent test unless there were a significant change
in the process.  This commenter argued that testing should be required
at least every 5five years or after a significant change in the process.
 

Response: In response to this comment, EPA has reduced the required
frequency of emissions tests at process vents to once every five years,
or after a significant change to the process.  EPA has also clarified
that the requirement applies only to HCFC-22 production facilities that
use a thermal oxidizer connected to the HCFC-22 production equipment. 
These are the only facilities that use process vent emission estimates
in their calculation of facility-wide HFC-23 emissions.  

EPA is decreasing the frequency of emissions tests at process vents for
two reasons.  First, EPA agrees with the commenter that, in the absence
of a significant process change, the process vent emission rate is not
likely to vary much (in percentage terms) from year to year.  Second,
although small variations in the emission rate could still lead to
significant absolute errors for facilities with large process vent
emissions, the facilities that are required to test their process vent
emissions are likely to have small process vent emissions (because they
use thermal oxidizers connected to the production equipment).
(Facilities that do not use thermal oxidizers connected to the equipment
would be expected to have larger process vent emissions, but they are
required to use a mass-balance approach to calculate emissions rather
than summing emissions across process vents, equipment leaks, and
thermal oxidizers.)  Together, these considerations lead to the
conclusion that testing process vent emissions every five years should
sufficiently minimize errors in the overall HFC-23 emission calculations
of the facilities affected by the testing requirement.   

Comment:  EPA should add a term to Equation O-4 (the mass-balance
equation for HCFC-22 production facilities that do not have a thermal
oxidizer that is directly connected to the HCFC-22 production equipment)
to account for increases in the inventory of stored HFC-23 that can
occur during the year.

Response:  EPA added a term to Equation O-4 for increases in the
inventory of stored HFC-23.  EPA agrees that the equation should account
for changes in the inventory of HFC-23 that is stored on site.  It is
important to track all reservoirs of HFC-23 at the facility;
mass-balance approaches used to track emissions from other sources
(e.g., from electrical equipment) frequently include terms to account
for the increase in inventory.

Definition of Source Category

Comment:  EPA received a comment that the measurement of HFC-23
emissions from HCFC-22 production should be moved to Subpart L, which
covers the reporting of fluorinated greenhouse gasGHG production.  

Response:  EPA proposed provisions for facilities producing fluorinated
gases in three separate subparts: 40 CFR part 98, Subpart L, Subpart O,
and Subpart OO.  Although there are many similarities across the
chemicals and processes covered by the three subparts, the subparts were
deliberately tailored to different sources and types of emissions. 
Subpart L was intended to address emissions of fluorinated GHGs from
fluorinated GHG production.  Subpart40 CFR part 98, subpart O was
intended to address HFC-23 generation and emissions from HCFC-22
production.  Subpart40 CFR part 98, subpart OO was intended to address
flows affecting the U.S. industrial gas supply, including production,
transformation, and destruction.  

EPA determined that 40 CFR part 98, subpart O was necessary because
HCFC-22 production and HFC-23 destruction facilities differ from other
fluorinated gas production facilities in two key respects.  First, the
primary fluorinated GHG that they generate (HFC-23) is made as a
byproduct to the production of a substance that is not defined as a
fluorinated GHG (HCFC-22).  Second, due to the very high GWP of HFC-23,
each HCFC-22 facility generates very large quantities of CO2-equivalent.
 For the second reason, EPA has worked with HCFC-22 producers for over
ten years to understand and reduce HFC-23 emissions.  The requirements
for HCFC-22 producers are therefore based on a close knowledge of their
production processes and methods for accounting for emissions.  These
methods are also comprehensive (e.g., accounting for emissions from
equipment leaks and losses during transport of HFC-23 that is shipped
off-site for destruction).  These requirements may not be appropriate
for other fluorinated gas producers, and, at the same time, the
requirements for fluorinated gas producers may not be appropriate for
HCFC-22 producers. 

P.  Hydrogen Production 

1.  Summary of the Final Rule 

Source Category Definition.  The merchant hydrogen production source
consists of process units that produce hydrogen by reforming,
gasification, or other transformation of feedstock and transfer the
hydrogen produced off site.  Hydrogen production facilities located at
petroleum refineries or other large facilities are included in this
source category only if they are not owned by or under the direct
control of the refinery owner.  Otherwise, they are considered to be a
captive hydrogen production source that reports emissions under the
subpart applicable to the larger facility, e.g., Subpart40 CFR part 98,
subpart Y (Petroleum Refineries).  

Reporters must submit annual GHG reports for facilities that meet the
applicability criteria in the General Provisions (40 CFR 98.2)
summarized in Section II.A of this preamble.

GHGs to Report.  For hydrogen production, report the following
emissions:

CO2 process emissions from hydrogen production.

CO2, N2O, and CH4 emissions from each stationary combustion unit on site
by following the requirements of 40 CFR part 98, subpart C (General
Stationary Fuel Combustion Sources).

CO2 collected and transferred off site under 40 CFR part 98, subpart PP
(Suppliers of Carbon Dioxide). 

In addition, report GHG emissions for other source categories for which
calculation methods are provided in the rule, as applicable.  

GHG Emissions Calculation and Monitoring.  

To calculate and report process CO2 emissions from hydrogen production,
most reporters can elect to either (1) install and operate CEMS and
follow the Tier 4 methodology (in 40 CFR part 98, subpart C) or (2)
calculate process CO2 emissions using equations in the 40 CFR part 98,
subpart P and the following data:

Measurements of monthly feedstocks and fuel consumed.

Carbon content of the feedstock measured monthly. 

Molecular weight of the feedstock (gaseous fuels only).

However, if process CO2 emissions from hydrogen production are vented
through the same stack as a combustion unit or process equipment that
uses a CEMS to follows Tier 4 methodology to report CO2 emissions, then
the CEMS must be used to measure and report combined CO2 emissions from
that stack instead of the calculation procedure described in approach 2
above.  

Monitoring and QA/QC Requirements.  The methods for the initial
calibration and annual recalibration of flow meters are defined in a
prescriptive list of industry standard test methods incorporated by
reference in the Tier 3 method in Subpart40 CFR part 98, subpart C,
while the methods for determining carbon content of fuels and feedstocks
are defined in a prescriptive list of an assortment of industry standard
test methods incorporated by reference.  

Data Reporting.  In addition to the information required to be reported
by the General Provisions (40 CFR 98.3(c)) and summarized in Section
II.A of this preamble, reporters must submit additional data that are
used to calculate GHG emissions.  A list of the specific data to be
reported for this source category is contained in 40 CFR part 98,
subpart P.

Recordkeeping.  In addition to the records required by the General
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this
preamble, reporters must keep records of additional data used to
calculate GHG emissions.  A list of specific records that must be
retained for this source category is included in 40 CFR part 98, subpart
P.

2.  Summary of Major Changes Since Proposal

The major changes since proposal are identified in the following list. 
The rationale for these and any other significant changes can be found
below or in the comment response document for“Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to Public Comments, Subpart P: Hydrogen
Production.Prodution.”

40 CFR 98.160 was reworded to clarify the definition of reporting
entity. 

40 CFR 98.162 was revised to allow reporting of combined process and
combustion CO2, CH4, and N2O emissions.

In 40 CFR 98.162163(b), “feedstock” was changed to “fuel and
feedstock”.

40 CFR 98.164 was restructured to clarify between CEMS measurements and
QA/QC and feedstock method measurements and QA/QC.

40 CFR 98.164 was reworded to allow the characterization of feedstocks
to be conducted by either the consumer or the supplier, to allow
standard gaseous hydrocarbon fuels of commerce to be characterized
annually, and to allow liquid and solid hydrocarbon fuels of commerce to
be characterized upon delivery if delivered by bulk transport.

The recalibration requirements in 40 CFR 98.164 were changed to reduce
economic impact.

The list of standards incorporated by reference in 40 CFR 98.164 was
broadened. 

The missing data procedures in 40 CFR 98.165 were revised to be
consistent with §40 CFR 98.35(b). 

40 CFR 98.166 and 98.167 were restructured to clarifydistinguish between
CEMS recordkeeping and feedstock method recordkeeping. 

40 CFR Section 98.166 was reorganized and updated to improve the
emissions verification process.  Some data elements were moved from
section40 CFR 98.167 to section40 CFR 98.166, and some data elements
that a reporter must already use to calculate GHG'sGHGs as specified in
section40 CFR 98.163 were added to section40 CFR 98.166 for clarity.

3.  Summary of Comments and Responses 

This section contains a brief summary of major comments and responses. 
A large number of comments on hydrogen production were received covering
numerous topics.  Responses to significant comments received can be
found in the comment response document for hydrogen production in the
docket (EPA-HQ-OAR-2008-508-XXX).Responses to significant comments
received can be found in “Mandatory Greenhouse Gas Reporting Rule:
EPA’s Response to Public Comments, Subpart P: Hydrogen Production.”

Definition of Source Category

Comment:  Multiple commenters pointed out the lack of clarity regarding
the definition of the reporting entity, and suggested defining the
entity holding the air permit for an affected facility as the reporting
entity.  For example, “If the owner/operator of the facility is the
holder of the air permit for an affected facility, then the operator
should be responsible for reporting GHG emissions.  If not, then EPA
should clarify the responsibility for reporting.”

Response:  EPA reviewed this complex issue.  First, a facility is
defined in §40 CFR 98.6:  “Facility means any physical property,
plant, building, structure, source, or stationary equipment located on
one or more contiguous or adjacent properties in actual physical contact
or separated solely by a public roadway or other public right-of-way and
under common ownership or common control, that emits or may emit any
greenhouse gas.”  Therefore, a any hydrogen production process unit
that is not part of a larger facility, as defined above,  covered by
another subpart of this rule is a merchant hydrogen production facility
which reports emissions under Subpart40 CFR part 98, subpart P.  On the
other hand, a hydrogen production process unit that is part of a larger
facility, as defined above, covered by another subpart of this rule is a
captive hydrogen production facility that does not report emissions
under Subpart40 CFR part 98, subpart P.  Their emissions, including
those emissions from the captive hydrogen production facility, are
reported under the subpart applicable to the larger facility.  Second,
in answer to the question, “Do I need to report?”, 40 CFR 98.2
states that “A the rule applies to a facility that contains any of the
source categoriescategory listed in this paragraph [40 CFR §98.2(a)(2)
(which includes hydrogen production]) and that emits 25,000 metric tons
CO2e or more per year in combined emissions from stationary fuel
combustion units, miscellaneous uses of carbonates, and all source
categories that are listed in this paragraph in any calendar year
starting in 2010.listed in 40 CFR §98.2(a)(2).  EPA has concluded that
the rule explains this clearly in §40 CFR 98.2 and §98.6, and that it
is not necessary to change the rule.   To add clarity, however, EPA has
revised §40 CFR 98.160(c) as follows:  “This source category includes
merchant hydrogen production facilities located within a petroleum
refinery if they are not owned by, or under the direct control of, the
refinery owner and operator.”  

GHGs to Report

Comment:  Multiple commenters requested clarification on the CO2
emission reporting obligation as combined “process” and
“combustion” CO2 emissions, regardless of the calculation method
employed.  If separate, discrete reporting of such emissions is actually
required, commenters asked EPA to provide explicit protection for this
information which they stated was very critical CBI.

Response:  In response to these multiple commenters, EPA has clarified
the rule in §40 CFR 98.162 to provide operators the option of providing
combined process and combustion CO2 emissions for each hydrogen
production process unit whether or not it meets the conditions in §40
CFR 98.33(b)(54)(ii) or and (iii) for CEMs.  Under 40 CFR 98.166,
facilities must report additional parameters for emissions verification.
 

See Sections II.I and II.N of this preamble for responses to the
comments received on the general content of the annual GHG report and
the emissions verification approach, respectively.  EPA reviewed CBI
comments received across the rule (both general and subpart-specific
comments) and our response is discussed in Section II.R of this preamble
and in the comment response document for legal issues.“Mandatory
Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments,
Legal Issues.”  

Method for Calculating GHG Emissions

Comment:  Multiple commenters pointed out the need for a calculation
method to account for feedstock carbon that does not exit the hydrogen
production facility as CO2, but rather in the form of other products or
co-products that contain carbon (such as synthesis gas, CO, CH4).  Many
argued in favor of correcting equations P-1, P-2 and P-3 to account for
feedstock carbon that does not exit the hydrogen production facility as
CO2, but rather as products (such as synthesis gas, CO, CH4) that are
manufactured which contain carbon.

Response:  EPA generally concurs with the need to account for “carbon
other than CO2” that exits the facility.  EPA considered several
options for reporting such carbon and chose to have facilities report
CO2 and “carbon other than CO2” as separate data reporting elements
in §40 CFR 98.166 rather than including this carbon in equations P-1,
P-2, and P-3.  As a result, EPA has added data reporting elements under
§40 CFR 98.166 for (1) quarterly quantity of CO2 collected and
transferred off site in either gas, liquid, or solid forms (metric
tons), following the requirements of 40 CFR part 98, subpart PP of this
part, and (2) annual quantity of carbon other than CO2 collected and
transferred off site in either gas, liquid, or solid forms (metric
tons). 

Monitoring and QA/QC Requirements

Comment:  Multiple commenters recommended that EPA should allow the
characterization of feedstocks (sampling and analysis) to be conducted
by either the feedstock consumer (the regulated source) or the feedstock
supplier. They state that the characterization of standard fuels of
commerce used as hydrogen production feedstocks, such as natural gas,
should not be required since default values will yield a sufficiently
accurate emission estimate. Commenters recommend that characterization
of such standard fuels of commerce used as feedstocks be optional, at
the source'ssource’s discretion.

Response:  EPA concurs  with this comment, since feedstock suppliers
regularly monitor the carbon content of their fuels and also, the carbon
content of standard fuels of commerce are quite consistent month to
month.  EPA has revised this section to allow the characterization of
feedstocks to be conducted by either the consumer or the supplier, to
allow standard gaseous hydrocarbon fuels of commerce to be characterized
annually, and allow liquid and solid hydrocarbon fuels of commerce to be
characterized upon delivery if delivered by bulk transport (e.g., by
truck or rail).  Other non-standard gaseous fuels and feedstocks must
still be subjected to weekly sampling and analysis to determine the
carbon content and molecular weight. 

Comment:  Commenters recommended that EPA limit the requirement for
sampling non-gaseous fuels to new deliveries rather than monthly in
order to pinpoint the onset of fuel parameter variations.

Response:  EPA concurs that the carbon content of a liquid or solid
hydrocarbon fuel delivered in bulk will remain constant as the stock on
hand from the delivery is consumed, and therefore periodic testing
during the interim is not needed.  EPA has revised this section to allow
the characterization of feedstocks to be conducted by either the
consumer or the supplier, to allow standard gaseous hydrocarbon fuels of
commerce to be characterized annually, and allow liquid and solid
hydrocarbon fuels of commerce to be characterized upon delivery if
delivered by bulk transport (e.g., by truck or rail).  On the other
hand, other non-standard gaseous fuels and feedstocks must still be
subjected to weekly sampling and analysis to determine the carbon
content and molecular weight since their carbon content can vary
significantly from week to week. 

Comment:  Multiple commenters recommended that EPA should include
provisions for an extension of the required meter/monitor calibration
deadline (as well as the initial calibration, if appropriate) when the
calibration would require removing the process line from service.  They
recommend that the calibration requirement be extended to the next
scheduled maintenance shutdown for the impacted unit/process.

Response:  EPA concurs that requiring the facility to remove the process
line from service represents an undue hardship and has therefore revised
Subpart40 CFR part 98, subpart P to refer to the less stringent
monitoring and QA/QC requirements for the Tier 3 methodology included in
Subpart40 CFR part 98, subpart C (General Stationary Fuel Combustion
Sources). 

Comment:  One commenter suggested adding ISO 5167-1 through ISO 5167-4
(Measurement of Fluid Flow by Means of Pressure Differential Devices) to
list of standards incorporated by reference.

Response:  EPA agrees ISO 5167-1 through ISO 5167-4 are suitable
calibration standards and would be good additions to the list of
standards.  However, given that the issues covered by these standards
(Venturi and orifice plate differential pressure flow meters) are
covered by two the American Society of Mechanical Engineers (ASME)
standards, one ASHRAE standard, and one AGA report which are already
included in §40 CFR 98.164, EPA has not explicitly added these
references to the list of standards incorporated by reference. 

Procedures for Missing Data

Comment:  Multiple commenters recommended that the data substitution
method for missing feedstock supply rate data should be changed to be
consistent with §40 CFR 98.35(b)(2), allowing use of the “best
available estimate”, and that the data substitution method for missing
feedstock carbon content data should be changed to be consistent with
§40 CFR 98.35(b)(1), allowing use of the average before/after values.

Response:  EPA concurs that the required level of accuracy for hydrogen
production is similar to that required for stationary combustion, and
that the less stringent “best available estimate” approach is
appropriate for hydrogen production.  Therefore, EPA has changed the
language in Subpart P, §40 CFR 98.165, Procedures for Estimating
Missing Data, to follow the data substitution method for missing fuel
carbon content data prescribed in §40 CFR 98.35 and the data
substitution method for missing fuel usage data prescribed in §40 CFR
98.35 under Subpart C (General Stationary Combustion).

Data Reporting Requirements

Comment:  Multiple commenters stated that annual feedstock consumption,
annual hydrogen production, and feedstock carbon content are
confidential business information (CBI) and should not be reported.  The
commenters asked that this information be maintained by the facility and
be made available to the Agency upon request. One commenter further
stated that if data must be reported, the reporting rules must provide
explicit protection for this very critical confidential business
information.

Response:  Feedstock consumption and feedstock carbon content are
parameters used to calculate emissions.  Since annual CO2 emissions are
calculated from the sum of the products of monthly feedstock consumption
multiplied by the monthly average carbon content of the feedstock, all
of these parameters are required for emissions data verification
purposes.  Annual hydrogen production is an additional parameter which
is necessary for EPA to effectively verify emissions, since the ratio of
carbon emissions to hydrogen production is relatively consistent for
each hydrogen production facility.  See sectionSection II.N of this
preamble for information on emissions verification.  EPA reviewed CBI
comments received across the rule (both general and subpart-specific
comments) and our response is discussed in Section II.R of this preamble
and in the comment response document for legal issues.“Mandatory
Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments,
Legal Issues.”  

Q.  Iron and Steel Production 

1.  Summary of the Final Rule 

Source Category Definition.  The iron and steel production source
category consists of facilities with any of the following processes: 

Taconite iron ore processing.

Integrated iron and steel manufacturing.

Cokemaking not co-located with an integrated iron and steel
manufacturing process.

EAF steelmaking not co-located with an integrated iron and steel
manufacturing process. 

Integrated iron and steel manufacturing means the production of steel
from iron ore or iron ore pellets.  At a minimum, an integrated iron and
steel manufacturing process has a basic oxygen furnace for refining
molten iron into steel. Each cokemaking process and EAF process located
at a facility with an integrated iron and steel manufacturing process is
part of the integrated iron and steel manufacturing facility.

Reporters must submit annual GHG reports for facilities that meet the
applicability criteria in the General Provisions (40 CFR 98.2)
summarized in Section II.A of this preamble.

GHGs to Report.  Facilities must reportReport the following emissions
annually:

CO2, CH4, and N2O emissions from fuel combustion at each stationary
combustion unit according to the requirements in 40 CFR part 98, subpart
C (General Stationary Fuel Combustion Sources).  Stationary combustion
units include, but are not limited to, byproduct recovery coke oven
battery combustion stacks, blast furnace stoves, boilers, process
heaters, reheat furnaces, annealing furnaces, flame suppression, ladle
reheaters, and any other miscellaneous combustion sources (except
flares).

CO2 emissions from flares according to the requirements in 40 CFR part
98, subpart Y (Petroleum Refineries) and CH4 and N2O emissions from
flares using the default emission factors for coke oven gas and blast
furnace gas.

CO2 process emissions from each taconite indurating furnace, basic
oxygen furnace, nonrecovery coke oven battery combustion stack, coke
pushing process, sinter process, EAF, argon-oxygen decarburization
vessel, and direct reduction furnace.

In addition, report GHG emissions for any other source categories at the
facility for which calculation methods are provided in other subparts of
the rule, as applicable.

GHG Emissions Calculation and Monitoring.  For CO2 process emissions at
each taconite indurating furnace, basic oxygen furnace, nonrecovery coke
oven battery, sinter process, EAF, argon-oxygen decarburization vessel,
and direct reduction furnace, reporters must calculate emissions using
one of the following methods, as appropriate: 

Most reporters can elect to calculate and report process CO2 emissions
by either: (1) installing and operating a CEMS and following the Tier 4
methodology (in 40 CFR part 98, subpart C) or (2) using one of the
following two calculation procedures: 

Use a carbon balance method described in 40 CFR part 98, subpart Q to
calculate the annual mass emissions rate of CO2 for each process, based
on the annual mass of inputs and outputs and an annual analysis of the
respective weight fraction of carbon in each process input or output
that contains carbon.  Use separate procedures and equations for
taconite indurating furnaces, basic oxygen process furnaces, nonrecovery
coke oven batteries, sinter processes, EAFs, argon-oxygen
decarburization vessels, and direct reduction furnaces, or 

Use a site-specific emission factor determined from a performance test
that measures CO2 emissions from all exhaust stacks and also measures
either the feed rate of materials into the process or the production
rate during the test for taconite indurating furnaces, basic oxygen
process furnaces, nonrecovery coke oven batteries, sinter processes,
EAFs, argon-oxygen decarburization vessels, and direct reduction
furnaces.

However, if process CO2 emissions from a taconite indurating furnace,
basic oxygen furnace, nonrecovery coke oven battery, sinter process,
EAF, argon-oxygen decarburization vessel, and direct reduction furnace
are emitted through the same stack as CO2 emissions from a combustion
unit or process equipment that uses a CEMS and follows the Tier 4
methodology to report CO2 emissions, then the CEMS must be used to
measure and report combined CO2 emissions from that stack.  In such
cases, the reporter cannot use the other process CO2 calculation
approaches outlined above.

For coke oven pushing, facilities must use a CO2 emission factor
provided in the rule.

Data Reporting.  In addition to the information required to be reported
by the General Provisions (40 CFR 98.3(c)) and summarized in Section
II.A of this preamble, reporters must submit additional data that are
used to calculate GHG emissions.  A list of the specific data to be
reported for this source category is contained in 40 CFR part 98,
subpart Q.

Recordkeeping.  In addition to the records required by the General
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this
preamble, reporters must keep records of additional data used to
calculate GHG emissions.  A list of specific records that must be
retained for this source category is included in 40 CFR part 98, subpart
Q.

2.  Summary of Major Changes Since Proposal

The major changes since proposal are identified in the following list. 
The rationale for these and any other significant changes can be found
below or in the comment response document for“Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to Public Comments, Subpart Q: Iron and
Steel Production.”

The major changes made since proposal include: 

The carbon mass balance method was revised to require an annual analysis
of all process inputs and outputs for carbon content rather than weekly
sampling and monthly analysis.

The site-specific emission factor method was revised to:  (1) require
testing based on representative performance rather than at 90 percent of
capacity, (2) sampling for a minimum of three hours or production cycles
rather than nine, (3) conducting separate tests for each different
process condition that is a part of normal operation if the change in
CO2 emissions at the different conditions is more than 20 percent, and
(4) adding a provision to clarify testing requirements when the EAF and
argon-oxygen decarburization vessel are ducted to the same control
device and stack.

To improve the emissions verification process, section40 CFR 98.176 was
reorganized and updated. Some data elements were moved from section40
CFR 98.177 to section40 CFR 98.176, and some data elements that a
reporter must already use to calculate GHG'sGHGs as specified in
section40 CFR 98.173 were added to section40 CFR 98.176 for clarity.

3.  Summary of Comments and Responses 

This section contains a brief summary of major comments and responses
related to the requirements for iron and steel processes.  A large
number of comments on iron and steel production were received covering
numerous topics.  Many of these comments were directed at the
requirements for 40 CFR part 98, subpart C (General Stationary Fuel
Combustion Sources in subpart C), and responses to those comments are
provided in preamble section IISection III.C of this preamble.  Also see
the Section II.N of this preamble for the response to comments on the
emissions verification approach.  Responses to other significant
comments received related to process emissions from iron and steel
production can be found in the comment response document for
iron“Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to
Public Comments, Subpart Q: Iron and steel production in the docket
(EPA-HQ-OAR-2008-0508-XXX).Steel Production.”

Method for Calculating GHG Emissions.

Comment:  Several industry representatives and their three trade
associations requested that EPA allow the use of a simplified
facility-wide carbon balance approach developed by the American Iron and
Steel Institute (AISI) to calculate CO2 emissions from iron and steel
production facilities.  According to the commenters, the AISI
methodology has recently been adapted to facility-wide reporting and is
emerging as the preferred reporting protocol internationally.  The
commenters described the approach as based on determining the mass of
carbon in the most significant carbon-containing inputs entering the
plant and in the most significant carbon-containing outputs that leave
as products or byproducts (excluding, for example, iron ore, scrap,
steel).  The difference between the mass of carbon entering the facility
and leaving the facility is assumed to be converted to CO2.  The annual
mass rates of significant inputs and outputs are determined from company
records, and their carbon contents are based on typical or default
values.  The commenters noted that the AISI approach provides a single
estimate of the combined total CO2 emissions from all processes and
combustion sources at the facility.  The commenters claimed that the
approach would provide a more accurate and complete accounting of
facility-wide emissions at a much lower cost than that of the proposed
EPA process-specific methods.   

Response:  As we explained at proposal (74 FR 16517), we considered the
many domestic and international monitoring guidelines and protocols for
process and combustion sources at iron and steel production facilities,
including the AISI facility-wide approach.  The vast majority of these
guidelines and protocols are process-specific rather than facility-wide
approaches (e.g., 2006 IPCC Guidelines, U.S. Inventory, the World
Business Council for Sustainable Development (WBCSD)/WRI GHG protocol,
DOE 1605(b), TCR, European Union Emissions Trading System, and
Environment Canada’s mandatory reporting guidelines).  In addition,
the “higher tier” (more accurate) site-specific methods use
process-specific approaches.  We explained at proposal (74 FR 16517)
that we did not choose to propose these approaches based on the use of
default values in general (such as the AISI approach) because the use of
default values and lack of direct measurements results in a very high
level of uncertainty (greater than ±25 percent), and default approaches
would not provide site-specific estimates of emissions that reflect
differences in feedstocks, operating conditions, fuel combustion
efficiency, variability in fuels, and other differences among
facilities.  

We also stated at proposal that we decided not to finalize the proposal
using methodologies that relied on default emission factors or default
values for carbon content of materials because the differences among
facilities described above could not be discerned, such default
approaches are inherently inaccurate for site-specific determinations,
and the use of default values is more appropriate for sector wide or
national total estimates from aggregated activity data than for
determining emissions from a specific facility.  

We further note here that the AISI approach is not adequate for our
reporting needs because it provides only a single emissions number
aggregated from the numerous individual processes and combustion units
at the iron and steel facility.  In contrast, the approaches we are
promulgating today for determining CO2 emissions provide information at
the process level and distinguish between combustion emissions and
process emissions.  Information at the process level is needed for many
reasons, such as verification of the reported emissions from comparison
with known ranges expected from various types of processes for a given
production rate and emissions verification based on data for different
plants for similar processes.  Process-level reporting also provides
information that will be useful in identifying processes that that have
reduced emissions over time and processes at specific plants that have
the most potential for future reductions in emissions.  In addition, the
process-level reporting may provide information that can be used to
improve methodologies for specific processes under future programs and
to identify processes that may use a technology that could be the basis
for an emission standard at a later time. 

We developed estimates of costs for the proposed options for determining
CO2 emissions and concluded that the costs were reasonable.  However, as
explained below, we have revised the proposed options in response to
comments, and these revisions significantly reduce the burden and costs
of the carbon mass balance and site-specific emission factor methods
while maintaining a similar level of accuracy.

Comment:  Several commenters claimed that the proposed carbon mass
balance method is unnecessarily burdensome because it requires weekly
sampling, monthly analyses, and determining the monthly mass quantities
of all process inputs and outputs.  The commenters suggested that EPA
allow the use of default values for carbon content, neglect streams that
have very little or no carbon, drop the requirement for analysis by an
“independent certified laboratory,” and allow the use of analyses
from suppliers.  One commenter recommended sampling and analysis for
carbon content no more frequently than annually.  The commenters stated
that lime, dolomite and slag contain no appreciable carbon and do not
need to be tracked, and that it is not necessary to account for the
carbon in scrap that is charged to the furnace or in the steel product
because they offset each other.  One commenter noted that “independent
certified laboratory” is not defined or explained, and another claimed
that it is an unnecessary complication and expense because these carbon
analyses are typically done in an in-house laboratory.  

One commenter stated that the carbon mass balance equations were
incomplete because they did not account for carbon removed by pollution
control devices.  Another commenter recommended that EPA use default
carbon contents for different grades of steel scrap and noted that
because companies already track the chemical content of each grade of
scrap, highly accurate carbon calculations could be made with minimal
additional burden.

Response:  We received several useful suggestions for improving the
carbon mass balance method without significantly decreasing the accuracy
in the estimates.  After a close review of the sampling and analysis
requirements and comparing them to the requirements applied to other
source categories in other subparts of this reporting rule, we concluded
that the weekly sampling and monthly analysis of carbon content could be
reduced in frequency to an annual analysis of all inputs and outputs at
each facility.  We also revised the rule to allow the use of carbon
content analyses from the material supplier, which is consistent with
what is required in other subparts using the carbon balance method. 
Carbon content does not vary widely at a given facility for the
significant process inputs and outputs that contain carbon, and we
continue to account for variations due to changes in production rate,
which is likely a more significant source of variability.  We continue
to choose not to use default values for the reasons given in the
previous comment response, and we have determined that an annual
analysis of carbon content to provide plant-specific values is not
burdensome because facilities already perform many such analyses.  We
agree that the analysis does not have to be performed by an independent
certified laboratory, especially since we specify the analytical
procedures that must be used by any laboratory, and we note that
in-house laboratories may have more applicable experience in analyses of
their particular process inputs and outputs.    

We agree with the suggestion to evaluate carbon content by the grade or
type of ferrous material charged to the furnace, and we incorporated a
provision to calculate an average carbon content of ferrous materials
charged based on the average weight percent of each type that is used. 
In addition, we have corrected the equations as suggested to account for
carbon in the residue collected by emission control equipment.  Finally,
we agree that inputs and outputs that contain no carbon or an
insignificant amount (i.e., contributing to less than one percent of the
carbon in or out) do not need to be tracked in the carbon balance
method.

Comment:  Several commenters claimed that the site-specific emission
factor method is not a viable option as proposed and should be
streamlined to:  (1) eliminate annual re-testing, (2) reduce the test
length from 9nine hours (or from 9nine production cycles for batch
processes), (3) clarify that a separate test is not required for each
grade of steel, and (4) remove the requirement to operate at 90 percent
of capacity.  One commenter stated that the most frequent re-testing
currently required in operating permits is once every 2.5 years rather
than annually.  Another commenter noted that 9nine production cycles for
certain small specialty steel producers would require 27 hours of
testing for each grade of steel because each production cycle is 3three
hours.  Commenters stated that testing at 90 percent of production is
problematic and is beyond their control because it is dictated by
upstream and downstream production levels as well as economic
conditions.  In addition, capacity is difficult to determine because
steelmaking furnaces do not have a nameplate capacity since it is
determined by the iron production rate, how fast downstream processes
(such as the caster) operate, process inputs, and product specifications
that may require different operating cycle times.

One commenter questioned the value of the requirement to re-test if the
carbon content of feed materials changes by more than 10 percent because
this type of change could occur on a daily or weekly basis when the
grade of steel being produced changes.  Another commenter noted that EPA
did not define what constituted a significant change in fuel type or mix
and recommended that the provision be changed to 20 percent to allow for
environmentally beneficial process improvements.  Two commenters stated
that the 10 percent threshold for re-testing is infeasible for
steelmaking and sinter processes because of routine changes in the type
of steel produced and the types of materials recycled to the sinter
plant.  The commenters requested that they be permitted to develop
separate emission factors based on various modes that represent
different operating scenarios or product categories.  The commenters
also recommended that EPA eliminate the 10 percent change threshold for
re-testing and require that testing be conducted under conditions that
are representative of normal operation.  One commenter noted that the
rule did not address how a site-specific emission factor would be
developed when emissions from the EAF and argon-oxygen decarburization
vessel are combined and routed to a single emission control device and
stack.

Response:  We further reviewed the testing requirement in other rules
and those in operating permits and found that typical requirements (such
as test requirements for particulate matter) include 3 one-hour runs or
production cycles for representative testing of process emissions. 
Consequently, we are revising the testing requirements to 3three hours
or 3three production cycles.  We also agree with the commenters who
noted that different routine operating modes may result in different
levels of CO2 emissions, and it is necessary to develop separate
emission factors for these different operating conditions. 
Consequently, we have dropped the 10 percent re-testing threshold and
instead require that separate emission factors be developed for each of
different routine operating conditions that result in a change in CO2
emissions by 20 percent or more.  

We disagree that annual re-testing is excessive because testing for CO2
emissions is much simpler and less costly than sampling for hazardous
pollutants or for particulate matter, and annual sampling is consistent
with our requirement for annual reporting.  We agree that it is not
necessary or always possible to test while operating at 90 percent of
capacity for the reasons identified by the commenters.  Instead, we are
requiring that the test be performed based on representative
performance, i.e., under normal operating conditions.  We have revised
the rule to clarify and provide options for testing when emissions from
the EAF and argon-oxygen decarburization vessel are combined.

Comment:  Several commenters asked EPA to clarify that CH4 and N2O
emissions do not have to be reported for iron and steel production
processes, and other commenters requested that CH4 and N2O emissions
reporting not be required for the combustion of coke oven gas and blast
furnace gas.  Commenters noted that default emission factors for CO2,
CH4, and N2O were not provided in the tables in 40 CFR part 98, subpart
C, and in the absence of such emission factors, asked if they would be
required to test for these minor emissions.   

Response:  We have clarified that 40 CFR part 98, subpart Q does not
require reporting of CH4 and N2O emissions from the iron and steel
production processes because we expect these emissions (if any) to be
very low, and we have no protocols for calculating them.  However,
emission factors are available in the 2006 IPCC guidelines for
combustion sources, including the combustion of coke oven gas and blast
furnace gas.  We have added the IPCC default emission factors for CO2
and N2O for these process gases to the tables in 40 CFR part 98, subpart
C, and we developed new emission factors for CH4 based on the typical
CH4 content of coke oven gas (28 percent) and blast furnace gas (0.2
percent). 

R.  Lead Production 

1.  Summary of the Final Rule 

Source Category Definition.  The lead production source category
consists of primary lead smelters and secondary lead smelters.  A
primary lead smelter is a facility engaged in the production of lead
metal from lead sulfide ore concentrates through the use of
pyrometallurgical techniques (smelting).  A secondary lead smelter is a
facility at which lead-bearing scrap materials (including but not
limited to lead-acid batteries) are recycled by smelting into elemental
lead or lead alloys. 

Reporters must submit annual GHG reports for primary lead smelters and
secondary lead smelters that meet the applicability criteria in the
General Provisions (40 CFR 98.2) summarized in Section II.A of this
preamble.

GHGs to Report.  For lead production, report the following emissions: 

CO2 process emissions from each smelting furnace used for lead
production. 

CO2 combustincombustion emissions from each smelting furnace used for
lead production. 

N2O and CH4 emissions from each smelting furnace under 40 CFR part 98,
subpart C (General Stationary Fuel Combustion Sources) using the
methodologies in subpart C. 

CO2, N2O, and CH4 emissions from each on-site stationary combustion unit
other than smelting furnaces under 40 CFR part 98, subpart C (General
Stationary Fuel Combustion Sources).

In addition, report GHG emissions for any other source categories at the
facility for which calculation methods are provided in other subparts of
the rule, as applicable.

GHG Emissions Calculation and Monitoring.  To calculate annual process
CO2 emissions from an affected smelting furnace, the reporter must use
the following methods, as applicable to the affected smelting furnace.

For each affected smelting furnace with certain types of CEMS in place,
the reporter must use the CEMS and follow the Tier 4 methodology (in 40
CFR part 98, subpart C) to measure and report under the Lead Production
subpart (40 CFR part 98, subpart R) combined process and combustion CO2
emissions.

For other affected smelting furnaces, the reporter can elect to either
(1) install and operate a CEMS and follow the Tier 4 methodology to
measure and report combined process and combustion CO2 emissions or (2)
calculate annual process CO2 emissions using a carbon mass balance
procedure specified in 40 CFR part 98, subpart R.  If using approach
(2):

Calculate emissions once per year using recorded monthly production data
and the average carbon content for each smelting furnace input material
determined by either using material supplier information or by annual
analysis of representative samples of the material.

Report process CO2 emissions from each smelting furnace under 40 CFR
part 98, subpart H (Cement Production), and report combustion CO2
emissions from each kiln under 40 CFR part 98, subpart C (General
Stationary Fuel Combustion Sources).

Data Reporting.  In addition to the information required to be reported
by the General Provisions (40 CFR 98.3(c)) and summarized in Section
II.A of this preamble, reporters must submit additional data that are
used to calculate GHG emissions.  A list of the specific data to be
reported for this source category is contained in 40 CFR part 98,
subpart R.

Recordkeeping.  In addition to the records required by the General
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this
preamble, reporters must keep records of additional data used to
calculate GHG emissions.  A list of specific records that must be
retained for this source category is included in 40 CFR part 98, subpart
R.

2.  Summary of Major Changes Since Proposal 

The major changes to the rule since proposal for lead production
facilities were revisions to the carbon mass balance calculation
procedure used by reporters for calculating process CO2 emissions from
affected smelting furnaces.  The rationale for these and any other
significant changes can be found below or in the comment response
document for“Mandatory Greenhouse Gas Reporting Rule: EPA’s Response
to Public Comments, Subpart R: Lead Production.  These changes
include:.”

The frequency of performing the carbon mass balance calculations was
revised to be required on an annual basis instead of the proposed
monthly basis.

The frequency of material carbon content sampling and analysis of each
smelting furnace input material used for the carbon mass balance was
revised to be performed by annual analysis of representative samples of
the material instead of the proposed monthly basis.

A de minimis carbon content level was added to exclude the need to
account for carbon-containing materials contributing less than
1one percent of the total carbon into the smelting furnace in the
carbon mass balance calculations. 

Data reporting procedures (Section40 CFR 98.186) were  reorganized and
updated to consolidate and clarify the emissions verification process. 
Some data elements for the carbon mass balance calculation were moved
from section40 CFR 98.187 to section40 CFR 98.186, and some data
elements that a reporter must already use to calculate GHGs as specified
in section40 CFR 98.183 were added to section40 CFR 98.186 for clarity. 

3.  Summary of Comments and Responses 

This section contains a brief summary of major comments and responses
specific to the lead production source category.  Comments were received
from one commenter regarding several topics.  Responses to significant
comments received are presented in the comment response document for
lead production in the docket (EPA-HQ-OAR-2008-508-XXX).“Mandatory
Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments,
Subpart R: Lead Production.”

Selection of Threshold

Comment:  The commenter stated that Lead Production is not a source of
significant GHG emissions and that EPA cannot assert that the Lead
Production sector is a significant part of the stationary source
combustion sector.  The commenter notes that based on EPA'sEPA’s
estimates in the TSDs for the proposal, estimated emissions from the
Lead Production sector are 0.02% percent of the total estimated
nationwide emissions from stationary fossil fuel combustion.  Moreover,
they argue that the combustion-related emissions from lead production
are overstated by incorrect assumptions in the TSD.  The commenter
states that given Lead Production’s relative contribution, it is not a
significant source of emissions and should be eliminated from further
consideration.  The commenter further states that Lead Production is the
only category evaluated where raising the threshold to the 100,000 ton
level would results in zero facilities being covered.  Accordingly, when
the analysis shows that all facilities in a particular source category
are not covered at the 100,000 ton threshold level, no insignificant GHG
emitters in the category should be required to report under the Proposed
Rule.  The commenter noted that using the 100,000 threshold would not
significantly reduce the coverage of emissions of EPA'sEPA’s rule, as
the majority of sources identified would still have well over 90%
percent of emissions from that source category covered under the 100,000
threshold.  EPA provides no justification for imposing substantially
more costs on industry for limited estimated benefits and small
likelihood for regulation under the CAA.  For these reasons, the Lead
Production sector should be eliminated as a source category, and EPA
should raise the threshold to 100,000 for non-source category
facilities.

Response:  We acknowledge this comment and concerns; however the final
rule retains the applicability requirement for this source category.  To
balance the burden for lead producers, we did apply a We used
information available to us for estimating GHG emissions from this
industry which involved several assumptions related to the emission
factors in the IPCC Guidance and other sources.  As noted by the
commenter, many of the underlying assumptions were based on an
international perspective as opposed to the primary and secondary lead
production industry in the U.S.  The final rule contains a threshold of
25,000 metric tons CO2e and only lead production facilities with
emissions that equal or exceed 25,000 metric tons CO2e will have to
report emissions.  In addition, the final rule now contains a provision
provisions allowing a reporter to cease reporting if the annual reports
for a given facility demonstrate emissions less than 25,000 metric tons
CO2e per yearspecified levels for 5 consecutivemultiple years.  This
provision applies to These provisions apply to all reporting facilities,
including those with lead production processes.  See Section II.H of
this preamble for the response on provisions to cease reporting.

We have further simplified the reporting requirement to further reduce
burden for lead and similar industries by requiring annual as opposed to
monthly sampling of carbon inputs.  The purpose of this rule is to
collect information on emissions sources for future policy development. 
Requiring reporting for these sources will provide EPA with valuable
data to better characterize them and provide a more credible position if
EPA elects to exclude these sources from future GHG policy analyses. 
Additionally, while some of these sources are currently believed to be
small compared to the larger sources, they are not necessarily
insignificant.  The inclusion of reporting data for these sources is
critical to support analysis of future policy decisions for lead
production facilities. 

When evaluating potential thresholds for reporting GHG emissions, we
considered several thresholds between 1,000 and 100,000 metric tons
CO2e.  We selected the 25,000 metric tons CO2e threshold for reporting
GHG emissions in order to achieve a balance between quantifying the
majority of the emissions, while minimizing the number of facilities
impacted.  For example, at a 1,000 metric tons CO2e threshold, 99
percent of emissions would be covered, with about 63 percent of
facilities being required to report.  The 100,000 metric tons CO2e
threshold captures no emissions or facilities while the proposed 25,000
metric tons CO2e threshold achieves reporting of 92 percent of the GHG
emissions while requiring less than 50 percent of the facilities to
report.  We consider this a significant coverage of the emissions, while
impacting a relatively small portion of the industry.  We believe the
proposed threshold of 25,000 metric tons CO2e represents the best option
for ensuring that the majority of emissions are reported without
imposing an unreasonable burden on the industry.  Also see also the
preamble and separate comment response document volume for the response
on selection of the threshold.See also Section II.E of this preamble and
“Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to Public
Comments, Selection of Reporting Thresholds, Greenhouse Gases, and De
Minimis Provisions.”

Method for Calculating GHG Emissions

Comment:  The commenter made several comments regarding the proposed
procedures used to calculate process CO2 emissions from smelting
furnaces at secondary lead smelters.  First, use of default emission
factors should be allowed as a calculation method alternative because
the smelting furnaces operated at used lead battery recycling facilities
consistently process furnace feed materials with low carbon content
variability. For affected sources using the carbon mass balance
procedure, the frequency required for monitoring carbon content of the
smelting furnace input materials should be reduced to reflect
consistency and low carbon content variability of these materials.

Response:  We decided not to finalize the proposal using methodologies
for calculating CO2 emissions from lead production that relied on
published default emission factors or default values for carbon content
of materials because the differences among individual lead production
facilities could not be discerned using these factors.  Consequently,
the available default factors for lead production facilities are
inherently less accurate for calculating smelting furnace process CO2
emissions than using procedures that include use of site-specific
material carbon data.  Default approaches do not provide site-specific
estimates of emissions that reflect differences in use of and
variability in feedstocks, variability in fuels, operating conditions,
fuel combustion efficiency, and other differences among facilities.  For
some carbon-containing input materials, such as lead scrap,
representative published defaults do not exist.  Therefore, the use of
default values is more appropriate for sector wide or national total
estimates from aggregated production data for multiple facilities rather
than for providing an accurate representation of CO2 emissions from a
specific facility. 

For the final rule, we did reduce the monitoring frequency for
determining carbon contents of the smelting furnace input materials used
for the carbon mass balance to be determined on annual rather than
monthly basis. Facilities can determine carbon contents either by using
material supplier information or by annual analysis of representative
samples of the input materials.  We agree that the carbon content for
the significant input materials typically does not vary widely at a
given lead production facility.  Annual carbon content determinations
will still provide representative carbon content data for the smelting
furnace process CO2 emissions calculations while minimizing the
monitoring burden reporters.  We continue to account for process
variations due to changes in production rate, which is likely a more
significant source of variability in the CO2 emissions from an affected
smelting furnace during the year, by maintaining the requirement to
measure and record monthly carbon containing input materials.  

S.  Lime Manufacturing 

1.  Summary of the Final Rule 

Source Category Definition.  Lime manufacturing plants (LMPs) engage in
the manufacture of a lime product (e.g., calcium oxide, high-calcium
quicklime, calcium hydroxide, hydrated lime, dolomitic quicklime,
dolomitic hydrate, or other products) by calcination of limestone,
dolomite, shells or other cacareous substances.  This source category
includes all LMPs unless the LMP is located at a kraft pulp mill, soda
pulp mill, sulfite pulp mill, or only processes sludge containing
calcium carbonate from water softening processes.   

Lime kilns at pulp and paper manufacturing facilities need to report
emissions under 40 CFR part 98, subpart AA (Pulp and Paper
Manufacturing).  

Reporters must submit annual GHG reports for facilities that meet the
applicability criteria in the General Provisions (40 CFR 98.2)
summarized in Section II.A of this preamble and meet the definition of
lime manufacturing plants in 40 CFR 63.7081(a)(1).

GHGs to Report.  For lime manufacturing, report the following emissions:

Total CO2 process emissions from all lime kilns combined.

CO2 combustion emissions from each lime kilns.

N2O, and CH4 emissions from fuel combustion at each kiln under 40 CFR
part 98, subpart C (General Stationary Fuel Combustion Sources) using
the methodologies in subpart C.

CO2, N2O, and CH4 emissions from each stationary combustion unit other
than kilns under 40 CFR part 98, subpart C (General Stationary Fuel
Combustion Sources).

CO2 collected and transferred off site under subpart 40 CFR part 98,
subpart PP (Suppliers of CO2), 

In addition, report GHG emissions for any other source categories at the
facility for which calculation methods are provided in other subparts of
the rule, as applicable.

GHG Emissions Calculation and Monitoring.  For CO2 emissions from kilns,
facilities must use one of two methods, as appropriate:

Kilns withIf all lime kilns at a facility have certain types of CEMS in
place, the reporter must use the CEMS and follow the Tier 4 methodology
(in 40 CFR part 98, subpart C) to measures and report under the Lime
Manufacturing subpart (40 CFR part 98, subpart S) combined process and
combustion CO2 emissions.

For otherIf CEMS meeting the specifications above are not in place for
all kilns at the facility, , the reporter can elect to either (1)
install and operate a CEMS and follow the Tier 4 methodology to measure
and report combined process and combustion CO2 emissions from all lime
kilns or (2) calculate CO2 process emissions for each lime type using an
emission factor for each lime type, the mass of lime produced, an
emission factor for byproduct/waste (such as lime kiln dust and scrubber
sludge), and the mass of byproduct/waste.  If using approach (2): 

Each emission factor must be determined monthly for each lime type from
monthly measurements of the calcium oxide and magnesium oxide content of
the lime and stoichiometric ratios of CO2 to each oxide in the lime. 

The emission factor for each lime byproduct/waste sold (such as lime
kiln dust) must be determined monthly.

The emissions from lime byproducts/wastes that are not sold (such as
lime kiln dust and scrubber sludge) must be determined annually. 

The mass of each lime type produced and lime byproduct/waste sold (such
as lime kiln dust) must be recorded on a monthly basis.

The mass of each lime byproduct/waste not sold (such as lime kiln dust
and scrubber sludge) must be recorded annually.

Report process CO2 emissions from all kilns combined under 40 CFR part
98, subpart S (Lime Manufacturing), and report combustion CO2 emissions
from kilnseach kiln under 40 CFR part 98, subpart C (General Stationary
Fuel Combustion Sources).

Data Reporting.  In addition to the information required to be reported
by the General Provisions (40 CFR 98.3(c)) and summarized in Section
II.A of this preamble, reporters must submit additional data that are
used to calculate GHG emissions.  A list of the specific data to be
reported for this source category is contained in 40 CFR part 98,
subpart S.

Recordkeeping.  In addition to the records required by the General
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this
preamble, reporters must keep records of additional data used to
calculate GHG emissions.  A list of specific records that must be
retained for this source category is included in 40 CFR part 98, subpart
S.

2.  Summary of Major Changes Since Proposal

The major changes since proposal are identified in the following list. 
The rationale for these and any other significant changes can be found
below or in the comment response document for“Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to Public Comments, Subpart S: Lime
Manufacturing.”

The definition of lime manufacturing was revised to be similar to the
definition in the Lime NESHAP at §§63.7081(a) and (a)(1).

Reporting requirements were revised from a “per kiln” basis to
“all kilns combined”.

The emissions calculations were revised to determine monthly emissions
factors for each lime type and byproduct/waste type rather than for each
kiln.

Emission calculations for byproducts/wastes were added.

The requirement to measure the calcium oxide and magnesium oxide content
of byproducts/wastes on a monthly basis was changed to an annual basis
for byproducts/wastes that are not sold.

The correction factor for byproducts/wastes was removed from the rule.

Additional direct measurement devices/methods are being allowed to
include those currently in use by the industry.

Section40 CFR 98.196 was reorganized and updated.  Some data elements
were moved from section40 CFR 98.197 to section40 CFR 98.196, and some
data elements that a reporter must already use to calculate GHGs as
specified in section40 CFR 98.193 were added to section40 CFR 98.196 for
clarity.

3.  Summary of Comments and Responses 

This section contains a brief summary of major comments and responses. 
A large number of comments on lime manufacturing were received covering
numerous topics.  Responses to significant comments received can be
found in the comment response document for lime manufacturing in the
docket (EPA-HQ-OAR-2008-0508-XXX).Responses to significant comments
received can be found in “Mandatory Greenhouse Gas Reporting Rule:
EPA’s Response to Public Comments, Subpart S: Lime Manufacturing.”

Definition of Source Category

Comment:  Multiple commenters requested more clarification in defining
which sources and equipment are covered by the proposed rule. 
Currently, the The rule defines the source category as a facility that
contains “a rotary lime kiln to produce a lime product,” and other
equipment covered is referred to as “any other stationary
equipment”..” In addition, proposed 40 CFR 98.192(b) required
sources to report emissions from “each lime kiln and any other
stationary combustion unit.”  

Response:  We have reviewed the rule language and decided the source
category definition should provide more clarity.  The source category is
meant to include all kiln types used in the lime manufacturing industry;
therefore, language in the final rule has been changed to be similar to
the definition from the Lime NESHAP sectionsin 40 CFR 63.7081(a) and
(a)(1).  This Lime NESHAP effectively characterizes lime plants as those
engaging in the manufacture of a lime product by calcination.  The final
rule requires all stationary combustion units to report under 40 CFR
part 98, subpart C of the final rule.

Final rule language under 40 CFR 98.192 requires facilities to report
CO2, CH4, and N2O emissions from kilns used in the lime manufacturing
process and all other combustion units at the lime manufacturing
facility other than kilns.  The language has also been clarified in 40
CFR 98.193.  Facilities using CEMS for all lime kilns report combined
process and combustion emissions from kilns under 40 CFR part 98,
subpart S, according to the Tier 4 methodology in 40 CFR part 98 subpart
C (General Stationary Fuel Combustion Sources).  Facilities must follow
the requirements of subpart C for estimating and reporting combustion
related emissions for all other combustion units and report these
emissions under subpart C.  See Section III.C of this rule.preamble for
an overview of the requirements for stationary combustion units.

Selection of Proposed GHG Emissions Calculation and Monitoring Methods 

Comment:  Multiple commenters requested the language in 40 CFR part 98,
subpart S be changed to allow emissions to be reported by “all kilns
combined” instead of the proposed rule’s request to report emission
for each kiln.  Multiple commenters further recommended that the process
emissions calculations be changed to calculate emissions by the lime
type produced as opposed to the current rule calculations which use a
kiln specific emission factor.  Two commenters stated that lime products
are commonly aggregated at the plant making it difficult to estimate the
amount of product produced at an individual kiln.  These commenters
stated that current lime plant configuration do not allow accurate kiln
specific calculations.

Response:  We have reviewed the common lime plant configuration and the
currently proposed rule language and have decided that it is not
necessary to require kiln-specific emissions reporting, as emission
factors are determined in the proposed rule by lime type.  Some.  We
have observed that some kilns would have to retrofit weigh belt scales
in the production line between kilns and storage silos, since they do
not currently exist.  Calculating emissions by kiln could increase the
reporting burden for these facilities.  According to one commenter, when
kiln-specific emissions have been reported in the past, the data are
usually derived by distributing the aggregated emissions among the
kilns.  Accurate measurements at the kiln level are rarely
used.achieved.  If this is true for most lime manufacturing facilities,
the data does not necessarily provide a better estimate of emissions.   

For the purposes of this rulemaking, reporting for all kilns combined
will simplify and minimize the reporting burden without significant loss
in accuracy because: (1) kilns may produce more than one type of lime in
a given reporting period, (2) emission factors are based on lime type,
and (3) lime plants collect products in combined bagging areas
(separated by lime type).  The final rule language has been changed to
require reporting by lime type from all kilnkilns combined rather than
all lime types for each kiln.  This final rule language is consistent
with the National Lime Association (NLA) Protocol, which was used as the
basis for the methodology in the proposed rule.  Information collected
under this rule will help to inform future methodologies and determine
whether kiln level reporting could be more appropriate for future
reporting.  

Comment:  The proposed rule used a default correction factor in
calculating lime product and byproduct/waste emissions.  Multiple
commenters suggested using the National Lime Association Protocol to
determine lime product and by-product/waste process emissions. 
According to the commenters, this method is more precise due to the use
of measured oxide values and stoichiometrystoichiometric ratios rather
than correction factors.  

Response:  We have reviewed the proposed rule and NLA Protocol
calculation methods and noted that the use of actual oxide measurements
in calculating emissions from lime plants does not cause an additional
burden to the reporter andsince this is a currently used practice.  We
also agree that the use of actual measurements is more accurate. 
Therefore, we have decided to remove the use of a correction factor in
the final rule equations; emissions will be calculated from actual oxide
measurements of each type of lime and calcined byproducts/wastes.  

Monitoring and QA/QC Requirements 

Comment:  Multiple commenters asked that the language pertaining to
allowable measurement devices for lime products and byproducts/wastes
sold, be changed to include measurement devices commonly used in the
lime industry.  The current rule language requires weigh hoppers and
belt weigh feeders as the measurement devices; the aforementioned
commenters have identified bag, truck and rail scales as reliable
(annually calibrated) direct measurement methods commonly used in the
lime industry.  In addition, commenters have requested lime
byproducts/wastes not sold be calculated by a facility generation rate.

Response:  After reviewing the rule language and common industry
practices, we have decided to include other direct measurement devices
used for accounting purposes, including but not limited to, weigh
feeders, calibrated bag, rail or truck scales, and barge measurements. 
These methods are consistent with the original intent of the rule and
add further clarification on measurement methods applicable to determine
quantities of both lime produced and byproducts/waste generated.

In addition, reporters are required to perform an annual cross check by
measuring lime products at the beginning and end of the year.  For
calcined byproducts/wastes not sold, a material balance approach that
indirectly measures the generation rate should be used.

Comment:  Multiple commenters asked that the language in 40 CFR part 98,
subpart S pertaining to testing the chemical composition of each type of
lime (including the byproducts and waste) be changed to allow testing by
onsite lab facilities.  Currently the rule specifies an “off-site
laboratory analysis” but according to the commenter, commercial lime
plants normally have onsite lab facilities.

Response:  We agree that the analysis does not have to be performed by
an independent certified laboratory, especially since we specify the
analytical procedures that must be used by any laboratory, and we note
that in-house laboratories may have more applicable experience in
determining chemical composition.  Reporters can determine whether to
perform the test onsite or send the samples to offsite laboratory
facilities.  Therefore the language in the final rule has been changed.

Data Reporting Requirements

Comment:  Multiple commenters requested the language in 40 CFR part 98,
subpart S pertaining to reporting information to EPA be changed so that
business sensitive information is kept in company records.  Commenters
argueagree that while the production capacity, product
quantityproductquality (i.e., oxide content), emission factors and
operating hours and days for each kiln, are required for emissions
calculations but are concerned that making this information public,
would give information about their efficiency, productivity and capacity
of kilns and facility.

Response:  EPA reviewed CBI comments received across the rule (both
general and subpart-specific comments) and our response is discussed in
Section II.R of this preamble for legal issues.  Also, see Section II.N
of this preamble for the response to comments on the emissions
verification approach.

We agree that annual operating hours and capacities are not used in the
calculation of CO2 emissions and these parameters have been moved to
recordkeeping.  This information can help to verify anomalies in
emissions data if there were temporary shutdowns, etc.

We disagree that emission factors and product quantityquality be
maintained as records rather than be reported.  Emission factors and
product quantityquality are used in calculations to establish the site
specific rate of CO2 emissions generated for each type of lime produced.
 Therefore these data are required in order to verify the CO2 emissions
that are being reported.  This internal verification system ensures that
the GHG emissions reported are as accurate as possible.

T.  Magnesium Production 

At this time EPA is not going final with the magnesium production
subpart (40 CFR part 98, subpart T).  For the immediate future, EPA
believes that emissions of greenhouse gasesGHGs from magnesium
production are sufficiently covered by the reporting requirements under
Subpart40 CFR part 98, subpart OO for Industrial Gas Supply.  This
information on U.S. production, imports, and exports of SF6 will provide
at least a general, order-of-magnitude check on consumption of SF6 by
magnesium production and other uses of SF6.  EPA will finalize the
proposed reporting requirements for the magnesium production industry at
a later date.

U.  Miscellaneous Uses of Carbonate 

1.  Summary of the Final Rule 

Source Category Definition.  The Miscellaneous Uses of Carbonate source
category consists of any facility that uses carbonates listed in Table
U-1 of 40 CFR part 98, subpart U in manufacturing processes that emit
carbon dioxide.  The Table includes the following carbonates: limestone,
dolomite, ankerite, magnesite, siderite, rhodochrosite, or sodium
carbonate, or any other carbonate in a manufacturing process that emits
carbon dioxide.  

. Facilities are considered to emit CO2 if they consume at least 2,000
tons per year of the carbonates listed above and that are heated to a
temperature sufficient to allow calcination to occur.

This source category does not include facilities processing carbonates
or carbonate containing minerals consumed for producing cement, glass,
ferroalloys, iron and steel, lead, lime, phosphoric acid, pulp and
paper, soda ash, sodium bicarbonate, sodium hydroxide or zinc as CO2
emissions from these processes are covered elsewhere in the this rule.

Reporters must submit annual GHG reports for facilities that meet the
applicability criteria in the General Provisions (40 CFR 98.2)
summarized in Section II.A of this preamble.

GHGs to Report.  For miscellaneous uses of carbonates, report the
following emissions:

Annual CO2 process emissions for all miscellaneous uses of carbonates as
specified in this subpart.

CO2, N2O, and CH4 emissions from carbonates used in sorbent technology
and each stationary combustion unit on site under 40 CFR part 98,
subpart C (General Stationary Fuel Combustion Sources). 

In addition, report GHG emissions for other source categories at the
facility for which calculation methods are provided in the rule, as
applicable.  

GHG Emissions Calculation and Monitoring.  Calculate process CO2
emissions using annual carbonate consumption.  All reporters must
calculate the annual mass of carbonates used in processes which are
heated to temperatures that allow calcination.  If the annual amount of
carbonates consumed is greater than 2,000 tons, CO2 emissions must be
calculated using either calcination fractions or the actual mass of
input/output carbonates.

Data Reporting.  In addition to the information required to be reported
by the General Provisions (40 CFR 98.3(c)) and summarized in Section
II.A of this preamble, reporters must submit additional data that are
used to calculate GHG emissions.  A list of the specific data to be
reported for this source category is contained in 40 CFR part 98,
subpart U.

Recordkeeping.  In addition to the records required by the General
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this
preamble, reporters must keep records of analyses and calculations
required for this source category.

2.  Summary of Major Changes Since Proposal 

The major changes since proposal are identified in the following list. 
The rationale for these and any other significant changes can be found
below or in the comment response document for“Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to Public Comments, Subpart U:
Miscellaneous Uses of Carbonates.”

The source category definition was revised to exclude non-emissive uses
of carbonates.  

A de minimis reporting threshold was added to exclude facilities with
minor emissions based on annual carbonate consumption.

The GHG calculation methodology was changed to allow reporters to
determine emissions from the mass of carbonate input/output or
calcination fractions.

To improve the emissions verification process, 40 CFR 98.216 was
reorganized and updated.  Some data elements were moved from section40
CFR 98.217 to section40 CFR 98.216, and some data elements that a
reporter must already use to calculate GHG as specified in section40 CFR
98.213 were added to section40 CFR 98.216 for clarity.

3.  Summary of Comments and Responses

This section contains a brief summary of major comments and responses. 
A large number of comments on miscellaneous uses of carbonates were
received covering numerous topics.  Most comments requested
clarification on the definition of the source category and its
applicability to affected sources.  Responses to significant comments
received can be found in the comment response document for miscellaneous
uses of carbonates in the docket (EPA-HQ-OAR-2008-0508-XXX).Responses to
significant comments received can be found in “Mandatory Greenhouse
Gas Reporting Rule: EPA’s Response to Public Comments, Subpart U:
Miscellaneous Uses of Carbonates.”

Definition of source category

Comment:  Multiple commenters requested that the source category be
revised to exclude non-emissive uses of carbonates.  Commenters stated
that the source category is poorly defined, making it difficult to
accurately assess its applicability to an industrial facility. 
Commenters noted a number of non-emissive uses as examples, such as the
production of sodium bicarbonate and sodium hydroxide, during which
sodium carbonates are used, but no carbon dioxide is released; onsite
mixing of processed cement with aggregate, limestone used in poultry
grit and as an asphalt filler; or adding sodium carbonate to a water
softener system.

Response:  The rule language has been modified to exclude non-emissive
uses of carbonates.  Non-emissive uses do not result in CO2 emissions,
such as adding sodium carbonate to a water softener system. 
Acid-induced releases of CO2 from the use of carbonates are addressed in
other subparts, where they are significant, such as Phosphoric Acid
Production.

Selection of Threshold

Comment:  Multiple commenters requested that a de minimus reporting
threshold be added to exclude facilities with minor emissions.  One
commenter noted that some facilities use limestone and other carbonate
as refractory in furnaces, and it is unclear whether or not this use of
carbonates triggers 40 CFR part 98, subpart U, and at what level it is
triggered. 

One commenter noted that at a pharmaceutical manufacturing facility
there would also be a significant listing of small operations and
activities which use carbonate compounds in trace quantities, including
the creation of reagent solutions, and wastewater treatment operations
employing carbonate compounds for buffering, chemical precipitation, or
solids stabilization. This commenter recommended that EPA implement a
threshold of 2,000 tons per year of carbonates per facility, which would
correlate to CO2 emissions of about 1,000 tons per year.

One commenter requested that EPA incorporate a de minimis threshold to
only include equipment where carbonate is present at greater than 10%
percent by weight and heated to a temperature that allows for
decomposition.  This commenter suggested an alternative threshold, where
EPA would require facilities to calculate CO2 emissions from each type
of carbonate used in quantities exceeding 2,000 tons per year.

Response:  The rule language has been modified to specify that GHG
emissions from miscellaneous carbonate use are required to be reported
only from processes that consume at least 2,000 tons per year and,
further, where the carbonates are heated to a temperature sufficient to
allow the calcination reaction to occur.  This modification to the
definition of the source category allows facilities with minimal
carbonate consumption and low amounts of GHG emissions to be excluded
from reporting emissions.

Method for Calculating GHG Emissions

Comment:  Multiple commenters requested that EPA allow emission
calculations to be based on carbonate fraction of the product instead of
calcination fractions.  One commenter noted that in acid scrubbing for
SO2, one molecule of CO2 is formed for each molecule of SO2 captured,
thus direct measurement of sulfur removal efficiency is a more accurate
means of determining CO2 emissions from scrubber systems.

Response:  The rule has been changed to allow emission calculations by
either the mass of carbonate input/output or calcination fraction. 
These methods should provide comparable estimates of emissions.  

The calcination fraction method calculates the amount of CO2 emissions
based on the based on the amount of each carbonate that is calcined
during the process.  The mass and calcination fraction of each carbonate
are measured and used with a default CO2 emission factor to determine
CO2 emissions.

The carbonate fraction method calculates the amount of CO2 emissions as
a mass balance between the input and output amount of each type of
carbonate that is input and output from the kiln.  The masses are
measured and used with a default CO2 emission factor to determine CO2
emissions.

The mass of carbonate input/output is determined by use of the same
plant instruments used for accounting purposes or by direct measurement.
 Calcination fractions can be measured by the appropriate industry
consensus standards that require laboratory analysis of each carbonate
type.  Alternatively, a default value of 1 one can be used as the
calcination fraction.

Emissions from carbonates used in sorbent technology (such as scrubbers)
should be calculated and reported under subpart C (General Stationary
Combustion), 40 CFR 98.33 “Calculation of CO2 from Sorbent.”

Data Reporting Requirements and Records That Must be Retained

Comment:  One commenter requested that recordkeeping and reporting
requirements be exempted for carbonates kept on-site for emergency
purposes (not manufacturing or equipment), such as for neutralizing a
chemical spill.  This commenter explained that when used, these
emergency reserves of carbonate material typically generate
insignificant amounts of CO2 and should therefore be excluded from
reporting requirements.

Response:  The final rule does not cover carbonates that are used in
quantities of less than 2,000 tons per year and that are not heated to
the point of calcination.  Also, this subpart does not include
requirements for calculating and reporting CO2 emissions from acid
neutralization.  Therefore, the use of carbonates in the manner
described is not covered by the final rule. 

Comment:  One commenter noted that the required records are duplicated
in sectionproposed 40 CFR 98.217(a) and 98.217(c), and requested that
EPA revise this so as not to place unnecessary costs on facilities. 

Response:  EPA agrees that asking facilities to maintain records on
procedures used to ensure the accuracy of monthly carbonate consumption
will be duplicative with maintaining records of all carbonate purchases
and deliveries.  This is especially true if purchase records are used to
determine monthly carbonate consumption.  We removed this duplicative
recordkeeping requirement from the rule.  

To improve the emissions verification process, section 40 CFR 98.216 was
reorganized and updated.  Some data elements were moved from section40
CFR 98.217 to section40 CFR 98.216, and some data elements that a
reporter must already use to calculate GHG as specified in section40 CFR
98.213 were added to section40 CFR 98.216 for clarity.  All affected
sources must follow the general recordkeeping provisions under 40 CFR
part 98.3(g) in subpart A.  

Commenters may also want to review Section II.M  for the response on the
general recordkeeping requirements and Section II.N of this preamble for
the response on the emissions verification approach.

V.  Nitric Acid Production 

1.  Summary of the Final Rule 

Source Category Definition.  The nitric acid production source category
consists of facilities that use one or more trains to produce weak
nitric acid (30 to 70 percent in strength) through the catalytic
oxidation of ammonia. 

Reporters must submit annual GHG reports for facilities that meet the
applicability criteria in the General Provisions (40 CFR 98.2)
summarized in Section II.A of this preamble.

GHGs to Report.  For nitric acid production facilities, report N2O
process emissions from each nitric acid train. 

In addition, report GHG emissions for other source categories at the
facility for which calculation methods are provided in the rule, as
applicable.  For example, report CO2, N2O, and CH4 emissions from each
stationary combustion unit on site under 40 CFR part 98, subpart C
(General Stationary Fuel Combustion Sources). 

GHG Emissions Calculation and Monitoring.  Reporters must calculate N2O
process emissions for each nitric acid train.  Calculate the emissions
by multiplying the site-specific emission factor for each train by the
measured annual nitric acid production for that train.  Determine the
site-specific emission factor for each train through an annual
performance test to measure N2O from the absorber tail gas vent and the
production rate for that train.

When N2O abatement devices (such as nonselective catalytic reduction)
are used, adjust the N2O process emissions for the amount of N2O removed
using a destruction efficiency factor.  The destruction factor is the
destruction efficiency can be specified by the abatement device
manufacturer.  Reporters can also determine this factor or can be
determined using process knowledge or another performance test.

Data Reporting.  In addition to the information required to be reported
by the General Provisions (40 CFR 98.3(c)) and summarized in Section
II.A of this preamble, reporters must submit additional data that are
used to calculate GHG emissions.  A list of the specific data to be
reported for this source category is contained in 40 CFR part 98,
subpart V.

Recordkeeping.  In addition to the records required by the General
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this
preamble, reporters must keep records of additional data used to
calculate GHG emissions.  A list of specific records that must be
retained for this source category is included in 40 CFR part 98, subpart
V.

2.  Summary of Major Changes Since Proposal 

The major changes since proposal are identified in the following list. 
The rationale for these and any other significant changes can be found
below or in the comment response document for“Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to Public Comments, Subpart V: Nitric
Acid Production.”

The re-testing trigger was eliminated.changed.  Performance testing is
only required annually to determine the N2O emissions factor is required
annually and whenever new abatement technology is installed.  The
performance test should be conducted under normal operating parameters.

Equation V-2 was edited to correct a calculation error and to allow
multiple types of abatement technologies. 

Reorganized and updated Section40 CFR 98.226 to improve the emissions
verification process.  Some data elements were moved from section40 CFR
98.227 to section40 CFR 98.226, and some data elements that a reporter
must already use to calculate GHGs as specified in section40 CFR 98.223
were added to section40 CFR 98.226 for clarity.

 3.  Summary of Comments and Responses 

This section contains a brief summary of major comments and responses. 
A large number of comments on nitric acid production were received
covering numerous topics.  Responses to significant comments received
can be found in the comment response document for nitric acid production
in the docket (EPA-HQ-OAR-2008-508-XXX).Responses to significant
comments received can be found in “Mandatory Greenhouse Gas Reporting
Rule: EPA’s Response to Public Comments, Subpart V: Nitric Acid
Production.”

GHGs to Report

Comment:  Multiple commenters asked that the language in section40 CFR
98.222(b) be clarified to include emissions under 40 CFR part 98,
subpart V only from units that are 100% percent dedicated to nitric acid
production to avoid double counting of combustion emissions. 

Response:  We appreciate the comments but have decided not to make any
changes to 40 CFR part 98, subpart V.  According to the applicability
criteria in subpart C, all combustion unit emissions from nitric acid
facilities (regardless of whether or not the combustion units are
associated with nitric acid production operations) are to be reported
under subpart C.  There will be no potential for double counting of
combustion emissions at the facility because all combustion unit
emissions are to be reported under subpart C.  Subpart V provides
methods for reporting only the process N2O emissions.  Also see the
preamble for responses on comments related to Subpart C (General
Stationary Combustion).

Method for Calculating GHG Emissions

Comment:  Multiple commenters asked that the requirement to repeat the
annual performance test be removed.  In the proposal, re-testing was
triggered whenever the nitric acid production rate changed by more than
10 percent.  Commenters asserted that production depends on demand for
nitric acid and often varies by up to 20 percent.

Response:  We appreciate the comments and have decided to eliminate
re-testing.  We believe that annual determination of the N2O emissions
factor is sufficient to accurately calculate N2O emissions as long as
the train equipment remains consistent over the year-long period (i.e.
no installation of abatement technology).

Comment:  Multiple commenters asked that alternative methods be allowed
for calculating N2O emissions from nitric acid production.  Specifically
the commenters asked that EPA allow the use of N2O and flow CEMS to
directly measure N2O emissions and use the performance test to evaluate
the CEMS accuracy.  They also requested that EPA allow use of existing
process flow meters, process N2O analyzers to determine the amount of
N2O sent to control devices and conduct a performance test measuring
control device destruction efficiency for each control device and then
calculate N2O emissions.

Commenters also asked that finalizing a methodology for N2O stack
testing for nitric acid units be delayed until EPA can coordinate with
the commenters in formulating a more accurate means of measurement from
these sources.

Response:  We agree that there are other accurate means of determining
N2O emissions, such as N2O CEMS.  The final rule has been changed to
allow alternative test methods, in addition to the proposed methods. 
Any alternative must be approved by the Administrator before being used
to comply with this rule.  An implementation plan that details how the
alternative method will be implemented must be included in the request
for the alternative method.  Currently there is no EPA method for using
N2O CEMs.CEMS.  EPA understands the need to further evaluate and
establish alternative comparable or potentially more accurate methods
for sources to use in calculating N2O emissions from nitric acid
production and will address in future rulemakings or amendments to
rulemaking.  Until the method is approved facilities must use the
alternatives proposed in the rule for a performance test.  At minimum
the performance test will help to QA/QC alternative methods currently
used to monitor N2O emissions (including N2O CEMS). 

The final rule allows the use of existing process flow meters and
process knowledge in the determination of parameters used in the
calculation of N2O emissions, such as the destruction factorefficiency
of N2O abatement technologies.  These parameters are This parameter is
often based on site-specific knowledge and of operations in combination
with manufacturer specifications.  We believe that using existing
methods reduces the potential cost impacts of this rulemaking and that
it is in the best interest of the facilities that production rates and
destruction factors required parameters be accurately measured.  

Comment:  Multiple commenters asked that Equation V-2 be edited to
follow the summation format used in the IPCC Tier 2 methodology.  The
current format does not allow for multiple abatement technologies
(including no abatement).

Response:  We agree with this comment.  The equation in the proposed
rule contained an error and did not allow for multiple abatement
technologies.  The final rule contains a corrected version of the
equation.

Data Reporting Requirements

Comment:  Multiple commenters argued that the annual production rates,
capacity and operating hours are considered CBI and should not be
reported.  The commenters asked that this information be maintained by
the facility and made available to the Agency upon request.

Response:  We reviewed CBI comments received across the rule (both
general and subpart-specific comments) and our response is discussed in
Section II.R of this preamble and in the comment response document for
legal issues.“Mandatory Greenhouse Gas Reporting Rule: EPA’s
Response to Public Comments, Legal Issues.”  See also Section II.N of
this preamble for the response on the emissions verification approach.  

We agree that annual operating hours are not used in the calculation of
N2O emissions and this parameter has been moved to recordkeeping.
However, this parameter is still important for emissions verification.
This information can help to verify anomalies in emissions data if there
were temporary shutdowns, etc.

We disagree that production be maintained as records rather than be
reported.  We need production rate in order to verify the N2O emissions
that are being reported.  Nitric acid production is a parameter in the
method for determining annual N2O emissions.  This so we need production
rate in order to verify the N2O emissions that are being reported.  The
internal verification system ensures that the GHG emissions reported are
as accurate as possible. 

We disagree that capacities be considered confidential information. 
During the data gathering process, we located multiple publicly
available sources that included production capacities for nitric acid
production facilities.  Capacity information can help EPA determine a
reasonable range within which reported emissions should be.  However, we
We agree that capacities are not used in the calculation of N2O
emissions; however, this is still an important parameter for verifying
emissions, so .  Therefore, this parameter has been moved to
recordkeeping.

W.  Oil and Natural Gas Systems 

At this time, EPA is not going final with the fugitive and vented
methane emissions from the oil and gas sector under Subpart40 CFR part
98, subpart W.  As EPA considers next steps, we will be reviewing the
public comments and other relevant information.   

EPA received a number of lengthy, detailed comments regarding Subpart40
CFR part 98, subpart W.  Commenters generally opposed the proposed
reporting requirements and thought they would entail significant burden
and cost.  For example, many commenters asserted that use of direct
measurement to collect data required under Subpart40 CFR part 98,
subpart W would entail significant burden and that the proposal lacked
standards for leak detection and measurement equipment.  In many cases,
commenters provided alternative approaches to the reporting requirements
proposed by EPA such as the use of emission factors and/or reducing the
number of sources and sites requiring direct measurement e.g., through
statistical sampling.  In addition to comments on burden, commenters
requested clarification from EPA on a number of proposed reporting
provisions. 

As EPA received extensive comments on this subpart, EPA plans to take
additional time to perform additional analysis and consider alternatives
to data collection procedures and methodologies.  These alternatives
will provide similar coverage of vented and fugitive methane and other
greenhouse gasGHG emissions in the oil and gas sector, while
concurrently taking into account industry burden.  As stated in Section
V.W of the draft Subpart W preamble to the proposed rule (74 FR 166606,
April 10, 2009), EPA will also consider the inclusion of greenhouse
gasGHG reporting from other sectors of the oil and gas industry. 

Where applicable, EPA will also consider the applicability of
engineering estimates, emissions modeling software and emissions factors
rather than relying so extensively on the use of direct measurement. 
EPA will consider optimal methods of data collection in order to
maximize data accuracy, while considering industry burden.

X.  Petrochemical Production 

1.  Summary of the Final Rule 

Source Category Definition.  The petrochemical production source
category consists of all processes that produce acrylonitrile, carbon
black, ethylene, ethylene dichloride, ethylene oxide, or methanol, with
certain exceptions.  Exceptions include processes that produce a
petrochemical as a byproduct, processes that produce methanol from
synthesis gas when the annual mass production of hydrogen or ammonia
exceeds the annual mass of methanol produced, direct chlorination
processes operated independently of oxychlorination processes to produce
ethylene dichloride, processes that produce bone black, and processes
that produce a petrochemical from bio-based feedstock.

Reporters must submit annual GHG reports for facilities that meet the
applicability criteria in the General Provisions (40 CFR 98.2)
summarized in Section II.A of this preamble.

GHGs to Report.  For petrochemical production facilities, report CO2,
CH4, and N2O process emissions from each petrochemical production unit. 
Process emissions include CO2 generated by reaction in the process. 
Process emissions also include CO2, CH4, and N2O emissions generated by
combustion of off-gas from the process in stationary combustion units
and flares.  For some of the GHG emission calculation and monitoring
options, 40 CFR part 98, subpart X references procedures in 40 CFR part
98, subpart C for calculating emissions from stationary combustion
sources, and it references procedures in 40 CFR part 98, subpart Y for
calculating emissions from flares.

In addition, report GHG emissions for other source categories at the
facilities for which calculation methods are provided in the rule, as
applicable.  For example, report CO2, N2O, and CH4 emissions from each
stationary combustion unit on site that does not burn process off-gas
under 40 CFR part 98, subpart C (General Stationary Fuel Combustion
Sources).  The quantity of CO2 captured must also be reported by
following the requirements of 40 CFR part 98, subpart PP.

GHG Emissions Calculation and Monitoring.  CO2 process emissions from
petrochemical production must be determined by one of three methods. 
Process emissions include emissions from CO2 generated by chemical
reactions in the process and from the combustion of process off-gas and
liquid wastes.

One emission calculation option is to route all process vent emissions
to one or more stacks and use CEMS to measure the CO2 emitted from each
stack (except flare stacks).  For each stack that includes emissions
from combustion of process off-gas, reporters must calculate CH4 and N2O
emissions by the procedures specified in 40 CFR part 98, subpart C.  For
each flare, the final rule requires CO2, CH4, and N2O emissions to be
calculated using the procedures in 40 CFR 98.253(b) (Petroleum
Refineries).  If CO2 CEMS are used on all subject stacks, even if the
CEMS were installed for reasons other than compliance with this rule,
then the rule requires the use of this reporting option.

A second emission calculation option is to use a mass balance.  Under
this option, the quantity of each carbon-containing feedstock added to
the process and the quantity of each carbon-containing product produced
by the process must be measured for each calendar month, or it may be
calculated based on measured changes in the liquid level in storage
tanks.  The carbon content of each feedstock and product also must be
determined at least once per month.  The carbon content may be measured
directly, or it may be calculated based on measurements of the
composition and known compound molecular weights.  Under this option,
the procedures for products also apply to byproducts and liquid organic
wastes that are not combusted onsite.  To prevent double-counting of
combustion emissions, this option specifies that the procedures for
stationary combustion sources in 40 CFR part 98, subpart C apply only to
the supplemental fuel (e.g., natural gas) burned in combustion units
that supply energy needs for petrochemical processes.  The final rule
specifies numerous measurement method options and related calibration
requirements in 40 CFR 98.244.  To potentially minimize the sampling and
analysis burden, the final rule, like the proposed rule, includes an
option that allows reporters to assume a feedstock or product is always
100 percent pure if they determine that the specified compound is always
present at greater than 99.5 percent.

A third emission calculation option is available only for ethylene
processes.  Because nearly all process emissions from this process are
from combustion of process off-gas, the final rule allows calculation of
emissions from all stationary combustion units that burn process off-gas
(with or without supplemental fuel) in accordance with the Tier 3 or
Tier 4 procedures in 40 CFR part 98, subpart C.  In addition, this
option requires CO2, CH4, and N2O emissions from each flare to be
calculated using the procedures in 40 CFR 98.253(b) (Petroleum
Refineries).

Data Reporting.  In addition to the information required to be reported
by the General Provisions (40 CFR 98.3(c)) and summarized in Section
II.A of this preamble, reporters must submit additional data that are
used to calculate GHG emissions.  A list of the specific data to be
reported for this source category is contained in 40 CFR 98.246.

Recordkeeping.  In addition to the records required by the General
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this
preamble, reporters must keep records of additional data used to
calculate GHG emissions.  A list of specific records that must be
retained for this source category is included in 40 CFR 98.247.

2.  Summary of Major Changes Since Proposal 

The major changes since proposal are identified in the following list. 
The rationale for these and any other significant changes can be found
below or in the comment response document for“Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to Public Comments, Subpart X:
Petrochemical Production.”

The definition of the source category was changed to exclude ethylene
dichloride production by the direct chlorination process alone from the
petrochemical production source category because the only GHG emissions
from this process are from the combustion of supplemental fuel and the
combustion of hydrocarbon emissions in air pollution control devices. 
Ethylene dichloride produced by both direct chlorination and
oxychlorination in the “balanced process” is still part of the
source category.

For the mass balance option, the measurement and emission calculation
frequency was changed from weekly to monthly.

For ethylene processes, an alternative was added to the mass balance
option that allows reporters to calculate emissions from stationary
combustion sources that burn ethylene process off-gas (with or without
supplemental fuel) using the Tier 3 or Tier 4 procedures in 40 CFR part
98, subpart C.  This includes all such combustion units, including units
that supply energy to processes other than the ethylene process.  This
option does not affect requirements for stationary combustion sources
related to ethylene processes that burn no process off-gas; emissions
from these combustion units still must be calculated using the methods
in any applicable Tier in 40 CFR part 98, subpart C.

The reporting requirements in section40 CFR 98.246 were reorganized and
updated to facilitate the emissions verification process, simplify and
clarify requirements, and address requirements for the new monitoring
option for ethylene processes. 

3.  Summary of Comments and Responses 

This section contains a brief summary of major comments and responses. 
Many comments on petrochemical production were received covering
numerous topics.  Responses to significant comments received can be
found in the comment response document for petrochemical production in
the docket (EPA-HQ-OAR-2008-508-XXX).Responses to significant comments
received can be found in “Mandatory Greenhouse Gas Reporting Rule:
EPA’s Response to Public Comments, Subpart X: Petrochemical
Production.”

Definition of Source Category. 

Comment:  Several commenters stated that ethylene production should be
removed from the petrochemical production source category because
essentially all GHG emissions from such processes are from combustion
sources, which would be subject to reporting under 40 CFR part 98,
subpart C regardless of whether the process is included in the
petrochemical production source category.  According to two commenters,
using a mass balance approach is irrelevant and confusing because
ethylene processes have no normal process vents.  One commenter noted
that methane is produced in ethylene processes, but the vast majority is
returned as fuel within the plant or another plant at the same site and
thus would produce CO2 emissions only when combusted.  Another commenter
noted that off-gas from ethylene processes that are co-located with a
petroleum refinery or other chemical plants is sent to the fuel gas
system where it is mixed with other process gases from non-ethylene
units in a fuel gas blend drum and then distributed to combustion units
throughout the refinery and/or chemical plant.  According to two
commenters, the mass balance approach is onerous due to the number of
product streams that would have to be measured, and the results of a
mass balance most likely would be less accurate than a fuel combustion
methodology.  These two commenters also noted that calculating GHG
emissions based on fuel combustion is the methodology used currently by
most ethylene units.  One commenter suggested that as an alternative to
excluding ethylene units from the petrochemical production source
category, EPA could add an emission calculation methodology to 40 CFR
part 98, subpart X that would allow facilities to calculate combustion
emissions based on fuel consumption.

Response:  As one commenter noted, methane (and other light ends) are
generally burned in combustion units to supply energy needs for the
ethylene process itself and possibly other processes.  Emissions from
combustion of these process off-gases are process emissions that are
intended to be reported under 40 CFR part 98, subpart X.  At facilities
where the ethylene process off-gases are not mixed with off-gas from
other processes, we do not believe that the mass balance approach is
illogical; the flows and carbon contents of feedstocks and products can
be determined for an ethylene process, and the resulting values can be
used in the mass balance equations, just as they can for any other
petrochemical process.  Furthermore, we do not know if the views of the
commenters reflect the views of all ethylene manufacturers.  Therefore,
we have retained ethylene in the petrochemical production source
category, and we have retained the mass balance option in the final
rule.

Although we still think a mass balance approach is appropriate and valid
for ethylene processes, we have also evaluated combustion-based
methodology options for the final rule.  Given that the cracking and
separation operations generate negligible CO2, we agree with the
commenters that the only significant source of emissions in ethylene
production is from combustion operations.  One concern we have with
using the Tier 1 and Tier 2 methodologies in 40 CFR part 98, subpart C
is that they rely on default emission factors and company records
(rather than measurements) of fuel flow.  Given the variety of
feedstocks and the corresponding variety in process off-gas, we do not
believe default emission factors or fuel flow based on company records
are appropriate.  Therefore, we rejected the Tier 1 and Tier 2
methodologies.  On the other hand, Tier 3 requires measurement of the
total fuel flow and relatively frequent measurement of the carbon
content of the fuel.  Using CEMS to measure CO2 emissions (i.e., the
Tier 4 methodology in 40 CFR part 98, subpart C) is also a good way to
measure CO2 emissions from any combustion unit.  Therefore, we
determined that use of the Tier 3 or Tier 4 methodology is acceptable
for calculating emissions from combustion units that burn ethylene
process off-gas (with or without mixing with supplemental fuel), and
these options are included in the final rule.  In addition, because the
methodology used for calculating emissions from one combustion unit has
no bearing on the emissions from any other combustion unit, the final
rule states that a facility is not required to use the same Tier for
each stationary combustion unit.

Comment:  One commenter requested that EPA remove ethylene dichloride
(EDC) from the petrochemical source category because EDC is not
manufactured using a fossil fuel-based feedstock (e.g., crude oil,
naphtha, natural gas condensate, methane, or other fossil fuel-based
chemicals), no GHGs are used in the manufacturing process, and only a
trace amount of CO2 is generated in the process.  Another commenter
requested clarification that EDC produced as an intermediate in the
production of vinyl chloride monomer is not part of the petrochemical
source category because the entire process is considered to be an
“integrated process”, and the primary product of the process is not
EDC.  The commenter noted that the term “primary product” is also
used in the Hazardous Organic NESHAP (HON) (40 CFR part 63, subpart F),
but it has a different definition.  To avoid confusion created by
multiple definitions for the same term, the commenter urged EPA to
consider alternatives to the concept of primary product for determining
applicability of an integrated process.

Response:  EDC is produced by two processes.  In one process, the direct
chlorination process, ethylene is reacted with chlorine to create EDC. 
As the commenters noted, reactions in this process produce negligible
CO2 emissions and no other GHG emissions.  The only GHG emissions
associated with this process are from the combustion of process off-gas
and supplemental fuel.  We have determined that monitoring and reporting
of these emissions will be required under 40 CFR part 98, subpart C. 
Therefore, we have removed this process from the petrochemical source
category.

In the second EDC process, the oxychlorination process, ethylene is
reacted with hydrochloric acid to create EDC and water.  Some of the
ethylene, however, oxidizes to CO2 and water in a competing side
reaction.  All facilities in the United States (U.S.) that operate this
process operate it as part of an integrated process that includes vinyl
chloride monomer production and a direct chlorination process.  This
integrated process is called a “balanced process”.  Although
available estimates suggest the amount of CO2 emitted is small relative
to emissions from combustion, we do not have data to support such
estimates.  Furthermore, even if small relative to other sources, the
total amount is not necessarily insignificant.  We continue to believe
information about these emissions is needed in order to support future
policy decisions regarding petrochemical processes.  Therefore, we have
not removed EDC production by the balanced process from the
petrochemical production source category.

In the proposed rule, an “integrated process” was defined as “a
process that produces a petrochemical as well as one or more other
chemicals that are part of other source categories” subject to
reporting under 40 CFR part 98.  This concept does not apply to
production of EDC as an intermediate that is used in the onsite
production of vinyl chloride monomer because vinyl chloride monomer
production is not a source category that is subject to reporting under
40 CFR part 98.  We used general language in the proposed rule that
would apply to various integrated process scenarios, but the only
scenario we know of that meets these conditions is methanol production
from synthesis gas that is sometimes also used to produce hydrogen
and/or ammonia (both of which are subject to reporting under other
subparts in 40 CFR part 98).  Because this is the only situation where
the “integrated process” concept would apply, we decided to replace
it in the final rule with language in §40 CFR 98.240 that explicitly
states the applicability determination procedures for a process that
produces methanol, hydrogen, and/or ammonia from synthesis gas.  Thus,
the term “primary product” has also been removed from the final
rule, which eliminates the potential conflict with the definition in the
HON.  

Method for Calculating GHG Emissions.

Comment:  Two commenters stated that the proposed CEMS requirements are
overly restrictive.  According to these commenters, a facility should
have the option to install a CEMS on one or more sources without being
required to have a CEMS on all sources associated with a petrochemical
production process.  For example, the commenters suggested that a
facility should have the flexibility to use a CEMS on a large emission
point while being allowed to use the combustion equations and/or the
mass balance approach for smaller emission points in the process (e.g.,
start-up heaters and steam jet exhausts from distillation columns
operating under vacuum).

Response:  For the mass balance option to work, inputs and outputs of
process streams must be monitored.  It is not clear to us how to
accomplish this by monitoring only selected emission points within a
process.  Even if such monitoring is possible, it is unlikely that it is
being conducted currently, which would make such an approach more
burdensome than options specified in the rule.  Furthermore, we believe
the methodology should be standardized as much as possible, and it is
not clear how “small” emission points should be defined.Response: 
If some emissions were from stacks monitored with CEMS and all other
emissions were from combustion units without CEMS, it would be possible
to use a combination of CEMS and the combustion equation methodology to
calculate the total GHG emissions from a petrochemical process. 
However, this scenario is unlikely, which means other methodology would
be needed to estimate emissions from other emission points (e.g., the
steam jet exhausts cited by the commenters).  It is not clear to us how
the mass balance methodology would be used to estimate these other
emissions because the mass balance relies on knowledge of the total
carbon input to the process and the total amount of carbon in all
products (and organic liquid wastes); the difference is assumed to be
the total CO2 emissions.  Theoretically, other methodology could be
developed to calculate emissions from specific other emission points,
but the commenter has not suggested other techniques.  Therefore, the
final rule does not include an option to mix CEMS with the mass
balanceother methodology for a given process unit.  

Comment:  According to several commenters, weekly measurements of
feedstocks and products are burdensome or unwarranted.  Two commenters
suggested changing the frequency to monthly because monthly accounting
would align better with existing industry accounting procedures, reduce
the burden, and provide 12 high-quality estimates per year.  One
commenter suggested monthly mass balance calculations for carbon black
facilities because the emissions from a carbon black manufacturing
facility do not vary significantly from week to week.  Another commenter
requested a provision to allow the reporter to determine a sampling
frequency that is consistent with the variability of the stream.

Response:  We are sensitive to the burden imposed by the rule and want
to minimize it when possible.  Based on the results of an uncertainty
analysis (see memorandum entitled “Monte Carlo Simulation of
Uncertainty Analysisin Monitoring Frequency for Mass Balance Option for
Petrochemical Production Facilities” in the docket), we believe longer
monitoring periods will not significantly compromise the monitoring
results for the mass balance option.  Therefore, the mass balance option
in the final rule requires monthly monitoring instead of the proposed
weekly monitoring.

Data Reporting Requirements

Comment:  Two commenters stated that the proposed reporting requirements
are excessive, particularly information such as each carbon content
measurement and information on the calibration of each flow meter. 
According to the commenters, submitting this information will not
improve the overall quality of the GHG emission calculation, and it is
not necessary because the facilities are required to certify that the
submitted information is true, accurate, and complete.  Therefore, the
commenters recommended that facilities be required to retain records of
such information rather than submit it in reports. 

Response:  A primary reason that additional information beyond annual
emissions must be reported is so that EPA can verify the results.  To
facilitate the emissions verification process, section40 CFR 98.246 was
reorganized and updated.  For example, the final rule requires reporting
of all input data used in the emission calculation equations, not just
the carbon content values and the annual quantities, because this
information is needed so the calculations can be reproduced and
confirmed as part of the emissions verification process.  Note, however,
that any increase in the burden to report flow measurements has been
offset by the reduction in monitoring frequency from weekly to monthly. 
The reporting requirements in the final rule for the mass balance option
also have been simplified and clarified by replacing the requirement to
submit all information related to uncertainty estimates with a
requirement to submit only the dates and summarized results of
measurement device calibrations.  The estimated accuracy of measurement
devices and the technical basis for such measurements must also be
documented as part of the monitoring plan that is maintained onsite. 
The reporting section also was updated to include reporting requirements
for the new monitoring option for ethylene processes.

Y.  Petroleum Refineries 

1.  Summary of the Final Rule 

i.  Source Category Definition  

Petroleum refineries are facilities that produce gasoline, gasoline
blending stocks, naphtha, kerosene, distillate fuel oils, residual fuel
oils, lubricants, or asphalt (bitumen) by the distillation of petroleum
or the redistillation, cracking, or reforming of petroleum derivatives. 
The definition of petroleum refineries excludes facilities that distill
only pipeline transmix (off-spec material created when different
specification products mix during pipeline transportation), regardless
of the products produced.

Reporters must submit annual GHG reports for facilities that meet the
applicability criteria in the General Provisions (40 CFR 98.2)
summarized in Section II.A of this preamble.

ii.  GHGs to Report  

The refinery processes and gases that must be reported are listed in
Table Y-1 of this preamble along with the rule subpart that specifies
the calculation methodology that must be used. 

Table Y-1.  GHGs to Report

For this refinery process…	Report emissions of the listed GHGs by
following the requirements of the 40 CFR part 98, subpart indicated…

	CO2	CH4	 N2O

Stationary combustion	C	C	C

Flares	Y	Y	Y

Catalytic cracking	Y	Y	Y

Traditional fluid coking	Y	Y	Y

Fluid coking with flexicoking design	C/Y	C/Y	C/Y

Delayed coking	-	Y	-

Catalytic reforming	Y	Y	Y

Onsite and offsite sulfur recovery	Y	-	-

Coke calcining	Y	Y	Y

Asphalt blowing 	Y	Y	-

Equipment leaks	-	Y	-

Storage tanks	-	Y	-

Other process vents	Y	Y	Y

Uncontrolled blowdown systems	-	Y	-

Loading operations	-	Y	-

Hydrogen plants (nonmerchant)	P	P	-



Key: 

C = 40 CFR part 98, subpart C (General Stationary Combustion Sources)

P = 40 CFR part 98, subpart P (Hydrogen Production) 

Y = 40 CFR part 98, subpart Y (Petroleum Refineries)

- = Reporting from this process is not required

iii.  GHG Emissions Calculation and Monitoring  

Under 40 CFR part 98, subpart Y, petroleum refineries must calculate
CO2, CH4 and N2O emissions using the calculation methods described below
for each refinery process. 

For CO2 emissions, reporters must use CEMS or specified calculation
methods as follows: 

For refinery units with certain types of CEMS in place, reporters must
use the CEMS and follow the Tier 4 methodology of 40 CFR part 98,
subpart C to report combined process and combustion CO2 emissions.

For refinery units without CEMS in place, reporters can elect to either
(1) install and operate a CEMS to measure combined process and
combustion CO2 emissions according to the requirements specified in 40
CFR part 98, subpart C or (2) calculate CO2 emissions using the methods
summarized below. 

Flares.  CO2 emissions from flares must be calculated using the gas flow
rate (either measured with a continuous flow meter or calculated using
engineering calculations) and either: (1) at least weekly measured
carbon content of the flare gas, or (2) at least weekly measured heat
content of the flare gas and an emission factor provided in the rule. 
If the carbon content and heat content of the gas are not measured at
least weekly, engineering estimates of heat content during normal flare
use is allowed, but CO2 emissions for each startup, shutdown, and
malfunction event exceeding 500,000 standard cubic feet (scf) per day of
flare gas must be calculated separately using engineering estimates of
the quantity of gas discharged and the carbon content of the flared gas.
CH4 and N2O emissions from flares must be calculated using the methods
specified in 40 CFR part 98, subpart Y. 

Catalytic Cracking Units, Fluid Coking Units, and Catalytic Reforming
Units.  CO2 emissions must be calculated using the volumetric flow rate
of the exhaust gas (measured or calculated) and hourly measured carbon
monoxide (CO) and CO2 concentrations in the exhaust stacks from the
catalytic cracking unit regenerator and fluid coking unit burner from
units exceeding 10,000 barrels per stream day.  Catalytic cracking and
fluid coking units below this threshold must use the required flow and
gas monitors if they are in-place, but may use engineering estimates for
determining CO2 emissions if the required flow and gas monitors are not
in place.  Similarly, catalytic reforming units may use the flow and gas
monitors required for large catalytic cracking and fluid coking units;
alternatively, reporters may use engineering estimates based on the
quantity of coke burned off, the carbon content of the coke (using
either a measured or a default value), and the number of regeneration
cycles.  CH4 and N2O emissions may be measured or may be calculated
using the CO2 emissions and default emission factors.  Fluid coking
units that use the flexicoking design may account for their GHG
emissions either by using the methods specified for traditional fluid
coking units, or by using the methods for stationary combustion
specified in 40 CFR part 98, subpart C. 

Onsite and Off Site Sulfur Recovery.  CO2 emissions must be calculated
using the volumetric flow rate of the sour gas (measured continuously or
calculated from engineering calculations) and the carbon content of the
sour gas stream (using a measured or a default value). 

Coke Calcining Units.  CO2 emissions must be calculated from the
difference between the carbon input as green coke and the carbon output
as marketable petroleum coke and as coke dust collected in the dust
collection system. The CH4 and N2O emissions from coke calcining units
may be measured or calculated using the calculated CO2 emissions and
default emission factors. 

Asphalt Blowing Operations.  For uncontrolled asphalt blowing operations
or asphalt blowing operations controlled by vapor scrubbing, CH4 and CO2
emissions must be calculated using a facility-specific emission factor
based on test data or, where test data are not available, a default
emission factor provided in the rule.  For asphalt blowing operations
controlled by a thermal oxidizer or flare, CH4 and CO2 emissions must be
calculated by assuming 98 percent of the CH4 and other hydrocarbons
generated by the asphalt blowing operation are converted to CO2. 

Delayed Coking Units.  CH4 emissions from the depressurization of
delayed coking vessels must be calculated using the method outlined
below for other process vents.  The emissions released during the
opening of vessels for coke cutting operations must be calculated using
the vessel parameters (height and diameter), vessel pressure, the number
of times the vessel was opened, the void fraction of the coking vessel
prior to steaming, and the mole fraction of CH4 in the gas released
(using a measured or a default value provided in the rule). The rule
provides an alternative of using only the vessel parameter equation if
no water or steam is added to the vessel after the vessel is vented to
the atmosphere. 

Other Process Vents.  GHG emissions from other process vents that
contain CO2, CH4, or N2O exceeding concentration thresholds specified in
the rule must be calculated using the volumetric flow rate, the mole
fraction of the GHG in the exhaust gas, and the number of hours during
which venting occurred. 

Uncontrolled Blowdown Systems.  CH4 emissions from uncontrolled blowdown
systems must be calculated using either the method specified for process
vents or a default emission factor and the sum of crude oil and
intermediate products received from off site and processed at the
facility.

Equipment Leaks.  CH4 emissions from equipment leaks must be calculated
using either default emission factors or process-specific CH4
composition data and leak data collected using the leak detection
methods specified in EPA’s Protocol for Equipment Leak Emission
Estimates. 

Storage Tanks.  For storage tanks covered by the requirements of this
rule, the methodology used to calculate the CH4 emissions depends on the
material stored.  For storage tanks used to store unstabilized crude
oil, facilities must use either: (1) the CH4 composition of the
unstabilized crude oil (based on direct measurement or product
knowledge) and the measured gas generation rate; or (2) an emission
factor-based method using the quantity of unstabilized crude oil
received at the facility, the pressure difference between the previous
storage pressure and atmospheric pressure, the mole fraction of CH4 in
the vented gas (using either a measured or a default value), and an
emission factor provided in the rule.  For storage tanks used to store
material other than unstabilized crude oil with a vapor-phase CH4
concentration of 0.5 percent by volume or more, facilities must use
either tank-specific methane composition data and applicable
correlations in AP-42, Section 7.1 (as implemented in the TANKS Model
(Version 4.09D) or similar models) or a default emission factor provided
in the rule. 

Loading Operations.  CH4 emissions from loading operations must be
calculated using vapor-phase methane composition data and the method in
Section 5.2 of AP-42: “Compilation of Air Pollution Emission
Factors..”  Facilities must calculate CH4 emissions only for loading
materials that have an equilibrium vapor-phase CH4 concentration equal
to or greater than 0.5 percent by volume.  Other facilities may assume
zero CH4 emissions.

iv.  Data Reporting  

In addition to the information required to be reported by the General
Provisions (40 CFR 98.3(c)) and summarized in Section II.A of this
preamble, reporters must submit additional data that are used to
calculate GHG emissions.  A list of the specific data to be reported for
this source category is contained in 40 CFR part 98, subpart Y.

v.  Recordkeeping 

In addition to the records required by the General Provisions (40 CFR
98.3(g)) and summarized in Section II.A of this preamble, reporters must
keep records of additional data used to calculate GHG emissions.  A list
of specific records that must be retained for this source category is
included in 40 CFR part 98, subpart Y.

2.  Summary of Major Changes Since Proposal 

The major changes since proposal are identified in the following list. 
The rationale for these and any other significant changes can be found
below or in the comment response document for“Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to Public Comments, Subpart Y:
Petroleum Refineries.”

The minimum monitoring frequency for flare gas heat value or carbon
content was changed to weekly from daily.  (For background on the
selection of a weekly frequency, see memorandum entitled: “Uncertainty
in Flare Estimates Based on Sampling Frequency” in the docket.) 
Engineering calculations are allowed in the final rule for reporters
that do not monitor flare gas flow continuously or flare heating value
or carbon content at least weekly. 

The minimum monitoring frequency for refinery fuel gas carbon content
and molecular weight was changed to weekly from daily in 40 CFR part 98,
subpart C for reporters that do not have continuous monitoring
equipment, and we clarified in 40 CFR part 98, subpart Y that common
(fuel) pipe monitoring is allowed for petroleum refineries.

We added a flare combustion efficiency of 98 percent, and we revised the
equation for flare CH4 emissions to account for uncombusted methane.

The final rule allows engineering calculations to determine CO2
emissions for catalytic cracking units and fluid coking units below
10,000 bbl/stream day that do not have CO2/CO/O2 monitors already
installed. 

The delayed coking unit depressurization emission equations and asphalt
blowing equations were amended to address comments received.

We added concentration thresholds for CO2, CH4 and N2O from process
vents below which GHG emissions are not required to be calculated and
reported.

The reporting requirements were updated to facilitate the emissions
verification process.

3.  Summary of Comments and Responses 

This section contains a brief summary of major comments and responses. 
A large number of comments on petroleum refineries were received
covering numerous topics.  Responses to significant comments received
can be found in the comment response document for petroleum refineries
in the docket (EPA-HQ-OAR-2008-508-XXX).Responses to significant
comments received can be found in “Mandatory Greenhouse Gas Reporting
Rule: EPA’s Response to Public Comments, Subpart Y: Petroleum
Refineries.”

Definition of Source Category

Comment:  Several commenters expressed concern that EPA defined a
Petroleum Refinery so broadly that it could be interpreted to include
chemical facilities that use petroleum-based materials as raw materials.
 Of particular concern was the term “…and other products…” which
many commenters interpreted to include the manufacture of chemicals,
synthetic rubber, and a variety of plastics.  One commenter also
requested clarification that “other products” did not include
sulfur, ammonia, or hydrogen sulfide.  Several commenters requested
clarification that the definition of petroleum refineries did not
include lube oil production or fuel blending operations if the products
were produced without distilling, redistilling, cracking, or reforming
of the petroleum derivatives.

Response:  We have revised and clarified the definition of petroleum
refinery to list a few additional refinery products (specifically
gasoline blending stocks and naphtha) and deleted the term “or other
products.”  We believe that this change clarifies that companies that
use petroleum derivatives to make only petrochemicals, plastics,
synthetic rubber, sulfur, or any other product other than those
specifically listed are not considered petroleum refineries.  We feel
the definition also clearly excludes lube oil manufacturing provided the
lube oil manufacturer does not distill, redistill, crack, or reform the
petroleum derivatives at the facility.  

Comment:  Numerous commenters requested that many of the emission
sources for which 40 CFR part 98, subpart Y required reporting were
small and should not have to be reported.  Several commenters noted that
EPA's Technical Support DocumentEPA’s TSD for the Petroleum Refining
Sector: Proposed Rule for Mandatory Reporting of Greenhouse Gases,
indicates that 92.9% percent of the refining sector'ssector’s GHG
emissions come from two sources, combustion and catalytic coke
operations. The remaining 7.1% percent of emissions come from eight
distinct categories, including: Hydrogen plants (2.7% percent); Sulfur
Plants (1.9% percent); Flaring (1.6% percent); Wastewater Treatment
(0.43% percent); Blowdown (0.18% percent); Asphalt Blowing (0.10%
percent); Delayed Coking (0.058% percent); Equipment Leaks (0.014%
percent); Storage Tanks (0.007% percent); and Cooling Towers (0.003%
percent).  The commenters argued that the burden associated with the
collection of data as prescribed in the proposed rule is not warranted
for small sources and/or not consistent with EPA‘’s stated intended
purpose of the rule which is to support analysis of future policy
decisions. 

Response:  The Technical Support DocumentTSD estimates are based largely
on engineering estimates without significant supporting data.  For the
smaller sources, we have provided very simple methods to calculate the
GHG emissions from these sources to minimize the monitoring,
recordkeeping, and reporting burden associated with these sources when
no measurement data are available.  However, requiring reporting for
these sources will provide EPA with valuable data to better characterize
them and provide a better record upon which to formulate decisions
regarding whether to include or exclude these sources from future GHG
policy decisions.  Additionally, while some of these sources are
currently believed to be small compared to the larger sources present at
petroleum refineries, they are not necessarily insignificant.  The
inclusion of reporting data for these sources is critical to support
analysis of future policy decisions for petroleum refineries.

Comment:  Several commenters objected to the mandatory reporting of CH4
and N20 emissions within the Petroleum Refinery source category.  Many
commenters cited the Technical Support DocumenttheTSD, which indicated
that N20 emissions account for 0.09% percent of the GHG emissions and
CH4 account for only 0.87% percent of the GHG emissions.  The commenters
argued that the measurement error for the larger sources (stationary
combustion sources and catalytic cracking unit coke burn-off) exceeds
the contributions of these sources.  As such, the commenters stated that
the burden associated with reporting these emissions is not warranted
and/or not consistent with EPA‘’s stated intended purpose of the
rule which is to support analysis of future policy decisions.

Response:  The Technical Support DocumentTSD estimates for CH4 and N2O
are based largely on engineering estimates without significant
supporting data.  We specifically require reporting of these various
GHGs to obtain better data by which to support future policy analysis. 
Moreover, EPA has pending before it a petition to reconsider the
recently revised New Source Performance Standard (NSPS) for petroleum
refineries asking EPA to reconsider, among other things, whether to
establish GHG standards under section 111 for refineries. As such, we
have a keen interest in obtaining improved GHG emissions data in order
to better analyze policy options.  For instance, refineries are a
significant source of NOX emissions, but we have no data to determine
the fraction of NOX that is N2O.  With the increased use at refineries
of NOX control devices, such as low-NOx burners, low excess air,
selective catalytic reduction (SCR) systems, and selective non-catalytic
reduction (SNCR) systems, it seems plausible that N2O may be a more
significant portion of a refinery’s NOX emissions.  Thus, if a
facility has measurement data for a source, the reporting of these data
are important for better understanding the impact of current and future
policy options, and they are encouraged to be reported.  Consequently,
we have provided additional alternatives that allow the use of measured
N2O (and CH4) emissions or site-specific emission factors in addition to
the default factors.  Nonetheless, we have provided very simple default
methods to calculate the emission of these GHGs when measurement data
are not available.  While emissions of CH4 and N2O may not be large
comparatively, the reporting method for these pollutants is
straightforward and commensurate with the anticipated emissions
contribution.

Method for Calculating GHG Emissions

Comment:  Several comments objected to the requirements for flares,
particularly the requirements for startup, shutdown, or malfunction
(SSM) events.  Some commenters also stated that daily sampling was too
burdensome.  The commenters suggested that flare emissions be dropped
from the rule or that refineries be allowed to perform a one-time
calculation.  One commenter noted that the proposed equation did not
account for flare combustion efficiency, which was inconsistent with
other subparts, and recommended that a flare efficiency factor be added
to the equation to calculate the CO2 emissions from flares.

Response:  EPA needs accurate data on flare emissions to better
understand this emission source, as flare use can vary significantly
from day-to-day and year-to-year.  Use of flares is too episodic and
variable to allow a one-time calculation.  However, we recognize that
flares may contribute about 2two percent of a refinery’s GHG
emissions.  Therefore, we sought to reduce the burden associated with
the flare monitoring and reporting requirements.  As proposed, special
calculations for SSM events were only required if daily measurement data
were not available.  In this final rule, we allow weekly monitoring of
flare use without triggering special SSM event calculations, which
should lessen the burden associated with calculating flare emissions
while not significantly changing the accuracy of the data. 
Additionally, we included a threshold flaring rate of 500,000 scf/day
for SSM events.  Only SSM events exceeding this gas flare rate require
special SSM calculations in the final rule.  Some consent decree
requirements and stateState rules require root cause analysis and
quantification of emission events exceeding 500,000 scf/day.  We
consider events of this magnitude to be significant and believe a
separate analysis is justified in addition to the procedures that apply
to routine operation.  We have also revised the equations for CO2 and
CH4 to account for flare combustion efficiency.

Monitoring and QA/QC Requirements

Comment:  Several commenters argued that the monitoring and QA/QC
requirements were excessive and that EPA significantly underestimated
the costs associated with complying with the reporting requirements
under 40 CFR part 98, subpart Y.  One commenter noted that existing
facility CO2 CEMS, HHV monitors, carbon content monitors, and flow
meters are not necessarily for “regulatory” purposes and thus may
not meet the accuracy requirements of the rule.  The commenter suggested
many more refineries would have to add or replace monitors as a result
of the rule.  Many commenters suggested EPA significantly underestimated
the labor hours required to collect and analyze daily samples as well as
to develop and implement a QA plan.  Various commenters supplied labor
or cost estimates for various requirements in the rule, including costs
of implementing an LDAR program and flare SSM calculations.  Several
commenters stated that the requirement to use a CEMS for monitoring CO2
from the catalytic cracking unit was expensive and burdensome,
especially for small refineries that do not have a CEMS infrastructure. 
   

Response:  We have significantly revised our rule requirements for
petroleum refineries and stationary combustion sources to reduce burden
to the industry.  We have provided in the final rule (in 40 CFR part 98,
subpart C) a default emission factor for refinery (still) gas to allow
combustion sources that combust refinery gas and meet the applicability
requirements in 40 CFR part 98, subpart C to use Tier 2 methods.  For
sources that do not meet the Tier 2 requirements, weekly monitoring for
refinery fuel gas under Tier 3 (40 CFR part 98, subpart C) and for flare
gas (40 CFR part 98, subpart Y) is allowed.  We have also re-assessed
our costs based on the comments received and increased the labor hours
estimated to collect and analyze samples, develop QA plans, and to
perform QA/QC of existing equipment.  We did review our QA/QC
requirements and see no validity to the argument that our QA/QC
requirements are so stringent that refineries will have to replace
existing monitors to comply with the rule.  While we note that some cost
elements suggested by commenters are relevant and have been addressed in
the changes in the labor estimates for sampling, analysis, and QA/QC as
described above, other cost elements suggested by commenters are not
relevant.  For example, revisions of LDAR programs are not required
under the rule; the proposed and final rule specifically provides a
simple process-based emission factor approach for estimating CH4
emissions from equipment leaks.  We are cognizant that refineries with
small catalytic cracking units are most likely to elect a compliance
option under Part40 CFR part 63, subpart UUU that does not require
monitoring of coke burn-off, so these small refineries are most likely
the facilities that would have been required to install monitoring
equipment under the proposed rule.  After reviewing these costs and
impacts on the small refineries, we have allowed engineering
calculations to determine CO2 emissions for catalytic cracking units
below 10,000 bbl/stream day that do not have CO2/CO/O2 monitors already
installed.

Even though we have reduced the stringency of the rule in many places,
our revised cost estimates indicate that the average cost per refinery
is approximately 60 percent higher than projected at proposal.  We
believe our revised refinery costs accurately portray the burden
associated with the final reporting requirements in 40 CFR part 98,
subpart Y.  Nonetheless, we continue to believe that the costs are
reasonable for this rule, especially considering that petroleum
refineries are among the larger sources of GHG emissions in the U.S.

Z.  Phosphoric Acid Production 

1.  Summary of the Final Rule 

Source Category Definition.  The phosphoric acid production source
category consists of facilities that use a wet-process phosphoric acid
process to produce phosphoric acid.  A wet-process phosphoric acid
process line is any system that manufactures phosphoric acid by reacting
phosphate rock and acid and is usually identified by an individual
identification number in a CAA operating permit.

Reporters must submit annual GHG reports for Facilities that meet the
applicability criteria in the General Provisions (40 CFR 98.2)
summarized in Section II.A of this preamble.

GHGs to Report.  Report CO2 emissions from each wet-process phosphoric
acid process line. 

In addition, report GHG emissions at each facility for other source
categories for which calculation methods are provided in the rule, as
applicable.  For example, report CO2, N2O, and CH4 emissions from each
stationary combustion unit on site under 40 CFR part 98, subpart C
(General Stationary Fuel Combustion Sources). 

GHG Emissions Calculation and Monitoring.  Calculate process emissions
of CO2 using one of two methods, as appropriate:

Most reporters can elect to either (1) install and operating CEMS and
follow the Tier 4 methodology (in 40 CFR part 98, subpart C) or (2)
calculate CO2 emissions based on monthly measurements of the mass of
phosphate rock consumed and inorganic carbon content of each grab sample
of phosphate rock.  

However, if process CO2 emissions from phosphoric acid production are
emitted through the same stack as a combustion unit or process equipment
that uses a CEMS and follows Tier 4 methodology to report CO2 emissions,
then the CEMS must be used to measure and report combined CO2 emissions
from that stack.  In such cases, the reporter cannot use the CO2
calculation methodology outlined in approach (2 above) in the previous
bullet. 

Data Reporting.  In addition to the information required to be reported
by the General Provisions (40 CFR 98.3(c)) and summarized in Section
II.A of this preamble, reporters must submit additional data that are
used to calculate GHG emissions.  A list of the specific data to be
reported for this source category is contained in 40 CFR part 98,
subpart Z.

Recordkeeping.  In addition to the records required by the General
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this
preamble, reporters must keep records of additional data used to
calculate GHG emissions.  A list of specific records that must be
retained for this source category is included in 40 CFR part 98, subpart
Z.

2.  Summary of Major Changes Since Proposal

The major changes since proposal are identified in the following list. 
The rationale for these and any other significant changes can be found
below or in the comment response document for“Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to Public Comments, Subpart Z:
Phosphoric Acid Production.”

The rule was revised to allow the use of techniques from Part 60 and
Part 63 for calculating the weight of phosphorous-containing rock.

The missing data provisions were revised to allow the use of default
inorganic carbon content values based on the origin of the
phosphorous-containing rock, in addition to determining missing
inorganic carbon contents of phosphate rock consumed using an arithmetic
average of measured values from of inorganic carbon contents of
phosphate rock of the appropriate origin preceding and following the
missing data incident.

40 CFR 98.266 was reorganized and updated to improve the emissions
verification process.  Some data elements were moved from section40 CFR
98.267 to section40 CFR 98.266, and some data elements that are already
used to calculate GHG emissions as specified in section40 CFR 98.263
were added to section40 CFR 98.266 for clarity.

3.  Summary of Comments and Responses 

This section contains a brief summary of major comments and responses. 
Several comments on phosphoric acid production were received covering
numerous topics shown below.  Responses to significant comments received
can be found in the comment response document for phosphoric acid
production in the docket (EPA-HQ-OAR-2008-508-XXX).Responses to
significant comments received can be found in “Mandatory Greenhouse
Gas Reporting Rule: EPA’s Response to Public Comments, Subpart Z:
Phosphoric Acid Production.”

Selection of Threshold

Comment:  Multiple commenters asked that phosphoric acid production
units not be included as an “all-in” category.  According to the
commenters, the facilities are very minor sources of GHG emissions.  The
commenter conceded that most (if not all) would still fall within the
reporting threshold requirement, but asserted that it was unnecessary to
include all phosphoric acid production units as regulated facilities
regardless of the amount of emissions.  The commenters stated that EPA
inaccurately suggests that these units are major emitters of GHGs which
could have significant impacts on these minor sources.

Response:  We acknowledge the comments and concerns; however the final
rule retains the “all-in” applicability requirement for this source
category.  The “once in, always in” provision has been removed.  The
final rule now contains a provisionprovisions to cease reporting if
annual reports demonstrate emissions less than 25,000 metric tons CO2e
per yearspecified levels for 5 consecutivemultiple years.  This
provision appliesThese provisions apply to all reporting facilities,
including those with phosphoric acid production processes.  We believe
that obtaining GHG emissions from all phosphoric acid facilities over a
five year period will document the number of facilities (if any) that
fall below the suggested threshold.  The purpose of this rule is to
collect information on emissions sources for future policy development. 
Requiring reporting for these sources will provide EPA with valuable
data to better characterize greenhouse gasGHG emissions from phosphoric
acid production and provide a more credible position if EPA elects to
exclude these sources from future GHG policy analyses.  We also believe
that the accurate assessment of the emissions from phosphoric acid
production will address the commenters’ concerns about potential
future impacts. 

Commenters may also be interested in reviewing Section II.H of this
preamble for the response on provisions to cease reporting.  

Method for Calculating GHG Emissions and Monitoring and QA/QC
Requirements

Comment:  Multiple commenters asked that production measurements in this
rule be consistent with the existing MACT and NSPS regulations for the
phosphate industry.  In these regulations, production measurement is
determined by the mass of phosphate feed (as P2O5).  Two commenters
stated that the change would provide consistency, and ensure a reporting
structure that fits with the actual practices of the industry.

Response:  We agree with the commenters that consistency among EPA
regulations is important.  Therefore, the final rule allows for
techniques from Part 60 and Part 63 to calculate the weight of
phosphorous-containing rock. This request is consistent with the intent
of the proposed rule.  Under existing regulations in Part 60 and Part
63, phosphoric acid manufacturing facilities already measure the mass of
phosphorous bearing feed on a ton/hour basis.  This feed rate can be
used to determine monthly phosphate rock consumption.  Process CO2
emissions from phosphoric acid production are calculated from the total
phosphate rock consumption multiplied by the inorganic carbon content of
that rock.  Further, Part 60 and Part 63 establish the appropriate
monitoring and QA/QC procedures for determining this feed rate.  

Procedures for Estimating Missing Data

Comment:  Multiple commenters asked that the final rule allow options
for missing data.  The commenters asked that the use of default carbon
content values based on the origin of the rock be allowed if analytical
data are unavailable.  In addition, commenters requested that procedures
be added for measurement of the mass of phosphate rock consumed,
suggesting procedures similar to those in 40 CFR part 98, Subpart C, the
lesser of the maximum capacity of the system, the maximum rate the meter
can measure, or best available estimate based on available process data.

Response:  We agree with the commenters on this point.  The final rule
has been changed to allow the use of a default factor (by origin of the
phosphate rock) for each missing value of the inorganic carbon content
of phosphate rock.  Use of a default carbon value in place of the
missing data will provide a reasonable estimate of the total emissions
from the facility and will avoid assuming the maximum possible facility
emissions when no data isare available.  These default values have been
added to the final rule in Table Z-1 of 40 CFR part 98, subpart Z.  

Missing data procedures have also been added as suggested for missing
monthly estimates of the mass of phosphate rock consumed consistent with
the later recommendation. Again use of the best available data based on
all available process data will avoid assuming the maximum possible
facility emissions when no data isare available.  Facilities must
document must document and keep records of the procedures used for all
such estimates.

AA.  Pulp and Paper Manufacturing 

1.  Summary of the Final Rule 

Source Category Definition.  This source category consists of facilities
that produce market pulp (i.e., stand-alone pulp facilities),
manufacture pulp and paper (i.e., integrated mills), produce paper
products from purchased pulp, produce secondary fiber from recycled
paper, convert paper into paperboard products (e.g., containers), or
operate coating and laminating processes.

Reporters must submit annual GHG reports for facilities that meet the
applicability criteria in the General Provisions (40 CFR 98.2)
summarized in Section II.A of this preamble.

GHGs to Report.  Table AA-1 of this preamble lists the GHG emission
sources at pulp and paper manufacturing facilities for which GHG
emissions must be reported along with the rule subpart that specifies
the calculation methodology. 

Table AA-1.  GHGs to Report

For pulp and paper mills…	Report emissions of the listed GHGs by
following the requirements of the 40 CFR part 98, subpart indicated…

	CO2	Biogenic CO2 	CH4	N2O	Biogenic CH4 	Biogenic N2O

Chemical recovery furnaces at kraft and soda facilities	C	AA	C	C	AA	AA

Chemical recovery combustion units at sulfite facilities	C	AA	C	C	AA	AA

Chemical recovery combustion units at stand alone semi-chemical
facilities	C	AA	C	C	AA	AA

Lime kilns of kraft and soda facilities	AA/C	AA	AA/C	AA/C	AA	AA

Makeup chemicals used in pulp mills	AA





	Stationary combustion units	C	C	C	C	C	C



Key: 

C = 40 CFR part 98, subpart C (General Stationary Fuel Combustion
Sources)

AA = 40 CFR part 98, subpart AA (Pulp and Paper Manufacturing)

AA/C = use 40 CFR part 98, subpart AA for GHG emission factor and
subpart C to determine default High Heating Values.

 

GHG Emissions Calculation and Monitoring.  Under 40 CFR Subpartpart 98,
subpart AA, reporters must calculate emissions from pulp and paper
manufacturing facilities as follows:

Chemical recovery Furnaces: Calculate biogenic CO2 emissions from
combustion of biomass in spent pulping liquor using:

Measured quantities of spent liquor solids fired, site-specific high
heating value (HHV), and default or site-specific emission factors for
each chemical recovery furnace located at kraft or soda facilities.

Measured quantities of spent liquor solids fired and the carbon content
of the spent liquor solids for each chemical recovery unit at sulfite or
stand-alone semichemical facilities.

Calculate CO2 emissions from fossil fuels used in chemical recovery
furnaces using direct measurement of fossil fuels consumed and default
emission factors according to the Tier 1 methodology for stationary
combustion sources in 40 CFR part 98, subpart C.

Calculate CH4 and N2O emissions as the sum of emissions from the
combustion of fossil fuels and the combustion of biomass in spent
pulping liquor, as follows: 

For fossil fuel emissions, use direct measurement of fuels consumed, a
default HHV, and default emission factors according to the methodology
for stationary combustion sources in 40 CFR 98.33(c). 

For biomass emissions, use measured quantities of spent liquor solids
fired, site-specific HHV, and default or site-specific emission factors.

Lime kilns at kraft and soda facilities

Lime kilns: Calculate CO2, CH4, and N2O emissions from combustion of
fossil fuels in pulp mill lime kilns using direct measurement of fossil
fuels consumed and default emission factors and HHV found in 40 CFR part
98, subparts AA and C, respectively.

Makeup chemicals: Calculate CO2 emissions from the use of makeup
chemicals using direct or indirect measurement of the quantity of
chemicals added and ratios of the molecular weights of CO2 and the
makeup chemicals. 

Data Reporting.  In addition to the information required to be reported
by the General Provisions (40 CFR 98.3(c)) and summarized in Section
II.A of this preamble, reporters must submit additional data that are
used to calculate GHG emissions.  A list of the specific data to be
reported for this source category is contained in 40 CFR part 98,
subpart AA.

Recordkeeping.  In addition to the records required by the General
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this
preamble, reporters must keep records of additional data used to
calculate GHG emissions.  A list of specific records that must be
retained for this source category is included in 40 CFR part 98, subpart
AA.

2.  Summary of Major Changes Since Proposal 

The major changes since proposal are identified in the following list. 
The rationale for these and any other significant changes can be found
below or in the comment response document for“Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to Public Comments, Subpart AA: Pulp
and Paper Manufacturing:.”

Language was added to clarify that 40 CFR part 98, subpart AA GHG
emissions are to be reported for makeup chemicals added in the chemical
recovery areas of pulp mills (as opposed to makeup chemicals used at
paper coating and laminating facilities).  

The frequency of measurements for the spent liquor solids mass fired
(TAPPI Test Method T 650), heating value (TAPPI Test Method T 684), and
carbon content (ASTM D5373-08) was reduced from monthly to annually.  

An option to use data from existing online solids meters to determine
the annual mass of spent liquor solids fired is provided (in lieu of
conducting an annual TAPPI Test Method T 650)   

The requirement to report quarterly data was eliminated.

The reporting requirements were revised to specify units to standardize
inputs into the data reporting system.

3.  Summary of Comments and Responses 

This section contains a brief summary of major comments and responses. 
A number of comments on pulp and paper manufacturing were received
covering numerous topics.  Responses to significant comments received
can be found in the comment response document for pulp“Mandatory
Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments,
Subpart AA: Pulp and paper manufacturing in the docket
(EPA-HQ-OAR-2008-508-XXX).Paper Manufacturing.”

Definition of Source Category

Comment:  Two commenters stated that literal interpretation of 40 CFR
part 98, subpart AA could require any facility operating paper coating
and laminating processes to report emissions for any system used to add
makeup chemicals.  The commenters requested that language be added to 40
CFR part 98, subpart AA to clearly exclude facilities not intended to be
covered and which have not traditionally been part of the pulp and paper
source category.

Response:  Definitions of terms used in 40 CFR part 98, subpart AA are
provided in 40 CFR 98.6 (in subpart A orof part 98).  The definition of
“makeup chemicals” is specific to the chemical recovery areas of
pulp mills and serves to limit the scope of the pulp and paper
subcategory.  As defined in §98.6 (emphasis added):

“Chemical recovery combustion unit means a combustion device, such as
a recovery furnace or fluidized-bed reactor where spent pulping liquor
from sulfite or semi-chemical pulping processes is burned to recover
pulping chemicals.” 

“Makeup chemicals means carbonate chemicals (e.g., sodium and calcium
carbonates) that are added to the chemical recovery areas of chemical
pulp mills to replace chemicals lost in the process.”

Thus, we disagree that the rule could be interpreted to require any
facility operating coating and laminating processes to report emissions
for any system used to add makeup chemicals.  This was not the intent of
the rule.  Nevertheless, we have added language consistent with the
definition of “makeup chemicals” to 40 CFR 98.270(b)(5) and
98.272(e) to further clarify that GHG emissions are to be reported for
systems adding makeup chemicals (CaCO3 and Na2CO3) in the chemical
recovery areas of pulp mills.

Comment:  Commenters stated the rule should include categorical
exemptions for emissions from the combustion of non-condensable gases
(NCG), stripper off gases (SOG), tall oil and turpentine (small sources
of GHG that are difficult to measure).  The commenters noted that these
streams are of biogenic origin.  One commenter described safety issues
associated with sampling these gas streams.  

Response:  Pulp mill NCG, SOG, tall oil and turpentine were discussed in
the Proposed Rule TSD for the pulp and paper manufacturing sector.  The
Proposed Rule TSD noted that process vent gases such as NCG and SOG and
the byproducts tall oil and turpentine are derived from biomass.  We
acknowledge the safety and measurement issues described by commenters
regarding sampling of NCG and SOG streams.  No methods are specified in
the rule for calculation of GHG associated with combustion of NCG, SOG,
tall oil and turpentine.  Thus, calculation of these emissions is not
required and there is no need for categorical exemptions.

Method for Calculating GHG Emissions

Comment:  Commenters stated that monthly measurements of the mass of
spent liquor solids, HHV, and carbon content of spent liquor solids are
unnecessary.  The commenters requested that EPA either allow default
fuel carbon content and heating value for spent pulping liquor, or
reduce the frequency of measurements to annually or every two years. 
Commenters noted that spent liquor HHV and carbon content are measured
from time to time but less frequently than monthly.  In addition, one
commenter pointed out that chemical recovery furnaces often have online
solids meters installed to provide continuous measurement of the mass of
spent liquor solids entering the furnace for safety and process control
reasons.  This commenter requested that EPA allow use of such continuous
measurement devices instead of requiring monthly measurement of the mass
of spent liquor solids with TAPPI Test Method T 650.

Response:  We disagree with commenters that default fuel carbon content
and high heating values should be allowed instead of measured values. 
These parameters are already measured by mills (though less frequently
than monthly) and thus are available for use and more accurate than
default values.  We are reducing the frequency of fuel property
measurements from monthly to annual.  There is little monthly variation
in fuel properties over the course of a year.  Therefore, annual
measurements are sufficient to develop site specific emission factors.
This change also reduces the burden associated with complying with the
rule. These changes have been incorporated throughout the text and
equations of 40 CFR part 98, subpart AA.  

In addition, the final rule allows use of either an annual measurement
of the mass of spent liquor solids fired (with TAPPI Test Method T 650)
or use of annual spent liquor solids data calculated from continuous
measurements already performed for process control purposes (e.g., with
existing online solids meters).  If the annual spent liquor solids fired
is determined using existing measurement equipment, then reporters must
retain records of the calculations used to determine the annual mass of
spent liquor solids fired from the continuous measurements in order to
demonstrate, if necessary, that calculations where done correctly. 
Reporters must also document that these measurement devices have been
regularly and properly calibrated according to the manufacturer’s
specifications.

Data Reporting Requirements

Comment:  One commenter noted that presenting quarterly data in annual
reports for pulp and paper manufacturing annual emissions, consumption
of biomass fuels, and quantity of spent liquor solids fired is
unnecessary for an annual reporting system.  

Response:  We have revised §§40 CFR 98.276 and 98.277(a) to remove the
requirement for providing quarterly details in the annual report.  EPA
agrees that requiring quarterly details was not necessary for ensuring
the accuracy of data reported annually.

Comment:  One commenter requested that the spreadsheets developed by the
National Council for Air and Stream Improvement (NCASI) for the
International Council of Forest and Paper Associations (ICFPA) be
allowed as an option for facilities subject to the Rule to determine
emissions.  These spreadsheets segregate calculated GHG emissions into
fossil fuel and biogenic categories.  The commenter believes that tools
like those developed by NCASI and others should be allowed as an option
for facilities subject to the emission calculation requirements imposed
by the Rule at §98.40 CFR 98.3.  This streamlined approach will provide
the Agency with valid GHG emission data without imposing extraordinary
capital and labor burdens on the industry.

Response: The ICFPA/NCASI tools were considered in developing the
requirements of the GHG reporting rule.  However, the ICFPA/NCASI
spreadsheets, though valuable tools, are not broadly applicable to all
industrial sectors covered under the GHG reporting rule, as are the
monitoring, reporting, recordkeeping, and emissions verification
requirements specified in 40 CFR 98.3.  Additionally, these tools often
use default factors and estimates, which differs from the approach
proposed by EPA.  The data collected from all subparts of the GHG
reporting rule will be tabulated in EPA’s electronic reporting system.
 This system will be used to verify emission calculations and will
require specific data be reported in order to run the calculations used
for verification.  The tools suggested by the commenter, however, would
only provide a total emission number.  Consequently, EPA would not be
able to check the underlying calculations for accuracy.  The final GHG
reporting rule reflects the data reporting requirements necessary for
emissions verification by EPA.  Edits to the reporting and recordkeeping
language (40 CFR 98.276 and 98.277) of 40 CFR part 98, subpart AA were
made to clarify calculation inputs and units of measure to be reported. 
As part of the implementation phase of today’s final rule, EPA intends
to prepare guidance documents to assist the industry in complying with
the rule’s requirements.  In recognition of the fact that the pulp and
paper industry has been using the ICFPA/NCASI spreadsheets, EPA will
consider including in the guidance materials a comparison between these
spreadsheets and the EPAEPA’s electronic reporting system to reduce
the burden on the industry and minimize confusion.

BB.  Silicon Carbide Production 

1.  Summary of the Final Rule 

Source Category Definition.  The silicon carbide production source
category consists of any process that produces silicon carbide for
abrasive purposes.  

Reporters must submit annual GHG reports for facilities that meet the
applicability criteria in the General Provisions (40 CFR 98.2)
summarized in Section II.A of this preamble.

GHGs to Report.  Report process CO2 and CH4 emissions from all silicon
carbide production furnaces or process units at the facility combined. 

In addition, report GHG emissions for other source categories at the
facility for which calculation methods are provided in the rule, as
applicable.  For example, report CO2, N2O, and CH4 emissions from each
stationary combustion unit on site under 40 CFR part 98, subpart C
(General Stationary Fuel Combustion Sources).  

GHG Emissions Calculation and Monitoring.  For CO2 emissions, reporters
must use one of the following methods, as appropriate:

Most reporters can elect to calculate and report process CO2 emissions
from silicon carbide production processes by either (1) installing and
operating CEMS and following the Tier 4 methodology (in 40 CFR part 98,
subpart C) or (2) calculating emissions using the measured petroleum
coke consumption and a monthly facility-specific emission factor.  The
facility-specific emission factor is the carbon content of the petroleum
coke (provided monthly by the supplier or measured monthly using the
appropriate test methods) adjusted for carbon in the silicon carbide
product. 

However, if process CO2 emissions from silicon carbide production are
vented through the same stack as a combustion unit or process equipment
that uses a CEMS and follows Tier 4 methodology to report process CO2
emissions, then the CEMS must be used to measure and report combined CO2
emissions from that stack.  In such cases, the reporter cannot use the
CO2 calculation approach (2) outlined in the above bullet.

For CH4 emissions, reporters must use the measured petroleum coke
consumption and a default emission factor of 10.2 kilograms (kg) per
metric ton of coke consumed. 

Data Reporting.  In addition to the information required to be reported
by the General Provisions (40 CFR 98.3(c)) and summarized in Section
II.A of this preamble, reporters must submit additional data that are
used to calculate GHG emissions.  A list of the specific data to be
reported for this source category is contained in 40 CFR part 98,
subpart BB.

Recordkeeping.  In addition to the records required by the General
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this
preamble, reporters must keep records of additional data used to
calculate GHG emissions.  A list of specific records that must be
retained for this source category is included in 40 CFR part 98, subpart
BB.

2.  Summary of Major Changes Since Proposal 

The major changes since proposal are identified in the following list. 
The rationale for these and any other significant changes can be found
below or in the comment response document for“Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to Public Comments, Subpart BB: Silicon
Carbide Production.”

The emissions calculation method under 40 CFR 98.283(b) was revised to
require data on monthly petroleum coke consumption and monthly petroleum
coke carbon contents rather than quarterly determinations.

Missing data procedures were added under 40 CFR 98.285 for monthly
parameters used to calculate emissions, including mass of petroleum
coke, and carbon contents of petroleum coke.

Section40 CFR 98.286 was reorganized and updated to improve the
emissions verification process.  Some data elements were moved from
section40 CFR 98.287 to section40 CFR 98.286, and some data elements
that a reporter must already use to calculate GHGs as specified in
section40 CFR 98.283 were added to section40 CFR 98.286 for clarity. 

3.  Summary of Comments and Responses 

No specific comments were received pertaining to the proposed reporting
requirements for silicon carbide production facilities.  However, the
proposed rule did not clearly not specify how quarterly carbon contents
should be determined.  This determination should be made on a monthly
basis as proposed for other chemical production processes where process
emissions arise from use of petroleum coke, such as titanium dioxide
production.  Quarterly reporting of carbon contents of petroleum coke
consumed for the quarter would have to be averaged from monthly data. 
For verification, EPA would require reporting of the monthly carbon
contents of the petroleum coke.  Therefore, we revised the emissions
calculation method to directly require monthly petroleum coke
consumption and monthly petroleum coke contents, rather than quarterly
based on an arithmetic average of the monthly estimates to improve
accuracy of emissions calculations.  We have retained the flexibility in
use of supplier data to determine carbon contents.  We understand that
most supplier data on carbon contents of petroleum coke is readily
available and that businesses track production inputs and outputs on a
monthly basis as a part of normal business practice or existing
accounting procedures.  The increased frequency of data collection from
quarterly to monthly provides greater clarity and accuracy without
significantly increasing burden.  In addition, see the Section II.N of
this preamble for an explanation of the emissions verification approach.

CC.  Soda Ash Manufacturing 

1.  Summary of the Final Rule 

Source Category Definition.  A soda ash manufacturing facility is any
facility with a manufacturing line that produces soda ash by either:
calcining trona or sodium sesquicarbonate; or by using a liquid alkaline
feedstock process that directly produces CO2.  In the context of the
soda ash manufacturing sector, “calcining” means the
thermal/chemical conversion of the bicarbonate fraction of the feedstock
to sodium carbonate.

Soda ash produced from a liquid alkaline feedstock using sodium
hydroxide does not emit process CO2 and therefore is not subject to the
requirements of Subpart CC. However, such facilities may be covered
under Subpart C (General Stationary Combustion) if they meet the
requirements of either §98.2(a)(1) or (2).

Reporters must submit annual GHG reports for facilities that meet the
applicability criteria in the General Provisions (40 CFR 98.2)
summarized in Section II.A of this preamble.

GHGs to Report.  For soda ash manufacturing, report the following
emissions:

CO2 process emissions from soda ash manufacturing, reported for each
manufacturing line.

CO2 combustion emissions from each calciner (kilns) on each soda ash
manufacturing line.

N2O, and CH4 emissions from fuel combustion at each calciner (kiln)soda
ash manufacturing line under 40 CFR part 98, subpart C (General
Stationary Fuel Combustion Sources) using the methodologies in subpart
C.

CO2, N2O, and CH4 emissions from each stationary combustion unit other
than calciners (kilns)soda ash manufacturing lines under 40 CFR part 98,
subpart C (General Stationary Fuel Combustion Sources).

In addition, report GHG emissions for any other source categories at the
facility for which calculation methods are provided in other subparts of
the rule, as applicable.

GHG Emissions Calculation and Monitoring.  For CO2 emissions from soda
ash manufacturing lines, reporters  must select one of the following
methods, as appropriate:

For each calciner in soda ash manufacturing line with certain types of
CEMS in place, reporters must use the CEMS and follow the Tier
4 methodology (in 40 CFR part 98, subpart C) to report under the Soda
Ash Manufacturing subpart (40 CFR part 98, subpart CC) combined process
and combustion CO2 emissions.

For other soda ash manufacturing lines, reporters can elect to either 
(1) install and operate a CEMS and follow Tier 4 methodology to measure
and report combined process and combustion CO2 emissions or (2)
calculate CO2 process emissions using the procedures specified in 40 CFR
part 98, subpart CC and summarized below.  

If using approach 2, calculate process CO2 emissions using one of three
alternative methods, as appropriate for each manufacturing line:

The trona input method calculates the calcination emissions using:
monthly mass of trona input (required to be measured), the average
monthly mass-fraction of inorganic carbon in the trona (required to be
measured weekly), and the ratio of CO2 emitted for each ton of trona
consumed (a default value is provided).

The soda ash output method calculates the calcination emissions using:
monthly mass of soda ash produced (required to be measured), the monthly
average mass-fraction of inorganic carbon in the soda ash (required to
be measured weekly), and the ratio of CO2 emitted for each ton of soda
ash produced (a default value is provided).

The site-specific emission factor method calculates emissions from
production of soda ash using liquid alkaline feedstock through an annual
performance test using: the average process vent flow rate from the mine
water stripper/evaporator for each manufacturing line, direct
measurements of hourly CO2 concentration, the hourly stack gas
volumetric flow rate, the annual process vent flow rate from mine water
stripper/evaporator, and annual operating hours. 

Report process CO2 emissions from each soda ash manufacturing line under
40 CFR part 98, subpart CC (Soda Ash Manufacturing), and report
combustion CO2 emissions from each calciner (kiln) in each manufacturing
line under 40 CFR part 98, subpart C (General Stationary Fuel Combustion
Sources).

Data Reporting.  In addition to the information required to be reported
by the General Provisions (40 CFR 98.3(c)) and summarized in Section
II.A of this preamble, reporters must submit additional data that are
used to calculate GHG emissions.  A list of the specific data to be
reported for this source category is contained in 40 CFR part 98,
subpart CC.

Recordkeeping.  In addition to the records required by the General
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this
preamble, reporters must keep records of additional data used to
calculate GHG emissions.  A list of specific records that must be
retained for this source category is included in 40 CFR part 98, subpart
CC.

2.  Summary of Major Changes Since Proposal

The major changes since proposal are identified in the following list. 
The rationale for these and any other significant changes can be found
below or in the comment response document for“Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to Public Comments, Subpart CC: Soda
Ash Manufacturing..” 

A site-specific emission factor method has been added for production of
soda ash using liquid alkaline feedstock or mine water.  This method was
not included in the proposed rule.

The frequency of inorganic carbon content determination of either trona
or soda ash has been revised from daily to monthly based on a weekly
composite.

Procedures were added to 40 CFR 98.295 for estimating missing data for
monthly values of inorganic carbon content of trona and monthly values
of trona consumption or soda ash production. We also added missing data
procedures for parameters specific to calculating emissions from soda
ash produced from liquid alkaline feedstock (i.e. site-specific emission
factor method).

40 CFR 98.296 was reorganized and updated to improve the emissions
verification process. Some data elements were moved from section40 CFR
98.297 to section40 CFR 98.296, and some data elements that a reporter
must already use to calculate GHGs as specified in section40 CFR 98.293
were added to section40 CFR 98.296 for clarity. 

3.  Summary of Comments and Responses 

This section contains a brief summary of major comments and responses. 
Two sets of comments on soda ash manufacturing were received covering
several topics.  Responses to significant comments received can be found
in the comment response document for soda ash manufacturing in the
docket (EPA-HQ-OAR-2008-508-XXX).Responses to significant comments
received can be found in “Mandatory Greenhouse Gas Reporting Rule:
EPA’s Response to Public Comments, Subpart CC: Soda Ash
Manufacturing.”

Method for Calculating GHG Emissions

Comment:  Both commenters noted that facilities produced soda ash using
alternative methods to calcining trona or other carbonate containing
minerals.  Facilities also produce soda ash from mine water, a liquid
alkaline feedstock; this is a “process” emissive production process,
but was not addressed in the proposal.  The methods in the proposal did
not include methods appropriate for calculating process CO2 from the
liquid alkaline feedstock production process.  One commenter using this
production method recommended that the appropriate method for
calculating emissions from this process would be an annual performance
test and described the appropriate parameters that would be measured
during the annual performance test to establish an emission factor for
calculating annual emissions based on concentration of the CO2 in the
evaporated stripped mine water and the annual flow from the mine water
stripper/evaporator.  

Response:  We agree that the final rule should address process CO2
emissions generated from this relatively new alternative production
process which produces soda ash from liquid alkaline feedstock or mine
water.  From additional information provided by the commenter, process
CO2 emissions from this production method are likely to be significant
and exceed 25,000 mtmetric tons CO2e.  This process is currently used by
a single company, but could become more widespread within the industry
in the future as it makes more efficient use of raw materials previously
not used.  We have updated all sections of the rule (40 CFR part
98.290-297), subpart CC for calculating, monitoring and QA/QC, and
reporting of process CO2 emissions specific to production of soda ash
from liquid alkaline feedstock or minewater.  We added procedures for
developing  site-specific emission factor based on an annual performance
test consistent with the recommendations provided by the commenter.

Comment:  One commenter noted that using the total alkalinity of either
trona or soda ash as prescribed in Equations CC-2 and CC-3 is
inappropriate given that the ratio of carbon dioxide to carbon is a
factor in the equations.  The equations’ results artificially inflated
the CO2 level by 3.67 times the actual amount.

Response:  Upon further review, we agree with the commenter’s analysis
that the ratio 44/12 will overestimate emissions and have removed this
fraction 44/12, , which is the ratio of carbon dioxide to carbon, from
Equations CC-2 and CC-3.  Equations CC-2 and CC-3 provide results
directly for CO2 therefore it is not necessary to use a conversion
factor to convert the carbon to carbon dioxide. 

Comment:  One commenter noted that Equation CC-3 does not address plant
inefficiency specific to each manufacturing line. ItThe commenter
suggested that an efficiency factor should be added to Equations CC-3 to
account for these inefficiencies.

Response:  The commenter has not suggested an efficiency factor or
otherwise provided data with enough specificity to modify the equations
and modify the calculation methods as suggested; therefore, we have
decided not to add efficiency factors to Equations CC-3. 

EPA needs more information to effectively evaluate this comment and
update the equations noted, if appropriate.  Efficiency factors can
relate to a number of factors including combustion and also kiln
conditions, which may vary.  We need more information to understand how
this factor would be derived for each kiln or manufacturing line. The
comment was specific to CC-3, and we suggest the use of Equation CC-2 as
an alternative calculation method. 

Monitoring and QA/QC Requirements

Comment:  One commenter stated that daily sampling of inorganic carbon
content of each manufacturing line is an unnecessary and potentially
extremely costly requirement. They suggested that instead of daily
testing, testing should be completed as a weekly composite analysis
which would then be used in calculating the monthly average.

Response:  We concur that testing of the inorganic carbon content can be
done on a weekly schedule and used to calculate a monthly composite
without significant loss in accuracy.  The weekly composite would still
be based on several daily tests.  We have updated the monitoring and
QA/QC requirements accordingly in the rule under accordingly under 40
CFR 98.294.

Comment:  One commenter stated that the prescribed ASTM method, ASTM
E359-00(2005), for determining the inorganic carbon content of trona or
soda ash describes a manual titration method using a methyl orange
endpoint.  They stated that procedures that use autotitrators with fixed
endpoint titration are commonly used in the soda ash manufacturing
industry and should be allowed as an acceptable equivalent alternative.

Response:  We agree that methods using autotitration to determine
inorganic carbon content of trona or soda ash expressed as total
alkalinity are acceptable equivalent methods for determining the
inorganic carbon content of trona or soda ash. We understand that manual
titration offers good levels of accuracy but are labor and time
intensive.  From our understanding, autotitration methods provide
comparable or improved levels of accuracy and are less labor and time
intensive by “automating” the analysis process.  Autotitration
methods could provide more consistency in results across the industry. 
We have updated the procedures in 40 CFR 98.294 for monitoring and QA/QC
in the rule to allow for such comparable methods.

DD.  Sulfur Hexafluoride (SF6) from Electrical Equipment

At this time EPA is not going final with the electrical equipment
subpart.  As we consider next steps, we will be reviewing the public
comments and the relevant information.  

Based on careful review of comments received on the preamble, rule, and
technical support documentsTSDs under Subpart40 CFR part 98, subpart DD,
EPA will perform additional analysis and evaluate a range of data
collection procedures and methodologies.  EPA’s goal is to optimize
methods of data collection to ensure data accuracy while considering
industry burden.  In addition, EPA will further evaluate the scope of
coverage of electric power systems and the reporting boundaries in other
subparts.   

EE.  Titanium Dioxide Production

1.  Summary of the Final Rule 

Source Category Definition.  The titanium dioxide production source
category consists of any facility that uses the chloride process to
produce titanium dioxide. 

Reporters must submit annual GHG reports for facilities that meet the
applicability criteria in the General Provisions (40 CFR 98.2)
summarized in Section II.A of this preamble.

GHGs to Report.  For titanium dioxide production, report CO2 process
emissions from each chloride process line.

In addition, report GHG emissions for other source categories for which
calculation methods are provided in the rule, as applicable.  For
example, facilities must report CO2, N2O, and CH4 emissions from each
stationary combustion unit on site under 40 CFR part 98, subpart C
(General Stationary Fuel Combustion Sources). 

GHG Emissions Calculation and Monitoring.  Reporters must calculate CO2
process emissions using one of two methods, as appropriate:

Most reporters can elect to calculate and report process CO2 emissions
from titanium dioxide process lines by either (1) installing and
operating CEMS and following the Tier 4 methodology (in 40 CFR part 98,
subpart C) or (2) using the calculation procedures specified below.

However, if process CO2 emissions from titanium dioxide production are
emitted through the same stack as a combustion unit or process equipment
that uses a CEMS and follows Tier 4 methodology to report CO2 emissions,
then the reporter must use the CEMS to measure and report combined CO2
emissions from that stack instead of using the calculation procedures
described below.  

If using approach #2, calculate the process CO2 emissions using the
equation provided 40 CFR part 98, subpart EE and monthly determination
of the mass and carbon content of calcined petroleum coke consumed in
each line and all lines combined.  Determine petroleum coke consumption
by either direct measurement or purchase records.  Determine carbon
content of petroleum coke using supplier data or measurement using
appropriate test methods.  If applicable, also determine the quantity of
carbon containing waste generated and its carbon contents using direct
measurement.

Data Reporting.  In addition to the information required to be reported
by the General Provisions (40 CFR 98.3(c)) and summarized in Section
II.A of this preamble, reporters must submit additional data that are
used to calculate GHG emissions.  A list of the specific data to be
reported for this source category is contained in 40 CFR part 98,
subpart EE.

Recordkeeping.  In addition to the records required by the General
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this
preamble, reporters must keep records of additional data used to
calculate GHG emissions.  A list of specific records that must be
retained for this source category is included in 40 CFR part 98, subpart
EE.

2.  Summary of Major Changes Since Proposal 

The major changes since proposal are identified in the following list. 
The rationale for these and any other significant changes can be found
below or in the comment response document for“Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to Public Comments, Subpart EE:
Titanium Dioxide Production.”

Requirements were added for reporting of carbon-containing waste
generated from less than 100% percent oxidation of coke during the
titanium production process.  40 CFR 98.316 allows for reporting of
quantity of carbon-containing waste generated and associated carbon
contents. 

Missing data procedures were added under 40 CFR 98.315 for monthly
parameters used to calculate emissions, including mass of calcined
petroleum coke, mass of carbon-containing waste, and carbon contents of
calcined petroleum coke.

40 CFR 98.316 was reorganized and updated to improve the emissions
verification process.  Some data elements were moved from section40 CFR
98.317 to section40 CFR 98.316, and some data elements that a reporter
must already use to calculate GHGs as specified in section40 CFR 98.313
were added to section40 CFR 98.316 for clarity. 

3.  Summary of Comments and Responses 

This section contains a brief summary of major comments and responses. 
We received three sets of comments on titanium dioxide production
covering several topics.  Several of these comments were directed at the
requirements for General Stationary Fuel Combustion Sources in subpart
C, and responses to those comments are provided in the preamble section
dealing with that source category.  Responses to significant comments
received can be found in the comment response document for titanium
dioxide production in the docket (EPA-HQ-OAR-2008-508-XXX).Responses to
significant comments received can be found in “Mandatory Greenhouse
Gas Reporting Rule: EPA’s Response to Public Comments, Subpart EE:
Titanium Dioxide Production.”

Method for Calculating GHG Emissions

Comment:  One commenter noted that the carbon oxidation factor for
calcined petroleum coke is not always 100 percent.  They point out that
the calcined petroleum coke comes with impurities, and a certain amount
of the calcined coke is returned to the ground as landfill along with
components such as the un-converted TiO2. Thus, they suggest that EPA
should revise the carbon oxidation factor to allow facilities to use the
most appropriate factor for their process, with supporting documentation
of its derivation available for EPA review as needed.

Response:  EPA has considered the comment but is going to
maintainmaintains the assumption of 100 percent oxidation across all
sectors in the final rule.  Data reporting requirements have been added
to 40 CFR 98.316 to collect information on the quantity of
carbon-containing waste generated that is landfilled and its carbon
contents which are not emitted.  This information will help inform
future methods for calculating process emissions from titanium dioxide
production (e.g.., how to address oxidation rates).  EPA interpreted
that this comment may also be applicable to carbon content of calcined
petroleum coke.  EPA agrees that carbon content may not always be 100%
percent and therefore has revised the rule to allow facilities to use
supplier data or determine carbon contents using appropriate test
methods as part of calculating emissions in section40 CFR 98.313.

Procedures for Estimating Missing Data

Comment:  Two commenters noted there can be numerous reasons data may
not be available, on time, or in the format EPA requires.  In cases
where a required record is found to be missing or determined to be
incorrect, the commenters requested that EPA should provide a procedure
for estimating missing data.

Response:  We concur that there may be circumstances where data on
carbon contents of coke,  and petroleum coke consumption may be missing.
 Records could be misplaced or lost.  Thus, we have revised the rule and
added specific procedures for estimating missing data in 40 CFR 98.315.
These procedures are consistent with those allowed across the rule for
similar parameters.  For example, if a facility is missing data on
carbon contents of petroleum coke we allow facilities to allow sources
to substitute the missing data with another quality assured parameter,
such as the arithmetic average of the carbon contents from the month
immediately preceding and the month immediately following the missing
data incident.

Data Reporting Requirements

Comment:  All commenters noted they are concerned that the level of
information to be reported, which is considered available for public
distribution, could put the domestic TiO2 producers at a disadvantage
relative to international producers.  The commenters do not believe that
CBI provisions briefly outlined in the preamble are adequate to
safeguard the proprietary technical and financial positions of titanium
dioxide production facilities.  The annual production of titanium
dioxide, annual amount of petroleum coke consumed, and annual operating
hours are considered CBI and are unnecessary to carry out the purposes
of this proposed regulation.  This data should only be available onsite
or offsite (e.g., a centralized location), or as requested for security
cleared EPA personnel and their security cleared contractors where a
need is demonstrated for the purposes of this inventory.

Response:  EPA reviewed CBI comments received across the rule (both
general and subpart-specific comments) and our response is discussed in
Section II.R of this preamble and in the comment response document for
legal issues.“Mandatory Greenhouse Gas Reporting Rule: EPA’s
Response to Public Comments, Legal Issues.”  

In addition, see the Section II.N of this preamble for the response on
the emissions verification approach. The amount of petroleum coke
consumed is necessary to calculate annual process CO2 emissions. 
Production capacity and annual production of titanium dioxide is are
required for EPA to verify annual CO2 process emissions.  These
parameters help EPA to determine whether reported emissions are within a
reasonable range.  EPA concurs that data on operating hours can be
retained as a record and does not need to be reported to EPA. It is not
a parameter used in calculating process CO2 emissions.  However,
operating hours would help to verify any anomalies in reported emissions
or supporting parameters related to temporary closures for repairs, or
maintenance.  This data has been moved to recordkeeping requirements in
40 CFR 98.317.

FF.  Underground Coal Mines

At this time, EPA is not finalizing the Underground Coal Mines Subpart
(40 CFR part 98, subpart FF).  As EPA considers next steps, we will be
reviewing the public comments on the proposal preamble, rule and
technical support documentsTSDs for proposed 40 CFR 98 Subpart FF and
other relevant information. EPA will perform additional analysis and
consider alternatives to the monitoring requirements.

GG.  Zinc Production

1.  Summary of the Final Rule 

Source Category Definition.  Zinc production facilities consist of zinc
smelters and secondary zinc recycling facilities.

Reporters must submit annual GHG reports for facilities that meet the
applicability criteria in the General Provisions (40 CFR 98.2)
summarized in Section II.A of this preamble.

GHGs to Report.  For zinc production, report the following:

CO2 process emissions from each Waelz kilns and electrothermic furnace
used for zinc production.

CO2, N2O, and CH4 combustion emissions from each Waelz kiln and each
other stationary combustion unit on site under 40 CFR part 98, subpart C
(General Stationary Fuel Combustion Sources). 

In addition, report GHG emissions for other source categories at the
facility for which calculation methods are provided in the rule, as
applicable.  

GHG Emissions Calculation and Monitoring.  Facilities must calculate CO2
process emissions using one of two methods, as appropriate:

Most reporters can elect to calculate and report process CO2 emissions
from each Waelz kiln and electrothermic furnace by either (1) installing
and operating CEMS and following the Tier 4 methodology (in 40 CFR part
98, subpart C) or (2) using the calculation procedures specified in the
rule.

However, if process CO2 emissions from a Waelz kiln or electrothermic
futnacefurnace are emitted through the same stack as a combustion unit
or process equipment that uses a CEMS and follows Tier 4 methodology to
report CO2 emissions, then the CEMS must be used to measure and report
combined CO2 emissions from that stack, instead of the calculation
procedure described below.  

If using approach #2, calculate process CO2 emissions by determining on
an annual basis the total mass (metric tons) of carbon-containing input
materials (i.e., zinc-bearing material, flux, electrodes, and any other
carbonaceous materials) introduced into each kiln and furnace and the
carbon content of each material.  Determine carbon content annually
either by using supplier data, or by direct measurement using
appropriate test methods.

Data Reporting.  In addition to the information required to be reported
by the General Provisions (40 CFR 98.3(c)) and summarized in Section
II.A of this preamble, reporters must submit additional data that are
used to calculate GHG emissions.  A list of the specific data to be
reported for this source category is contained in 40 CFR part 98,
subpart GG.

Recordkeeping.  In addition to the records required by the General
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this
preamble, reporters must keep records of additional data used to
calculate GHG emissions.  A list of specific records that must be
retained for this source category is included in 40 CFR part 98, subpart
GG.

2.  Summary of Major Changes Since Proposal 

The major changes since proposal are identified in the following list. 
The rationale for these changes can be found below.

The carbon input method was revised to require an annual analysis of all
process inputs and outputs for carbon content rather than monthly
sampling and monthly analysis.

A de minimis was added to exclude accounting for carbon-containing
materials contributing less than 1one percent of the total carbon into
Waelz kiln or electrothermic furnaces.  These materials do not need to
be included carbon mass balance calculations.

Section40 CFR 98.336 was reorganized and updated to improve the
emissions verification process.  Some data elements were moved from
section40 CFR 98.337 to section40 CFR 98.336, and some data elements
that a reporter must already use to calculate GHG'sGHGs as specified in
section40 CFR 98.333 were added to section40 CFR 98.336 for clarity.

 3.  Summary of Comments and Responses 

No comments specific to regulation of the zinc production sector were
received.  We revised the frequency of sampling and analysis of carbon
contents for carbon containing input materials from monthly to annual
consistent with revisions made in response to comments for similar
production processes (e.g. emissions from metal production, see the
preamble sectionSection III.Q for iron and steel for specific responses
to comments.).  These revisions reduce the reporting burden for zinc
production facilities.  We understand that the carbon content of
material inputs does not vary widely at a given facility for the
significant process inputs that contain carbon, and we continue to
account for variations due to changes in production rate, which is
likely a more significant source of variability.   

HH.  Municipal Solid Waste Landfills

1.  Summary of the Final Rule 

Source Category Definition.  This source category consists of: Municipal
municipal solid waste (MSW) landfills that accepted waste on or after
January 1, 1980.  The source category includes the MSW landfill,
landfill gas collection systems, and landfill gas destruction devices
(including flares)) at the landfill. 

This source category does not include hazardous waste, construction and
demolition, or industrial landfills. 

Reporters must submit annual GHG reports for facilities that meet the
applicability criteria in the General Provisions (40 CFR 98.2)
summarized in Section II.A of this preamble.

GHGs to Report.  For MSW landfills, report the following:

Annual CH4 generation and CH4 emissions from the landfill.

Annual CH4 destruction (for landfills with gas collection and control
systems).   

Annual CO2, CH4, and N2O emissions from stationary fuel combustion
devices under 40 CFR part 98, subpart C (General Stationary Combustion
Sources).  

GHG Emissions Calculation and Monitoring.  All facilities must calculate
modeled annual CH4 generation based on:

Measured or estimated values of historic annual waste disposal
quantities; and

Appropriate values for model inputs (i.e., degradable organic carbon
fraction in the waste, CH4 generation rate constant).  Default parameter
values are specified for bulk municipal waste and individual waste
categories.

Facilities that do not collect and destroy landfill gas must adjust the
modeled annual CH4 generation to account for soil oxidation (CH4 that is
converted to CO2 as it passes through the landfill cover before being
emitted) using a default soil oxidation factor.  The resulting value
must be reported and represents both CH4 generation and CH4 emissions.

Facilities that collect and control landfill gas must calculate the
annual quantity of CH4 recovered and destroyed based on either
continuous or weekly monitoring of landfill gas flow rate, CH4
concentration, temperature, and pressure of the collected gas prior to
the destruction device.  

Those facilities that collect and control landfill gas must then
calculate CH4 emissions in two ways and report both results.  Emissions
must be calculated by:

1.  Subtracting the measured amount of CH4 recovered from the modeled
annual CH4 generation (with adjustments for soil oxidation using the
default value and destruction efficiency of the destruction device)
using the equations provided; and

2.  Applying a gas collection efficiency to the measured amount of CH4
recovered to calculate CH4 generation, then subtracting the measured
amount of CH4 recovered (with adjustments for soil oxidation using the
default value and destruction efficiency of the destruction device)
using the equations provided.  Default collection efficiencies are
specified, based on cover material and other factors. 

Data Reporting.  In addition to the information required to be reported
by the General Provisions (40 CFR 98.3(c)) and summarized in Section
II.A of this preamble, reporters must submit additional data that are
used to calculate GHG emissions.  A list of the specific data to be
reported for this source category is contained in 40 CFR part 98,
subpart HH.

Recordkeeping.  In addition to the records required by the General
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this
preamble, reporters must keep records of additional data used to
calculate GHG emissions.  A list of specific records that must be
retained for this source category is included in 40 CFR part 98, subpart
HH.

2.  Summary of Major Changes Since Proposal 

The major changes since proposal are identifiesidentified in the
following list.  The rationale for these and any other significant
changes can be founds below or in the comment response documents for
landfills.“Mandatory Greenhouse Gas Reporting Rule: EPA’s Response
to Public Comments, Subpart HH: Landfills.”

Industrial landfills were removed from the applicability provisions of
Subpart40 CFR part 98, subpart HH.  The applicability provisions were
also modified to exempt landfills that did not accept any waste after
January 1, 1980.

Additional methods for estimating quantities of waste for prior
(historic) years are provided.

The requirement to continuously monitor CH4 composition in the flare gas
was removed.  If a continuous monitoring system is in place, that data
must be used, but weekly sampling of the gas is allowed if such a
continuous system is not usedin place. 

Direct flame ionization methods were added to the rule as an alternative
to the gas chromatographic methods for determining methane
concentrations.  To use a direct flame ionization method, a correction
factor must be determined at least once each reporting year and applied
to adjust the analyzer’s total gaseous organic concentration to an
unbiased methane concentration.  

More detailed default values are provided for landfill gas collection
efficiencies based on cover material and other factors. 

3.  Summary of Comments and Responses 

This section contains a brief summary of major comments and responses. 
A large number of comments on landfills were received covering numerous
topics.  Responses to significant comments received can be found in the
comment response document for landfills in the docket
(EPA-HQ-OAR-2008-508-XXX).“Mandatory Greenhouse Gas Reporting Rule:
EPA’s Response to Public Comments, Subpart HH: Landfills.”

Definition of Source Category

Comment:  Several commenters stated that EPA should limit the
applicability of the industrial landfills to landfills located at food
processing, pulp and paper, and ethanol production facilities (some also
listed petroleum refineries) because these are the only industries for
which landfills were specifically called out.  Several commenters noted
that impacts were only estimated for pulp and paper and food processing
landfills, so EPA should limit the rule to those industries or correct
the cost analysis to reflect the true burden of the rule on industrial
landfills.  Several commenters noted that the reporting requirements
seemed tailored for MSW landfills and were generally inappropriate for
industrial landfills (truck scales, etc.).  One commenter also noted
that, if reporting of GHG emissions from industrial landfills is not
limited to the food processing, pulp and paper, and ethanol production
facilities, then EPA should amend Table HH-1 of 40 CFR part 98, subpart
HH and provide specific factors that are relevant to the regulated
industry.  Several commenters requested that EPA specifically exempt
inorganic chemical manufacturing and mining landfills because they do
not contain organic waste; other commenters suggested EPA delete
requirements for landfills in 40 CFR part 98, subpart Y because
landfills are insignificant compared to other sources at a petroleum
refinery.  

On the other hand, one commenter suggested that EPA may be overlooking
an important source of methane emissions by excluding construction and
demolition landfills as it seems possible that these landfills receive
organic materials such as wood or yard waste that could degrade in an
anaerobic environment.  This commenter requested EPA provide information
on the waste composition of construction and demolition landfills to
explain more fully the basis for its decision to categorically exempt
these sources from GHG reporting requirements. 

Response:  At this time, EPA is not going final with the industrial
landfills proposed requirements of this Subpart.subpart.  In response to
the proposal, EPA received numerous detailed public comments on the
preamble, rule and technical support documentsTSDs under Subpart40 CFR
part 98, subpart HH.  Comments addressed the appropriateness, coverage,
and methodology for addressing greenhouse gasGHG emissions from
industrial landfills. In particular, commenters questioned which
industrial landfills should be covered by the rule and the need for
industry specific factors and methodologies for  calculating and
reporting emissions. As EPA considers next steps, we will be reviewing
the comments and other relevant information and will perform additional
analysis and consider alternatives to the proposed monitoring and
reporting requirements for industrial landfills.  

With regard to construction and demolition landfills, we note that the
IPCC 2006 Guidelines for National Greenhouse Gas Inventories estimates
that construction and demolition waste has a degradable organic content
(DOC) of 0.04 kg/kg waste (see Table 2.5 in Volume 5: Waste), and most
of this organic matter is expected to be wood, with slow degradation
rates (k=0.02 yr-1).  Based on the anticipated properties of
construction and demolition wastes, we anticipated that methane
generation at dedicated construction and demolition debris landfills
would be small compared to MSW landfills.  We will further review these
assumptions as we review comments on industrial landfills.

Comment:  Several commenters stated that the reporting requirements for
closed landfills are burdensome, and the rule should be limited to
reporting for active landfills.  Information on waste disposal
quantities and waste composition data are usually not available for
closed MSW facilities.  Thus, it is impossible to retain or provide the
agency with such records for many old landfill sites.  Several
commenters suggested that EPA should provide additional guidance and
screening tools to identify landfills likely to be below the threshold. 
The commenters noted that small and closed landfills have to collect all
of the data needed to report their emissions in order to determine if
they are above the reporting threshold.

Response:  Closed MSW landfills account for approximately half of the
nationwide methane emissions from MSW landfills.  This is because
landfills can continue to emit for decades after they are closed and
because these landfills are older, and less likely to have been required
to add landfill gas collection systems.  However, we do agree that we
can remove reporting requirements for a subset of closed landfills to
lessen the burden on long-closed landfill facilities.  We evaluated the
various landfill characteristics and identified that a 30-year
waste-in-place (i.e., the total quantity of waste added to the landfill
in the past 30 years) provided the best correlation of the data to sites
that account for the majority of the contribution to the nationwide
greenhouse gasGHG emissions from landfills(see memorandum entitled
“Correlations with Landfill Methane Generation and Actual Emissions”
in the docket EPA-HQ-OAR-2008-0508-2165).  Providing an applicability
date for closed landfills is essential to minimize the burden associated
with obtaining data on old landfills that provide only a small
contribution to the nationwide GHG emissions for landfills, and
landfills closed prior to 1980 would not be relevant for the purposes of
policy analyses.  Therefore, the final rule excludes MSW landfills that
have not accepted waste since January 1, 1980.  We have also expanded
and clarified options for projecting waste disposal quantities that will
help ease the burden associated with calculating emissions from
landfills that have closed after 1980.  EPA remains committed to
providing additional outreach materials, guidelines, and screening tools
to help potential reporters determine whether the reporting rule applies
to their landfill.   

Method for Calculating GHG Emissions

Comment:  Several commenters requested additional guidance on how to
determine waste disposal rates for years prior to the first reporting
year.  One commenter noted that the population method provided in the
rule was difficult for many landfills because of contract carriers that
may haul waste to different landfills in different years, so that the
population served by a landfill can be variable.  Several commenters
noted that the data needed to estimate waste disposal rates for past
years was especially challenging for closed landfills and requested
guidance on how to comply with the rule if the necessary data do not
exist.

Response:  EPA acknowledges that the single proposed method of
estimating past year disposal rates is limiting and may not provide the
most accurate projection of waste disposal rates in all cases.  We have
provided a number of alternative approaches that could be used to
estimate annual waste acceptance rates.  These include using the current
year’s annual waste acceptance rate for all past years of operation
(for active landfills) and using the landfill capacity and the operating
life of the landfill to calculate an average annual acceptance rate (for
active and closed landfills).  These methods provide a reasonable
estimate of historic disposal quantities based on readily available
information, even for older landfills.  Furthermore, these alternative
methods may be just as appropriate or more appropriate for MSW landfills
that do not serve a fixed population area.  

Comment:  A few commenters noted that the Solid Waste Industry for
Climate Solution (SWICS) has developed protocols for calculating
greenhouse gasGHG emissions from landfills [see paper titled, Current
MSW Industry Position and State-of-the-Practice on LFG Collection
Efficiency, Methane Oxidation, and Carbon Sequestration in Landfills
(July 2007)].  The commenters requested that the SWICS recommended
defaults for gas recovery system efficiency, soil oxidation, and flare
combustion efficiency be provided in the rule.  They also stated that an
accurate inventory should account for carbon sequestered in the
landfill. 

Response:  We again reviewed the SWICS methods in light of these
comments.  We agree that the SWICS default recommendations for gas
recovery system efficiency (which vary from 60 to 95 percent for
different types of soil covers) could provide more refined data than
using the default values provided in the rule.  Therefore, we have
included these cover-specific gas recovery efficiencies (commensurate
with the SWICS Protocol) as an alternative to the 75%  percent default
value for collection efficiency.  We have also reviewed the SWICS
protocol for soil oxidation, which provides suggested oxidation factors
ranging from 0.22 to 0.55 depending on the soil cover type.  We have
several concerns with these factors.  First, the values were calculated
using arithmetic means which appear to be biased high due to a few high
oxidation factors; the median values were generally significantly lower
than the average values suggested.  Second, the recommended values
included laboratory test vales, which always yielded higher oxidation
fractions.  The percent of methane oxidized at the landfill surface is
highly dependent on the velocity of gas flow.  While areas of low flow
are expected to have significant oxidation, areas of high flow will have
little to no oxidation.  Landfill gas will generally flow to the surface
in fissures and channels that offer the least resistance to flow. 
Consequently, a significant portion of the landfill gas is likely to
exit the landfill in a limited number of areas under much higher flow
rates than other locations.  These high volume flows will not have
significant oxidation.  Consequently, field test data tend to show lower
oxidation factors than laboratory tests where flow is more uniform. 
Data for 5five field studies for clay covers (the predominant soil cover
type used in the U.S.) were included in the SWICS report.  Four of the
5five field studies had oxidation factors ranging from 0.08 to 0.21, and
the median of all 5five field studies was 0.14.  These data appear to
support the default 0.10 oxidation factor as provided in the final rule
more than they do the 0.22 oxidation factor suggested by SWICS.  We will
continue to assess the available data to improve soil oxidation
estimates; however, we maintain that the use of the 10% percent default
rate is appropriate for this final rule, and clarify that the
site-specific oxidation factors (based on the SWICS method or other
method) are not to be used. We also find that the SWICS Protocol
recommended flare efficiency of 99.996 percent appears unreasonably
high.  The combustion efficiency of flares is very difficult to assess
and may be affected by wind speed and other variables that are not under
the direct control of the landfill owner and operator.  Consequently, we
retained the proposed flare efficiency default.  Finally, with respect
to the suggested sequestration factors, since collecting data on carbon
sequestration is not the purpose of this rule, we do not require
facilities to calculate or report carbon storage in landfills.

Monitoring and QA/QC Requirements 

Comment:  Several commenters stated that EPA’s proposal to require
landfills with gas collection systems to continuously measure the
methane flow and concentration at the flare or energy device is
financially burdensome.  According to commenters, the capital costs as
well as operation and maintenance costs of a continuous composition
analyzer are prohibitive for many facilities, and EPA underestimated the
number of facilities that would have to install the required monitors. 
The commenters also stated that the composition of landfill gas is not
highly variable, so less frequent monitoring is justified.  One
commenter noted that the standard operating procedure at many landfills
with gas collection systems is to collect monthly CH4, flow, and
concentration data at the flare.  Another commenter recommended that MSW
landfills be allowed to calculate quarterly, by means of engineering
formulae and/or modeling, the amount of methane present at the flare or
energy device.  The commenter further noted that, in many cases, it is
not practical or even possible for the MSW facility to measure the
amount of methane or even landfill gas at the energy device because this
device is not owned, operated, or controlled by the facility.  Several
commenters also requested that EPA allow direct flame ionization
analyzers in addition to the gas chromatography methods provided in the
proposed rule.

On the other hand, several commenters suggested that EPA should allow,
require, or otherwise move towards direct measurement methodologies for
characterizing landfill emissions. 

Response:  Methane composition of landfill gas can be expected to vary
based on extreme barometric changes, rainfall event, etc.  We expect
diurnal variations as well (although not to the same extent as seasonal
variations).  We also expect variations if the gas collection system has
a variable speed fan and the fan speed is adjusted.  The commenters
provided no data to support the claim that the anticipated fluctuations
are not significant enough to warrant continuous monitoring.  At
proposal, we required continuous flow and composition monitors to
improve the accuracy of the emissions estimate.  However, after
additional uncertainty analysis, we determined that the cost of
continuous monitoring systems is not justified in relation to the
relatively small improvement in certainty over somewhat less frequent
monitoring, i.e. weekly.  We do require landfill gas collection systems
already equipped with continuous monitoring systems to determine daily
average flow and concentrations and to use these data in their gas
recovery calculations.  For collection systems that do not have
continuous gas monitors, weekly sampling is required.  Weekly monitoring
provides an adequate number of samples to evaluate the variability and
uncertainty associated with methane generation.  We did not select
monthly monitoring because monthly monitoring would result in greater
uncertainty and would not significantly reduce the costs compared to
weekly monitoring.  

We did provide for direct flame ionization analyzers to be used as an
alternative to the gas chromatography methods provided in the proposed
rule.  This alternative reduces the burden on landfills that do not have
existing gas chromatography equipment.  However, direct flame ionization
analyzers will measure both methane and non-methane organic compounds
and, as such, will tend to overstate the methane concentration in the
landfill gas and provide a high bias to the amount of methane recovered.
 To eliminate this bias, we also required a correction factor that must
be determined at least annually, to arrive at the ratio of the methane
concentration to the direct flame ionization analyzer response
(calibrated with methane).  Including this alternative method with the
correction factor reduces the burden on landfills, but still ensures
that the calculated methane recovery quantities are unbiased and
comparable to the recovery quantities calculated when gas
chromatographic methods are used to speciate methane specifically. 

With respect to direct measurement methods, we find that direct soil
measurements have high uncertainties due to heterogeneity of the
landfill and cover soils and are, therefore, less desirable than the
methods provided in the rule (cost more and have higher uncertainty). 
Optical sensing methods, while potentially more accurate, are very
expensive.  If measurements were done for only a one-time performance
test, the measured emissions would have rather high uncertainties due to
variations in temperature and atmospheric pressure.  If the measurements
were conducted more often, they would be prohibitively expensive.  At
this time, we cannot justify requiring these types of monitoring systems
for this rule.  Furthermore, we find that the monitoring requirements in
the final rule provide for accurate emission estimates at a reasonable
cost burden to reporters. 

II.  Wastewater Treatment 

At this time, EPA is not going final with the wastewater treatment
subpart (Subpart 40 CFR part 98, subpart II).  As EPA considers next
steps, we will be reviewing the public comments and other relevant
information.  Please note, as originally proposed for this rule,
centralized domestic wastewater treatment plants continue to be
excluded.

The Agency received a number of comments regarding the applicability of
this subpart as well as clarification of the definition of anaerobic
wastewater treatment processes.  In addition, commenters requested that
EPA consider a de minimus exemption for emissions from wastewater
treatment.  The Agency also received a number of comments requesting
redefinition of the monitoring requirements for this supart.subpart.    

Based on careful review of comments received on the preamble, rule and
technical support documentsTSDs under proposed 40 CFR part 98, Subpart
II, EPA will consider alternatives to data collection procedures and
methodologies and examine additional study results that have been
released since the proposal was issued.  Specifically, EPA will consider
requirements for the location of meters for taking flow measurements,
the frequency of flow and chemical oxygen demand (COD )measurements
taken, as well as the potential use of alternate parameters, such as
BOD.  EPA will also consider the inclusion of indirect or non-methane
VOCvolatile organic compound emissions.  Lastly, EPA will consider the
acceptable methods for estimating missing data.  EPA will consider
optimal methods of data collection in order to maximize data accuracy,
while considering industry burden.  

JJ.  Manure Management

1.  Summary of the Final Rule 

Source Category Definition.  Reporters must submit annual GHG reports
for facilities A livestock facility that emits 25,000 metric tons CO2e
or more per year from manure management systems and meet the
applicability criteria in the General Provisions (40 CFR 98.2)
summarized in Section II.A of this preamble.  must report.  A facility
with an average annual animal population below those listed in Table
JJ-1 of 40 CFR part 98, subpart JJ does not need to calculate emissions
or report.  A facility with an average annual animal population that
exceeds those listed in Table JJ-1 should conduct a more thorough
analysis to determine applicability.  Average annual animal populations
for static populations (e.g., dairy cows, breeding swine, layers) are
estimated by performing an animal inventory or review of facility
records.  Average annual animal populations for growing populations
(meat animals such as beef and veal cattle, market swine, broilers, and
turkeys) are estimated using the average number of days each animal is
kept at the facility and the number of animals produced annually.  The
rule also contains procedures for facilities with more than one animal
group present (e.g., swine and poultry) to determine if they must
report.

A manure management system stabilizes or stores livestock manure, or
does both, in one or more of the following system components:

Uncovered anaerobic lagoons. 

Liquid/slurry systems with and without crust covers (including but not
limited to ponds and tanks).

Storage pits.

Digesters, including covered anaerobic lagoons.

Solid manure storage.

Feedlots and other drylots.

Drylots, including feedlots.

High-rise houses for poultry production.

Other  (poultry without litter).

Poultry production with litter.

Deep bedding systems for cattle and swine.

Manure composting.

Aerobic treatment.

GHG emissions from sources at livestock facilities unrelated to the
stabilization and/or storage of manure are not covered under this rule
and are not reported.  These sources Sources considered to be unrelated
to the stabilization and/or storage of manure include daily spread or
pasture/range/paddock systems or land application activities or other
methods of manure utilization not listed above.  In addition, manure
management activities located off site from a livestock operation are
not included in this rule.  These off site activities include but are
not limited to off site land application of manure, other off site
methods of manure utilization, or off site manure composting operations.


Facilities that meet the applicability criteria in the General
Provisions (40 CFR 98.2) summarized in Section II.A of this preamble
must report GHG emissions.

GHGs to Report.  For all livestock facilities with a manure management
system that meets or exceeds the reporting threshold, the facility must
report aggregate CH4 and N2O emissions from the system components listed
above.  For those manure management systems that include digesters, CH4
generated and destroyed, as well as any CH4 leakage, at the digester
must also be reported.

A facility that is subject to this rule only because of emissions from
manure management systems is not required to report emissions under 40
CFR part 98 subparts C through PP other than subpart JJ.  

GHG Emissions Calculation and Monitoring.  Detailed methods for
calculating GHG emissions are included in the rule and are briefly
described below.  For each manure management system component other than
digesters, facilities must calculate CH4 mass emissions using the
following inputs and data:

Type of system component.

Average annual animal population (by animal type)) contributing manure
to the manure management system component.

Typical animal mass (for each animal type).

Fraction of manure handled by weight for each animal type managed in
each system component (assumed to be equal to the fraction of volatile
solids and /nitrogen handled in each system component).

Estimated annual average volatile solids (VS) value calculated using
values provided in look-up tables.

Volatile solids excretion rates provided in look-up tables for the
animal populations contributing manure to the manure management system
component.

Maximum CH4-producing potential of the managed manure and CH4 conversion
factors provided in look-up tables.  for the animal populations
contributing manure to the manure management system component.

Methane conversion factor used (for each manure management system
component). 

Nitrogen excretion rates (by animal type) using values provided in
look-up tables for the animal populations contributing manure to the
manure management system component.

N2O emission factors (by animal type) provided in look-up tables for the
animal populations contributing manure to the manure management system
component. 

For anaerobic digesters, facilities must calculate CH4 emissions and the
annual mass of CH4 generated and destroyed based on the following inputs
and data:

Continuous monitoring of CH4 concentration, flow rate, temperature, and
pressure of the digester gas.

CH4 destruction efficiency of the burned digester gas (based on the
manufacturer’s specified efficiency or 99 percent, whichever is
less),destruction device and fugitive (leakage) emissions.

For each manure management system component, calculate N2O emissions
using the following inputs:

Type of system component.

Average annual animal population.

Percent of manure handled in each component.

Estimated annual average nitrogen (N) value calculated using values
provided in look-up tables.

N2O emission factors provided in look-up tables. 

The CH4 collection efficiency(ies) used (for each digester).

Data Reporting.  In addition to the information required to be reported
by the General Provisions (40 CFR 98.3(c)) and summarized in Section
II.A of this preamble, reportersfacilities must submit additional data
that are used to calculate GHG emissions.  A list of the specific data
to be reported for this source category is contained in 40 CFR part 98,
subpart JJ.

Recordkeeping.  In addition to the records required by the General
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this
preamble, reportersfacilities must keep records of additional data used
to calculate GHG emissions.  A list of specific records that must be
retained for this source category is included in 40 CFR part 98, subpart
JJ.

2.  Summary of Major Changes Since Proposal 

The major changes since proposal are identified below.  The rationale
for these and any other significant changes can be found below or in the
comment response document for “Mandatory Greenhouse Gas Reporting
Rule: EPA’s Response to Public Comments, Subpart JJ: Manure
Management.”

To assist facilities in determining if they are subject to this rule, a
table has been provided that presents average annual animal population
values for specific livestock operations (i.e., beef, dairy, swine, and
poultry).  Facilities that have average annual animal population values
below those shown in the table will not be required to report or
complete the calculations to determine whether they need to report. 

Since proposal, the requirements for monthly manure sampling to
determine volatile solids (VS) and nitrogen (N) content have been
removed.  As an alternative to Instead of obtaining VS and N content
from manure sampling, facilities must use default VS and N excretion
values as provided by EPA in look up tables.  The default VS and N
excretion values are consistent with the 1990-2008 U.S. GHG inventory
for manure management and enteric fermentation.  For beef and dairy
cows, heifers, and steers, VS and N excretion rates arewere calculated
using the IPCC Tier II methodology, based on the relationship between
animal performance characteristics such as diet, lactation, and weight
gain and energy utilization.  The method used is that outlined by the
IPCC Tier II methodology.In response to comments, EPA used the most
up-to-date information on U.S. animal diets to calculate these excretion
rates.  For other animal groups, reference values from ASAE and USDA are
used.  

EPA has also adjusted the calculationcalculations for methaneCH4 and N2O
emissions from manure management systems to account for volatile solids
and nitrogen removal through solid separation.  If solid separation
occurs prior to the MMS manure management systemcomponent, facilities
must use default removal efficiencies as provided by EPA in look up
tables.  The default values are consistent with those cited in the
“Development Document for the Final Revisions to the National
Pollutant Discharge Elimination System Regulation and the Effluent
Guidelines for Concentrated Animal Feeding Operations”
(EPA-821-R-03-001), published in December 2002.  

3.  Summary of Comments and Responses 

This section contains a brief summary of major comments and responses. 
A large number of comments on manure management were received covering
numerous topics.  Responses to significant comments received can be
found in the comment response document for manure management in the
docket (EPA-HQ-OAR-2008-508-XXX).“Mandatory Greenhouse Gas Reporting
Rule: EPA’s Response to Public Comments, Subpart JJ: Manure
Management.”

Comment:  A number of commenters supported EPA’s decision to include
livestock facilities with manure management operationssystems in the
proposed rule.  These commenters noted that the establishment of a
mandatory GHG reporting rule is the next logical step in reducing and
mitigating GHG emissions in the U.S., and that manure management is a
significant source of GHG emissions in the United States .S. that should
be addressed.

However, other commenters stated that livestock farms facilities should
not be required to report GHG emissions.  These commenters noted that a
small number of farms facilities would be covered by the proposed rule,
and these farmsfacilities would represent a very small percentage of the
total number of farmslivestock facilities in the U.S. which would not
provide a large enough set of data to help improve or reduce
uncertainties associated with GHG inventories.  Several of the
commenters stated that manure management is not a major source of GHG
emissions in the U.S., and the environmental benefits from the rule
would be minimal compared to the effort required to report emissions.  

Response:  EPA disagrees that the manure management source category be
excluded from this rule.  Emissions from manure management represent
approximately 14% of all agricultural emissions. The Manure management
has been determined to be a key source of GHG emissions in the U.S.,
based on the key source category methodology developed by the
Intergovernmental Panel on Climate Change (IPCC).  The IPCC identifies
key sources as those sources that have significant impacts on the total
emissions or emission trends in a country.

While livestock manure GHG emissions represent a relatively small
fraction of the total U.S. GHG emissions, these emissions are large in
absolute terms.  According to the 2009 U.S. GHG Inventory, CH4 emissions
from manure management systems totaled 44 million metric tons CO2e, and
N2O emissions were 14.7 million metric tons CO2e in 2007; manure
management systems account for 7.5 percent of total anthropogenic CH4
emissions and 4.7 percent of N2O emissions in the U.S.  

In addition, the collection of facility level GHG emission data,
including the type of manure management systems in operation and the
number and types of animals serviced by those systems, will help to
inform future climate change policy decisions.  While the actual number
of facilities reporting will be quite small in comparison to the total
number of facilities in the U.S., the data gathered through this effort
is quite valuable.  For example, these data will help to improve the
understanding of emission rates and actions that facilities take to
reduce emissions and may potentially improve the effectiveness ofand
design of voluntary and/or mandatory programs designed to reduce
emissions.  

Comment:  Multiple commenters stated that the monitoring requirements in
the proposed rule would be too burdensome and expensive for industry to
comply with.  These commenters expressed concern that sampling manure
for VS and N would require more time and effort and be more expensive
than EPA estimated.  Multiple commenters suggested that default values
such as from the American Society of Agricultural and Biological
Engineers (ASABE) be permitted for VS and N instead of measured values
to eliminate some of the expense associated with the proposed rule.  

In addition, a number of commenters noted that there were some
methodological issues associated with the monitoring requirements for VS
and N.  Multiple commenters noted that the requirements for manure
sampling should be clarified.  

Response:  EPA acknowledges these concerns and has removed the manure
sampling requirements from the final rule.  As discussed earlier, EPA
believes thatused default values for VS and N excretion from USDA and
ASAE for swine and poultry, and has calculated these rates for beef and
dairy cows, heifers, and steers using the IPCC Tier II methodology,
based on the relationship between animal performance characteristics
such as diet, lactation, and weight gain and energy utilization.  The
use of these animal-specific default values for VS and N will greatly
lessenreduce the burden to comply with the reporting rule, while only
minimally impacting the estimates of greenhouse gasGHG emissions.  EPA
also believes theThe variation in sampling techniques from farm facility
to farmfacility when characterizing manure “as excreted” from the
various animal populations on the farmfacility (as would have been
required by the proposal) would negate the benefit derived from this
requirement.  EPA considered designing a more complex and rigorous
program to ensure consistency in the implementation of a manure sampling
program and to ensure that manure samples represented “as excreted”
manure (prior to any storage or treatment).  However, after reviewing
comments, we determined that the expected burden of such a program, in
terms of both time, effort, and expense, outweighed the merits at this
time.

Comment:  Some commenters claimed that methodological issues existed
with the estimation of GHG emissions from manure management.  A number
of commenters noted that calculation errors caused threshold head
numbers to be overestimated, which caused the amount of emissions from
these operations and the number of operations that would need to report
to be underestimated.

Response:  To estimate the number of facilities at each threshold, EPA
first developed a number of model facilities to represent the manure
management systems that are most common on large livestock operations
and have the greatest potential to exceed the GHG reporting threshold. 
Next, EPA used the U.S. GHG inventory methodology for manure management
to estimate the numbers of livestock that would need to be present to
exceed the threshold for each model livestock operation type.  Finally,
EPA combined the numbers of livestock required on each model operation
to meet the thresholds with U.S. Department of Agriculture (USDA) data
on farm sizes to determine how many farms in the United States have the
livestock populations required to meet the GHG thresholds for each model
livestock operation.

Since proposal, EPA made revisions to the threshold analysis spreadsheet
calculations based on information and data provided by commenters.  EPA
corrected conversion factors used in the nitrous oxide emission
calculations, and corrected spreadsheet cell reference errors along with
using updated VS and N values.  EPA now estimates that there will be
approximately 107 livestock facilities that will need to report under
the rule.  

Comment: Commenters also expressed concerns with the emission
calculation methodologies.calculations.  Multiple commenters noted that
the maximum methane producing capacity (Bo) values used do not reflect
variations in animal diet.  Several commenters had concerns about the
methodology used to estimate the methane conversion factors (MCFs).  In
addition, some commenters suggested that other data sources should be
considered, such as the ASABE manure standards.   

Response:  EPA has corrected errors in the threshold estimation
calculations in the final rule.  

EPA supportsResponse:  After a thorough review of available information,
EPA has determined that the methodologies and data sources that are
being used to calculate emissions in the this rule represent the best
available methods and data.  EPA reviewed many protocols and approaches
prior to selecting the proposed methodology.  EPA’s selected
methodology for reporting GHG emissions (methane and nitrous oxide)
associated with manure management systems is based on EPA’s Inventory
of U.S. Greenhouse Gas Emissions and Sinks, as well as the
Intergovernmental Panel on Climate Change (IPCC) Guidelines for National
Greenhouse Gas Inventories.  These methodologies rely on the use of
activity data, such as the number of head of livestock, operational
characteristics (e.g., physical and chemical characteristics of the
manure, type of management system(s)), and climate data, to calculate
greenhouse gasGHG emissions associated with traditional manure
management systems.  In addition, the selected methodology for the
reporting rule uses measured values for those manure management systems
(e.g., anaerobic digesters) that collect and combust biogas. 

EPA considered requiring direct measurement of GHG emissions from manure
management systems, but rejected this approach due to the extreme
expense and complexity of such a measurement program.  EPA is
promulgating an approach that would allowallows the use of default
factors, such as a system emission factor, for certain elements of the
calculation, and encourageencourages the use of some site-specific data
wherever possible.  The cost of such an approach is significantly lower
than a direct measurement program.  In addition, this approach is
consistent with the methods used in offset programs throughout the
world, including the California Climate Action Registry’s (CCAR)
Manure Management Project Reporting Protocol.  For these offset
programs, farms livestock operations are required to complete
calculations that establish their “baseline” emissions (prior to the
use of a biogas collection system).  These baseline emission
calculations use similar emissions calculations and default values as
are in EPA’s Reporting Rule.

The IPCC guidelines have been established by a recognized panel of
experts and underwent significant peer review prior to their adoption. 
In addition, protocols for offset programs, such as CCAR, have gone
through similar public review processes prior to their acceptance and
use.  

Comment:  Multiple commenters have requested more detailed look up
tables and a tool to provide more clarity on which facilities are
required to report under the final rule.  

Response:  EPA agrees that additional tables and tools would facilitate
compliance with the rule and ease the burden associated with reporting. 
In response to the comments, EPA has added a threshold table to the
final rule (Table JJ-1) to help livestock facilities with manure
management systems better determine if they might be subject to the
requirements of the rule.  EPA also intends to develop applicability
tools that can assist facilities that could be covered by the rule,
based on table JJ-1 in 450 CFR part 98, subpart JJ, in conducting a more
detailed evaluation.  These tools will include detailed look-up tables
showing the estimated livestock head numbers that would be necessary in
order to meet or exceed the threshold and a calculation tool to assist
in performing the calculations in the proposed rule.

KK.  Suppliers of Coal 

At this time, EPA is not going final with a subpart for suppliers of
coal.  As EPA considers next steps, we will be reviewing the public
comments and other relevant information.   

The Agency received a number of lengthy, detailed comments regarding the
coal suppliers subpart.  Commenters generally opposed the proposed
reporting requirements and raised multiple issues with EPA’s legal
authority for requiring coal suppliers to report CO2 emissions.  Several
commenters stated that reporting by coal suppliers would represent a
duplication of the reporting by coal users.  For example, electric
utilities and industrial plants, which consume the vast majority of coal
supplied, are already required to report data on emissions based on
their coal purchases.  Commenters also stated that the reporting
requirement would entail significant burden and capital costs to coal
suppliers.  In most cases, commenters provided alternative approaches to
the reporting requirements proposed by EPA.  For example, commenters
suggested that EPA exempt from reporting coal mines that supply coal to
mine-mouth power plants, modify the required coal weighing and sampling
standards, and eliminate the required statistical correlation between
HHV and carbon content.

Commenters raised other issues regarding the reporting of data such as
concerns that coal suppliers and laboratories could not realistically
purchase and install new coal testing and sampling equipment and provide
training to meet the requirements of the proposed rule.

Based on careful review of comments received on the preamble, rule and
technical support documentsTSDs under proposed 40 CFR part 98,
Subpartsubpart KK, EPA will perform additional analysis and consider
alternatives to data collection procedures and methodologies.  These
alternatives will provide coverage of coal supplied, imported, or
exported while concurrently taking into account industry burden.

LL.  Suppliers of Coal-based Liquid Fuels 

1.  Summary of the Final Rule 

Source Category Definition.  This source category consists of producers,
importers, and exporters of products listed in Table MM-1 of 40 CFR part
98, subpart MM that are coal-based (coal-to-liquid products).  A
producer of coal-to-liquid products is any owner or operator who
converts coal into liquid products (e.g., gasoline, diesel) using the
Fischer-Tropsch or an alternative process. 

Suppliers of coal-to-liquid products that meet the applicability
criteria in the General Provisions (40 CFR 98.2) summarized in Section
II.A of this preamble must report GHG emissions.

GHGs to Report.  Suppliers of coal-to-liquid products must report the
CO2 emissions that would result from the complete combustion or
oxidation of the coal-to-liquid products.

Suppliers of coal-to-liquid products are not required to report data on
emissions of other GHGs that would result from the complete combustion
or oxidation of their products, such as CH4 or N20.

GHG Emissions Calculation and Monitoring.  For each type of
coal-to-liquid product, suppliers must calculate CO2 emissions that
would result from the complete combustion or oxidation of the
coal-to-liquid products by following the procedures in 40 CFR 98.393.

Data Reporting.  In addition to the information required to be reported
by the General Provisions (40 CFR 98.3(c)) and summarized in Section
II.A of this preamble, reporters must submit additional data that are
used to calculate GHG emissions that would result from the complete
combustion or oxidation of their products.  A list of the specific data
to be reported for this source category is contained in 40 CFR 98.386.

Recordkeeping.  In addition to the records required by the General
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this
preamble, reporters must keep records of additional data used to
calculate GHG emissions that would result from the complete combustion
or oxidation of their products.  A list of specific records that must be
retained for this source category is included in 40 CFR 98.387.

2.  Summary of Major Changes Since Proposal 

The major changes since proposal are identified in the following list. 
The rationale for these and any other significant changes can be found
below.

We replaced the procedures and calculations proposed in Subpart40 CFR
part 98, subpart LL with references to the Subpart40 CFR part 98,
subpart MM procedures and calculations.  As a result of considerable
comment and EPA analysis, Subpart40 CFR part 98, subpart MM procedures
and calculations were significantly updated.  Since the procedures and
calculations necessary for sampling, testing, and measuring
coal-to-liquid products are intrinsically linked to the procedures and
calculations used for petroleum products, we concluded that referencing
Subpart40 CFR part 98, subpart MM in Subpart40 CFR part 98, subpart LL
would achieve consistency and completeness.  

We reorganized and updated 40 CFR 98.386 by mirroring 40 CFR 98.396 in
order to reflect the updates we made to procedures and calculations and
to assist in EPA data verification.  

3.  Summary of Comments and Responses 

EPA did not receive any specific comments on proposed 40 CFR part 98,
subpart LL (suppliers of coal-based liquid fuels).  Changes made to this
subpart were implemented to ensure consistency with changes made to
Subpart40 CFR part 98, subpart MM based on public comments provided and
EPA analysis conducted.

MM.  Suppliers of Petroleum Products 

1.  Summary of the Final Rule 

Source Category Definition.  Suppliers of petroleum products consist of:

Petroleum refineries that produce petroleum products through
distillation of crude oil.

Importers who satisfy the same meaning given in §40 CFR 98.6, including
any entity that imports petroleum products or natural gas liquidsNGLs as
listed in Table MM-1. of 40 CFR part 98, subpart MM.  Any blender or
refiner of refined or semi-refined petroleum products shall be
considered an importer if it otherwise satisfies the aforementioned
definition. 

Exporters who satisfy the same meaning given in §40 CFR 98.6, including
any entity that exports petroleum products or natural gas liquidsNGLs as
listed in Table MM-1. of 40 CFR part 98, subpart MM.  Any blender or
refiner of refined or semi-refined petroleum products shall be
considered an exporter if it otherwise satisfies the aforementioned
definition.

Suppliers of petroleum products that meet the applicability criteria in
the General Provisions (40 CFR 98.2) summarized in Section II.A of this
preamble must report GHG emissions that would result from the complete
combustion or oxidation of the product(s) they supply.

GHGs to Report.  Suppliers of petroleum products must report annually:

CO2 emissions that would result from the complete combustion or
oxidation of each petroleum product and natural gas liquid produced,
used as feedstock, imported, or exported during the calendar year. 

CO2 emissions that would result from the complete combustion or
oxidation of any biomass co-processed with petroleum feedstocks at a
refinery.

Suppliers of petroleum products are not required to report data on
emissions of other GHGs that would result from the complete combustion
or oxidation of their products, such as CH4 or N20. 

GHG Emissions Calculation and Monitoring.  Suppliers of petroleum
products must choose one of two methods to calculate CO2 emissions that
would result from the combustion or oxidation of each petroleum product
and natural gas liquid: 

Method 1: Use the default CO2 emission factors provided in the
regulations for eacha given petroleum product and natural gas liquid or
NGL; or

Method 2: Develop an emission factor for a given petroleum product or
natural gas liquid using direct measurements of density and carbon
share.

To calculate CO2 emissions that would result from the combustion or
oxidation of biomass co-processed with petroleum feedstock, reporters
must use a CO2 emission factor that is provided in the regulations for
each type of biomass.

In calculating total CO2 emissions that would result from the combustion
or oxidation of all petroleum products and natural gas liquids that
leave the refinery, refineries must subtract the emissions from
petroleum products and natural gas liquids that enter the refinery as a
feedstock to be further refined or used on site as well as biomass and
biomass-based fuels that are co-processed or blended with petroleum
feedstocks.

Data Reporting.  In addition to the information required to be reported
by the General Provisions (40 CFR 98.3(c)) and summarized in Section
II.A of this preamble, reporters must submit additional data used to
calculate GHG emissions that would result from the complete combustion
or oxidation of the product(s) supplied as well as information on the
characteristics of crude oil used at a refinery.  The specific list of
data to be reported for this source category is contained in 40 CFR part
98.396 and includes information to support the data verification
process.

Recordkeeping.  In addition to the records required by the General
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this
preamble, reporters must keep records of additional data used to
determine the quantities and characteristics of product(s) reported
under this subpart and to calculate GHG emissions that would result from
the complete combustion or oxidation of the product(s) supplied.  A list
of specific records that must be retained for this source category is
included in 40 CFR part 98.387.

2.  Summary of Major Changes Since Proposal 

The major changes since proposal are identified in the following list. 
The rationale for these and any other significant changes can be found
below or in the comment response document for suppliers“Mandatory
Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments,
Subpart MM: Suppliers of petroleum products
(EPA-HQ-OAR-2008-508-XXX).Petroleum Products.” 

We established a reporting threshold for importers and exporters of
25,000 metric tons of CO2 per year.

We changed the source category definition of petroleum refinery for the
purposes of 40 CFR part 98, subpart MM to only include facilities that
process crude oil.  As such, we are not requiring reporting from
facilities that only handle intermediary petroleum products.

We refined the definition of importers and exporters of petroleum
products to clarify reporting requirements for blenders.

We are not requiring reporters to rely on an exclusive list of standard
methods for the measurement of the quantity of products or the
calibration and recalibration of equipment.  Instead, reporters must use
an appropriate standard method published by a consensus-based standards
organization.  If no such standard exists, reporters are allowed to rely
on industry standard practices.

We provide more flexibility in the frequency of equipment recalibration.
 Reporters must now comply with the frequency specified by the
manufacturer’s directions or the selected quantity measurement method.

We removed the option for reporters to directly measure density but not
carbon share under Calculation Method 2.  We determined that using a
measured density and a default carbon share factor will likely adversely
affect the accuracy of the calculated emission factor since the density
and carbon share of hydrocarbons are, in the absence of impurities,
correlated.  

We are not requiring reporters to rely on an exclusive list of standard
methods for sampling products, measuring density, and measuring carbon
share under Calculation Method 2.  Instead, reporters must use an
appropriate standard method published by a consensus-based standards
organization.  

We added more specific requirements for the frequency of sampling under
Calculation Method 2 and now allow for mathematical composites of
samples in addition to physical composites of samples.

To ensure consistent accounting of denaturant across reporters, we are
requiring reporters to assume that 2.5% percent of the volume of any
ethanol product that is blended into a petroleum-based product is a
petroleum-based denaturant.  See below for further explanation. 

For bulk natural gas liquids (NGLs), reporters must calculate the
emissions that would result from the complete combustion or oxidation of
the individual components that constitute the NGL (i.e., ethane,
propane, butane, isobutane, and pentanes plus).

We updated the definition of petroleum products to be clear that no
petroleum product supplier must report on plastics and plastic products
and that importers and exporters must report on asphalt, road oil, and
lubricants.

We updated the default emissions factors based on technical research
since the proposal.  We updated certain factors to correct technical
errors and to reflect more recent data.  We expanded the factors to four
significant digits to enhance precision.  We also added grade-based
sub-categories of finished motor gasoline and blendstocks, combined
diesel and fuel oil categories into “distillate fuel” categories,
and added sulfur-based subcategories of distillate fuel No. 1 and 2 to
better distinguish between product categories with potentially different
carbon contents.  Full documentation of default emissions factors can be
found in the TSD. 

We updated section 40 CFR 98.396. First, we made section40 CFR 98.396
more specific, in some cases breaking up one reporting requirement into
two for clarity. Second, to allow for EPA verification of reporter
calculations, we added reporting requirements for data that a reporter
must already use to calculate GHGs as specified in section40 CFR 98.393
to section  through 98.396.  Third, after removing the prescriptive list
of allowable methods, we added data reporting requirements on the method
selected to measure quantity, density, and carbon content and the method
selected to sample in order to track the appropriateness of these
methods.

We require reporters to assume that ethanol contains 2.5%  percent
petroleum-based denaturant because we want to ensure that reporters
account for the CO2 emissions that would result from the combustion or
oxidation of the denaturant.  All ethanol that is blended with petroleum
products reported in 40 CFR part 98, subpart MM should contain more than
1.96% percent petroleum-based denaturant by volume, per the requirements
in 27 CFR Parts 20 and 21 to make ethanol non-potable.  We considered
relying on reporters to estimate the percent volume of denaturant in
their products, but we determined that, in many cases, reporters would
not know this information.  We have concluded that 2.5% percent is a
suitable assumption for the level of denaturant since, according to an
Internal Revenue Service interpretation of Section 15332 in the Food,
Conservation, and Energy Act of 2008 in notice 2009-06, ethanol
containing greater than 2.5% percent denaturant by volume would not be
eligible for the full value of the Volumetric Ethanol Excise Tax Credit.
 There may be cases where ethanol containing less than 2.5% percent
denaturant is blended with petroleum-based products, but we concluded
that it is better to conservatively account for potential
petroleum-based carbon emissions rather than arbitrarily pick a number
between 1.96% percent and 2.5% percent.

3.  Summary of Comments and Responses 

This section contains a brief summary of major comments and responses. 
A large number of comments on suppliers of petroleum products were
received covering numerous topics.  Responses to significant comments
received can be found in the comment response document for
suppliers“Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to
Public Comments, Subpart MM: Suppliers of petroleum products
(EPA-HQ-OAR-2008-508-XXX).Petroleum Products.”

Selection of Threshold

Comment:  In the proposed rule, EPA sought comment on whether or not to
establish a de minimis level of imported and exported petroleum
products, either in terms of the quantity of products or the CO2
emissions associated with the combustion or oxidation of products, to
eliminate any reporting burden for parties that may import or export a
small amount of petroleum products on an annual basis. In response, EPA
received several comments in support of establishing some type of de
minimis value, including a threshold of 25,000 metric tons of CO2 from
the complete combustion or oxidation of all products from individual
importers and exporters. EPA also received at least one comment in
support of establishing a threshold value for refineries reporting under
40 CFR part 98, subpart MM. 

Response:  In today’s rule, we are establishing a threshold of 25,000
metric tons of CO2 per year for importers and exporters of petroleum
products and natural gas liquids; the threshold is based on a
calculation of CO2 emissions that would result from complete combustion
or oxidation of the imported or exported petroleum products and natural
gas liquids. 

When we conducted the threshold analysis for the proposed rule, we
estimated from EIA data that 224 companies would be covered in subpart40
CFR part 98,  MM as importers.  Through this analysis, we found that at
a threshold of 25,000 metric tons CO2 per year 175 importers and 99.9%
percent of total emissions that would result from the combustion or
oxidation of imported products would be covered by the proposed rule. 
Therefore, establishing a 25,000 metric ton CO2 threshold would drop 49
reporters in exchange for a 0.1% percent drop in total emissions. 
Nonetheless, we decided to propose reporting for all importers because
we felt the reporting burden would be minimal since importers already
report the product quantity data to other federalFederal agencies.

Since proposing the rule, EPA has learned new information, through
comments and research, about importers that could be covered as
reporters under 40 CFR part 98, Subpart MM. EPA may have omitted some
importers of small volumes of petroleum products or natural gas liquids
from our original threshold analysis, due to lack of public data. We
never intended to cover such small volume imports with this rule (e.g.,
importers of non-fossil fuel products that contain small quantities of
petroleum or natural gas liquids, such as butane lighters).  Therefore,
for the final rule, EPA concludes that establishing a 25,000 metric ton
CO2 threshold for importers will relieve burden on importers of
insignificant quantities of petroleum products and natural gas liquids
that we never intended to cover with this rule without significantly
diminishing the amount of information received by the agency.  In
addition, a 25,000 metric ton CO2 threshold is consistent with other
upstream fuel and industrial gas supplier thresholds for importers and
exporters in today’s rule. 

When we conducted the threshold analysis for the proposed rule, we could
not estimate the number of exporting companies that would be covered in
40 CFR part 98, subpart MM because the necessary data was not publically
available.  Nonetheless, we decided to propose reporting for all
exporters because we concluded that the reporting burden would be
minimal given the type of information that exporters must maintain as
part of their normal business operations. 

Since proposing the rule, based on analogous information learned on
importers, EPA has concluded that some exporters of very small volumes
of petroleum products or natural gas liquids could be covered as
reporters under Subpart MM40 CFR part 98, subpart MM.  We never intended
to cover such small volume exporters with this rule (e.g., exporters of
non-fossil fuel products that contain small quantities of petroleum or
natural gas liquids, such as butane lighters).  Therefore, for the final
rule, EPA has concluded that establishing a threshold for exporters will
relieve burden on exporters of insignificant quantities of petroleum
products and natural gas liquids that we never intended to cover with
this rule.  In today’s rule, we have selected a 25,000 metric ton CO2
threshold because we conclude that it will not significantly diminish
the amount of information received by the agency; overall, exports of
refined and semi-refined products are lower than imports, so the
threshold adopted for imports will be adequate for collecting data on
exports.  In addition, a 25,000 metric ton CO2 threshold is consistent
with other upstream fuel and industrial gas supplier thresholds for
importers and exporters in today’s rule. 

In today’s rulemaking, we require all refineries as defined in 40 CFR
part 98, subpart MM to report, as was proposed.  Our threshold analysis
of refineries in the proposed rule indicated that all refineries would
be covered even if we were to establish a 100,000 metric ton CO2
threshold.  Furthermore, we have determined that all refineries covered
by this subpart are already tracking the necessary data to comply with
the reporting requirements so the requirements would not pose an undue
burden.

Monitoring and QA/QC Requirements

Comment:  EPA received several comments that the proposed approach to
determining product quantity was too prescriptive.  These comments
indicated that the list of allowable methods and equipment types for
determining the quantity of products in the proposed rule was
incomplete, would result in significant costs for industry, and could
adversely impact the quality of the measurements. Commenters noted that
industry uses a much larger and ever-growing number of industry methods
and equipment types to determine quantity for purposes of product
transfers and financial records, including methods and equipment types
used to comply with Internal Revenue Service, Securities and Exchange
Commission, and Department of Homeland Security’s Bureau of U.S.
Customs & Border Protection regulations.  Commenters suggested that
EPA’s ability to develop and maintain a comprehensive list of methods
would require considerable resources, since companies and
consensus-based standards organizations review quantity measurement
methods regularly to ensure consistency with technological changes and
advancements.  Commenters also suggested that methods may improve over
time for certain products as a direct result of this rulemaking.

Response:  In today’s rule, we are addressing these concerns by
adopting an approach that recognizes the multitude of appropriate
industry standard methods and practices and leaves open the possibility
that industry may adopt better methods, equipment, and practices over
time to determine quantities of products.  EPA is requiring that
petroleum product suppliers use an appropriate standard method developed
by a consensus-based standards organization, when such a standard method
exists.  If no such standard method exists, reporters are allowed to
follow industry standard practices.  Consensus-based standards
organizations include organizations such as ASTM International, the
American National Standards Institute (ANSI), the American Gas
Association (AGA), the American Society of Mechanical Engineers (ASME),
the American Petroleum Institute (API), and North American Energy
Standards Board (NAESB).  Reporters must ensure that all equipment used
for measuring quantity is calibrated and periodically recalibrated
according to the manufacturer’s directions or specifications in the
appropriate consensus-based industry standard method.

In order to further EPA’s understanding of the methods and equipment
that reporters use, and to help us better assess the appropriateness of
the standard methods and industry practices that individual reporters
select, we are requiring that all petroleum product suppliers report the
standard method or industry standard practice they use to measure each
distinct product quantity that they report to EPA.

Comment:  Several commenters recommended that EPA provide more flexible
approaches to the direct measurement of carbon share and density under
Calculation Method 2.  Some noted that the proposed requirement to test
samples at the end of the year could negatively impact the integrity and
quality of those samples.  These commenters suggested that EPA allow
reporters to test samples monthly and create a mathematical composite of
these test results at the end of the year.  Some commenters suggested
that EPA develop a mechanism whereby reporters could reduce the
frequency of sampling once the reporter demonstrates that the
variability in the density and carbon share of the product is
sufficiently small, and even eliminate direct measurement requirements
and allow reporters to use emissions factors developed in previous
years.  We also received comments requesting that we expand our list of
acceptable carbon share measurement methods.

Response:  We have incorporated several of the suggestions to increase
the flexibility of the Calculation Method 2 approach in today’s rule. 
Reporters are now allowed to test their monthly samples throughout the
year and conduct a mathematical composite of the test results at the end
of the year.  We have also expanded the list of acceptable sampling,
density, and carbon share methods to include any appropriate standard
method published by a consensus-based standards organization.  

We could not determine an adequate approach for allowing reporters to
reduce the sampling frequency of products based on statistical evidence
of low variability in the density and carbon share for a given product.
We want to capture changes in product characteristics over time and have
determined that taking monthly samples of an entire product category
would not be overly burdensome.  Furthermore, reporters are allowed to
use default factors under Calculation Method 1 if they so choose.

Data Reporting Requirements

Comment:  EPA received several comments requesting that we eliminate
reporting requirements related to products that have potentially
non-emissive uses, including plastics and plastic products,
petrochemical feedstocks, petroleum coke sent to landfill, asphalt and
road oil, and lubricants and waxes.  One commenter questioned the
incongruity in reporting requirements proposed for refiners, who would
report on all products, and importers and exporters who would not be
required to report on asphalt, road oil, lubricants, waxes, plastics,
and plastic products.

Response:  Today’s rule requires reporting on products with
potentially non-emissive uses.  Comprehensive upstream data will provide
EPA with a full accounting of the emissions that would result from the
complete combustion or oxidation of all petroleum products and natural
gas liquids introduced into the economy. Furthermore, comprehensive
facility-level data can help us conduct a more robust mass balance
assessment for data verification purposes.  While we recognize that
carbon in some petroleum products, such as asphalt, can remain
un-oxidized for long periods, petroleum product supplier cannot always
know with certainty whether or not the carbon in their products will be
released into the atmosphere. Even asphalt can be burned as fuel or
incinerated as waste. In the Inventory of US Greenhouse Gas Emissions
and Sinks, EPA notes several areas of uncertainty surrounding the fate
of carbon in petroleum products including those for which the Inventory
assumes a 100% percent storage factor for the purposes of the national
inventory (e.g., asphalt roofing, asphalt cement, and asphalt paving
materials).  As discussed in the proposal, a comprehensive and rigorous
system for tracking the fate of petroleum products that may have
non-emissive uses is beyond the scope of this rule, and would require a
much more burdensome reporting obligation for petroleum product
suppliers and other downstream users of petroleum products and natural
gas liquids. The data reported as a result of this rulemaking will allow
EPA to conduct further research in the future on the pathways and
ultimate fate of products with potential non-emissive uses.

It was never EPA’s intention to require reporting on plastics and
plastic products, so we made this explicit in the definition of
petroleum products as well as our definition of a refinery in 40 CFR
part 98, subpart MM, which now excludes any facility (e.g. a plastics
manufacturing plant) that does not process crude oil. Any CO2 emissions
that would result from the combustion or oxidation of plastics and
plastic products manufactured in the U.S. should already be accounted
for when a petroleum product supplier introduces the petrochemical
feedstock (e.g., propylene) into the economy.

In response to comments on the incongruity of the reporting burden for
refiners compared to importers and exporters, we have reevaluated the
list of petroleum products with potentially non-emissive uses that
importers and exporters do not have to report.  In the proposed rule,
this list included asphalt, road oil, lubricants, waxes, plastics, and
plastic products.  Our rationale for excluding these products for
importers and exporters was our assessment that there is a much larger
variety of these products entering and leaving the country than is
produced at a petroleum refinery.  Upon further consideration, however,
we have concluded that only waxes, plastics, and plastic products would
pose an undue administrative burden on importers and exporters.  Waxes,
plastics, and plastic products enter and leave the country in
wide-ranging forms (e.g., cosmetics, candles, lawn furniture, plastic
wear) making it difficult to accurately assess the petroleum-based
carbon content of these products.  We have concluded that the types of
asphalt, road oil, and lubricants imported in and exported from the
country is much less variable, and importers already track these
products and report the quantities to EIA.  We have also established a
25,000 metric tons CO2 annual reporting threshold for importers and
exporters in today’s rule, which should reduce the number of reporters
and minimize the reporting of products that are imported or exported in
very low quantities.  Therefore, we are requiring importers and
exporters to report the volume and CO2 emissions that would result from
the complete combustion or oxidation of the asphalt, road oil, and
lubricants they supply.

In response to comments that collecting data on products with
potentially non-emissive uses will overestimate actual emissions
released into the atmosphere, EPA has and will continue to characterize
CO2 emissions data reported under 40 CFR part 98, subpart MM as
emissions that would result from the complete combustion or oxidation of
the reported product(s) and not as actual emissions. 

Comment: EPA received many comments urging us to leverage data that
petroleum product suppliers already report to the Energy Information
Administration (EIA) and to follow EIA’s data collection procedures
and protocols. For example, one commenter urged EPA to require refiners
on a facility-level and company-wide basis to report to the EPA the same
level of information on crude imports and processing that is currently
reported to the EIA and to follow a process similar to the one used by
the EIA; and another commenter urged us to align our reporting
requirements with what the industry is already providing to the EIA. 
Some commenters, urged EPA to make use of data already reported to EIA
or other federalFederal agencies instead of requiring reporting directly
to EPA through this rulemaking.  EPA also received comments recommending
that EIA reporting remain separate from the reporting requirements of
this rule.

Response:  In the proposed rulemaking, EPA stated that we considered,
but did not propose, the option of obtaining data by accessing existing
Federal government reporting databases and we sought comment on this
decision. 

In today’s rulemaking, we are requiring reporters to report data
directly to EPA.  We have determined that in order to collect
facility-level data from refineries (and company-level data from
importers and exporters) that is consistent with other reporters in this
rule, in terms of timing, reporting, and verification procedures, we are
not able to rely upon EIA data.  In addition, EIA relies on a number of
legal authorities to pledge confidentiality to statistical survey
respondents for company-level information.  Some data are collected with
legal authority from the Confidential Information Protection and
Statistical Efficiency Act of 2002 (CIPSEA), under which reported
information must be held in confidence and must be used for statistical
purposes only.  Collection of data directly by EPA in a central system
will allow EPA to electronically verify and publish the data quickly, to
use the information for non-statistical purposes, and to handle
confidential business information in accordance with the Clean Air Act
CAA (see the general provisions preamble for addition discussion on
CBI).  In addition, EPA is collecting data that is not currently
reported to EIA, such as carbon content.

In today’s rulemaking we did not replicate EIA’s reporting
requirements and methodologies if we did not consider them sufficient to
achieve our objective, which is to collect the most comprehensive and
accurate carbon data possible on on the CO2 emissions that would result
from the complete combustion or oxidation of petroleum products
introduced into the economy. For example, we provide a comprehensive
list in Tables MM-1 and MM-2 of 40 CFR part 98, subpart MM, according to
which reporters must categorize their products for reporting under
today’s rulemaking.  This list differs from EIA’s list of products,
according to which reporters must report to EIA.  Some of the products
are the same on both lists (e.g., finished aviation gasoline and
kerosene) while some products are classified differently on one list
than on the other (i.e., the EPAEPA’s list breaks reformulated
gasoline up by summer and winter varieties while EIA breaks reformulated
gasoline up by type of oxygenate blended into it).  We crafted the
EPAEPA’s product list carefully and we feel that each category has the
potential to have a unique carbon share and/or density.  Therefore, we
are continuing to require reporting on these products in today’s
rulemaking to meet our objective, even though our list deviates from the
EIA product list in certain cases.  Overall, the items on our list are
common products in commerce and are already tracked by refineries,
importers, and exporters.  Therefore,, we estimate that the additional
burden to comply with this rule would will be minimal.

NN.  Suppliers of Natural Gas and Natural Gas Liquids 

1.  Summary of the Final Rule 

Source Category Definition.  Suppliers of natural gas and natural gas
liquids are:

Natural gas liquids (NGL) fractionators, which are installations that
fractionate NGLs into their constituent liquid products: ethane,
propane, normal butane, isobutane or pentanes plus for supply to
downstream facilities.

Local natural gas distribution companies (LDCs) that own or operate
distribution pipelines that deliver natural gas to end users.  Companies
that operate interstate pipelines transmission or intrastate
transmission pipelines are not part of this source category. 

Suppliers of natural gas and NGLs that meet the applicability criteria
in the General Provisions (40 CFR 98.2) summarized in Section II.A of
this preamble must report GHG emissions that would result from complete
combustion or oxidation of products they supply.

GHGs to Report.  Natural gas fracionatorsfractionators must report CO2
emissions that would result from the complete combustion or oxidation of
the annual quantities of propane, butane, ethane, isobutene, and
pentanes plus supplied. 

Local distribution companies must report CO2 emissions that would result
from the complete combustion or oxidation of the annual volume of
natural gas distributed to their customers.

Suppliers of natural gas and NGLs are not required to report data on
emissions of other GHGs that would result from the complete combustion
or oxidation of their products, such as CH4 or N20. 

GHG Emissions Calculation and Monitoring.  Reporters must use one of two
methods to calculate the CO2 emissions that would result from the
complete combustion or oxidation of natural gas supply or NGL supply:

One method uses either a measured or default fuel heating value and
either a measured or default CO2 emissions factor.  This method is most
appropriate for liquid fuels.  

The second method uses either a measured or default CO2 emissions
factor.  This method is most appropriate for gaseous fuels.

A NGL fractionator must then follow two additional equations, if
applicable, to subtract the CO2 emissions that would result from the
complete combustion or oxidation of NGL supply that are double-counted. 
A LDC must then follow up to four additional equations, if applicable,
to subtract the CO2 emissions that would result from the complete
combustion or oxidation of natural gas supply that is double-counted.  

Data Reporting.  In addition to the information required to be reported
by the General Provisions (40 CFR 98.3(c)) and summarized in Section
II.A of this preamble, reporters must submit additional data that are
used to calculate natural gas or NGL supply.  A list of the specific
data to be reported for this source category is contained in 40 CFR part
98, subpart NN.

Recordkeeping.  In addition to the records required by the General
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this
preamble, reporters must keep records of additional data used to
calculate natural gas or NGL supply.  A list of specific records that
must be retained for this source category is included in 40 CFR part 98,
subpart NN.

2.  Summary of Major Changes Since Proposal

The major changes since proposal are identified in the following list. 
The rationale for these and any other significant changes can be found
below or in the comment response document for“Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to Public Comments, Subpart NN:
Suppliers of Natural Gas and NGLs.Natural Gas Liquids.”

We changed the source category responsible for reporting NGL supply in
40 CFR part 98, subpart NN from all natural gas processors to only
facilities that fractionate natural gas liquids.  See Section 3 for
rationale.

We eliminated the requirement to report bulk NGL since NGL fractionators
do not supply bulk NGL. 

We added equations to calculate emissions that would result from the
oxidation or combustion of the following volumes of natural gas and NGLs
because they should be subtracted from the reporter’s total emissions
calculation, when applicable: fractionated NGLs received from other
fractionators; natural gas injected for storage; natural gas delivered
to individual customers already reporting under another Subpart of this
rule; and natural gas delivered by an LDC to another LDC.  

We clarified the points of measurements for reporting purposes.  See
Section 3 for rationale. 

We changed the rule to allow local distribution companies to use
transmission pipeline metered volumes and calculated heating value where
the local distribution companies do not perform their own measurements. 

We provide flexibility in frequency of equipment calibration, requiring
reporters to comply with standard industry practices for measurements
used for billing purposes as audited under Sarbanes Oxley regulations.

We added a procedure for measuring the carbon content of blends of NGLs
since NGL fractionators may supply blends of NGLs.  

We updated section40 CFR 98.406.  First, we made section 98.39640 CFR
98.406 more specific, in some cases breaking up one reporting
requirement into two for clarity.  Second, to allow for EPA verification
of reporter calculations, we added reporting requirements for data that
a reporter must already use to calculate GHGs as specified in section40
CFR 98.403 to section40 CFR 98.406.  This includes the addition of
reporting requirements for new calculations introduced in the final rule
to prevent supply double-counting.  Third, after removing the
prescriptive list of allowed standards and methods, we added data
reporting requirements on the method selected to measure quantity, HHV,
and carbon content.  Fourth, we added a reporting requirement for the
quantity of odorized propane. See Section 3 for our rationale of this
decision. Fifth, we added data reporting requirements for inputs
received by a NGL fractionator in order to conduct verification using a
mass-balance approach.

3.  Summary of Comments and Responses 

This section contains a brief summary of major comments and responses. 
A large number of comments on suppliers of natural gas and NGLs were
received covering numerous topics.  Responses to significant comments
received can be found in the comment response document for
suppliers“Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to
Public Comments, Subpart NN: Suppliers of natural gasNatural Gas and
NGLs in the docket (EPA-HQ-OAR-2008-508-XXX).Natural Gas Liquids.”

Definition of Source Category

Comment:  EPA received many comments on the non-emissive use of natural
gas liquids (NGLs).  In general, these comments stated that NGLs such as
ethane, butane, and isobutene, are either used as feedstocks in the
petrochemical industry or as blendstocks that are reported by refineries
in Subpart40 CFR part 98, subpart MM, and should not be reported as
though they are completely combusted or oxidized.  Several commenters
proposed that odorized propane should be the focus of Subpart40 CFR part
98, subpart NN rather than all NGLs because odorized propane is the only
NGL that is combusted as fuel.

Response:  Today’s rule still requires reporting on all NGL products,
even those with potentially non-emissive uses.  Comprehensive upstream
data will provide EPA with a full accounting of the emissions that would
result from the complete combustion or oxidation of all natural gas
liquids introduced into the economy.

As discussed in the proposal, a comprehensive and rigorous system for
tracking the fate of natural gas liquids that may have non-emissive uses
is beyond the scope of this rule, and would require a much more
burdensome reporting obligation for NGL fractionators and downstream
users of natural gas liquids.  Based on the data available today, we do
not believe that a NGL fractionator can know with certainty whether or
not the carbon in their products will be released into the atmosphere. 
The data reported as a result of this rulemaking will allow EPA to
conduct further research on the pathways and ultimate fate of NGL and to
refine our understanding of and policy on products with potential
non-emissive uses.

Therefore, EPA does not concur with the proposal to replace NGL
reporting with propane odorizers.  However, EPA concurs that odorized
propane lines up closely with propane combusted downstream, and that
data collection on odorized propane would help EPA decide if and how to
carry out a wide variety of CAA provisions on emission sources, as
authorized broadly under CAA Sectionssections 114 and 208.  As a result,
we have added reporting requirements on the volume of propane odorized
on site in today’s rule.  

We do not concur that products reported under 40 CFR part 98, subpart
NN, such as isobutane to be blended with fuel, will be double-counted as
products reported under subpart MM 40 CFR part 98, subpart MM. Subpart
MM requires refineries to report all non-crude feedstocks that enter the
facility in order to subtract the emissions that would result from the
oxidation or combustion of those products from their calculations.  Such
methodology allows EPA to collect data on the entire petroleum and
natural gas liquids system without any double-counting.

Finally, in response to comments that collecting data on products with
potentially non-emissive uses will overestimate actual emissions
released into the atmosphere, EPA will continue to characterize CO2
emissions data reported under 40 CFR part 98, subpart NN as emissions
that would result from the complete combustion or oxidation of the
reported product(s) and not as actual emissions.

Comment:  Many commenters discouraged EPA from requiring reporting from
natural gas processors.  In general, these comments stated that
processors do not know the constituents of the gas they process.  They
further stated that since bulk NGLs are often sent from one processor to
another, reporting by processors on bulk NGLs would result in
double-counting of supply.  Ultimately, several commenters were confused
by the multiple definitions provided in the rule for a natural gas
processor and were not clear on the exact covered party in 40 CFR part
98, subpart NN. 

Response:  In the final rule, we specify the source category as NGL
fractionators rather than as natural gas processors, and we have removed
the requirement to report bulk NGLs.  To avoid any remaining potential
for double-counting, we provide an equation for a
fractionaterfractionator to subtract from its calculations any NGL
constituents received from other fractionators that would report those
products under this rule.

By requiring reporting from NGL fractionators, we have removed the need
for the term “natural gas processor” in Subpart40 CFR part 98,
subpart NN.  Multiple definitions for this term no long exist in the
rule.

Monitoring and QA/QC Requirements

Comment:  Many commenters interpreted EPA’s measurement and
calibration requirements differently than we intended, and as a result
pressed upon EPA the inability of industry to reasonably meet such
requirements.  Many commenters interpreted that EPA required meter
reading and calibration of every customer meter.  Other commenters
interpreted that EPA required daily measurement totals of throughput.

Response:  In today’s rule, we provide precise language to remove any
confusion about monitoring and quality assuranceQA requirements.  First,
we clarify that the point of measurement for natural gas supply is the
city gate meter.  If the LDC makes its own measurements at the city gate
according to business as usual practices, then it must use its own
measurements.  If not, it must use the delivering pipeline invoices
measurements.  The only exceptions are that the point of measurement for
natural gas delivered to large end-users is the customer meter and the
point of measurement for natural gas stored or removed from storage is
the appropriate storage meter.  However, we clarify that customer meters
and storage meters are not subject to the Subpart40 CFR part 98, subpart
NN calibration requirements.

Second, we clarify that the minimum frequency of the measurements of
quantities of NGLs and natural gas shall be based on the reporter’s
standard practices for commercial operations.  For NGL fractionators the
minimum frequency of measurements shall be the measurements taken at
custody transfers summed to the annual reportable volume.  For natural
gas the minimum frequency of measurement shall be based on the LDC’s
standard measurement schedules used for billing purposes and summed to
the annual reportable volume.  If daily measurements are not standard
practice for a reporter, then that reporter need not conduct daily
measurements.

EPA clarifies in the final rule that customer meters do not face
calibration requirements under Subpart40 CFR part 98, subpart NN.  Other
equipment used to measure quantities must be calibrated prior to their
first use for reporting under this subpart, using a suitable standard
test method published by a consensus based standards organization or
according to the equipment manufacturer’s directions. Such equipment
must also be recalibrated at the frequency specified by the standard
test method used or by the manufacturer’s directions. EPA has
concluded that initial calibration requirements are necessary to ensure
consistency across all reporters and accuracy of data. Since such a wide
variety of calibration methods is allowed and since commenters stated
that industry already calibrates carefully as a result of State Utility
Commission and other regulations, EPA concluded that industry is already
following such calibration requirements for usual business operations. 

Data Reporting Requirements

Comment:  EPA received many comments on the requirement for LDCs to
report information on individual customers.  In general, commenters
interpreted the reason for EPA to collect this data differently than was
intended.  Many commented on the CBI nature of customer-specific
delivery information.  Others commented that LDCs do not or may not have
access to the EIA or EPA numbers of their customers.  One commenter told
us that a LDC can only attest to the gas volume delivered through a
single particular meter at a single particular location, which is not
necessarily an individual customer.

Response:  In the final rule, EPA has clarified that an LDC must report
on customers that receive more than 460,000 million standard cubic feet
(Mscf) per year in order to subtract that volume out of its total
calculations.  EPA’s intention is to use this data to remove potential
double-counting and to prevent a LDC from calculating and reporting an
overstated supply volume.  EPA can also use these data to verify that
covered direct emitters are approximately reporting under the rule.  In
response to comments that LDCs do not or may not have access to
customers’ EIA or EPA numbers, we have changed the reporting of this
from required to voluntary, if known.  We have further specified that
LDCs must report large volumes delivered to a single meter rather than
to a particular end-user. 

OO.  Suppliers of Industrial GHGs 

1.  Summary of the Final Rule 

Source Category Definition.  Suppliers of industrial GHGs consist of the
following:

Facilities producing any fluorinated GHG or N2O, except those that
produce only HFC-23 generated as a byproduct during HCFC-22 production.

Bulk importers of fluorinated GHGs or N2O, if the total combined imports
of industrial GHGs and CO2 exceed 25,000 metric tons of CO2e per year.

Bulk exporters of fluorinated GHGs or N2O, if the total combined exports
of industrial GHGs and CO2 exceed 25,000 metric tons CO2e per year.

Suppliers of Industrial GHGs that meet the applicability criteria in the
General Provisions (40 CFR 98.2) summarized in Section II.A of this
preamble must report industrial GHG supply flows.

GHGs to Report.  Suppliers of industrial GHGs must report the amount of
N2O and each fluorinated GHG produced, imported, exported, transformed,
or destroyed during the calendar year.  Importers and exporters of CO2
must calculate and report annual amounts of CO2 according to 40 CFR part
98, subpart PP. 

GHG Emissions Calculation and Monitoring.  Suppliers must use the
following methods to calculate annual industrial GHG supply flows:

The mass of each fluorinated GHG or N2O produced must be determined by
measurements of gas production, less the mass of that GHG added to the
process upstream (e.g., where used GHGs are added back to the production
process for reclamation).

The mass of each fluorinated GHG transformed must be determined
considering the mass of fluorinated GHG fed into the transformation
process and the efficiency of that process (as indicated by yield
calculations or quantities of unreacted fluorinated GHGs or nitrous
oxide permanently removed from the process and recovered, destroyed, or
emitted).

The mass of each fluorinated GHG destroyed must be determined by
measurements of the mass of fluorinated GHG fed to the destruction
device and a measurement of the destruction efficiency.

Data Reporting.  In addition to the information required to be reported
by the General Provisions (40 CFR 98.3(c)) and summarized in Section
II.A of this preamble, reporters must submit additional data that are
used to calculate industrial GHG supply flows or that can be used to
verify industrial gas supply flows.  A list of the specific data to be
reported for this source category is contained in 40 CFR part 98,
subpart OO.

Recordkeeping.  In addition to the records required by the General
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this
preamble, reporters must keep records of additional data used to
calculate GHG emissions.  A list of specific records that must be
retained for this source category is included in 40 CFR part 98, subpart
OO.

2.  Summary of Major Changes Since Proposal 

The major changes since proposal are identified in the following list. 
The rationale for these and any other significant changes can be found
below or in the comment response document for industrial gas
supply.“Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to
Public Comments, Subpart OO: Suppliers of Industrial GHGs.”

EPA has elaborated on the definition of "produce" to clarify what it
does and does not include.  The definition now explicitly includes (1)
the manufacture of a fluorinated GHG for use in a process that will
result in the transformation of that GHG (either at or outside of the
production facility) and (2) the creation of a fluorinated GHG (with the
exception of HFC-23) that is captured and shipped off site for any
reason, including destruction.  The definition now explicitly excludes
the creation of by-products that are released or destroyed at the
production facility.     

EPA has eased the accuracy and precision requirements for measuring
production, transformation, and destruction.  EPA is also permitting
facilities flexibility in the frequency of measurements and calibration
of measurement devices.  Masses produced, fed into transformation
processes, and fed into destruction devices must now be estimated to a
precision and accuracy of one percent rather than 0.2 percent. 
Requirements to measure concentrations, which had previously been
associated with the transformation and destruction provisions, have been
changed to requirements to estimate concentrations or related
quantities.    

EPA has eliminated the requirement that fluorinated GHG production
facilities that destroy fluorinated GHGs annually verify the
DEdestruction efficiency of their destruction devices.

EPA has added an additional method for estimating missing mass flow data
in the event that a secondary mass measurement for that stream
isn'tisn’t available.  In that event, producers can use a related
parameter and the historical relationship between the related parameter
and the missing parameter to estimate the flow.  

EPA has removed the option for reporters to develop their own methods
for estimating missing data if they believe that the prescribed method
will over- or under-estimate the data.  

EPA has added some reporting requirements to be consistent with the
changes to the calculations and monitoring sections and to permit
verification of emissions calculations. 

EPA has added an exemption from reporting requirements for import or
export shipments containing less than 250 metric tons of CO2e.  

EPA has clarified that the criteria for imported container heels at
paragraph 98.417(e) set forth the conditions under which importers do
not need to report heels; they do not establish requirements for all
containers containing residual gas.  If importers import containers with
residual gas that does not meet these conditions, they must simply
report these imports under paragraph 98.416(c).  In addition, EPA is
adding another condition under which imported heels do not need to be
reported; that is the case in which the heels are recovered and included
in a future shipment.  

EPA is requiring fluorinated GHG production facilities to submit a
one-time report describing current measurement and estimation practices.

EPA is requiring the one-time report on measurement practices because
the Agency is providing some flexibility to reporters regarding the
methods that they use to calculate industrial gas supply flows.  This
flexibility permits reporters to use a larger range of methods and
measurement equipment than were proposed, and it is important for EPA to
understand the methods and equipment and their accuracies.  Similar
reports are required under EPA’s Stratospheric Ozone Protection
Regulations at 40 CFR part 82.

As noted above, EPA removed the option for reporters to develop their
own methods for estimating missing data if they believe that the
prescribed method will over- or underestimate the data.  EPA removed
this option for two reasons.  First, the proposed provision lacked clear
guidance on when alternative methods should be used (e.g., on the size
of an underestimate that would justify use of an alternative method) and
on how they should be developed.  Second, the proposed provision was
redundant with the new provision that permits reporters to estimate
missing data using a related parameter and the historical relationship
between the related parameter and the missing parameter.  This new
option provides reporters with flexibility in substituting for missing
data in the event that a secondary mass measurement is not available,
but sets out general guidance on how to select the substitute data.

3.  Summary of Comments and Responses 

This section contains a brief summary of major comments and responses. 
A large number of comments on suppliers of industrial GHGs were received
covering numerous topics.  Responses to significant comments received
can be found in the comment response document for suppliers“Mandatory
Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments,
Subpart OO: Suppliers of industrialIndustrial GHGs in the docket
(EPA-HQ-OAR-2008-508-XXX)..”

Definition of Source Category

Comment:  EPA received a number of comments regarding the proposed
definition of “fluorinated greenhouse gas.”  Several commenters
argued that the proposed definition was too broad because it would
include nonvolatile materials that could not be emitted to the
atmosphere and materials for which GWPs had not been calculated.  One
commenter suggested establishing a lower vapor pressure limit for
fluorinated GHGs (heat transfer fluids) of 400 Pa (0.004 bar, or 3three
mm Hg absolute) at 25 C.  Some commenters expressed the concern that the
lack of GWPs for some covered compounds would lead to incomplete or
inconsistent reporting because facilities would assign their own GWPs to
compounds for which GWPs were not provided in Table A-1 of 40 CFR part
98, subpart OOA.

Some commenters recommended that EPA address these concerns by requiring
reporting of only those fluorinated compounds listed in Table A-1 of 40
CFR part 98, subpart OO.A.  However, one of these commenters noted that
the list in A-1 is incomplete and inconsistent, excluding for example,
some high-GWP compounds whose low-GWP alternatives are included.  This
commenter recommended that EPA establish a “visible and participative
process” to add other compounds as appropriate to Table A-1 of 40 CFR
part 98, subpart A.

Response:  In today’s final rule, EPA is modifying the proposed
definition of fluorinated greenhouse gasGHG by adding an exemption for
“substances with a vapor pressure of less than 1 one mm of Hg absolute
at 25 degrees C.”  This modification ensures that non-volatile
fluorocarbons such as fluoropolymers are excluded from reporting
requirements, while requiring reporting of fluorocarbons (as well as SF6
and NF3) that could reasonably be expected to be emitted to the
atmosphere.   

As noted by several commenters, this definition would require reporting
of some fluorocarbons to which GWPs have not been assigned in either
IPCC or World Meteorological Organization (WMO) Scientific Assessments
(i.e., fluorocarbons for which Table A-1 of 40 CFR part 98, subpart OOA
does not provide GWPs).  However, the lack of GWPs for some
fluorocarbons will not impede reporting because EPA is requiring
reporting of production and other quantities in tons of chemical rather
than in tons of CO2e.  For purposes of determining whether or not the
25,000 metric ton CO2e import or export threshold is exceeded, EPA is
requiring facilities to include only substances whose GWPs appear in
Table A-1 of 40 CFR part 98, subpart A.  

EPA believes that this approach is prudent and appropriate.  As
acknowledged by commenters, Table A-1 of 40 CFR part 98, subpart OOA is
not a complete listing of current or potential fluorinated GHGs; the
IPCC and WMO lists on which it is based reflect only the facts that the
listed materials have been synthesized, their atmospheric properties
investigated, the results published, and the publications found by the
IPCC and WMO Assessment authors.  Table A-1 is known to omit some
existing fluorinated GHGs and it unavoidably omits future fluorinated
GHGs that have not yet been synthesized.  Given the radiative properties
of the carbon-fluorine bond, any fluorocarbon emitted into the
atmosphere may have a significant GWP.  This is true even for some
fluorocarbons with lifetimes of less than one year, including, for
example, HFE-356pcc3, with a lifetime of four months and a 100-year GWP
of 110.  

Reporting of fluorocarbons that do not appear in Table A-1 of 40 CFR
part 98, subpart OOA will provide valuable information on the full range
of volatile fluorocarbons entering U.S. commerce.  This information can
be used to assess the overall volume and importance of compounds for
which GWPs have not been evaluated and to help identify which compounds
should have their GWPs evaluated first.  In addition, once GWPs have
been identified for these compounds, historical reports in tons of
chemical can be converted into CO2e.  Without a comprehensive reporting
requirement, such historical information could be lost.  Ultimately, all
of this information can be used to inform policy decisions regarding the
appropriate type and scope of emission reduction measures for these
gases.  Considering the modest cost of reporting production, import, and
export of such compounds, the potential value of this information
justifies a comprehensive definition of fluorinated GHG.  

EPA agrees with commenters who noted that Table A-1 of 40 CFR part 98,
subpart OOA should be periodically updated through a visible and
participative process.  EPA anticipates that as GWPs are evaluated or
re-evaluated by the scientific community, the Agency will update Table
A-1 of 40 CFR part 98, subpart A through notice and comment rulemaking. 
EPA may also, through rulemaking, establish a more proactive process for
ensuring that GWPs are appropriately evaluated or re-evaluated.  

Comment:  EPA received comments both supporting and opposing a
requirement to report imports of fluorinated GHGs contained in equipment
and foams.  Commenters supporting such a requirement noted that these
imports comprised a significant fraction of U.S. consumption of
fluorinated GHGs, that excluding these imports from reporting would put
domestic manufacturers at a disadvantage and lead to leakage of
manufacturing and increased emissions of GHGs, and that the burden of
reporting these imports would be low, since there are relatively few
importers and the reported information is easily accessible.  Commenters
opposing such a requirement stated that the benefit of reporting would
be small because pre-charged equipment and foams are “hermetically
sealed systems that essentially emit no GHGs,” while the cost would be
high due to the large number of importers.   

Response:  EPA did not propose to require reporting of fluorinated GHGs
contained in imported products because EPA was concerned that the
administrative burden of such a requirement could be considerable, while
the quantities imported in at least some types of products could be
small.  However, in the proposal EPA acknowledged that the quantities of
fluorinated GHGs imported in pre-charged equipment and foams appeared
significant, and that ascertaining the identity and quantity of
fluorinated GHGs in these products might be relatively straightforward. 
EPA is continuing to research these issues, and is deferring the final
decision on whether to include imports of equipment and foams containing
fluorinated GHGs to a later rulemaking.

Monitoring and QA/QC Requirements

Comment:  Several commenters stated that facilities could not meet the
proposed accuracy, precision, and frequency requirements for their
measurements of production, transformation, and destruction using
existing equipment and practices.  These commenters stated that they
would need to expend significant funds (millions of dollars in some
cases) and time to install Coriolis flowmeters in multiple streams and
to implement daily sampling protocols to analyze the contents of these
streams.  One commenter requested that EPA revise its precision and
accuracy requirements to one percent for measurements of mass.  Other
commenters argued that instead of establishing strict accuracy,
precision, and frequency requirements for measuring production, EPA
should permit facilities to use existing measurement instruments and
practices, such as NIST Handbook 44 and the trial HFC reporting program
patterned on EPA’s reporting requirements for ozone-depleting
substances.  

Response:  Given the limited amount of time before 2010 data collection
must begin, EPA agrees that it is appropriate to ease the accuracy and
precision requirements proposed for measuring production,
transformation, and destruction.  EPA is therefore revising these
requirements in the final rule.  EPA is also permitting facilities
flexibility in the frequency of measurements and calibration of
measurement devices.

This approach will permit facilities to begin measuring their
production, transformation, and destruction for purposes of the rule
beginning in January, 2010, using their current practices and equipment.
 However, EPA is planning to revisit the precision and accuracy
requirements for industrial gas supply as we review public comments and
perform analyses related to proposed 40 CFR part 98, subpart L
(fluorinated gas production), which is not included in today’s final
rule.  This is because the accuracy and precision with which production
facilities track production, transformation, and destruction can have a
profound influence on the accuracy and precision of these facilities’
fluorinated GHG emission estimates.  For one method of monitoring F-GHG
emissions under consideration, a one percent relative error in
production mass measurements could result in a much higher relative
error in the emissions estimate, e.g., over 90 percent at an emission
rate of 1.5 percent.  For other methods of monitoring F-GHG emissions,
however, a one percent relative error in production mass measurements
would not lead to large errors in emission estimates.  For both 40 CFR
part 98, subpart OO and 40 CFR part 98, subpart L, EPA’s goal is to
optimize methods of data collection to ensure data accuracy while
considering industry burden. 

PP.  Suppliers of Carbon Dioxide (CO2) 

1.  Summary of the Final Rule 

Source Category Definition.  Under the rule, suppliers of CO2 consist of
the following:

Facilities with production process units that capture and supply CO2 for
commercial applications or that capture and maintain custody of a CO2
stream in order to sequester or otherwise inject it underground.

Facilities with CO2 production wells that extract a CO2 stream for the
purpose of supplying CO2 for commercial applications.

Importers of bulk CO2, if total combined imports of CO2 and other GHGs
exceed 25,000 metric tons of CO2 equivalent (CO2e) per year.

Exporters of bulk CO2, if total combined exports of CO2 and other GHGs
exceed 25,000 metric tons CO2e per year.

This source category is focused on upstream supply. It does not cover:
storage of CO2 above ground or in geologic formations; use of CO2 in
enhanced oil and gas recovery; transportation or distribution of CO2; or
purification, compression, on-site use of CO2 captured on site, or
processing of CO2.  This source category does not include CO2 imported
or exported in equipment, such as fire estinguishers. 

Suppliers of CO2 that meet the applicability criteria in the General
Provisions (40 CFR 98.2) summarized in Section II.A of this preamble
must submit GHG reports.

GHGs to Report.  Suppliers of CO2 must report the mass of CO2 in a
stream captured from production process units and extracted from
production wells, and the mass of CO2 in containers that is imported and
exported.

GHG Emissions Calculation and Monitoring.  While this source category is
focused on upstream supply of CO2, EPA recognizes that all CO2 supplied
to the economy does not necessarily result in an emission.  There are a
variety of downstream applications for CO2 - some applications are
emissive and some are non-emissive.  Under this rulemaking, a CO2
supplier facility must calculate the mass of CO2 supplied quarterly by
measuring the mass or volumetric flow of gas and multiplying by the CO2
concentration, and density in the case a volumetric flow meter is used,
of the gas or liquid, as specified below.  EPA requires quarterly
monitoring because EPA has concluded that the CO2 concentration of the
stream varies throughout the year, and a quarterly concentration number
multiplied by a quarterly volume will generate more accurate calculation
of CO2 supply than annual measurements.  EPA requires these quarterly
numbers to be reported or that EPA can electronically verify the
calculations.  The CO2 supplier must also provide information on the
downstream CO2 application, if known.  Reporters must use the following
methodologies, as applicable, for calculating CO2 supplied: 

For suppliers that make measurements with mass flow meters, calculate
quarterly for each meter the total mass of CO2 in a CO2 stream in metric
tons captured or extracted, prior to any subsequent purification,
processing, or compressing, according to Equation PP-1 of 40 CFR 98.423.
 Measure mass flow and concentration in accordance with 40 CFR 98.424.

For suppliers that make measurements with volumetric flow meters,
calculate quarterly for each meter the total mass of CO2 in a CO2 stream
in metric tons captured, prior to any subsequent purification,
processing, or compressing, according to Equation PP-2 of 40 CFR 98.423.
 Measure volumetric flow, concentration and density in accordance with
40 CFR 98.424.

For suppliers that have multiple flow meters, aggregate data at the
facility level according to methods specified in Equation PP-3 in 40 CFR
98.423.

Importers or exporters that import or export CO2 in containers must
calculate the total mass of CO2 supplied in metric tons, prior to any
subsequent purification, processing, or compressing, according to
equation PP-4 of 40 CFR 98.423.  Use weigh bills, scales, or load cells
to measure the mass of CO2 imported or exported in containers.  

Data Reporting.  In addition to the information required to be reported
by the General Provisions (40 CFR 98.3(c)) and summarized in Section
II.A of this preamble, reporters must submit additional data that are
used to calculate CO2 supply.  A list of the specific data to be
reported for this source category is contained in 40 CFR 98.426.

Recordkeeping.  In addition to the records required by the General
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this
preamble, reporters must keep records of additional data used to
calculate CO2 supply.  A list of specific records that must be retained
for this source category is included in 40 CFR 98.427.

2.  Summary of Major Changes Since Proposal 

The major changes since proposal are identified in the following list. 
The rationale for these and any other significant changes can be found
below or in the comment response document for“Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to Public Comments, Subpart PP:
Suppliers of CO2.Carbon Dioxide.”

We developedadded equations and quality assurance QArequirements to
allow reporters to determine CO2 quantity using mass flow meters,
volumetric flow meters, weigh bills, scales, or load cells, as
appropriate.  These additions supplement the propose equations and
quality assurance requirements to determine CO2 quantity using mass flow
meters.  

We revised the reporting procedures for missing data in 40 CFR 98.425 to
allow for use of either data from the prior quarterly reported data or
prior annual reported data. .  Facilities must use quarterly values as
substitute data as can no longer use annual average values.  We added
missing data procedures to allow for more quarterly data points to be
used, as appropriate. EPA concluded that quarterly missing data values
will generate more accurate estimates than annual average values.

To improve the emissions verification process, we reorganized and
updated 40 CFR 98.426.  We moved some data elements from section40 CFR
98.427 to section40 CFR 98.426, and added some data elements that a
reporter must already use to calculate GHGs as specified in section40
CFR 98.423 to section40 CFR 98.426 for clarity.  We also introduced new
data reporting requirements, such as volumes of propane odorized, as a
result of comments received.

We revised the reporting and calculation procedures to require
facilities using flow meters to determine annual mass for every flow
meter used. To aggregate data at the facility level for CO2 being
captured in production wells or production process units, we have added
Equation PP-3. 

To decrease unnecessary sampling burden, we have removed the requirement
of quarterly concentration sampling for importers and exporters that use
containers of CO2. 

3.  Summary of Comments and Responses 

This section contains a brief summary of major comments and responses. A
large number of comments on suppliers of CO2 were received covering
numerous topics.  Responses to significant comments received can be
found in the comment response document for suppliers“Mandatory
Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments,
Subpart PP: Suppliers of CO2 in the docket
(EPA-HQ-OAR-2008-508-XXX).Carbon Dioxide.”  

Definition of Source Category

Comment:  EPA received many comments about how we defined the source
category in this Subpart.  One group of comments stated that the CO2
supplied to the economy should not be characterized as an emission. 
Some in this group of comments specified that much of the supplied CO2
is stored at enhanced oil recovery (EOR) sites, which are “closed
systems”, rather than emitted.  In general, these same commenters
stated that any CO2 reporting requirements placed by EPA on industry
should be placed on downstream CO2 users, such as EOR facilities, rather
than CO2 suppliers and should be for actual emissions only.  Other
comments echoed that EPA needs to collect data from recipients of
supplied CO2 such as EOR sites.  This group pressed upon EPA the need to
collect not only data on actual emissions but also data on injection,
production, and geologic sequestration of CO2.  Some of the benefits
cited for collecting such comprehensive data include: assisting in
ensuring no more than negligible releases at a facility if it is
properly sited, designed, and permitted; achieving full public
accountability of CO2 geologic sequestration effectiveness; and tracking
the CO2 throughout the entire carbon dioxide capture and sequestration
(CCS) chain for the purposes of adjusting CO2 emissions reported or
assigning offsets.  Along those lines, some commenters urged EPA to rely
on or expand the existing underground injection control (UIC )program to
deal with CCS.

Response:  EPA did not intend to characterize all CO2 supplied to the
economy as emissions and recognizes that there are a variety of
applications for CO2, both emissive and non-emissive.  CO2 supplied to
the economy would result in an emission if the CO2 were used in an
application which would ultimately result in release of the CO2 to the
atmosphere.  EPA is also collecting information from upstream suppliers
in other subparts of this rulemaking such as natural gas supply and
petroleum product supply.

EPA recognizes that, in order to determine whether or not supplied CO2
has been or will be released to the atmosphere (e.g. emitted), the
Agency needs information on the downstream CO2 end-use.  In today's
today’s final rulemaking, CO2 suppliers must provide information on
the downstream CO2 application, if known.  EPA believes information on
the end-use will provide some idea of the amounts of CO2 which are
emitted.  Where that end-use is geologic sequestration (at EOR or other
types of facilities), EPA will need additional information on the amount
of CO2 that is permanently and securely sequestered and on the
monitoring and verification methodologies applied.  With respect to EOR,
the geology of an oil and gas reservoir can create a good barrier to
trap CO2 underground.  Because these formations effectively stored oil
or gas for hundreds of thousands to millions of years, it is believed
that they can be used to store injected CO2 for long periods of time. 
However, EPA also recognizes that the requirements to identify a
suitable GS site extend beyond geophysical trapping parameters alone and
include: the evaluation and appropriate management of potential leakage
pathways, appropriate rate and pressure of injection, appropriate
monitoring, and other such features. While some amount of CO2 injected
into oil and gas reservoirs for EOR purposes will be trapped in the
subsurface, these and other site-specific elements influence the amount
of CO2 securely sequestered and the potential for release of CO2 during
EOR operations.  

Given the comments in support of downstream data collection,
particularly with respect to EOR systems and CO2 geologic sequestration
(at EOR or other types of facilities), EPA plans to issue a new proposal
on geologic sequestration and will consider how to address emissions and
sequestration at active EOR facilities.  EPA will take action on this
issue in the near future with the goal that data collection for these
types of facilities can begin as quickly as possible.  EPA will seek
comment on monitoring, reporting, and verification methodologies which
can be used to determine the amount of CO2 emitted and geologically
sequestered at active EOR facilities and geologic sequestration sites
where CO2 is injected (for long-term storage) into saline aquifers, oil
and gas reservoirs, or other geologic formations.  Furthermore, as
stated in Section III.W of this preamble, EPA plans to take additional
time to consider alternatives to data collection procedures and
methodologies in the proposed 40 CFR part 98, subpart W and will
consider inclusion of GHG reporting from other sectors of the oil and
gas industry besides those proposed for reporting in proposed 40 CFR
part 98, subpart W.  EOR surface facility operations may be part of
those considerations.  The data reported under follow-onsubsequent
regulatory actions and the data reported under today’s rulemaking will
together enable EPA to understand the amount of CO2 supplied, emitted,
and sequestered in the U.S., to carry out a wide variety of CAA
provisions.  The options that we will have considered and the resulting
recommended approaches will be further fleshed out through a notice and
comment process.  See the next comment response for a discussion of why
EPA still needs to collect CO2 supplier data in today’s rulemaking
even though a new rulemaking on sequestration is planned.

In response to comments that EPA should rely on or expand the UIC
program to address emissions of CO2, that issue is outside the scope of
this rulemaking.  However, EPA agrees that the UIC program and EPA’s
authority under the Safe Drinking Water Act (SDWA) will provide a
foundation for ensuring safe and effective containment of CO2.  However,
SDWA is focused on permitting sites for protection of ground and
drinking water.  It is not ; the new proposal discussed above will be
designed to monitor, track, or quantify air emissions and the the UIC
program’s recent geologic sequestration proposal (FR 43492-43541) did
not specifically outline new geologic sequestration requirements for EOR
sites (Note:address issues related to the CAA. EPA did receive comments
that the proposed requirements should be expanded to active EOR
operations and is currently evaluating that issue). 

It is EPA’s strong intentionintends to harmonize CCS requirements
across relevant statutory or other programs in order to minimize any
redundancy and any burden on reporters.  The reporting requirements in
today’s rulemaking for CO2 suppliers and the reporting requirements in
new rulemaking for CO2 geologic sequestration sites will complement each
other and together they can be harmonized with reporting requirements
under the UIC proposed rulemaking.  In a new CAA rulemaking on geologic
sequestration reporting, EPA will rely on UIC permit requirements to the
maximum extent possible.  EPA will seek comment on these issues and will
also endeavor to issue a geologic sequestration GHG reporting rule in
the same time frame as it has planned for the stand-alone UIC GS
rulemaking. 

Comment:  EPA received comments requesting information on how CO2 supply
will assist EPA in developing future climate policy.  Commenters stated
that they do not believe CO2 supply data will provide EPA with useful
information. Commenters stated that data collection from CO2 suppliers
does not fit within EPA’s mandate from Congress to measure upstream
emissions only as appropriate.

Response:  As discussed in Sections I.C and II.Q of this preamble, EPA
is collecting data from CO2 suppliers in today’s rule to carry out a
wide variety of CAA provisions, as authorized broadly under CAA Sections
114 and 208.  For example, EPA needs to collect this data will enable
EPA to evaluate the appropriate action to take under section 103
regarding non-regulatory strategies for pollution prevention and
information could.  It will also be used to inform developmentevaluation
of possible CAA regulations under CAA Section 111 regarding New Source
Performance Standards. regulation of the supplier and/or recipient of
the CO2  Data on CO2 supply to the economy will allow EPA to make a well
informed decision about whether and how to use the CAA to regulate
facilities that capture, sequester, or otherwise receive CO2 as an
end-user.

Though CO2 capture and geologic sequestration are occurring now on a
relatively small scale, CCS is expected to play a major role in
mitigating greenhouse gasGHG emissions from a wide variety of stationary
sources.  According to the Inventory of U.S. Greenhouse Gas Emissions
and Sinks: 1990-2007 (EPA, April 2009), stationary sources contributed
67% percent of the total CO2 emissions from fossil fuel combustion in
2007.    The 500 largest stationary sources account for 82% of the
United States’ annual CO2 emissions.  These 500 stationary sources
represent a wide variety of sectors amenable to CO2 capture; electric
power plants (existing and new), natural gas processing facilities,
petroleum refineries, iron & steel foundries, ethylene plants, hydrogen
production facilities, ammonia refineries, ethanol production
facilities, ethylene oxide plants, and cement kilns.  Furthermore, 95%
percent of thesethe 500 largest stationary sources are within 50 miles
of a candidate CO2 reservoir.  

With this rule, EPA will begin building capacity to track the growth in
CO2 supply and learn about its disposition throughout the economy. EPA
has concluded that we need data now from CO2 suppliers - both industrial
facilities and CO2 production wells – in order to effectively track
how the supply sources will change over time. For example, we will need
to track if and by how much CO2 captured from industrial facilities will
offset or displace CO2 produced from natural formations. Even after EPA
begins collecting data on CO2 geologic sequestration under the proposed
new rulemaking (discussed above), EPA will continue to need data from
CO2 suppliers in order to track any CO2 that is not sequestered.

Comment:  EPA received some comments asking whether a specific situation
results in coverage under Subpart40 CFR part 98, subpart PP, and some
comments requesting that their specific situation be exempt from
coverage.  For example, one commenter asked whether a facility
separating CO2 that is not supplied to downstream customers is a covered
facility.  Another asked that a pulp and paper mill that transfers a CO2
stream to an adjacent facility by pipeline be exempt from Subpart40 CFR
part 98, subpart PP.  Several commenters requested clarification on
specific scenarios such as taking ownership of an already separated CO2
stream for further processing, separating CO2 for their own use, and
operating versus owning the separation unit.  Another commenter
requested that ethanol plants and other facilities capturing CO2 from
biomass be exempt from Subpart PP. 

Response:  EPA did not intend for Subpart40 CFR part 98, subpart PP to
cover facilities that take ownership of a CO2 stream that has already
been separated and removed from a manufacturing process or that has
already been extracted from CO2 production wells in order to do any of
the following: store it in above ground storage of CO2; transport or
distribute it via pipelines, vessels, motor carriers, or other means;
purify, compress, or process it; or sell it to other commercial
applications.  In the final rule, we clarified that Subpart40 CFR part
98, subpart PP covers facilities that own or operate the equipment that
physically separates and removes CO2 from an industrial or manufacturing
process or physically extracts CO2 from production wells because we
concluded that the entity with first touch of the CO2 supply was the
most logical point of coverage.  We wanted to prevent double-counting
minimize any unnecessary duplicative reporting of the same CO2 by being
as specific as possible about who in the supply chain is responsible for
reporting it. 

We did not intend for this source category to include facilities that
capture CO2 for further processing or use within the fence line of the
facility (e.g., for their own use).  EPA proposed that Subpart40 CFR
part 98, subpart PP only cover CO2 that is captured or extracted for
purposes of sequestration or supply to other facilities for commercial
applications because we concluded that CO2 captured and used on-site is
equivalent to an intermediary step in production rather than an actual
supply of CO2.

Comment:  EPA received a comment requesting that ethanol plants and
other facilities capturing CO2 from biomass be exempt from Subpart PP.

Response:  A long standing accountinginventory convention adopted by the
IPCC, the UNFCCC, the US GHG Inventory, and many other reporting
programs was applied to the proposed rule where is separate treatment of
emissions of CO2 from the combustion of renewable biomass and
biomass-based fuels are distinguished from emission emissions of CO2
from the combustion of fossil-based products.  As a resultIn national
inventories, emissions from the combustion of biomass-based fuels are
accounted for at the time of feedstock harvest, collection, or disposal,
notas part of a comprehensive system-wide tracking of carbon dioxide
emissions and sequestration in the land-use, land-use change and
forestry sector and the agriculture sector, rather than at the point of
fuel combustion.  In Consistent with this approach, in the proposed and
final rule, downstream emitters must only consider non-biogenic
emissions when conducting a threshold analysis but; however, downstream
emitters must report both biogenic and non-biogenic emissions once they
trigger the reporting threshold.  However, this convention only applies
to CO2 from the combustion of renewable fuel and only applies for the
threshold analysis.   because data on non-biogenic emissions is useful
and informative.  

For the final rule, EPA has decided not to apply the same logicapproach
to suppliers of CO2.  We have not established a threshold in Subpart PP
because we  We have concluded that data on capture of biogenic CO2 would
be useful and informative because biogenic CO2 can potentially be stored
in GS sites, or displace fossil CO2 applications.  We need a full
picture of the CO2 being supplied into the economy.  Though CO2 capture
and sequestration are is occurring now on a relatively small scale, it
is expected to play a major role in mitigating greenhouse gasGHG
emissions and therefore EPA needs to assess.  Therefore information on
all potential sources of CO2 for sequestration.  Therefore is necessary
for a complete picture.  Thus, a facility that captures CO2 from biomass
and otherwise meets the applicability test is covered under Subpart40
CFR part 98, subpart PP and is required to report all CO2 supplied along
with the percentage of that supply that is biomass-based.

Monitoring and QA/QC Requirements

Comment:  A large number of commenters requested that volumetric flow
meters be allowed for purposes of calculating CO2 supply in place of or
in addition to mass flow meters.  These comments indicated that mass
flow meters are not in operation at many covered facilities, and the
cost to comply with such an equipment requirement would be unnecessarily
high.  Some commenters suggested that reporters should be allowed to use
sales contracts to determine quantity of CO2 as long as the CBI is
protected.  Some commenters indicated that CO2 liquefaction and
purification facilities do not operate flow meters for the course of
usual business.  One of these also commented that importers and
exporters of CO2 do not operate flow meters for the course of usual
business if they handle the product in containers and requested
consideration of this incongruity.

Response:  As a result of these comments, EPA added two equations to the
methodology section of Subpart40 CFR part 98, subpart PP in today’s
rule in order to ensure that all covered CO2 can be reported,
irrespective of technical or physical conditions.  Therefore, a reporter
that measures CO2 in a stream using a volumetric flow meter may use this
volumetric flow meter to determine quantity rather than having to
purchase and install a mass flow meter. EPA has concluded that providing
this additional methodology reduces the burden on reporters without
compromising the quality of data received by the agency.  In addition, a
reporter that imports or exports CO2 in containers may use weigh bills,
scales, or load cells to determine quantity because applying a mass flow
meter would be technically impossible.  EPA has concluded that providing
this additional methodology reduces the burden on reporters without
compromising the quality of data received by the agency.

The final rule does not require reporting from facilities that liquefy
or purify CO2 that has already been separated or removed from a
manufacturing process or already extracted from production wells. 
Therefore we did not give consideration to the types of equipment in
operation at such facilities.  

Finally, the rule does not allow reporters to use sales contracts to
determine quantity because EPA has concluded that reporters capturing or
extracting CO2 already operate mass or volumetric flow meters, or
already determine quantities of CO2 imported or exported in containers
using weigh bills, scales, or load cells.  EPA has concluded that mass
and volumetric flow meters provide more accurate data than sales
contracts.

IV.  Mobile Sources 

A.  Summary of Requirements of the Final Rule

For manufacturers of engines used in mobile sources outside of the
light-duty sector, this rule includes new requirements for reporting
emission rates of GHGs.  Mobile source engine manufacturers have been
measuring CO2 emission rates from their products for many years as a
part of normal business practices and existing criteria pollutant
emission certification programs, but they have not consistently reported
these values to EPA.  This final rule requires manufacturers to
consistently measure and report CO2 for all engines beginning with model
year 2011 and other GHGs in subsequent model years.  Manufacturers
meeting the definitions of “small business” or “small volume
manufacturer” under EPA’s existing mobile source emissions
regulations will generally be exempt from any new GHG reporting
requirements.

In addition to CO2, most manufacturers will now be required to report on
two other major GHGs emitted by mobile sources, nitrous oxide (N2O) and
methane (CH4).  Although most current engines have relatively low
emission rates of these GHGs compared to CO2, these compounds have
global warming potentials significantly higher than CO2.  It is
important that EPA improve its understanding of these emissions from
today’s engines and monitor trends over time.  The broad base of
emission data that will begin to accrue from requirements in this rule
will support emissions modeling by EPA and others, and will help guide
future GHG policy.  

Emissions of N2O are related to catalytic treatment of engine exhaust,
specifically aftertreatment of NOx emissions.  Therefore, we will
require that manufacturers begin to measure and report N2O emissions,
but only for engine models that incorporate NOx aftertreatment
technology (as shown in Table IV-1 below of this preamble).  The program
will not require N2O reporting before model year 2013, and the
requirements will only apply to new engines equipped with NOx
aftertreatment technology.  (Manufacturers of some engine categories
have employed aftertreatment for many years to meet NOx standards; for
other engine categories, manufacturers are unlikely to introduce NOx
aftertreatment technologies for some years to come.)  

Emissions of CH4 are a part of overall hydrocarbon emissions from mobile
sources.  Because CH4 is not very reactive in the atmosphere, EPA has
often excluded CH4 from mobile source hydrocarbon regulations since it
has not traditionally been a major determinant of ozone formation.  The
new reporting requirements are necessary to evaluate the magnitude of
mobile source CH4 emissions from a GHG (rather than ozone precursor)
perspective. 

As described above, we are finalizing manufacturer reporting
requirements for N2O and CH4 emission rates in order to understand
current emissions of these GHGs and to monitor potential changes as
technologies and policies change in the future.  However, we believe
that manufacturers may be able to provide alternative test data (and/or
other information including engineering judgments based on test data)
that would give EPA a reasonable basis for estimating the likely N2O and
CH4 emission rates for each certified engine family.  Therefore, we are
including a provision in this final rule that would allow a manufacturer
the opportunity to provide such alternative information in lieu of N2O
and/or CH4 test data for each engine family.  

In assessing such alternative information, EPA would consider how well
the information provided by the manufacturer allows EPA to reasonably
anticipate the emission performance of each of the manufacturer’s
engines.  For example, we expect that in most cases a manufacturer
wishing to omit engine testing will provide EPA with N2O test data from
relevant testing programs (by such sources as industry collaboratives
and/or from the suppliers of the catalytic NOx aftertreatment systems
they are using on an engine.  We would expect the manufacturer to also
include an explanation of the manufacturer’s engineering judgment as
to why the data should apply to the engine family in question.  For CH4
emissions, our primary concern is the potential for unusually high
emissions from natural gas fueled engines.  Thus, we expect that in most
cases a manufacturer of such an engine will provide test data on similar
engines with similar catalyst systems for hydrocarbon control (with an
explanation of their engineering judgment as to why the data should
apply to that engine family).   

 

The reporting requirements related to C3 marine engines and turbofan and
turbojet aircraft engines differ from other engine categories.  As with
other manufacturers, C3 marine engine and aircraft engine manufacturers
will report CO2 emission rates beginning in 2011 (for aircraft engines,
they will report CO2 separately for each mode of the landing and
take-off (LTO) cycle used in the certification test, as well as the
entire LTO cycle).  For aircraft engine manufacturers, however, the
reporting requirements will apply not just to engines introduced in that
year, but for all engines still in production.  (This should not require
manufacturers to conduct any new testing, only to report existing data.)
 We are not requiring manufacturers of C3 marine engines and aircraft
engines to measure or report N2O or CH4 emission rates because of unique
aspects of their industries and technologies.  

C3 marine engines are very large and manufacturers generally test them
as they are installed into ships rather than in a laboratory setting. 
For this reason, we have determined that requiring the addition of new
N2O and CH4 measurement equipment for C3 engines would not be practical,
and, as proposed, are not requiring such reporting in this rule.  

Since aircraft engine manufacturers are unlikely to employ NOx after
treatment devices in the foreseeable future, we did not propose
requiring N2O reporting from aircraft engines and are not finalizing any
requirements in this final rule.  We are not finalizing our proposed
requirement that aircraft engine manufacturers measure and report CH4,
as we learned that aircraft jet turbine engines have been shown to
consume CH4 from the ambient air during the dominant operating modes. 
However, unlike NOx emissions from most mobile sources, NOx emissions
from aircraft have been shown to make a potential contribution to
climate change.  For this reason, we are requiring that aircraft engine
manufacturers report the NOx emission data for the LTO modes and the
overall LTO cycle for all engine models currently in production, and for
new engines as they are introduced.  Manufacturers are already measuring
NOx as part of current criteria pollutant certification requirements. 
NOx emissions rate data from LTO modes will support modeling of overall
NOx emissions from aircraft.  

For all engine categories, when a manufacturer certifies the engine in
one year and then carries over the certification to subsequent years,
EPA will not require re-testing of that engine model for reporting
purposes. 

As proposed, we are not including any requirements for mobile source
fleet operators or stateState and local governments to report in-use
travel activity or other emissions-related data in this final rule.

Table IV-1 below of this preamble shows the basic reporting requirements
we are finalizing in this notice for each engine category.  We discuss
in more detail how these reporting requirements will apply to
manufacturers of each engine category in the comment response document
for mobile sources (EPA-HQ-OAR-2008-508-XXX) associated with this final
rule.“Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to
Public Comments, Motor Vehicle and Engine Manufacturing.”

Table IV-1:  First Model Year for GHG Reporting Requirements

Engine Category	CO2	N2Oa	CH4

Highway Heavy-Duty (engine and vehicle)	2011	2013 or NOx AT 	2012

Nonroad Diesel	2011	2013 or NOx AT 	2012

Marine Diesel (other than C3)	2011	2013 or NOx AT 	2012

C3 Marine	2011	None	None

Locomotives	2011	2013 or NOx AT 	2012

Small Spark-Ignition	2011	2013 or NOx AT 	2012

Large Spark-Ignition	2011	2013 or NOx AT 	2012

Marine Spark-Ignition	2011	2013 or NOx AT	2012

Snowmobiles	2011	2013 or NOx AT	2012

Highway Motorcycles	2011	2013 or NOx AT	2012

Off Highway Motorcycles/ATVs	2011	2013 or NOx AT	2012

Aircraftb	2011	None	None

a N2O reporting for new engines begins in 2013 or when the manufacturer
introduces NOx aftertreatment technology, whichever is later.

b Applies to all turbofan and turbojet engines in production in 2011
with a rated output greater than 26.7 kilonewtons.  Reporting of NOx
also required.

B.  Summary of Major Changes Since Proposal

The major changes since proposal are identified in the following list. 
The rationale for these and any other significant changes can be found
below or in the comment response document for mobile sources
(EPA-HQ-OAR-2008-508-XXX).“Mandatory Greenhouse Gas Reporting Rule:
EPA’s Response to Public Comments, Motor Vehicle and Engine
Manufacturers.” 

We are not finalizing the proposed requirements related to light-duty
vehicles (including light-duty trucks and medium-duty passenger
vehicles).  EPA expects to propose a comprehensive light-duty GHG
emission control program commencing in MY 2012 (see Notice of Upcoming
Joint Rulemaking to Establish Vehicle GHG Emissions and CAFÉ Standards,
74 FR 24007 (May 22, 2009)), which is likely to contain monitoring,
reporting and GHG data retention requirements that would supersede any
reporting requirements established in this rule.  Eliminating light-duty
reporting requirements from this final rule will avoid issues of
inconsistency and duplication.  

We have revised our proposal that all engine manufacturers measure and
report N2O for all of their engines, and instead will require N2O
reporting only for engines that use NOx exhaust aftertreatment
technology.

We have delayed the proposed MY 2011 start year for N2O reporting until
MY 2013, and later for categories where the manufacturer has not applied
NOx aftertreatment technology.  

We have added additional emission test methods that manufacturers can
choose for measuring N2O, to assure that an appropriate method is
available for any foreseeable circumstance (including the need to
measure very low N2O emission rates).

The final rule incorporates an opportunity for a manufacturer to provide
EPA with appropriate alternative information in lieu of N2O and/or CH4
testing, as described above.

We have added one year of lead time to the proposed start year for
reporting of CH4 emissions, until 2012.  

We are not finalizing our proposal to require reporting of CH4 for
aircraft engines because, for the dominant operating modes, jet engines
may consume CH4 in the air.  

We are finalizing a requirement that we took comment on in the proposal
to have aircraft engine manufacturers report NOx emissions data they
already collect, since, at altitude, NOx emissions from aircraft have
been shown to make a potential contribution to climate change. 

Since aircraft engines are not certified every year (there is no annual
certification as is the case with other mobile sources), we have removed
references to “model year” in the regulations and revised them to
reflect the change to a January 1, 2011 start date for reporting CO2 and
NOx emissions.

C.  Summary of Comments and Responses

This section contains a brief summary of major comments and responses. 
A large number of comments on mobile source were received covering
numerous topics.  Responses to significant comments received can be
found in the comment response document for mobile sources
(EPA-HQ-OAR-2008-508-XXX).“Mandatory Greenhouse Gas Reporting Rule:
EPA’s Response to Public Comments, Motor Vehicle and Engine
Manufacturers.”

Comment:  Light-duty vehicle manufacturers and their trade organizations
raised several concerns about the timing and nature of the reporting
requirements.  

Response:  We agree in part with these comments. However, more
fundamentally, we have concluded that the likelihood of GHG emission
regulations affecting light-duty vehicles (including light-duty trucks
and medium-duty passenger vehicles) in the near future argues for
consolidating any new GHG reporting requirements into that upcoming
rule.  Therefore, we have elected to not finalize the proposed
requirements relating to these vehicles at this time, and expect to
incorporate similar provisions in a proposed rule on GHG standards for
light-duty vehicles in the coming monthsnear future.

Comment:  Engine manufacturers and their trade organizations challenged
the proposed rule in several ways.  In general, they questioned the need
for the data to be reported; expressed concern that the proposed timing
of the requirements, especially for N2O and CH4, was too aggressive; and
commented that the proposed test procedure for N2O was not adequate.  

Response:  We still conclude that there is significant value to
collecting CO2, N2O, and CH4 emissions rate data on the broad range of
mobile sources being produced.  As stated earlier, the domestic and
international attention to GHGs and their effects will only grow, and
the ability for EPA and the public to understand and monitor emissions
from mobile sources will be increasingly important as policies relating
to GHGs are considered.  Collecting emissions rate data from engine
manufacturers on their new engines can improve modeling of emissions for
the entire mobile source sector since current modeling relies on
assumptions about N2O and CH4 emissions based on a limited number of
field surveys.  The data from this rule will also help EPA track
emissions impacts from changes in technologies and policies over time. 

For N2O and CH4, we agree that revisions in the proposed provisions are
warranted.  We have limited the reporting requirements for N2O to
engines equipped with NOx aftertreatment technology as a way to reduce
the reporting burden on engine manufacturers without significantly
diminishing the amount of information we receive. As discussed earlier,
emissions of N2O are related to catalytic treatment of engine exhaust,
specifically aftertreatment of NOx emissions, and we have concluded that
collecting N2O emissions data from engines without NOx aftertreatment
technology would provide marginal value to the agency.  We expanded the
number of approved test methods for N2O measurement since we learned
from comments and our own technical research that our proposed test
methods for N2O were not appropriate for every foreseeable circumstance,
including measurement of very low levels of N2O.  We also extended the
lead time available to manufacturers before N2O and CH4 reporting is
required.  We are providing this flexibility based on our conclusion
that we can reduce the burden of purchasing and installing the required
CH4 and N2O emissions rate measurement equipment by extending the lead
time, without significantly diminishing the amount of information we
receive.  Finally, as described above, the final rule includes an
opportunity for a manufacturer to provide EPA with appropriate
alternative information in lieu of N2O and/or CH4 testing.  

Comment:  States and environmental organizations were generally
supportive of the proposed reporting requirements, although some argued
for earlier implementation, in 2010.

Response:  We believe that the lead times we are finalizing for each GHG
and for each engine category represent the earliest feasible timing,
taking into consideration existing test capabilities and past
experience, or the lack thereof.

Comment:  Aircraft engine manufacturers commented that reporting of CO2
emissions from each mode of the LTO cycle used in the emission
certification test, as proposed, is acceptable as long as existing
methods for CO2 are retained.  In particular, commenters noted that
reporting would result in minimal burden as long as CO2 is calculated
utilizing the engine fuel mass flow rate measurements, which are
currently part of the test procedure requirements for the LTO cycle. 
However, an industry trade association expressed concern that reporting
CO2 from the LTO cycle is unjustified because LTO measurements do not
include CO2 emissions from an entire aircraft flight, which is affected
by the propulsion system, drag, etc.  

Response:  We determined that calculating aircraft engine CO2 emissions
from fuel mass flow rate flow measurements is an appropriate method for
reporting CO2 emissions.  Therefore, for turbofan and turbojet engines
of rated output greater than 26.7 kilonewtons, we are finalizing that
manufacturers record and report CO2 separately for each mode of the LTO
cycle used in the certification test, as well as the entire LTO cycle,
according to the existing measurement criteria for CO2 or alternatively
by calculations of CO2 from fuel mass flow rate flow measurements or,
alternatively, according to the measurement criteria for CO2 in
Appendices 3 and 5 to ICAO Annex 16, volume II.  Comprehensive and
consistent reporting of LTO CO2 emissions, along with knowledge of
aircraft aerodynamic performance, will support modeling of full-flight
CO2 emissions and help us to better understand overall contributions to
global warming from aircraft operations.   

Comment:  Aircraft engine manufacturers raised two major issues related
to our proposed CH4 reporting.  First, in response to EPA’s request
for comment on the degree to which engine manufacturers now have the
needed equipment in their certification test cells to measure CH4, 
manufacturers replied that test stands are not currently equipped to
measure CH4, and thus, they would incur additional costs to measure CH4.
 Second, manufacturers noted that aircraft jet turbine engines have been
shown to be consumers of CH4 from the ambient air during the dominant
operating modes (CH4 is emitted at aircraft engine idle operation, but
at higher power modes aircraft engines usually consume CH4.  Over the
range of engine operating modes -- including cruise -- aircraft engines
are typically net consumers of CH4).

Response:  Given that aircraft engines are likely net consumers of CH4
and that manufacturers do not currently collect CH4 data as part of
existing test procedures, we are not requiring CH4 to be measured and
reported at this time.

Comment:  We received several responses to our request for comment on
whether to require aircraft engine manufacturers to report NOx emissions
in the four LTO test modes and for the overall LTO cycle.  Manufacturers
commented that NOx emissions do not need to be reported directly to EPA,
since this information is already voluntarily reported to the
International Civil Aviation Organization (ICAO) and provided to the
Federal Aviation Administration (FAA), and redundancy of reporting is
unnecessary.  Environmental organizations commented that EPA should
require manufacturers to report NOx since they currently do not report
the data to EPA.  In addition, environmental organizations commented
that NOx at high altitude can contribute to global warming.   

Response:  In this final rule, we are requiring that engine
manufacturers of turbofan and turbojet engines of rated output greater
than 26.7 kilonewtons record and report NOx emissions in the four LTO
test modes and for the overall LTO cycles.  As discussed in the proposal
and earlier in this final rule, NOx from aircraft have been shown to
make a potential contribution to climate change at high altitude.  As
required in 40 CFR 87, manufacturers must already measure and record NOx
emissions in each of the four LTO test modes in order to comply with the
LTO NOx emission standard (for the entire LTO cycle). These data are not
currently reported to EPA for public consideration as is the case with
all other mobile sources. Manufacturers voluntarily report the data to
ICAO, but there is no assurance that EPA will receive this information. 
Likewise, the information provided to FAA is not readily accessible to
EPA, and it is not of the detail provided to ICAO.  Comprehensive and
consistent reporting of LTO NOx emissions rate data will support
modeling of overall NOx emissions from aircraft and help us to better
understand overall contributions to global warming from aircraft
operations.

V.  Collection, Management, and Dissemination of GHG Emissions Data. 

This section of the preamble describes the general processes by which
EPA intends to collect, manage, and disseminate data under the GHG
reporting rule. Section A contains a brief description of the provisions
in the final rule concerning these processes, and Section B summarizes
public comments and responses on data collection, management, and
dissemination.  

Major changes since proposal include revisions in 40 CFR 98.4 that
provide flexibility for designated representatives to delegate their
responsibility to agents, and to submit revisions to the certificate of
representation within 90 days of a change in owners or operators (rather
than 30 days).  In addition, the final rule includes a requirement that
the designated representative submit the certificate of representation
at least 60 days before the deadline of the facility or supplier’s
initial GHG report.  The rationale for these and any other significant
changes can be found in sectionSection V.B of this preamble or in the
comment response document.“Mandatory Greenhouse Gas Reporting Rule:
EPA’s Response to Public Comments, Designated Representative, and Data
Collection, Reporting, Management, and Dissemination.”

A.  Summary of Data Collection, Management and Dissemination for the
Final Rule

1.  Designated Representatives, Alternate Designated Representatives,
and Agents

Each covered facility orand each supplier must identify one and only one
designated representative who is responsible for certifying, signing,
and submitting all submissions to EPA.  A designated representative must
certify and sign a submission, in accordance with the final rule, before
it is considered a complete submission.

The designated representative also serves as a single point of contact
for EPA to provide information about the program or a submission or to
ask questions about a submission.  Those reportersfacilities submitting
any other emission report under 40 CFR part 75, for example, ARP
facilities, must use the same designated representative for certifying,
signing and submitting all submissions and reports under this rule.  

Each covered facility or supplier may also identify one alternate
designated representatives to act in lieu of the designated
representative.  The alternate designated representative can perform the
same duties as the designated representative, but the designated
representative is responsible for ensuring the appropriate information
is submitted to EPA by the timelines specified in the rule.

A designated representative or alternate designated representative may
delegate the submission of information to one or more “agents”.  The
agent can make electronic submissions to EPA, but is not allowed to
certify or sign a submission.  By delegating to an agent the ability of
to make electronic submissions to EPA, a designated representative or
alternate designated representative agrees that a submission to EPA by
the agent is deemed to be a submission that is certified, signed, and
submitted by such designated representative or alternate designated
representative. 

2.  Certificate of Representation

A designated representative must submit a certificate of representation
that identifies the owners and operators of the facility or supplier,
the designated representative, any alternate designated representatives,
and other information as specified in 40 CFR 98.4.  EPA will establish
an electronic data reporting system that provides for the submission of
initial, as well as subsequently signed, certificates of representation.

In order to ensure sufficient processing time before a facility or
supplier’s initial GHG report under this part, EPA is requiring that
the designated representative submit a certificate of representation at
least 60 days before the deadline for the initial GHG report.  

3.  Data Collection

Methods.  If a reporting entity already reports GHG emissions data to an
existing EPA program, the Agency will make efforts to minimize any
additional burden on the reporter when developing the reporting system
for the final rule.  Some existing programs, however, have data
collection and reporting requirements that are inconsistent with the
requirements for the mandatory GHG reporting rule.  When it is not
feasible to adapt an existing program to collect the appropriate GHG
data and supplemental data, EPA will require reporters to submit the
data required by the mandatory GHG reporting rule to the new data
reporting system for this rule.  Such reporters would also continue to
submit data to the existing reporting systems for other applicable
programs as required by those programs. 

Reporters may fall into one or more categories:

(1)  Reporters that use existing data collection and reporting methods
and will not be required to report separately to the new data reporting
system for the GHG reporting rule. 

(2)  Reporters that use existing data collection and reporting methods
but will be required to report the data separately to the new data
reporting system for the GHG reporting rule.

(3)  Reporters that are not currently required to collect and report GHG
emissions data to EPA and will be required to report using the new data
reporting system for the mandatory GHG reporting rule. 

For categories (2) and (3), EPA is developing a new system for reporters
to submit the required data.  The detailed data elements that must be
reported are specified in the rule.  In general, reporters using this
new system must report annually to the Agency according to the schedule
specified in 40 CFR 98.3(b). 

Data Submission.  The Designated Representative (described in 40 CFR
98.4) must use an electronic signature device (for example, a personal
identification number (PIN) or password) to submit a report.  If the
Designated Representative holds an electronic signature device that is
currently used for valid electronic signatures accepted under another
Agency program, we intend to design the new reporting system to also
accept valid electronic signatures executed with that device where
feasible.  (See 40 CFR 3.10 and the definitions of "electronic signature
device" and "valid electronic signature" under 40 CFR 3.3.)

Unique Identifiers for Facilities and Units.  The Agency’s reporting
format for a given reporting year could make use of several ID codes –
unique codes for a unit or facility.  To ensure proper matching between
databases, e.g., EPA-assigned facility ID codes and the Office of
Regulatory Information Systems (ORIS) (DOE) ID code, and consistency
from one reporting year to the next, we plan for the reporting system to
provide each facility with a unique identification code to be specified
by the Administrator.

Reporting Emissions in a Single Unit of Measure.  To maintain
consistency with existing State-level and Federal-level greenhouse
gasGHG programs in the U.S. and internationally, all emission
measurements must be reported in the SI, also referred to as metric
units.  Data used in calculations and supplemental data for QA could
still be submitted in English weights and measures (e.g., mmBtu/hr) but
the specific units of measure must be included in the data submission. 
All emissions data must be submitted to the Agency in kilogramskg or
metric tons per unit of time. 

Conversion of Emissions to CO2e.  Reporters must submit the quantity of
each applicable GHG emitted (or other metric such as quantities supplied
for industrial GHG suppliers) in two forms.  The data will be in the
form of quantity of the gas emitted (e.g., metric tons of N2O) per unit
of time and CO2e emissions per unit of time.  

Delegation of Authority to State Agencies to Collect GHG Data. 
Reporters must submit the emissions data and supplemental data directly
to EPA.  At this time, EPA does not intend to delegate the authority to
collect data to State or local agencies. 

Submission Method.  All entities covered by this rule must report in an
electronic format to be specified by the Administrator.  The electronic
format, which will reflect the underlying electronic data reporting
system, will be developed prior to the first reporting date.  By
specifying in the rule text the exact information that must be reported
but not specifying the exact reporting format, EPA informs reporters
about exactly what information they must report and has flexibility to
modify the electronic reporting format and electronic data reporting
system in a timely manner based on implementation experience and new
technology.  EPA has used this approach successfully in existing
programs, such as the ARP and the Title VI Stratospheric Ozone
Protection Program, facilitating the deployment of new reporting formats
and reporting systems that take advantage of technologies such as,
eXtensible Markup Language (XML), and reducereducing the burden on
reporters and the Agency.  The electronic reports submitted under this
rule are subject to the provisions of 40 CFR part 3, specifying EPA
systems to which electronic submissions must be made and the
requirements for valid electronic signatures. 

4.  Data Management

QA Procedures.  The new reporting system will include automated checks
for data completeness, data quality, and data consistency.  Such
automated checks are used for many other Agency programs (e.g., ARP.)

Providing Feedback to Reporters.  EPA has established a variety of
mechanisms under existing programs to provide feedback to reporters who
have submitted data to the Agency.  EPA will consider the approaches
used by other programs (e.g., electronic confirmations, results of QA
checks) and develop appropriate mechanisms to provide feedback to
reporters for the GHG reporting rule when we develop the electronic data
reporting system.  Regardless of data collection system specifics, the
goal is to ensure appropriate transparency and timeliness when providing
feedback to reporters who submitted data.

5.  Data Dissemination 

Public Access to Emissions Data.  The Agency plans to publish data
submitted or collected under this rulemaking through EPA'sEPA’s Web
site, reports, and other formats (e.g., XML), with the exception of any
confidential business information (CBI) data.  For further discussion of
CBI, see sectionSection II.R of this preamble.

EPA will disseminate data after the reporting deadline.  The Agency
recognizes the high level of public interest in this data and plans to
disclose it in a timely manner, while also assuring completeness and
accuracy.   

Sharing Emission Data with Other Agencies.  There are a growing number
of programs at the State, Tribe, Territory, and local level that require
emission sources in their respective jurisdictions to monitor and report
GHG emissions.  In order to be consistent with and supportive of these
programs and to reduce burden on reporters and program agencies, EPA
plans to share emissions data, with the exception of any CBI data, with
relevant agencies or approved entities using, where practical, common
data exchange standards and infrastructure. 

B.  Summary of Comments and Responses on Collection, Management, and
Dissemination of GHG Emissions Data

This section contains a brief summary of major comments and responses. 
A large number of comments on data collection, management, and
dissemination were received covering numerous topics.  Responses to
significant comments received can be found in the comment response
document for data collection and management in the docket
(EPA-HQ-OAR-2008-508-XXX).Responses to significant comments received can
be found in “Mandatory Greenhouse Gas Reporting Rule: EPA’s Response
to Public Comments, Designated Representative and Data Collection,
Reporting, Management, and Dissemination.” 

1.  Designated Representatives, Alternative Designated Representatives,
and Agents

Designated Representatives.

Comment:  Several commenters requested that EPA use the ARP definition
for designated representatives to maintain consistency across the two
EPA programs and provide more flexibility regarding who can be a
designated representative.  Other commenters requested that EPA use the
responsible official definition from Title V or senior management
official from TRI to maintain consistency with those programs.  Other
commenters raised concerns over the employment status of designated
representatives.  

Comment:  A commenter noted that rule language was inconsistent in
defining the relationships between designated representatives,
facilities and suppliers, and owners and operators.  

Response:  EPA agrees that owners and operators should have more
flexibility to identify a designated representative, including
third-party representatives. EPA is striking the language requiring the
designated representative to be a person responsible for the overall
operation of the facility or supplier.  At this timeFurther, EPA is not
proposing to requirerequiring the use of a responsible official or
senior management official because either approach would be more
restrictive than the designated representative definition of the final
rule.  EPA believes that the proposed rule was neutral with respect to
the employment status of the designated representative.  The final rule
provides flexibility for the owners and operators to choose any
individual, employee or non-employee, to represent them.  EPA modified
the rule to clarify that each facility and each supplier shall have one
and only designated representative and that the designated
representative must be authorized by binding agreement of the owners and
operators. 

Agents.

Comment:  Several commenters requested that EPA allow designated
representatives and alternate designated representatives the option of
delegating their responsibility to prepare and submit reports to EPA to
a preparer or agent.  Commenters also stated that the designated
representative requirement is inconsistent with Title V reporting. 

Response:  EPA agrees that it is beneficial to give the designated
representatives and alternate designated representatives’ flexibility
concerning who prepares the reports that they are responsible for
submitting.  The final rule does not specify who must prepare reports,
but only specifies who must certify, sign, and submit them. EPA also
agrees that flexibility should be provided concerning who actually
submits the reports, similar to the flexibility provided in the ARP. 
This flexibility was implied in the provision in the proposed rule that
reports be submitted “in a format specified by the Administrator,”
which format has included, in other programs such as the ARP, the
ability to use agents.  However, EPA decided to make this flexibility
explicit by including in the final rule provisions allowing and setting
requirements for agents selected by designated representatives or
alternate designated representatives.  The structure of designated
representative, alternate designated representative and agent fits a
wide range of circumstances from large companies to small, including
those accustomed to reporting under Title V.  

Certification Statement.

Comment:  Several commenters described the self-certification procedures
in the proposed rule as too restrictive or suggested that the rule
should be consistent with requirements of the Title V or TRI program. 
For example, the rule’s requirement that the designated representative
certify that they have “personally examined” the data should be
replaced by the Title V requirement that a responsible official certify
that they have made a “reasonable inquiry” as to the accuracy of the
data. 

Response:  EPA believes that the high level of public interest in the
data collected under this rule, as well as its importance to future
policy, warrants establishment, by rule pursuant to CAA Sections 114,
208, and 301(a)(1), of a high standard for data quality and consistency
and a high level of accountability for reported data, which will help
ensure that the data quality and consistency standard is met.  The
certification requirements set forth in this rule are similar to the ARP
(Title IV).  EPA has successfully implemented a system allowing agents
in the ARP for over a decade.this approach in the ARP and found that it
provides a high degree of both data quality and consistency and
accountability. 

2.  Certificate of representationRepresentation.

Comment:  One commenter requested that EPA designate a deadline for the
submission of the certificate of representation to ensure sufficient
time to process the submissions.

Response:  EPA agrees that it will need an earlier deadline for
submitting certificates of representation is advisable to provide
additional lead time to process the certificates and, if necessary,
verify identities and resolve issues. Because any delay in processing a
certificate of representation could delay the submission of data, EPA is
requiring that the designated representative submit the initial
certificate of representation at least 60 days prior to the deadline for
a facility or supplier’s initial GHG report.  

Comment: Several commenters noted that a certificate of representation
for each facility and supplier is burdensome either due to timing with
the annual report, the need to maintain current information, or
ambiguities as to whether the certificate is complete.  Commenters also
requested that reporters be allowed more than 30 days to submit a
revised certificate of representation in the event of a change in
operators or owners. 

Comment:  Several commenters requested that EPA provide an electronic
system for submitting and processing certificates of representation.

Response:  EPA believes the proposed reporting rule required electronic
reporting of the certificate of representation.  To clarify this
requirement, EPA has explicitly stateddoes not agree that certificates
of representation, are unnecessary or overly burdensome or that there
should be any uncertainty as well as annual GHG reports, must be
submitted electronicallyto whether a certificate of representation is
complete.  The information required on the certificate of representation
is listed in the rule and should be well known to the owners and
operators of the facility or supplier.  It is the responsibility of the
individual submitting the certificate to ensure its completeness.  This
certificate of representation has been used successfully for over a
decade in the ARP.

To minimize burden, the electronic data reporting system will provide
the means to electronically submit both the initial and any subsequent
certificate of representation.  EPA agrees that reporters should be
allowed more time to update changes in owners or operators but does not
agree that doing so in the annual report is sufficient.  The designated
representative is the primary point of contact between the owners and
operators and the EPA.  However, the owners and operators are ultimately
responsible for compliance with the requirements of reporting rule, and
it is therefore essential that the information in the certificate of
representation be timely and accurate in the event EPA finds it
necessary to contact the owners and operators of the facility or
supplier during periods in between the submission dates of the annual
reports, for example, to perform an audit.  The final rule allows
reporters up to 90 days to submit a revised certificate of
representation when a change in owners or operators occurs.  In
addition, EPA modified both the owner definition and rule to clarify
that the certificate of representation does not need to list persons
whose legal or equitable title to or leasehold interest in a facility or
supplier arises solely because they are limited partners in a
partnership with legal or equitable title to, a leasehold interest in,
or control of, the facility or supplier.  

3.  Data collection Methods

Comment:  Several commenters requested that EPA use current emission
inventory reporting programs (e.g., NEI) to handle data collection or to
sunset the GHG reporting rule, and instead use such programs, after five
years.

Response:  EPA is requiring electronic reports to be submitted directly
to EPA using a new data reporting system for the GHG reporting rule. 
The rationale for the decision to report directly to EPA is contained in
Sections II.N (emissions verification) and VI.B (compliance and
enforcement) of this preamble.  EPA recognizes the value of integrating
the GHG data reported under this rule with other emission reporting
programs.  NEI, for example, plans to incorporate the GHG emissions data
from this collection, as feasible, where facilities report to both
programs.    

Comment:  Commenters requested that the design of the new data system be
modeled on existing electronic reporting programs, incorporate measures
to handle system errors, and provide opportunities for testing and user
training.

Response:  EPA agrees that a national electronic emissions database
should be the basis for receiving GHG data, and that the ARP database
provides a useful model for a future GHG emissions database.  Data would
be provided to EPA electronically to reduce the burden on the reporters
and EPA, and to increase the accuracy of the reported emissions, among
other reasons.  The issue of transmission failures and transmission
errors will be addressed in the development of the electronic reporting
system.  EPA agrees that is it important for data reporters to be able
to confirm that their data were accepted by the system and to compare
the data in the system to the data that they reported to ensure it was
accurately incorporated into the database.  The new data system will
meet Agency requirements for security and hosting.  EPA acknowledges
comments supporting a “user friendly” reporting system.  EPA plans
to follow well known design practices within the constraints of
security, accessibility and Agency design requirements.   

EPA agrees with commenters on the need for testing and user training. 
We will continue the outreach effort undertaken during this rulemaking
to encourage stakeholder participation in ‘beta’ testing and
training opportunities.

Unique Identifiers for Facilities and Units

Comment:  Several commenters requested that EPA assign and track
corporate identifiers for reporting facilities to facilitate
corporate-level analysis of emission data. Commenters also requested
that EPA publish a list of identifiers for all EPA programs that a
covered facility may report to.  

Response:  EPA is collecting owner and operator information through the
Certificate of Representation (40 CFR 98.4).  At this time, EPA is not
proposing to assign unique identifiers to the owners and operators
because of the complexity of ownership structures (including percentage
shares of owners, subsidiaries, holding companies, and limited liability
partnerships) that can be used in the multiplicity of industrial and
commercial sectors required to report emission data under this rule. 
Although as explained earlier in the preamble, we are exploring options
for adding additional data elements to the reports, such as name of
parent company and NAICS code(s), to allow easier aggregation of
facility-level data to the corporate level under this program.  EPA
expects to subject any additional requests to notice and comment
rulemaking.

EPA’s Facility Registry System (FRS) links EPA program identification
numbers under onea unique facility record.  The FRS database is publicly
available to queries from the EPA.GOV webWeb site under the Envirofacts
Data Warehouse home page:    HYPERLINK
"http://www.epa.gov/enviro/html/fii/fii_query_java.html" 
http://www.epa.gov/enviro/html/fii/fii_query_java.html . Descriptive
information about FRS can be found at:    HYPERLINK
"http://www.epa.gov/enviro/html/fii/index.html" 
http://www.epa.gov/enviro/html/fii/index.html .  FRS may be searched by
program identification, facility name or geographic location.  The
Agency will continue to make FRS and all program identification numbers
readily available and will include the facilities reporting under this
rule in the FRS collection of program ID’s once public release of the
data is authorized. 

Submission Method

Comment:  Several commenters requested that EPA specify the format of
the data collection methods and subject it to public comment before
finalizing the rule.  These commenters indicated that without the
details of the data collection methods it was not possible to evaluate
the GHG reporting rule, including implementation costs and reporting
burden.

Response:  The final rule requires reports to be submitted “in a
format specified by the Administrator.”  EPA is thereby retaining the
flexibility to specify the electronic format, and the underlying
electronic reporting system reflected in the format, after promulgation
of this final rule but well before the first reporting deadline and, if
necessary, to change the electronic format and electronic reporting
system based on implementation experience and new technology.  Several
other reporting programs (e.g., ARP) use a similar approach where the
specific electronic reporting system is not included within the rule or
subjected to formal notice and comment.  The relevant subparts of the
proposed GHG reporting rule specified the data elements that each entity
must report, and therefore parties could evaluate the reporting burden
and costs under the proposed rule and had an opportunity to comment on
that aspect of the proposed rule.  In addition, before specifying the
electronic format and underlying electronic reporting system, EPA will
conduct outreach and provide opportunities for stakeholder feedback on
the specific reporting format and reporting system.

Comment:  Several commenters requested that EPA provide alternative
methods to report emission data, including paper submissions, scanned
documents, and direct data upload.

Response:  EPA is requiring electronic reporting of the GHG and
supplemental data to increase the accuracy and timeliness of the
reported emission data and is not providing options for paper
submissions or scanned documents.GHG reports.  Requiring electronic
submission of data allows EPA to conduct electronic QA testing of all
such data when it is received and to provide electronic feedback to the
reporters almost instantaneously.  This gives reporters the opportunity
to correct any errors, or to provide explanations of potentially
problematic data, within a short time frame, thereby increasing the
accuracy and timeliness of the data.  Moreover, electronically submitted
data can be readily sorted and analyzed by EPA and members of the
public.  In contrast, submission of hardcopy data (whether in paper or
scanned documents) would make audit and correction, as well as sorting
and analysis, of the data much more cumbersome, inefficient, and time
consuming.  Indeed, particularly in light of the large number of
facilities and suppliers that will be reporting and the large amounts of
reported data that will be received as a result, the ability to audit
and analyze the data received in hardcopy format would likely be
significantly limited.  This would adversely affect the usefulness, as
well as the accuracy and timeliness of the data. 

In requiring electronic data submission, EPA will provide a Web-based
reporting system to guide reporters through the data entry, emission
calculation, and submission process.  This reporting system will conform
with to EPA information technology standards and 40 CFR part 3.  In
addition, EPA will provide a mechanism for reporters to submit data
files directly to EPA using a standard format (e.g., XML) to be
prescribed by the Administrator before the first reporting date.  To
reduce the burden on reporters and reduce errors, EPA will conduct
outreach and training for reporters on the reporting format and
underlying reporting systems.  EPA will also provide a hotline to answer
questions about the program and reporting format and reporting systems. 
EPA expects that most reporters affected by this rule are already
familiar with Web-based or electronic reporting systems through other
EPA programs.

Delegation of Authority to State Agencies to Collect GHG Data

Comment:  Several commenters requested that EPA delegate rule
implementation, including data collection, to State and local agencies. 
These commenters indicated that several States already have GHG
reporting requirements and have systems in place to collect and verify
this data, and suggested that delegation of the rule could help reduce
inconsistency or duplication of effort between State programs and this
Federal mandatory GHG reporting rule.  Other commenters supported
requiring facilities to submit data directly to EPA, without delegation
of data collection to State and local agencies, in order to provide
national consistency.

Response:  EPA is requiring electronic reports to be submitted directly
to EPA, and is not delegating data collection to State and local
agencies.  The rationale for this decision is provided in Section VI.B
of this preamble.

5.  Data Dissemination

Public Access to Emissions Data.

Comment:  Several commenters supported EPA’s proposal to make the data
submitted under the reporting rule available to the public. Some
requested that data be published real time, while others requested the
data be released in a timely manner.

Response:  With the exception of CBI, EPA intends to make data submitted
under this program available to the public in a timely manner after the
reports have been submitted and EPA has completed QA/QC of the data.  To
that end, EPA intends to establish a new reporting system that will
accept electronic submissions of GHG emissions and supporting data and
facilitate EPA’s verification of the submissions.  EPA plans to
provide public access to the data by posting electronic data on a webWeb
site in a timely manner after the reporting deadline.  This level of
transparency is important to public participation in future policy
development and for building public confidence in the quality of the
data collected. 

Sharing Emissions Data with Other Agencies.

Comment:  Some commenters stressed that electronic data reporting
systems need to be consistent and inter-operable and allow data exchange
between TCR, State rules, NEI, ARP, other stakeholders and EPA.

Response:  EPA will continue to coordinate with other Federal, State,
and regional programs and will make efforts to facilitate data exchange
when designing the data reporting systems system that will be used for
the GHG reporting rule.  EPA staff is working with the Exchange Network,
which includes States, other EPA programs and TCR, on a data exchange
standard for GHG reporting.    EPA intends to employ inter-operable data
exchange standards.  EPA intends to design and manage the GHG data
collection to take advantage of existing efforts on data exchange
standards and to work with stakeholder groups to promote the easy
exchange and sharing of the data collected under this rule.  For
example, EPA is extending the Consolidated Emissions Reporting Schema
(CERS), currently in use by the EPA’s NEI program, to support data
reporting and publication under this rule.  EPA also intends to use
existing tools, such as FRS and SRS, to ensure data consistency.  

To the extent possible, EPA will consider existing reporting systems and
work with those programs and systems to develop a reporting scheme that
facilitates data exchange.  EPA anticipates that this coordination will
reduce the burden of reporting for both reporters and government
agencies.  However, as explained in Section II.O of this preamble, the
various reporting programs do not have identical data needs and
requirements.  Therefore, at this time, it is not possible for companies
reporting under State and Federal rules and voluntary programs to file a
single report that will satisfy all reporting requirements.

Comment:  Commenters requested that the data system utilize common
standards, such as XML and geographic identifiers, and provide
descriptive text wherever codes or abbreviations are used. 

Response:  EPA agrees that publishing the results of this data
collection using common, standards-based schemas and formats will
promote the exchange of data between EPA, States and other entities. 
The published results will include the latitude and longitude of
facilities as well as help text with definitions of codes and
abbreviations.

VI.  Compliance and Enforcement

This section of the preamble generally describes the compliance
assistance and enforcement activities EPA intends to implement for the
GHG reporting rule and summarizes public comments and responses on
compliance assistance, role of the States, and enforcement.  

A.  Compliance and Enforcement Summary 

1.  Compliance Assistance

EPA plans to conduct an active outreach and technical assistance program
following publication of the final rule.  The primary audience is
potentially affected industries.  We intend to develop implementation
and outreach materials and training to help potential reporters
understand whether the rule applies to them and explain the reporting
requirements and timetables.  The program particularly will target
industrial, commercial, and institutional sectors that do not routinely
deal with air pollution regulations. 

Compliance materials will be tailored to the needs of various sectors. 
These materials might include, for example, fact sheets, information
sheets, plain English guides, frequently asked question and answer
documents, applicability tools, monitoring and recordkeeping checklists,
and training on rule requirements and the electronic reporting system. 
We also expect to implement a compliance assistance e-mail and telephone
hotline for answering questions and providing technical assistance. 
Note that while EPA plans to issue compliance assistance materials,
reporters should always consult the final rule to resolve any
ambiguities or questions.

2.  Role of the States

While EPA does not intend to formally delegate data collection and
enforcement of the GHG reporting rule to State agencies, the States can
play a vital role in compliance EPA will likely enlist State assistance,
when it is available, for outreach and compliance assistance with the
final rule.  (However, State and local agencies will not be required to
provide EPA any assistance with these activities, given State and local
agency resource constraints and priorities.).  State and local air
pollution control agencies routinely interact with many of the sources
that would report under this rule.  Further, several States have
experience implementing State mandatory GHG reporting and reduction
programs.  Therefore, we plan to work with those State and local
agenciesagencies that are able to assist EPA to define their important
role in communicating the requirements of the rule and providing
compliance assistance.  In concert with their routine inspection and
other compliance and enforcement activities for other CAA programs,
State and local agencies may also be able to assist with educating
facilities and assuring compliance at facilities subject to this rule.  

3.  Enforcement

Facilities or suppliers that fail to monitor or report GHG emissions,
quantities supplied, or other data elements according to the
requirements of the applicable rule subparts could potentially be
subject to enforcement action by EPA under CAA sections 113 and 203-205.
 The CAA provides for several levels of enforcement that include
administrative, civil, and criminal penalties.  The CAA allows for
injunctive relief to compel compliance and civil and administrative
penalties of up to $37,500 per day per violation.

Actions (or inactions) that could ultimately be considered violations
include but are not limited to the following:

Failure to report GHG emissions (for suppliers, the emissions that would
result from combustion or use of the products they supply).

Failure to collect data needed to calculate GHG emissions.

Failure to continuously monitor and test as required.  Note that merely
filling in missing data as specified does not excuse a failure to
perform the monitoring or testing.

Failure to calculate GHG emissions according to the methodology(s)
specified in the rule.

Failure to keep required records needed to verify reported GHG
emissions.

Falsification of reports.

B.  Summary of Public Comments and Responses on Compliance and
Enforcement

This section contains a brief summary of major comments and responses. 
A large number of comments on compliance and enforcement were received
covering numerous topics.  Responses to significant comments received
can be found in the comment response document for compliance“Mandatory
Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments,
Compliance and enforcement in the docket
(EPA-HQ-OAR-2008-508-XXX).Enforcement.”

1.  Role of States in compliance and enforcement

Comment:  Several commenters requested that EPA delegate rule
implementation, including data collection, emissions verification, and
enforcement of the rule to State and local agencies.  These commenters
indicated that several States already have GHG reporting requirements
and have systems in place to collect and verify these data, and they
suggested that delegation of the rule could help reduce inconsistency or
duplication of effort between State programs and this Federal mandatory
GHG reporting rule.  However the majority of commenters, including
industry, environmental organizations, and many public citizens
supported requiring facilities to submit data directly to EPA, without
delegation of data collection or emissions verification to State and
local agencies, in order to provide national consistency.

Response:  Section 114(b) of the CAA allows EPA to delegate to States
the authority to implement and enforce Federal rules.  At this time,
however, EPA does not propose to formally delegate implementation of the
rule (such as data collection and enforcement activities) to State and
local agencies, as discussed in sectionSection II.O of this preamble. 
The goal of data collection under this rule is to establish a
consistent, verified, national data set that is available to EPA,
States, other agencies, policy makers, and the public for use in
developing and implementing future GHG policies and reduction programs. 
To meet these data consistency and timeliness constraints, and to serve
policy objectives, it is most efficient to have the data submitted
directly into one central EPA system and have centralized emissions data
verification.  Direct reporting to EPA will also help us better
understand and address common compliance problems that may arise from
the GHG reporting rule.

EPA recognizes that several States already have mandatory GHG reporting
programs that are broader in scope, in a more advanced state of
development, and have different policy objectives than this rulemaking. 
These are important programs that not only led the way in reporting of
GHG emissions before the Federal government acted but also have
catalyzed important GHG reductions.

As discussed in sectionSection II.O of this preamble, we are committed
to working with States and other groups (e.g, TCR, Environmental Council
of the States (ECOS)) to develop electronic reporting tools that can
both collect and share data in an efficient and timely manner.  At this
time, EPA is in the process of developing the reporting format and tools
and therefore has not specified the exact reporting format, other than
it will be electronic, in order to maintain flexibility to modify the
reporting format and tools in a timely manner.  To the extent possible,
EPA will work with existing reporting programs and systems to develop a
reporting scheme that minimizes the burden on sources.

While EPA is not delegating authority to the States, we will work with
States as we develop rule implementation plans to determine appropriate
implementation roles, such as assisting with outreach efforts and site
visits to audit facility reports.  For related comments and responses,
please see the following sections of this preamble: II.N (verification
approach), II.O (role of States) and II.R (CBI).

2.  Enforcement

Comment:  Some commenters suggested that States should be allowed to
participate in the enforcement of the GHG reporting rule, perhaps
through delegated enforcement authority.

Response:  EPA welcomes States’ interest in helping EPA enforce this
or any other Federal rule and we will work with States to determine
appropriate roles as described above.  We do not plan to delegate the
enforcement of this rule in the same sense that we do under other CAA
programs such as the NESHAP program in which, for example, notices may
be sent only to the delegated States.  If a State would like the
authority to enforce this rule, then the State may adopt the provisions
of this GHG reporting rule into State laws or regulations by reference. 
This would make the provisions enforceable as a matter of State law
which can be enforced in a State court. 

Comment:  Some commenters stated that they should be able to petition
EPA to enforce against violators where they have evidence of or suspect
violations. 

Response:  EPA welcomes any tips from citizens about suspected
violations of this or any rule through our tips webWeb site,   HYPERLINK
"http://www.epa.gov/tips"  www.epa.gov/tips .  However, we are not
including a formal petition process in the rule because such a process
was not proposed.  We do not favor a formal petition process because a
formal petition is not necessary for us to investigate concerns raised
by citizens and such a process might take extra time or divert resources
from other priorities.  

Comment:  Some commenters stated that a flexible enforcement policy is
needed.  They noted that the proposed rule cited the CAA for the
authority for the GHG reporting rule and stated that a violation of the
reporting rule is a violation of the CAA and subject to maximum daily
penalties allowed under the CAA.  However, the commenters were concerned
that the maximum penalty should not be applied in most cases and argued
that there are many instances when a less severe action is appropriate.

Response:  EPA agrees with the commenters that flexibility is needed in
enforcing the rule.  The penalty cited in the proposal preamble and rule
is a statutory maximum, and would not be applied in every case.  EPA’s
objective with the reporting rule is to collect accurate GHG data in a
timely manner.  In order to achieve that objective, EPA will generally
work with sources that must submit GHG reports in order to facilitate
compliance and provide the needed data to EPA.  The CAA allows EPA
discretion to pursue a variety of informal and formal actions in order
to achieve compliance.  While EPA is committed to working with reporters
to ensure accuracy, this does not relieve reporters from their
obligation to report data that are complete, accurate, and in accordance
with the requirements of this rule.

In many instances, based on past enforcement experience, less punitive
enforcement actions are exhausted before more punitive fines and
penalties are imposed on a non-complying source.  These less punitive
actions may include a warning to the source that it is in non-compliance
along with advice on what needs to be done to comply and a request for
response from the facility.  Initial actions may also include a formal
legal notification from the EPA that defines the violation, provides
evidence, and requires (orders) corrective actions by specific dates. 
The EPA enforcement office always uses discretion and takes
case-specific circumstances into account when determining the
appropriate actions to address violations of CAA rules.  We will
continue to do so in enforcing the reporting rule, and we are not laying
out a specific enforcement policy or hierarchy in order to maintain the
necessary flexibility.

VII.  Economic Impacts on the Rule 

This section of the preamble examines the costs and economic impacts of
the GHG reporting rule, including the estimated costs and benefits of
the rule, and the estimated economic impacts of the rule on affected
entities, including estimated impacts on small entities.  Complete
detail of the economic impacts of the proposedfinal rule can be found in
the text of the Regulatory Impact Analysis (RIA) for the final rule
(EPA-HQ-OAR-2008-0318-XXX0508). 

This section also contains a brief summary of major comments and
responses.  A large number of comments on economic impacts of the rule
were received covering numerous topics.  Responses to significant
comments received can be found in the comment response document for
economic impacts in“Mandatory Greenhouse Gas Reporting Rule: EPA’s
Response to Public Comments, Cost and Economic Impacts of the docket
(EPA-HQ-OAR-2008-508-XXX).Rule.”

A.  How were compliance costs estimated?

1.  Summary of Method Used to Estimate Compliance Costs 

EPA estimated costs of complying with the rule for reporting process
emissions of GHGs in each affected industrial facility, as well as
emissions from stationary combustion sources at industrial facilities
and other facilities, GHG and supply data from fuel suppliers and
industrial gas suppliers, and GHG data for mobile sources.  2006 is the
representative year of the analysis in that the annual costs were
estimated using the 2006 population of emitting sources.  EPA used
available industry and EPA data to characterize conditions at affected
sources.  Incremental monitoring, recordkeeping, and reporting
activities were then identified for each type of facility and the
associated costs were estimated.

The costs of complying with the rule will vary from one facility to
another, depending on the types of emissions, the number of affected
sources at the facility, existing monitoring, recordkeeping, and
reporting activities at the facility, etc.  The costs include labor
costs for performing the monitoring, recordkeeping, and reporting
activities necessary to comply with the rule.  For some facilities,
costs include costs to monitor, record, and report emissions of GHGs
from production processes and from stationary combustion units.  For
other facilities, the only emissions of GHGs are from stationary
combustion.  EPA’s estimated costs of compliance are discussed in
greater detail below:

Labor Costs.  The costs of complying with and administering this rule
include time of managers, technical, and administrative staff in both
the private sector and the public sector.  Staff hours are estimated for
activities, including:

Monitoring (private): staff hours to operate and maintain emissions
monitoring systems.

Reporting (private): staff hours to gather and process available data
and reporting it to EPA through electronic systems.

Assuring and releasing data (public): staff hours to quality assure,
analyze, and release reports.

Staff activities and associated labor costs will potentially vary over
time.  Thus, cost estimates are developed for start-up and first-time
reporting, and subsequent reporting.  Wage rates to monetize staff time
are obtained from the Bureau of Labor Statistics (BLS).

Equipment Costs.  Equipment costs include both the initial purchase
price of monitoring equipment and any facility/process modification that
may be required.  For example, the cost estimation method for mobile
sources involves upstream measurement by the vehicle manufacturers. 
This may require an upgrade to their test equipment and facility.  Based
on expert judgment, the engineering costs analyses annualized capital
equipment costs with appropriate lifetime and interest rate assumptions.
 Cost recovery periods and interest rates vary by industry, but
typically, one-time capital costs are amortized over a 10-year cost
recovery period at a rate of 7seven percent.

2.  Summary of Comments and Responses 

Comment:  A majority of the comments received on the compliance costs of
the reporting rule focused on facility level costs for monitoring and
reporting.  Commenters noted that noted that costs estimated for a
representative facility may differ from actual facility level costs. 
Some commenters specifically referred to the costs associated with
installing and maintaining capital equipment.  Other commenters noted
that some source categories had higher estimated compliance costs than
others.  Several commenters expressed confusion over how combustion
related monitoring costs are added to process related monitoring costs.

Response:  EPA recognizes that the costs presented for facilities
represent costs that would be incurred by a representative facility, and
may not reflect the costs that would be incurred by each individual
facility in each industry because facilities affected by each subpart
vary.

Nevertheless, after reviewing the comments received, EPA has determined
that its analysis provides a reasonable characterization of costs for
facilities affected by each subpart and that its documentation provides
adequate documentation of how the costs were estimated.  As described in
the next section, EPA collected and evaluated cost data from multiple
sources, and weighed the analysis prepared at proposal against the input
received through public comments.  In any analysis of this type, there
will be variations in costs among facilities, and after thoroughly
reviewing the available information, we have concluded that the costs
developed for this rule appropriately reflect a “representative
facility” in the sector.

The costs facing facilities in some sectors include not only process
costs but additional costs associated with other subparts of the rule. 
While these costs are presented individually in Section 4 of the RIA for
the final rule, where these conditions apply the costs are summed across
applicable subparts and compared to revenues in the economic and small
entity impact analyses.

B.  What are the costs of the rule?

1.  Summary of Costs

For the cost analysis, EPA gathered existing data from EPA, industry
trade associations, States, and publicly available data sources (e.g.,
labor rates from the BLS) to characterize the processes, sources,
sectors, facilities, and companies/entities affected. EPA also
considered cost data submitted in public comments on the proposed rule,
as further discussed in Section VII.B.2 of this preamble.  Costs were
estimated on a per entity basis and then weighted by the number of
entities affected at the 25,000 metric tons CO2e threshold.  

To develop the costs for the rule, EPA estimated the number of affected
facilities in each source category, the number and types of combustion
units at each facility, the number and types of production processes
that emit GHGs, process inputs and outputs (especially for monitoring
procedures that involve a carbon mass balance), and the measurements
that are already being made for reasons not associated with the rule (to
allow only the incremental costs to be estimated).  Many of the affected
source categories, especially those that are the largest emitters of
GHGs (e.g., electric utilities, industrial boilers, petroleum
refineries, cement plants, iron and steel production, pulp and paper)
are subject to national emission standards and we use data generated in
the development of these standards to estimate the number of sources
affected by the reporting rule. 

Other components of the cost analysis included estimates of labor hours
to perform specific activities, cost of labor, and cost of monitoring
equipment.  Estimates of labor hours were based on previous analyses of
the costs of monitoring, reporting, and recordkeeping for other rules;
information from the industry characterization on the number of units or
process inputs and outputs to be monitored; and engineering judgment by
industry and EPA industry experts and engineers.  Labor costs were taken
from the BLS and adjusted to account for overhead.  Monitoring costs
were generally based on cost algorithms or approaches that had been
previously developed, reviewed, accepted as adequate, and used
specifically to estimate the costs associated with various types of
measurements and monitoring.

A detailed engineering analysis was conducted for each subpart of the
rule to develop unique unit costs.  This analysis is documented in the
RIA for the final rule.  The TSDs for each source category provide a
discussion of the applicable measurement technologies and any existing
programs and practices.  The comment response documentsappropriate
volume of “Mandatory Greenhouse Gas Reporting Rule: EPA’s Response
to Public Comments” for each source category provide responses to any
public comments on these source category engineering and cost analyses. 
Section 4 of the RIA for the final rule contains a description of the
engineering cost analysis. 

Table VII-1 of this preamble presents by subpart:  the number of
entities, the downstream emissions covered, the first year capital costs
and the first year annualized costs of the rule.  EPA estimates that the
total national annualized cost for the first year is $132 million, and
the total national annualized cost for subsequent years is $89 million
(2006$).  Of these costs, roughly 13 percent fall upon the public sector
for program administration in the first year, while 87 percent fall upon
the private sector.  General stationary combustion sources, which are
widely distributed throughout the economy, are estimated to incur
approximately 26 percent of costs in the first year; other sectors
incurring relatively large shares of costs are pulp and paper
manufacturing (9% percent) and vehicle and engine manufacturers (9%
percent).

The threshold, in large part, determines the number of entities required
to report GHG emissions and hence the costs of the rule.  The number of
entities excluded increases with higher thresholds.  Table VII-2 of this
preamble provides the cost-effectiveness analysis for various thresholds
examined.  Two metrics are used to evaluate the cost-effectiveness of
the emissions threshold.  The first is the average cost per metric ton
of emissions reported ($/metric ton CO2e).  The second metric for
evaluating the threshold option is the incremental cost of reporting
emissions.  The incremental cost is calculated as the additional
(incremental) cost per metric ton starting with the least stringent
option and moving successively from one threshold option to the next. 
For more information about the first year capital costs (unamortized),
project lifetime and the amortized (annualized) costs for each subpart,
please refer to section 4 of the RIA for the final rule and the RIA cost
appendix.  Not all subparts require capital expenditures but those that
do are clearly documented in the RIA for the final rule.    

Table VII-1.  Estimated Covered Entities, Emissions and Costs by Subpart
(2006$) 

Subpart	Number Covered of Entities	Downstream Emissions	First Year
Capital Costs	First Year Total Annualized Costs2



(Million 

of MtCO2e)	Share	(Million)	Share	(Million)	Share

Subpart A —General Provisions	0	0.0	0%	$0.0 	0%	$0.0 	0%

Subpart B — Reserved	0	0.0	0%	$0.0 	0%	$0.0 	0%

Subpart C —General Stationary Fuel Combustion Sources	3,000	220.0	6%
$10.5 	27%	$25.8 	20%

Subpart D —Electricity Generation	1,108	2262.0	59%	$0.0 	0%	$3.3 	2%

Subpart E —Adipic Acid Production	4	9.3	0%	$0.0 	0%	$0.1 	0%

Subpart F —Aluminum Production	14	6.4	0%	$0.0 	0%	$0.2 	0%

Subpart G —Ammonia Manufacturing	23	12.9	0%	$0.0 	0%	$0.4 	0%

Subpart H —Cement Production	107	86.8	2%	$5.4 	14%	$6.8 	5%

Subpart K —Ferroalloy Production	9	2.3	0%	$0.0 	0%	$0.1 	0%

Subpart N —Glass Production	55	2.2	0%	$0.0 	0%	$0.5 	0%

Subpart O —HCFC-22 Production	3	13.8	0%	$0.0 	0%	$0.0 	0%

Subpart P —Hydrogen Production	41	15.0	0%	$0.0 	0%	$0.4 	0%

Subpart Q —Iron and Steel Production	121	85.0	2%	$0.0 	0%	$3.7 	3%

Subpart R —Lead Production	13	0.8	0%	$0.0 	0%	$0.1 	0%

Subpart S —Lime Manufacturing	89	25.4	1%	$4.9 	12%	$5.3 	4%

Subpart U —Miscellaneous Uses of Carbonates	0	0.0	0%	$0.0 	0%	$0.0 	0%

Subpart V —Nitric Acid Production	45	17.7	0%	$0.2 	1%	$0.9 	1%

Subpart X —Petrochemical Production	80	54.4	1%	$0.0 	0%	$2.2 	2%

Subpart Y —Petroleum Refineries	150	204.7	5%	$1.6 	4%	$6.1 	5%

Subpart Z —Phosphoric Acid Production	14	3.8	0%	$0.8 	2%	$0.8 	1%

Subpart AA —Pulp and Paper Manufacturing	425	57.7	2%	$14.8 	37%	$8.6 
7%

Subpart BB —Silicon Carbide Production	1	0.1	0%	$0.0 	0%	$0.0 	0%

Subpart CC —Soda Ash Manufacturing	5	3.1	0%	$0.0 	0%	$0.1 	0%

Subpart EE —Titanium Dioxide Production	8	3.7	0%	$0.0 	0%	$0.1 	0%

Subpart GG —Zinc Production	5	0.8	0%	$0.0 	0%	$0.1 	0%

Subpart HH —Landfills	2,551	91.1	2%	$1.3 	3%	$12.4 	9%

Subpart JJ —Manure Management	107	4.5	0%	$0.0 	0%	$0.3 	0%

Subpart LL -Suppliers of Coal  & Subpart MM —Suppliers of Petroleum
Products	315	0.0	0%	$0.0 	0%	$3.7 	3%

Subpart NN —Suppliers of Natural Gas and Natural Gas Liquids	1,502	0.0
0%	$0.0 	0%	$6.8 	5%

Subpart OO —Suppliers of Industrial Greenhouse Gases	167	643.4	17%
$0.0 	0%	$0.5 	0%

Subpart PP —Suppliers of Carbon Dioxide (CO2)	13	0.0	0%	$0.0 	0%	$0.0 
0%

Subpart QQ - Motor Vehicle and Engine Manufacturers	317	NA	NA	$0.0 	0%
$8.6 	7%

Coverage Determination Costs for Non-Reporters	NA	NA	NA	NA	NA	$17.2 	13%

Private Sector, Total	10,152	3,827	100%	$39.6 	100%	$115.0 	87%

Public Sector, Total	NA	NA	NA	NA	NA	$17.0 	13%

Total	10,152	3,827	100%	$39.6 	100%	$132.0 	100%

1 Emissions from upstream facilities are excluded from these estimates
to avoid double counting.

2 Total costs include labor and capital costs incurred in the first
year. Capital Costs are annualized using appropriate equipment lifetime
and interest rate (see additional details in RIA section 4 of the RIA
for the final rule).

Table VII-2.  Threshold Cost-Effectiveness Analysis (2006$)

Threshold (tons CO2e)	Facilities Required to Report	Total Costs 

(million $2006)	Downstream Emissions Reported (MtCO2e/

year)	Percentage of Total Downstream Emissions Reported	Average
Reporting Cost ($2006/ton)	Incremental Cost ($/metric ton)

100,000	6,269	$89 	3,738	53%	$0.02 	 --

25,000	10,152	$132 	3,827	54%	$0.03 	$0.49

10,000	16,718	$160 	3,861	55%	$0.04 	$0.83

1,000	54,229	$398 	3,926	56%	$0.10 	$3.67

* Cost per metric ton relative to the selected option.

Note: Does not include emissions for Motor Vehicle and Engine
Manufacturers (Subpart QQ).

Table VII-3 of this preamble presents costs broken out by upstream and
downstream sources.  Upstream sources include the fuel suppliers and
industrial GHG suppliers.  Downstream suppliers include combustion
sources, industrial processes, and biological processes.  Most upstream
facilities (e.g., refineries) are also direct emitters of GHGs and are
included in the downstream side of the table.  As shown in Table VII-3
of this preamble, over 99 percent of industrial processes emissions are
covered at the 25,000 metric tons CO2e threshold for a cost of
approximately $36 million.  However, it should be noted that due to data
limitations the coverage estimates for upstream and downstream source
categories are approximations.

Table VII-3.  Upstream versus Downstream Costs 

Upstream1 	Downstream2,3,4

Source Category	#Reporters	Emissions Coverage (%)10	First Year Cost

(millions)	Source Category	#Reporters2	Emissions Coverage3,7,10

(%)	First Year Cost3

(millions)

Coal Supply 	0	0%	$0.00 	Coal5,6 Combustion	N/A	99.0%	N/A

Petroleum Supply	315	100%	$3.66 	Petroleum5 Combustion9	N/A	20.0%	N/A

Natural Gas Supply	1,502	68%	$6.76 	Natural Gas5 Combustion	N/A	23.0%
N/A





Sub Total Combustion	4,108	N/A	$29.04 

Industrial Gas Supply	167	100%	$0.52 	Industrial Gas Consumption	17	14%
$0.24 

	Industrial Processes	1,068	99.6%	$36.2 

	Fugitive Emissions (coal, oil and gas)	0	0%	$0.00 

	Biological Processes	2,658	58%	$12.77 

	Vehicle8 and Engine Manufacturers	317	80%	$8.61 

Notes

1   Most upstream facilities (e.g., refineries) are also direct emitters
of greenhouse gases, and are included in the downstream side of the
table.

2  Estimating the total number of downstream reporters by summing the
rows will result in double-counting because some facilities are included
in more than one row due to multiple types of emissions (e.g.,
facilities that burn fossil fuel and have process/fugitive/biological
emissions will be included in each downstream category).

3   The coverage and costs for downstream reporters apply to the
specific source category, i.e., the fixed costs are not
“double-counted” in both stationary combustion and industrial
processes for the same facility. 

4   The thresholds used to determine covered facilities are additive,
i.e., all of the source categories located at a facility (e.g.,
stationary combustion and process emissions) are added together to
determine whether a facility meets the threshold (e.g., 25,000 metric
tons of CO2e/yr).

5   Estimates for the number of reporters and total cost for downstream
stationary combustion do not distinguish between fuels.  National level
data on the number of reporters could be estimated.  However, estimating
the number of reporters by fuel was not possible because a single
facility can combust multiple fuels.  For these reasons there is not a
reliable estimate of the total of the emissions coverage from the
downstream stationary combustion.

6   Approximately 90 percent of downstream coal combustion emissions are
already reported to EPA through requirements for electricity generating
units under the Acid Rain ProgramARP.

7   Due to data limitations, the coverage for downstream sources for
fuel and industrial gas consumption in this table does not take into
account thresholds.  Assuming full emissions coverage for each source
slightly over-states the actual coverage that will result from this
rule.  To estimate total emissions coverage downstream, by fuel, we
added total emissions resulting from the respective fuel combusted in
the industrial and electricity generation sectors and divided that by
total national GHG emissions from the combustion of that fuel.

8  The percent of coverage here is percentage of total heavy-duty
highway vehicles and engines, motorcycles, and nonroad engine sales
covered by manufacturer reporting in this proposal rather than emissions
coverage.  The “threshold” for mobile sources is based on
manufacturer size rather than total emissions.  In this rule, all
heavy-duty highway and nonroad vehicle and engine manufacturers, except
those that meet EPA’s definition of “small business” or “small
volume manufacturers”, would report emissions rates of  CO2, CH4, and
N2O from the products they supply.  This source category is neither
upstream nor downstream, but is included in the downstream column for
illustrative purposes.  

9 The emissions coverage for petroleum combustion includes combustion of
fuel by transportation sources as well as other uses of petroleum (e.g.,
home heating oil).  It cannot be broken out by transportation versus
other uses as there are difficulties associated with tracking which
products from petroleum refiners are used for transportation fuel and
which were not.  We know that although refiners make these designations
for the products leaving their gate, the actual end use can and does
change in the market.  For example, designated transportation fuel can
always be used as home heating oil.  

10  Emissions coverage from the combustion of fossil fuels upstream
represents CO2 emissions only.  It is not possible to estimate nitrous
oxide and methane emissions without knowing where and how the fuel is
combusted.  In the case of downstream emissions from stationary
combustion of fossil fuels, nitrous oxide and methane emissions are
included in the emissions coverage estimate.  They represent
approximately 1one percent of the total emissions.

 

2.  Summary of Comments and Responses

Comment:  EPA received comments on source specific cost data reflected
in the engineering cost analysis presented in section 4 of the
Regulatory Impact Analysis (RIA) for the proposed rule
(EPA–HQ–OAR–2008–0318–002).  Some commenters asked EPA to not
overly burden entities that may be required to report and to balance
reporting costs with the need for accurate reporting of GHG emissions.

Additional comments received questioned EPA’s estimate of the costs
associated with third party verification, as well as the estimated
burden to the Federal government for self certification with EPA
verification.

Response:  EPA considered all relevant comments regarding source
specific cost data developed in the engineering cost analysis and used
in the Regulatory Impact Analysis (RIA). for the proposed rule.  In some
cases, we revised our cost estimates, and in some cases we revised
monitoring and reporting requirements in ways which reduced burden. 
Please see source specific comments and responses in Section III of this
preamble and the associated comment response documentsrelevant volume of
“Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to Public
Comments”.

EPA believes the selected option for the mandatory GHG reporting rule
strikes a balance between impacts on small entities, consistency with
other programs, costs incurred by the reporting entities, and emissions
coverage.  Section 5 of the Final Regulatory Impact Analysis
(RIA)(DOCKET NUMBER)  for the final rule provides cost comparisons for
each alternative evaluated.

In evaluating the costs of self certification with EPA verification and
third party verification, EPA conducted a thorough review of relevant
cost information available.  EPA also considered cost data submitted in
public comments on the proposed rule.  EPA’s review of verification
costs included examining estimated Agency costs for other EPA based
reporting programs, as well as a study conducted by the California Air
Resources Board (CARB).  The results of EPA’s review of verification
costs can be found in the Memo on Verification Costs [DOCKET #].in the
docket.  The final rule retains self-certification with EPA
verification.  EPA’s estimated cost for verification activities is $7
million per year.  Additional comments and responses on third party
verification can be found in Section II.N of this preamble.  Section
5.1.6 of the Final Regulatory Impact Analysis (DOCKET #)RIA for the
final rule contains the full economic analysis of verification costs and
options.

C.  What are the economic impacts of the rule?

1.  Summary of Economic Impacts

EPA prepared an economic impact analysis to evaluate the impacts of the
rule on affected industries and economic sectors.  In evaluating the
various reporting options considered, EPA conducted a cost-effectiveness
analysis, comparing the cost per metric ton of GHG emissions across
reporting options.  EPA used this information to identify the preferred
options described in today’s rule.

To estimate the economic impacts of the rule, EPA first conducted a
screening assessment, comparing the estimated total annualized
compliance costs by industry, where industry is defined in terms of
North American Industry Classification System (NAICS) code, with
industry average revenues.  Overall national costs of the rule are
significant because there are a large number of affected entities, but
per-entity costs are low.  Average cost-to-sales ratios for
establishments in affected NAICS codes are uniformly less than 0.8
percent. 

These low average cost-to-sales ratios indicate that the rule is
unlikely to result in significant changes in firms’ production
decisions or other behavioral changes, and thus unlikely to result in
significant changes in prices or quantities in affected markets.  Thus,
EPA followed its Guidelines for Preparing Economic Analyses (EPA, 2002,
p.124-125) and used the engineering cost estimates to measure the social
cost of the rule, rather than modeling market responses and using the
resulting measures of social cost.  Table VII-4 of this preamble
summarizes cost-to-sales ratios for affected industries.  

Table VII-4.  Estimated Cost-To-Sales Ratios for Affected Entities 

NAICS	NAICS Description	Average Cost Per Entity ($1,000/entity)	Average
Entity Cost-to-Sales Ratio1

211	Oil and Gas Extraction	$2 	<0.1%

221	SF6 from Electrical Systems	$5 	<0.1%

322	Pulp & Paper Manufacturing	$20 	<0.1%

324	Petroleum and Coal Products	$21 	<0.1%

325	Chemical Manufacturing	$14 	<0.1%

327	Cement & Other Mineral Production	$50 	0.8%

331	Primary Metal Manufacturing	$26 	<0.1%

486	Oil & Natural Gas Transportation	$4 	<0.1%

562	Waste Management and Remediation Services	$5 	0.2%

325199	Adipic Acid	$24 	<0.1%

325311	Ammonia	$17 	<0.1%

327310	Cement	$63 	0.2%

331112	Ferroalloys	$9 	<0.1%

3272	Glass	$8 	<0.1%

325120	Hydrogen Production	$3 	<0.1%

331112	Iron and Steel 	$30 	<0.1%

3314	Lead Production	$10 	<0.1%

327410	Lime Manufacturing	$60 	0.4%

325311	Nitric Acid	$20 	<0.1%

324110	Petrochemical	$27 	<0.1%

325312	Phosphoric Acid	$60 	<0.1%

322110	Pulp and Paper	$20 	<0.1%

324110	Refineries	$41 	<0.1%

327910	Silicon Carbide	$10 	<0.1%

3251	Soda Ash Manufacturing	$16 	<0.1%

325188	Titanium Dioxide	$10 	<0.1%

3314	Zinc Production	$13 	<0.1%

1This ratio reflects first year costs.  Subsequent year costs will be
slightly lower because they do not include initial start-up activities.

2.  Summary of Comments and Responses

Comment:  EPA received a number of comments on the overall economic
impacts of the proposed rule.  Some commenters stated that the economic
impacts are understated as costs will not be passed on to consumers from
reporters. Other commenters stated that large increases in operating
costs resulting from mandatory reporting of GHGs would lead facilities
to close or move offshore.

Response:  As described previously, EPA conducted a thorough analysis of
available information and reviewed comments submitted on this issue, and
we have determined that this analysis provides a reasonable
characterization of costs for facilities in each subpart and that the 
documentation provides adequate explanation of how the costs were
estimated.  Our economic impact analysis has been conducted without
taking into account the fact that some share of costs may be passed on
to customers of each affected sector.  Instead, facilities’ annualized
costs were compared to sales for entities in the sector, overall and for
small entities. Even when all costs are absorbed by the facility, the
costs represent less than 1one percent of sales and thus are not
expected to result in significant hardship for affected firms.

D.  What are the impacts of the rule on small businesses?

1.  Summary of Impacts on Small Businesses

As required by the RFA and Small Business Regulatory Enforcement and
Fairness ACT (SBREFA), EPA assessed the potential impacts of the rule on
small entities (small businesses, governments, and non-profit
organizations).  (See Section VIII.C of this preamble for definitions of
small entities.) 

EPA has determined the selected thresholds maximize the rule coverage
with 81 to 86 percent of U.S.  GHG emissions reported by approximately
10,152 reporters, while keeping reporting burden to a minimum and
excluding small emitters.  Furthermore, many industry stakeholders that
EPA met with expressed support for a 25,000 metric ton CO2e threshold
because it sufficiently captures the majority of GHG emissions in the
U.S., while excluding smaller facilities and sources.  For small
facilities that are covered by the rule, EPA has included simplified
emission estimation methods in the rule where feasible (e.g., stationary
combustion equipment under a certain rating can use a simplified
calculation approach as opposed to more rigorous direct monitoring) to
keep the burden of reporting as low as possible.  We received many
comments related to monitoring and reporting requirements in specific
source categories, and made many changes in response to reduce burden on
reporters.  For information on these issues, refer to the discussion of
each source category in this preamble and the associated comment
response documents.relevant volume of “Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to Public Comments.”  For further
detail on the rationale for excluding small entities through threshold
selection please see the Thresholds TSD (EPA-HQ-OAR-2008-0508-046) and
Section III.C.3 of this preamble.

EPA conducted a screening assessment comparing compliance costs for
affected industry sectors to industry-specific receipts data for
establishments owned by small businesses.  This ratio constitutes a
“sales” test that computes the annualized compliance costs of this
rule as a percentage of sales and determines whether the ratio exceeds
some level (e.g., 1one percent or 3three percent). The cost-to-sales
ratios were constructed at the establishment level (average reporting
program costs per establishment/average establishment receipts) for
several business size ranges.  This allowed EPA to account for receipt
differences between establishments owned by large and small businesses
and differences in small business definitions across affected
industries.  The results of the screening assessment are shown in Table
VII-5 of this preamble.  

Table VII-5. Estimated Cost-To-Sales Ratios by Industry and Enterprise
Sizea 

Industry	NAICS	NAICS Description	SBA Size Standard (effec-tive March 11,
2008)	Average Cost Per Entity ($1,000/entity)	All Enter-

prises	Owned by Enterprises with:







<20 Employ-

eesf	20 to 99 Employ-ees	100 to 499 Employ-

ees	500 to 749 Employ-

ees	750 to 999 Employ-ees	1,000 to 1,499 Employ-ees

Oil and Gas Extraction	211	Oil & gas extraction 	500	$2 	0.0%	0.2%	0.0%
0.0%	0.0%	0.0%	0.0%

SF6 from Electrical Systems	221	Utilities 	b	$5 	0.0%	0.2%	0.0%	0.0%
0.0%	0.0%	0.0%

Pulp & Paper Manufacturing	322	Paper mfg 	500 to 750	$20 	0.1%	1.2%	0.2%
0.1%	0.0%	0.0%	0.0%

Petroleum and Coal Products	324	Petroleum & coal products mfg 	c	$21 
0.0%	0.6%	0.1%	0.1%	0.0%	0.2%	0.0%

Chemical Manufacturing	325	Chemical mfg 	500 to 1,000	$14 	0.0%	0.7%
0.1%	0.0%	0.0%	0.0%	0.0%

Cement & Other Mineral Production	327	Nonmetallic mineral product mfg 
500 to 1,000	$50 	0.8%	4.8%	0.9%	0.5%	0.4%	0.5%	0.4%

Primary Metal Manufacturing	331	Primary metal mfg 	500 to 1,000	$26 
0.1%	2.1%	0.3%	0.1%	0.1%	0.0%	0.0%

Oil & Natural Gas Transportation	486	Pipeline transportation 	d	$4 	0.0%
0.0%	0.2%	0.1%	NA	NA	NA

Waste Management and Remediation Services	562	Waste management &
remediation services 	e	$5 	0.2%	0.7%	0.1%	0.1%	0.0%	0.0%	0.0%

Adipic Acid	325199	All other basic organic chemical mfg 	1,000	$24 	0.0%
0.9%	0.3%	0.1%	NA	0.0%	NA

Ammonia	325311	Nitrogenous fertilizer mfg 	1,000	$17 	0.1%	0.9%	0.5%	NA
NA	NA	NA

Cement	327310	Cement mfg 	750	$63 	0.2%	2.0%	1.5%	0.3%	NA	NA	0.1%

Ferroalloys	331112	Electrometallurgical ferroalloy product mfg 	750	$9 
0.0%	NA	NA	NA	NA	NA	NA

Glass	3272	Glass & glass product mfg 	500 to 1,000	$8 	0.1%	1.4%	0.2%
0.0%	0.0%	0.1%	0.0%

Hydrogen Production	325120	Industrial gas mfg 	1,000	$3 	0.0%	0.6%	0.0%
0.1%	NA	NA	NA

Iron and Steel 	331112	Electrometallurgical ferroalloy product mfg 	750
$30 	0.1%	NA	NA	NA	NA	NA	NA

Lead Production	3314	Nonferrous metal (except aluminum) production &
processing 	750 to 1,000	$10 	0.0%	0.6%	0.1%	0.0%	NA	NA	0.0%

Lime Manufacturing	327410	Lime mfg 	500	$60 	0.4%	16.5%	1.2%	NA	NA	NA	NA

Nitric Acid	325311	Nitrogenous fertilizer mfg 	1,000	$20 	0.1%	1.0%	0.6%
NA	NA	NA	NA

Petrochemical	324110	Petroleum refineries 	c	$27 	0.0%	0.4%	0.0%	0.0%
0.0%	NA	NA

Phosphoric Acid	325312	Phosphatic fertilizer mfg 	500	$60 	0.1%	10.1%	NA
NA	NA	NA	NA

Pulp and Paper	322110	Pulp mills 	750	$20 	0.0%	1.4%	NA	NA	NA	NA	NA

Refineries	324110	Petroleum refineries 	c	$41 	0.0%	0.6%	0.0%	0.0%	0.0%
NA	NA

Silicon Carbide	327910	Abrasive product mfg 	500	$10 	0.1%	0.8%	0.2%
0.1%	NA	NA	NA

Soda Ash Manufacturing	3251	Basic chemical mfg 	500 to 1,000	$16 	0.0%
0.5%	0.1%	0.0%	0.0%	0.0%	0.0%

Titanium Dioxide	325188	All other basic inorganic chemical mfg 	1,000
$10 	0.0%	0.7%	0.4%	0.1%	NA	NA	NA

Zinc Production	3314	Nonferrous metal (except aluminum) production &
processing 	750 to 1,000	$13 	0.1%	0.9%	0.1%	0.0%	NA	NA	0.0%



a The Census Bureau defines an enterprise as a business organization
consisting of one or more domestic establishments that were specified
under common ownership or control.  The enterprise and the establishment
are the same for single-establishment firms.  Each multi-establishment
company forms one enterprise—the enterprise employment and annual
payroll are summed from the associated establishments.  Enterprise size
designations are determined by the summed employment of all associated
establishments.

Since the SBA’s business size definitions (http://www.sba.gov/size)
apply to an establishment’s ultimate parent company, we assume in this
analysis that the enterprise definition above is consistent with the
concept of ultimate parent company that is typically used for SBREFA
screening analyses.

b NAICS codes 221111, 221112, 221113, 221119, 221121, 221122 – A firm
is small if, including its affiliates, it is primarily engaged in the
generation, transmission, and/or distribution of electric energy for
sale and its total electric output for the preceding fiscal year did not
exceed 4four million MW hours.

c 500 to 1,500.  For NAICS code 324110 – For purposes of Government
procurement, the petroleum refiner must be a concern that has no more
than 1,500 employees nor more than 125,000 barrels per calendar day
total Operable Atmospheric Crude Oil Distillation capacity.  Capacity
includes owned or leased facilities as well as facilities under a
processing agreement or an arrangement such as an exchange agreement or
a throughput.  The total product to be delivered under the contract must
be at least 90 percent refined by the successful bidder from either
crude oil or bona fide feedstocks.

d NAICS codes 486110 = 1,500 employees; NAICS 486210=$6.5 million annual
receipts; NAICS 486910 = 1,500 employees; and NAICS 486990 =$11.5
million annual receipts.

e Ranges from $6.5 to $13.0 million annual receipts; Environmental
Remediation services has a 500 employee definition and the following
criteria.  NAICS 562910 – Environmental Remediation Services:

1) For SBA assistance as a small business concern in the industry of
Environmental Remediation Services, other than for Government
procurement, a concern must be engaged primarily in furnishing a range
of services for the remediation of a contaminated environment to an
acceptable condition including, but not limited to, preliminary
assessment, site inspection, testing, remedial investigation,
feasibility studies, remedial design, containment, remedial action,
removal of contaminated materials, storage of contaminated materials and
security and site closeouts.  If one of such activities accounts for 50
percent or more of a concern'sconcern’s total revenues, employees, or
other related factors, the concern'sconcern’s primary industry is that
of the particular industry and not the Environmental Remediation
Services Industry.

2) For purposes of classifying a Government procurement as Environmental
Remediation Services, the general purpose of the procurement must be to
restore a contaminated environment and also the procurement must be
composed of activities in three or more separate industries with
separate NAICS codes or, in some instances (e.g., engineering), smaller
sub-components of NAICS codes with separate, distinct size standards. 
These activities may include, but are not limited to, separate
activities in industries such as: Heavy Construction; Special Trade
Construction; Engineering Services; Architectural Services; Management
Services; Refuse Systems; Sanitary Services, Not Elsewhere Classified;
Local Trucking Without Storage; Testing Laboratories; and Commercial,
Physical and Biological Research.  If any activity in the procurement
can be identified with a separate NAICS code, or component of a code
with a separate distinct size standard, and that industry accounts for
50 percent or more of the value of the entire procurement, then the
proper size standard is the one for that particular industry, and not
the Environmental Remediation Service size standard.

f Given the Agency’s selected thresholds, enterprises with fewer than
20 employees are likely to be excluded from the reporting program.

NA: Not available.  SUSB did not report the data necessary to calculate
this ratio.

EPA was not able to calculate a cost-to-sales ratio for manure
management (NAICS 112) as Statistics of U.S. Businesses ([SUSB]SBA,
2008a) data do not provide establishment information for agricultural
NAICS codes (e.g., NAICS 112 which covers manure management).  EPA
estimates that the total first year reporting costs for the entire
manure management industry to be $0.3 million with an average cost per
ton of CO2e reported of $0.07.

As shown, the cost-to-sales ratios are less than 1 one percent for
establishments owned by small businesses that EPA considers most likely
to be covered by the reporting program (e.g. establishments owned by
businesses with 20 or more employees).

EPA acknowledges that several enterprise categories have ratios that
exceed this threshold (e.g., enterprise with one to 20 employees).  EPA
took a conservative approach with the model entity analysis.  Although
the appropriate SBA size definition should be applied at the parent
company (enterprise) level, data limitations allowed us only to compute
and compare ratios for a model establishment within several enterprise
size ranges.  To assess the likelihood that these small businesses will
be covered by the rule, we performed several case studies for
manufacturing industries where the cost-to-receipt ratio exceeded 1one
percent.  For each industry, we used and applied emission data from a
recent study examining emission thresholds.  This study provides
industry-average CO2 emission rates (e.g., tons per employee) for these
manufacturing industries.   

The case studies showed two industries (cement and lime manufacturing)
where emission rates suggest small businesses of this employment size
could potentially be covered by the rule.  As a result, EPA examined
corporate structures and ultimate parent companies were identified using
industry surveys and the latest private databases such as Dun &
Bradstreet.  The results of this analysis show cost to sales ratios
below 1one percent.

For the other enterprise categories identified with ratios between 1one
percent and 3three percent EPA examined industry specific bottom up
databases and previous industry specific studies to ensure that no
entities with less than 20 employees are captured under the rule.

Although this rule will not have a significant economic impact on a
substantial number of small entities, the Agency nonetheless tried to
reduce the impact of this rule on small entities, including seeking
input from a wide range of private- and public-sector stakeholders. 
When developing the rule, the Agency took special steps to ensure that
the burdens imposed on small entities were minimal.  The Agency
conducted several meetings with industry trade associations to discuss
regulatory options and the corresponding burden on industry, such as
recordkeeping and reporting.  The Agency investigated alternative
thresholds and analyzed the marginal costs associated with requiring
smaller entities with lower emissions to report.  The Agency also
recommended a hybrid method for reporting, which provides flexibility to
entities and helps minimize reporting costs.   

Additional analysis for a model small government also showed that the
annualized reporting program costs were less than 1one percent of
revenue.  These impacts are likely representative of ratios in
industries where data limitations do not allow EPA to compute sales
tests (e.g., general stationary combustion and manure management). 
Potential impacts of the rule on small governments were assessed
separately from impacts on Federal Agencies.  Small governments and
small non-profit organizations may be affected if they own affected
stationary combustion sources, landfills, or natural gas suppliers. 
However, the estimated costs under the rule are estimated to be small
enough that no small government or small non-profit is estimated to
incur significant impacts.  For example, from the 2002 Census (in
$2006), revenues for small governments (counties and municipalities)
with populations fewer than 10,000 are $3 million, and revenues for
local governments with populations less than 50,000 is $7 million.  As
an upper bound estimate, summing typical per-respondent costs of
combustion plus landfills plus natural gas suppliers yields a cost of
approximately $18,000 per local government.  Thus, for the smallest
group of local governments (<10,000 people), cost-to-revenue ratio is
0.7 percent.  For the larger group of governments less than 50,000, the
cost-to-revenue ratio is 0.2 percent.

2.  Summary of Comments and Responses

Comment:  Comments received on small business impacts focused on the
economic burden to small businesses for compliance with mandatory GHG
reporting.  One commenter noted that lowering the reporting threshold
below the proposed 25,000 metric ton CO2e level would disproportionately
affect small businesses. Another commenter stated that small businesses
are not well equipped to handle detailed requirements for reporting and
that the proposed rule would impose a large burden for monitoring,
recordkeeping, and reporting activities.

Additional comments received requested that EPA establish a Small
Business Regulatory Enforcement and Fairness ACT (SBREFA) process to
investigate the impacts that the proposed rule would have on small
businesses.

Response:  As summarized above, EPA investigated alternative thresholds
and analyzed the marginal costs associated with requiring smaller
entities with lower emissions to report.  EPA recognized the additional
burden placed on small entities at lower thresholds, and had retained
the hybrid method for reporting that includes a 25,000 metric ton CO2e
level threshold.  Under this threshold, EPA has assessed the economic
impact of the final rule on small entities and concluded that this
action will not have a significant economic impact on a substantial
number of small entities.

For this reason, EPA did not establish a SBREFA panel process for the
rulemaking. The summary of the factual basis for the certification is
provided in the preamble for the rule.   Complete documentation of the
analysis can be found in the Final Regulatory Impact Analysis (RIA),
Section 5.2 of the RIA for the final rule.

E.  What are the benefits of the rule for society?

1.  Summary of Method Used to Estimate Compliance Costs

EPA examined the potential benefits of the GHG reporting rule.  The
benefits of a reporting system are based on their relevance to policy
making, transparency issues, and market efficiency.  Benefits are very
difficult to quantify and monetize.  Instead of a quantitative analysis
of the benefits, EPA conducted a systematic literature review of
existing studies including government, consulting, and scholarly
reports.  

A mandatory reporting system will benefit the public by increased
transparency of facility emissions data.  Transparent, public data on
emissions allows for accountability of polluters to the public
stakeholders who bear the cost of the pollution.  Citizens, community
groups, and labor unions have made use of data from Pollutant Release
and Transfer Registers to negotiate directly with polluters to lower
emissions, circumventing greater government regulation.  Publicly
available emissions data also will allow individuals to alter their
consumption habits based on the GHG emissions of producers. 

The greatest benefit of mandatory reporting of industry GHG emissions to
government will be realized in developing future GHG policies.  For
example, in the EU’s Emissions Trading System, a lack of accurate
monitoring at the facility level before establishing CO2 allowance
permits resulted in allocation of permits for emissions levels an
average of 15 percent above actual levels in every country except the
United Kingdom. 

Benefits to industry of GHG emissions monitoring include the value of
having independent, verifiable data to present to the public to
demonstrate appropriate environmental stewardship, and a better
understanding of their emission levels and sources to identify
opportunities to reduce emissions.  Such monitoring allows for inclusion
of standardized GHG data into environmental management systems,
providing the necessary information to achieve and disseminate their
environmental achievements.  

Standardization will also be a benefit to industry, once facilities
invest in the institutional knowledge and systems to report emissions,
the cost of monitoring should fall and the accuracy of the accounting
should improve.  A standardized reporting program will also allow for
facilities to benchmark themselves against similar facilities to
understand better their relative standing within their industry. 

2.  Summary of Comments and Responses

Comment:  Comments received on the benefits of the mandatory reporting
program focused on the potential future uses of the collected data. 
Additional comments on the benefits of the program were concerned that
the benefits of the rule are not quantified.

Response:  The data collected under this rule will provide comprehensive
and accurate data to inform future climate change policies.  Potential
future CAA and other climate policies include research and development
initiatives, economic incentives, new or expanded voluntary programs,
adaptation strategies, emission standards, a carbon tax, or a
cap-and-trade program.  Because EPA does not know at this time the
specific policies that may be adopted, the data reported through this
rule should be of sufficient quality to support a range of approaches.

Section VI of the Final Regulatory Impact Analysis (RIA) [DOCKET ##] for
the final rule summarizes the anticipated benefits of the rule, which
include providing the government with sound data on which to base future
policies and providing industry and the public independently verified
information documenting firms’ environmental performance.  While EPA
has not quantified the benefits of the mandatory reporting rule, EPA
believes that they are substantial and outweigh the estimated costs.

VIII.  Statutory and Executive Order Reviews  

A.  Executive Order 12866: Regulatory Planning and Review

Under section 3(f)(1) of EO 12866 (58 FR 51735, October 4, 1993), this
action is an "economically significant regulatory action” because it
is likely to have an annual effect on the economy of $100 million or
more.  Accordingly, EPA submitted this action to the OMB for review
under EO 12866 and any changes made in response to OMB recommendations
have been documented in the docket for this action.

In addition, EPA prepared an analysis of the potential costs and
benefits associated with this action.  A copy of the analysis is
available in Docket No. EPA-HQ-OAR-2008-0508-002, the RIA for the final
rule, and is briefly summarized in Section VII of this preamble. 

B.  Paperwork Reduction Act

The information collection requirements in this rule have been submitted
for approval to the Office of Management and Budget (OMB) under the
Paperwork Reduction Act, 44 U.S.C. 3501 et seq.  The information
collection requirements are not enforceable until OMB approves them. The
ICR document prepared by EPA has been assigned EPA ICR number 2300.0103.

EPA plans to collect complete and accurate economy-wide data on
facility-level GHG emissions. Accurate and timely information on GHG
emissions is essential for informing future climate change policy
decisions.  Through data collected under this rule, EPA will gain a
better understanding of the relative emissions of specific industries,
and the distribution of emissions from individual facilities within
those industries.  The facility-specific data will also improve our
understanding of the factors that influence GHG emission rates and
actions that facilities are already taking to reduce emissions. 
Additionally, EPA will be able to track the trend of emissions from
industries and facilities within industries over time, particularly in
response to policies and potential regulations.  The data collected by
this rule will improve EPA’s ability to formulate climate change
policy options and to assess which industries would be affected, and how
these industries would be affected by the options.  

This information collection is mandatory and will be carried out under
CAA sections 114 and 208.  Information identified and marked as CBI will
not be disclosed except in accordance with procedures set forth in 40
CFR part 2.  However, emissions data collected under CAA sections 114
and 208 cannot generally be claimed as CBI and will be made public.

The projected cost and hour burden for non-federalFederal respondents is
$86.3 million and 1.21 million hours per year.  The estimated average
burden per response is 2two hours; the frequency of response is annual
for all respondents that must comply with the rule’s reporting
requirements, except for electricity generating units that are already
required to report quarterly under 40 CFR part 75 (EPA Acid Rain
Program); and the estimated average number of likely respondents per
year is 16,725.  The cost burden to respondents resulting from the
collection of information includes the total capital cost annualized
over the equipment’s expected useful life (averaging $9.1 million), a
total operation and maintenance component (averaging $11.0 million per
year), and a labor cost component (averaging $66.1 million per year). 
Burden is defined at 5 CFR 1320.3(b).  These cost numbers differ from
those shown elsewhere in the RIA for the final rule because the ICR
costs represent the average cost over the first three years of the rule,
but costs are reported elsewhere in the RIA for the final rule for the
first year of the rule and for subsequent years of the rule.  In
addition, the ICR focuses on respondent burden, while the RIA for the
final rule includes EPA Agency costs.

An agency may not conduct or sponsor, and a person is not required to
respond to, a collection of information unless it displays a currently
valid OMB control number.  The OMB control numbers for EPA’s
regulations in 40 CFR are listed in 40 CFR part 9.  When this ICR is
approved by OMB, the Agency will publish a technical amendment to 40 CFR
part 9 in the Federal Register to display the OMB control number for the
approved information collection requirements contained in this final
rule. 

C.  Regulatory Flexibility Act (RFA)

The RFA generally requires an agency to prepare a regulatory flexibility
analysis of any rule subject to notice and comment rulemaking
requirements under the Administrative Procedure Act or any other statute
unless the agency certifies that the rule will not have a significant
economic impact on a substantial number of small entities.  Small
entities include small businesses, small organizations, and small
governmental jurisdictions.

For purposes of assessing the impacts of today’s rule on small
entities, small entity is defined as: (1) a small business as defined by
the Small Business Administration’s regulations at 13 CFR 121.201; (2)
a small governmental jurisdiction that is a government of a city,
county, town, school district or special district with a population of
less than 50,000; and (3) a small organization that is any
not-for-profit enterprise which is independently owned and operated and
is not dominant in its field.

After considering the economic impacts of today’s final rule on small
entities, I therefore certify that this proposed/final rule will not
have a significant economic impact on a substantial number of small
entities.  However, EPA recognizes that some small entities continue to
be concerned about the potential impacts of the statutory imposition of
PSD requirements that may occur given the various EPA rulemakings
currently under consideration concerning greenhouse gas emissions.  As
explained in the preamble for the proposed PSD phase-in rule [cite FR
for phase-in rule, if possible], EPA is using the discretion afforded to
it under section 609(c) of the RFA to [placeholder for description of
small entity outreach].

The small entities directly regulated by this final rule include small
businesses across all sectors encompassed by the rule, small
governmental jurisdictions and small non-profits.  We have determined
that some small businesses will be affected because their production
processes emit GHGs that must be reported, because they have stationary
combustion units on site that emit GHGs that must be reported, or
because they have fuel supplier operations for which supply quantities
and GHG data must be reported.  Small governments and small non-profits
are generally affected because they have regulated landfills or
stationary combustion units on site, or because they own an LDC.

For affected small entities, EPA conducted a screening assessment
comparing compliance costs for affected industry sectors to
industry-specific data on revenues for small businesses.  This ratio
constitutes a “sales” test that computes the annualized compliance
costs of this final rule as a percentage of sales and determines whether
the ratio exceeds some level (e.g., 1one percent or 3 three percent). 
The cost-to-sales ratios were constructed at the establishment level
(average compliance cost for the establishment/ average establishment
revenues).  As shown in Table VII-5 of this preamble, the cost-to-sales
ratios are less than 1one percent for establishments owned by small
businesses that EPA considers most likely to be covered by the reporting
program, those with more than 20 employees. For the few sectors where
the preliminary screening showed a cost-to-sales ratio exceeding 1one
percent, EPA’s examination of firm-specific sales information showed
that no affected entity was likely to incur costs exceeding 1one percent
of sales.

The screening analysis thus indicates that the final rule will not have
a significant economic impact on a substantial number of small entities.
 See Table VII-5 of this preamble for sector-specific results.  The
screening assessment for small governments compared the sum of average
costs of compliance for combustion, local distribution companies, and
landfills to average revenues for small governments.  Even for a small
government owning all three source types, the costs constitute less than
1one percent of average revenues for the smallest category of
governments (those with fewer than 10,000 people).

Although this final rule will not have a significant economic impact on
a substantial number of small entities, EPA nonetheless took several
steps to reduce the impact of this rule on small entities.  For example,
EPA determined appropriate thresholds that reduce the number of small
businesses reporting.  In addition, EPA is not requiring facilities to
install CEMS if they do not already have them.  Facilities without CEMS
can calculate emissions using readily available data or data that are
less expensive to collect such as process data or material consumption
data.  For some source categories, EPA developed tiered methods that are
simpler and less burdensome.  Also, EPA is requiring annual instead of
more frequent reporting.

Through comprehensive outreach activities prior to proposal of the rule,
EPA held approximately 100 meetings and/or conference calls with
representatives of the primary audience groups, including numerous trade
associations and industries that include small business members. 
EPA’s outreach activities prior to proposal of the rule are documented
in the memorandum, “Summary of EPA Outreach Activities for Developing
the Greenhouse Gas Reporting Rule,” located in Docket No.
EPA-HQ-OAR-2008-0508-055.  After proposal, EPA posted a guide for small
businesses on the EPAEPA’s GHG reporting rule Web site, along with a
general fact sheet for the rule, information sheets for every source
category, and an FAQ document.  EPA also operated a hotline to answer
questions about the proposed rule.  We continued to meet with
stakeholders and entered documentation of all meetings into the docket. 
We considered public comments, including comments from small businesses
and organizations that include small business members, in developing the
final rule.  

During rule implementation, EPA will maintain an “open door” policy
for stakeholders to ask questions about the rule or provide suggestions
to EPA about the types of compliance assistance that would be useful to
small businesses.  EPA intends to develop a range of compliance
assistance tools and materials and conduct extensive outreach for the
final rule.  

D.  Unfunded Mandates Reform Act (UMRA)

Title II of the UMRAUnfunded Mandates Reform Act of 1995 (UMRA), 2
U.S.C. 1531-1538, requires Federal agencies, unless otherwise prohibited
by law, to assess the effects of their regulatory actions on State,
local, and Tribal governments and the private sector.

EPA has developed this regulation under authority of CAA sections 114
and 208.  The required activities under this Federal mandate include
monitoring, recordkeeping, and reporting of GHG emissions from multiple
source categories (e.g., combustion, process, and biologic).  This rule
contains a Federal mandate that may result in expenditures of $100
million for the private sector in any one year.  As described below, we
have determined that the expenditures for State, local, and Tribal
governments, in the aggregate, will be approximately $12.1 million per
year, based on average costs over the first three years of the rule,
including approximately $2 million during the first year of the rule for
governments to make a reporting determination and subsequently determine
that their emissions are below the threshold and thus, they are not
required to report their emissions.  Accordingly, EPA has prepared under
section 202 of the UMRA a written statement which is summarized below. 

Consistent with the intergovernmental consultation provisions of section
204 of the UMRA, EPA initiated an outreach effort with the governmental
entities affected by this rule including State, local, and Tribal
officials.  EPA maintained an “open door” policy for stakeholders to
provide input on key issues and to help inform EPA’s understanding of
issues, including impacts to State, local and Tribal governments.  The
outreach audience included State environmental protection agencies,
regional and Tribal organizations, and other State and local government
organizations.  EPA contacted several States and State and regional
organizations already involved in GHG emissions reporting.  EPA also
conducted several conference calls with Tribal organizations during the
proposal phase.  For example, EPA staff provided information to tribes
through conference calls with multiple Tribal working groups and
organizations at EPA and through individual calls with two Tribal board
members of TRI.  In addition, EPA held meetings and conference calls
with groups such as TRI, National Association of Clean Air Agencies
(NACAA), ECOS, and with State members of RGGI, the Midwestern GHG
Reduction Accord, and WCI.  See the “Summary of EPA Outreach
Activities for Developing the Greenhouse Gas Reporting Rule,” in
Docket No. EPA-HQ-OAR-2008-0508-055 for a complete list of organizations
and groups that EPA contacted. 

At proposal of the rule, EPA posted a guide for State and local agencies
on the Web site, along with other information sheets, to communicate key
aspects of the proposed rule to these agencies.  Several State and local
agencies and three tribal Tribal organizations or communities submitted
written public comments, and EPA carefully considered these comments in
developing the final rule.  EPA also continued to meet with government
agencies or organizations with State members such as California ARB,
Connecticut DEP, New Jersey DEP, New Mexico ED, Washington DE,
Massachusetts DEP, Illinois EPA, Iowa DNR, and TCR  These meetings are
documented in the docket.  EPA intends to continue to work closely with
State, local, and Tribal agencies during rule implementation.

Consistent with section 205 of the UMRA, EPA has identified and
considered a reasonable number of regulatory alternatives.  EPA
carefully examined regulatory alternatives, and selected the lowest
cost/least burdensome alternative that EPA deems adequate to address
Congressional concerns and to provide a consistent, comprehensive source
of information about emissions of GHGs.  EPA has considered the costs
and benefits of the GHG reporting rule, and has concluded that the costs
will fall mainly on the private sector (approximately $77 million), with
some costs incurred by State, local, and Tribal governments that must
report their emissions (less than $10.1 million) that own and operate
stationary combustion units, landfills, or natural gas local
distribution companies (LDCs).  EPA estimates that an additional 2,034
facilities owned by stateState, local, or Tribal governments will incur
approximately $2.0 million in costs during the first year of the rule to
make a reporting determination and subsequently determine that their
emissions are below the threshold and thus, they are not required to
report their emissions.  Furthermore, we think it is unlikely that
State, local, and Tribal governments would begin operating large
industrial facilities, similar to those affected by this rulemaking
operated by the private sector. 

Initially, EPA estimates that costs of complying with the final rule
will be widely dispersed throughout many sectors of the economy. 
Although EPA acknowledges that over time changes in the patterns of
economic activity may mean that GHG generation and thus reporting costs
will change, data are inadequate for projecting these changes.  Thus,
EPA assumes that costs averaged over the first three years of the
program are typical of ongoing costs of compliance.  EPA estimates that
future compliance costs will total approximately $104 million per year. 
EPA examined the distribution of these costs between private owners and
State, local, and Tribal governments owning GHG emitters.  In addition,
EPA examined, within the private sector, the impacts on various
industries.  In general, estimated cost per entity represents less than
0.1 percent of company sales in affected industries.  These costs are
broadly distributed to a variety of economic sectors and represent
approximately 0.001 percent of 2008 Gross Domestic Product; overall, EPA
does not believe the final rule will have a significant macroeconomic
impact on the national economy.  Therefore, this rule is not subject to
the requirements of section 203 of UMRA because it contains no
regulatory requirements that might significantly or uniquely affect
small governments.

EPA does not anticipate that substantial numbers of either public or
private sector entities will incur significant economic impacts as a
result of this final rule.  EPA further expects that benefits of the
final rule will include more and better information for EPA and the
private sector about emissions of GHGs.  This improved information will
enhance EPA’s ability to develop sound future climate policies, and
may encourage GHG emitters to develop voluntary plans to reduce their
emissions. 

This regulation applies directly to facilities that supply fuel or
chemicals that when used emit greenhouse gases, to motor vehicle
manufacturers, and to facilities that directly emit greenhouses gases. 
It does not apply to governmental entities unless the government entity
owns a facility that directly emits greenhouse gasesGHGs above threshold
levels such as a landfill or large stationary combustion source, or LDC.
 In addition, this rule does not impose any implementation
responsibilities on State, local, or Tribal governments and it is not
expected to increase the cost of existing regulatory programs managed by
those governments.  Thus, the impact on governments affected by the rule
is expected to be minimal.

E.  Executive Order 13132: Federalism

EO 13132, entitled “Federalism” (64 FR 43255, August 10, 1999),
requires EPA to develop an accountable process to ensure “meaningful
and timely input by State and local officials in the development of
regulatory policies that have Federalism implications.” “Policies
that have Federalism implications” is defined in the EO to include
regulations that have “substantial direct effects on the States, on
the relationship between the national government and the States, or on
the distribution of power and responsibilities among the various levels
of government.”

This final rule does not have Federalism implications.  It will not have
substantial direct effects on the States, on the relationship between
the national government and the States, or on the distribution of power
and responsibilities among the various levels of government, as
specified in EO 13132.  However, for a more detailed discussion about
how this final rule relates to existing State programs, please see
Section II of the proposal preamble (74 FR 16457 to 16461, April 10,
2009) and Sections I.E. and II.C.2 of this preamble.  

This regulation applies directly to facilities that supply fuel or
chemicals that when used emit greenhouse gases, motor vehicle
manufacturers, or facilities that directly emit greenhouses gases.  It
does not apply to governmental entities unless the government entity
owns a facility that directly emits greenhouse gasesGHGs above threshold
levels such as a landfill, large stationary combustion source, or LDC,
so relatively few government facilities would be affected.  This
regulation also does not limit the power of States or localities to
collect GHG data and/or regulate GHG emissions.  Thus, EO 13132 does not
apply to this rule.  

In the spirit of Executive Order 13132, and consistent with EPA policy
to promote communications between EPA and State and local governments,
EPA specifically solicited comments on the proposed rule from State and
local officials. See Section VIII.D above, for discussion of outreach
activities to State, local, or Tribal organizations.

F.  Executive Order 13175: Consultation and Coordination with Indian
Tribal Governments

This final rule does not have Tribal implications, as specified in EO
13175 (65 FR 67249, November 9, 2000).  This regulation applies directly
to facilities that supply fuel or chemicals that when used emit
greenhouse gasesGHGs or facilities that directly emit greenhouses gases.
 Facilities expected to be affected by the final rule are not expected
to be owned by Tribal governments.  Thus, Executive Order 13175 does not
apply to this final rule.  

Although EO 13175 does not apply to this final rule, EPA sought
opportunities to provide information to Tribal governments and
representatives during development of the rule.  In consultation with
EPA’s American Indian Environment Office, EPA’s outreach plan
included tribes.  EPA conducted several conference calls with Tribal
organizations during the proposal phase.  For example, EPA staff
provided information to tribes through conference calls with multiple
Indian working groups and organizations at EPA that interact with tribes
and through individual calls with two Tribal board members of TCR.  In
addition, EPA prepared a short article on the GHG reporting rule that
appeared on the front page a Tribal newsletter—Tribal Air News—that
was distributed to EPA/OAQPS’s network of Tribal organizations.  EPA
gave a presentation on various climate efforts, including the mandatory
reporting rule, at the National Tribal Conference on Environmental
Management on June 24-26, 2008.  In addition, EPA had copies of a short
information sheet distributed at a meeting of the National Tribal
Caucus.  See the “Summary of EPA Outreach Activities for Developing
the GHG reporting rule,” in Docket No. EPA-HQ-OAR-2008-0508-055 for a
complete list of Tribal contacts.  EPA participated in a conference call
with tribal Tribal air coordinators in April 2009 and prepared a
guidance sheet for Tribal governments on the proposed rule.  It was
posted on the MRR webWeb site and published in the Tribal Air Newsletter

G.  Executive Order 13045: Protection of Children from Environmental
Health Risks and Safety Risks

EPA interprets EO 13045 (62 F.R. 19885, April 23, 1997) as applying only
to those regulatory actions that concern health or safety risks, such
that the analysis required under section 5-501 of the EO has the
potential to influence the regulation.  This action is not subject to EO
13045 because it does not establish an environmental standard intended
to mitigate health or safety risks.

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

This final rule is not a “significant energy action” as defined in
EO 13211 (66 FR 28355, May 22, 2001) because it is not likely to have a
significant adverse effect on the supply, distribution, or use of
energy.  Further, we have concluded that this rule is not likely to have
any adverse energy effects.  This final rule relates to monitoring,
reporting and recordkeeping at facilities that supply fuel or chemicals
that when used emit greenhouse gasesGHGs or facilities that directly
emit greenhouses gases and does not impact energy supply, distribution
or use.  Therefore, we conclude that this rule is not likely to have any
adverse effects on energy supply, distribution, or use.

I.  National Technology Transfer and Advancement Act

Section 12(d) of the National Technology Transfer and Advancement Act of
1995 (NTTAA), Public Law No. 104-113 (15 U.S.C. 272 note) directs EPA to
use voluntary consensus standards in its regulatory activities unless to
do so would be inconsistent with applicable law or otherwise
impractical.  Voluntary consensus standards are technical standards
(e.g., materials specifications, test methods, sampling procedures, and
business practices) that are developed or adopted by voluntary consensus
standards bodies.  NTTAA directs EPA to provide Congress, through OMB,
explanations when the Agency decides not to use available and applicable
voluntary consensus standards. 

This rulemaking involves technical standards.  EPA will use more than
4060 voluntary consensus standards from at least seven10 different
voluntary consensus standards bodies, including the following:  ASTM,
ASME, ISO, Gas Processors Association, American Gas Association, and
National Lime Association.  These voluntary consensus standards will
help facilities monitor, report, and keep records of greenhouse gasGHG
emissions.  No new test methods were developed for this rule.  Instead,
from existing rules for source categories and voluntary greenhouse
gasGHG programs, EPA identified existing means of monitoring, reporting,
and keeping records of greenhouse gasGHG emissions.  The existing
methods (voluntary consensus standards) include a broad range of
measurement techniques, including many for combustion sources such as
methods to analyze fuel and measure its heating value; methods to
measure gas or liquid flow; and methods to gauge and measure petroleum
and petroleum products.  The test methods are incorporated by reference
into the final rule and are available as specified in 40 CFR 98.7.

By incorporating voluntary consensus standards into this final rule, EPA
is both meeting the requirements of the NTTAA and presenting multiple
options and flexibility for measuring greenhouse gasGHG emissions.

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

EO 12898 (59 FR 7629, February 16, 1994) establishes Federal executive
policy on environmental justice.  Its main provision directs Federal
agencies, to the greatest extent practicable and permitted by law, to
make environmental justice part of their mission by identifying and
addressing, as appropriate, disproportionately high and adverse human
health or environmental effects of their programs, policies, and
activities on minority populations and low-income populations in the
U.S.  

EPA has determined that this final rule will not have disproportionately
high and adverse human health or environmental effects on minority or
low-income populations because it does not affect the level of
protection provided to human health or the environment.  This final rule
does not affect the level of protection provided to human health or the
environment because it is a rule addressing information collection and
reporting procedures. 

K.  Congressional Review Act

The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the
Small Business Regulatory Enforcement Fairness Act of 1996, generally
provides that before a rule may take effect, the agency promulgating the
rule must submit a rule report, which includes a copy of the rule, to
each House of the Congress and to the Comptroller General of the United
States.  EPA will submit a report containing this rule and other
required information to the U.S. Senate, the U.S. House of
Representatives, and the Comptroller General of the United States.S.
prior to publication of the rule in the Federal Register.  A major rule
cannot take effect until 60 days after it is published in the Federal
Register.  This action is a “major rule” as defined by 5 U.S.C.
804(2).  This rule will be effective [INSERT THE DATE 60 DAYS AFTER
PUBLICATION IN THE FEDERAL REGISTER].

List of Subjects 

40 CFR Part 86

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

40 CFR Part 87

Environmental protection, Air pollution control, Aircraft, Incorporation
by reference.

40 CFR Part 89

Environmental protection, Administrative practice and procedure,
Confidential business information, Imports, Labeling, Motor vehicle
pollution, Reporting and recordkeeping requirements, Research, Vessels,
Warranty.

40 CFR Part 90

Environmental protection, Administrative practice and procedure,
Confidential business information, Imports, Labeling, Reporting and
recordkeeping requirements, Research, Warranty.

40 CFR Part 94

Environmental protection, Administrative practice and procedure, Air
pollution control, Confidential business information, Imports,
Incorporation by reference, Labeling, Penalties, Vessels, Reporting and
recordkeeping requirements, Warranties.

40 CFR Part 98

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

40 CFR Part 600

Administrative practice and procedure, Electric power, Fuel economy,
Incorporation by reference, Labeling, Reporting and recordkeeping
requirements.

40 CFR Part 1033

Environmental protection, Administrative practice and procedure,
Confidential business information, Incorporation by reference, Labeling,
Penalties, Railroads, Reporting and recordkeeping requirements.

40 CFR Part 1039

Environmental protection, Administrative practice and procedure, Air
pollution control, Confidential business information, Imports,
Incorporation by reference, Labeling, Penalties, Reporting and
recordkeeping requirements, Warranties.

40 CFR Part 1042

Environmental protection, Administrative practice and procedure, Air
pollution control, Confidential business information, Imports,
Incorporation by reference, Labeling, Penalties, Vessels, Reporting and
recordkeeping requirements, Warranties.

40 CFR Parts 1045, 1048, 1051, and 1054

Environmental protection, Administrative practice and procedure, Air
pollution control, Confidential business information, Imports,
Incorporation by reference, Labeling, Penalties, Reporting and
recordkeeping requirements, Warranties.

40 CFR Part 1065

Environmental protection, Administrative practice and procedure,
Incorporation by reference, Reporting and recordkeeping requirements,
Research.

Date:				

					

Lisa P. Jackson, 

Administrator.

 Consolidated Appropriations Act, 2008, Public Law 110–161, 121 Stat.
1844, 2128.  Congress reaffirmed interest in a GHG reporting rule, and
provided additional funding, in the 2009 Appropriations Act (insert
reference).Consolidated Appropriations Act, 2009, Public Law 110–329,
122 Stat. 3574-3716).

 ADD CITITATION TO FY 09 APPROP ACT ALSO

   Although there are exclusions in CAA section 114(a)(1) regarding
certain title II requirements applicable to manufacturers of new motor
vehicle and motor vehicle engines, CAA section 208 authorizes the
gathering of information related to those areas.  

 Under the 1605(b) program an “entity” is defined as “the whole or
part of any business, institution, organization or household that is
recognized as an entity under any U.S. Federal, State or local law that
applies to it; is located, at least in part, in the U.S.; and whose
operations affect U.S. greenhouse gas emissions.”
(http://www.pi.energy.gov/enhancingGHGregistry/)

  For the purposes of this rule, facility means any physical property,
plant, building, structure, source, or stationary equipment located on
one or more contiguous or adjacent properties in actual physical contact
or separated solely by a public roadway or other public right-of-way and
under common ownership or common control, that emits or may emit any
greenhouse gas. Operators of military installations may classify such
installations as more than a single facility based on distinct and
independent functional groupings within contiguous military properties.

  Unless otherwise noted, years and dates in this notice refer to
calendar years and dates.

 This does not include portable equipment, emergency generators, or
emergency equipment as defined in the rule. 

  Supplied means produced, imported, or exported.

  Unless otherwise noted, years and dates in this notice refer to
calendar years and dates.

  Suppliers include producers, importers, and exporters of fuels and
industrial gases.  The level of reporting for suppliers is specified in
the rule.  Most report at the facility level.  Imports and exports are
reported at the corporate level.

  “Use” for purposes of industrial GHGs presumes that there will be
100 percent release of the GHG.

  Although CBI determinations are usually made on a case-by-case basis,
EPA has discussed in an earlier Federal Register notice what constitutes
emissions data that cannot be considered withheld as CBI (956 FR 7042
– 7043, February 21, 1991).  In addition, as discussed in Section II.R
of this preamble, EPA will be initiating a separate notice and comment
process to make CBI and emissions data determinations for the categories
of data collected under this rulemaking.

  For more information about the reporting format please see Section V
of this preamble.

  See the following sections of this preamble for discussion of source
categories not included in today’s final rule:  sections III.I
(electronics manufacturing), III.J (ethanol production), III.L
(fluorinated GHG production), III.M (food processing), III.T (magnesium
production), III.W (oil and natural gas systems), III.DD (SF6 from
electrical equipment), III.FF (underground coal mines), III.HH
(industrial landfills are not included in today’s rule, but MSW
landfills are covered by the rule), III.II (wastewater treatment), and
III.KK (suppliers of coal).

  2006 IPCC Guidelines for National Greenhouse Gas Inventories.  The
National Greenhouse Gas Inventories Programme, H.S. Eggleston, L.
Buendia, K. Miwa, T. Ngara, and K. Tanabe (eds), hereafter referred to
as the “2006 IPCC Guidelines” are found at:    HYPERLINK
"http://www.ipcc.ch/ipccreports/methodology-reports.htm" 
http://www.ipcc.ch/ipccreports/methodology-reports.htm .  For additional
information on these gases please see Table A-1 in proposed 40 CFR part
98, subpart A and the Suppliers of Industrial GHGs TSD
(EPA-HQ-OAR-2008-0508-041)

  For the discussion of the CAA authority to collect these data, see
Section II.Q of this preamble.  Also see the relevant source category
sections within Section III of this preamble.

 As explained in section II.A of this preamble, facilities that only
have stationary combustion units as their only source of emissions and
have units with an aggregate maximum heat input of less than 30 mmbtu
are not included in this rule.

 Although the thresholds were expressed in different ways (e.g.,
“all-in”, annual emissions) most corresponded to, or were consistent
with, an annual facility-wide emission level of 25,000 metric tons of
CO2e.

 Applicability thresholds for different source categories are expressed
in different ways (e.g., actual emissions, production capacity,
“all-in”), but most correspond to a facility-wide emission level of
25,000 metric tons per year.  The provision to cease reporting applies
to reporters regardless of the specific applicability threshold that
triggered reporting for their facility or supply operation.

 As explained in section II.E of this preamble, applicability thresholds
for different source categories are expressed in different ways (e.g.,
actual emissions, production capacity, “all-in”), but most
correspond to a facility-wide emission level of 25,000 metric tons per
year.  The provision to cease reporting applies to reporters regardless
of the specific applicability threshold that triggered reporting for
their facility or supply operation.

 For additional information about these programs please see overview of
existing programs ( EPA–HQ–OAR–2008–0508–0052) and the de
minimis memo (EPA–HQ–OAR–2008–0508–0048).

 As described earlier in this section, facilities or suppliers that have
emissions or products with emission less than 25,000 mtmetric tons CO2e
for five years in a row may cease reporting.  Those that cease reporting
must have records to cover those five years of emissions.  Similarly,
reporters who demonstrate emissions less than 15,000 metric CO2e for
three years is a row may cease reporting, and must have records to cover
those three years of emissions.

 We note that the statute is ambiguous, and thus EPA may adopt any
reasonable interpretation.  CHEVRON

 We note that the statute is ambiguous, and thus EPA may adopt any

reasonable interpretation.  See Chevron v. NRDC et al., 467

U.S. 837, 864 (1984).

 Biogenic CO2 from the conversion of CaCO3 to CaO in kraft or soda pulp
mill lime kilns is accounted for in the biogenic CO2 emission factor for
the recovery furnace.

 Dooley, JJ, CL Davidson, RT Dahowski, MA Wise, N Gupta, SH Kim, EL
Malone, "Carbon Dioxide Capture and Geologic Storage: A Key Component of
a Global Energy Technology Strategy to Address Climate Change."  Joint
Global Change Research Institute, Battelle Pacific Northwest Division.
May 2006.  PNWD-3602.  College Park, MD.

 Manufacturers of light-duty vehicles, light-duty trucks, and
medium-duty passenger vehicles are not covered in this final rule.

 The term “manufacturer,” as well as the term “manufacturing
company,” as used in this preamble, means companies that are subject
to EPA emission certification requirements.  This primarily includes
companies that manufacture engines domestically and foreign
manufacturers that import engines into the U.S. market.  In some cases
this also includes domestic companies that are required to meet EPA
certification requirements when they import foreign-manufactured
engines.

 For aircraft engine manufacturers, reporting requirements will apply
for the engine models in production in 2011.

 Small business manufacturers will continue to measurebe subject to
measurement and/or report any data that is currently requiredreporting
requirements for compliance with existing regulations.

 But see Ford Motor Co. v. EPA, 604 F. 2d 685 (D.C. Cir. 1979)
(permissible for EPA to regulate CH4 under CAA section 202 (b)).  In
addition, although CH4 is not itself regulated, manufacturers subject to
“non-methane hydrocarbon” standards have needed to determine CH4
emission levels, in some cases by using a default value and in many
cases by way of testing.

 Aerodyne, Rich Miake-Lye, AAFEX Methane presentation at the Seventh
Meeting of Primary Contributors  for the Aviation Emissions
Characterization Roadmap, June 9-10, 2009.

IPCC, Aviation and the Global Atmosphere, 1999, at   HYPERLINK
"http://www.grida.no/climate/ipcc/aviation/index.htm" 
http://www.grida.no/climate/ipcc/aviation/index.htm , and NOAA, Written
Testimony of Dr. David W. Fahey, Hearing on “Aviation and the
Environment: Emissions,” Before the Committee on Transportation and
Infrastructure, Subcommittee on Aviation, U.S. House of Representatives,
May 6, 2008.

 Modes of the landing and takeoff cycle are taxi/idle, takeoff, climb
out, and approach.

 The Federal Civil Penalties Inflation Adjustment Act of 1990, Public
Law 101-410, 104 Stat. 890, 28 U.S.C. 2461, note, as amended by Section
31001(s)(1) of the Debt Collection Improvement Act of 1996, Public Law
104-134, 110 Stat. 1321-373, April 26, 1996, requires EPA and other
agencies to adjust the ordinary maximum penalty that it will apply when
assessing a civil penalty for a violation.  Accordingly, EPA has
adjusted the CAA's provision in Section 113(b) and (d) specifying
$25,000 per day of violation for civil violations to $37,500 per day of
violation.

 EPA’s RFA guidance for rule writers suggests the “sales” test
continues to be the preferred quantitative metric for economic impact
screening analysis.

 Nicholas Institute for Environmental Policy Solutions, Duke University.
 2008.  Size Thresholds for Greenhouse Gas Regulation: Who Would be
Affected by a 10,000-ton CO2 Emissions Rule?  Available at:
http://www.nicholas.duke.edu/institute/10Kton.pdf

  Although CBI determinations are usually made on a case-by-case basis,
EPA has issued guidance in an earlier Federal Register notice on what
constitutes emissions data that cannot be considered CBI (956 FR 7042
– 7043, February 21, 1991).  As discussed in Section II.R of this
preamble, EPA will be initiating a separate notice and comment process
to make CBI determinations for the data collected under this rulemaking.

 EPA estimates that 30,000 facilities are potentially affected by the
rule. Of these, EPA estimates that 10,152 facilities across various
sectors will be over their sector-specific reporting threshold and thus
required to report; the remaining 19,848 will determine during the first
year that they are beneath the threshold and do not need to report. The
average number of respondents is thus (30,000+10,152+10,152)/3 = 16,768;
excluding 43 Federal facilities, the number of private respondents is
16,725.

 U.S. Small Business Administration (SBA). 2008. Firm Size Data from the
Statistics of U.S. Businesses: U.S. Detail Employment Sizes: 2002. 

<  HYPERLINK "http://www.census.gov/csd/susb/download_susb02.htm_" 
http://www.census.gov/csd/susb/download_susb02.htm >.

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Mandatory Reporting of Greenhouse Gases

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