## Friday,

October 30, 2009



# Part II



# Environmental Protection Agency

40 CFR Parts 86, 87, 89 et al.
Mandatory Reporting of Greenhouse Gases; Final Rule


### 56260 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

**ENVIRONMENTAL PROTECTION**
**AGENCY**

**40 CFR Parts 86, 87, 89, 90, 94, 98, 1033, 1039, 1042, 1045, 1048, 1051,**  **1054, 1065**

**[EPA–HQ–OAR–2008–0508; FRL–8963–5]**

**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 andmanufacturers of heavy-duty and offroad 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 December 29, 2009. The incorporation by reference of certain publications listed in the rule is approved by the Director of the Federal Register as of December 29, 2009.

**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 Web 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 EPA’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 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 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: 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—E XAMPLES OF 

### A FFECTED 

### E NTITIES BY 

### C ATEGORY

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, blastfurnaces, 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 manufacturin g 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.


### 56261 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

TABLE 

### 1—E XAMPLES OF 

### A FFECTED 

### E NTITIES BY 

### C ATEGORY

### —Continued

Category NAICS Examples of affected 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 (CO 2 ) .......... 325120 Industrial gas manufacturing facilities. Mobile Sources ......................................... 333618 Heavy-duty, non-road, aircraft, locomotive, and marine diesel eng ine 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 tomanufacturers of heavy-duty and offroad 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—S OURCE 

### C ATEGORIES AND 

### R ELEVANT 

### S UBPARTS

Source category (and main applicable subpart) Other subparts recommended for review to determine applicability

General Stationary Fuel Combustion Sources. Electricity Generation ............................................................................... General Stationary Fuel Co mbustion, Suppliers of CO 2

. Adipic Acid Production ............................................................................. General Stationary Fuel Comb ustion. Aluminum Production ............................................................................... General Stationary Fuel Combu stion. Ammonia Manufacturing ........................................................................... General Stationary Fuel Combust ion, Hydrogen, Nitric Acid, Petroleum Refineries, Suppliers of CO 2

. Cement Production ................................................................................... General Stationary Fuel Com bustion, Suppliers of CO 2

. Ferroalloy Production ............................................................................... General Stationary Fuel Com bustion. Glass Production ...................................................................................... General Stationary Fuel C ombustion. HCFC–22 Production and HFC–23 Destruction ...................................... General Stationary Fuel Combustion. Hydrogen Production ................................................................................ General Stationary Fuel Comb ustion, Petrochemicals, Petroleum Refineries, Suppliers of Industrial GHGs, Suppliers of CO 2

. Iron and Steel Production ......................................................................... General Stationary Fuel Combu stion, Suppliers of CO 2

.


### 56262 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

TABLE 

### 2—S OURCE 

### C ATEGORIES AND 

### R ELEVANT 

### S UBPARTS

### —Continued

Source category (and main applicable subpart) Other subparts recommended for review to determine applicability

Lead Production ....................................................................................... General Stationary Fuel C ombustion. Lime Manufacturing .................................................................................. General Stationary Fuel Com bustion. Nitric Acid Production ............................................................................... General Stationary Fuel Co mbustion, Adipic Acid. Petrochemical Production ......................................................................... General Stationary Fuel Combustion, Ammonia, Petroleum Refineries. Petroleum Refineries ................................................................................ General Stationary Fuel Com bustion, Hydrogen, Suppliers of Petroleum Products. Phosphoric Acid Production ..................................................................... General Stationary Fuel Combusti on. Pulp and Paper Manufacturing ................................................................. General Stationary Fuel Combustion

. Silicon Carbide Production ....................................................................... General Stationary Fuel Combustion. Soda Ash Manufacturing .......................................................................... General Stationary Fuel Combust ion. Titanium Dioxide Production .................................................................... General Stationary Fuel Combusti on. Zinc Production ......................................................................................... General Stationary Fuel Combustion. Municipal Solid Waste Landfills ................................................................ General Stationary Fuel Combusti on. Manure Management ............................................................................... General Stationary Fuel Combust ion. 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, Su ppliers of CO 2

. Suppliers of Industrial GHGs .................................................................... General Stationary Fuel Combust ion, Hydrogen Production, Suppliers
of CO 2

. Suppliers of Carbon Dioxide (CO 2 ) .......................................................... 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 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 December 29, 2009. Under CAA section 307(d)(7)(B), only an objection to this final rule that was raised with reasonable specificity during the period for public comment can be raised during judicial review. 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), 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.

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 CCS carbon capture and sequestration CEMS continuous emission monitoring

system(s)
cf cubic feet
CFCs chlorofluorocarbons CFR Code of Federal Regulations

CH 4 methane

CO 2 carbon dioxide

CO 2 e CO 2 -equivalent COD chemical oxygen demand DOE U.S. Department of Energy DOT U.S. Department of Transportation
EAF electric arc furnace
ECOS Environmental Council of the States EGUs electric generating units EIA Energy Information Administration
EO Executive Order EOR enhanced oil recovery EPA U.S. Environmental Protection Agency FY2008 fiscal year 2008 GHG greenhouse gas GWP global warming potential HCFC–22 chlorodifluoromethane (or

CHClF 2 ) HCFCs hydrochlorofluorocarbons HFC–23 trifluoromethane (or CHF 3 ) HFCs hydrofluorocarbons HFEs hydrofluorinated ethers HHV higher heating value ICR information collection request IPCC Intergovernmental Panel on Climate

Change kg kilograms LDCs local natural gas distribution

companies LMP lime manufacturing plants
mmBtu/hr millions British thermal units

per hour MSW municipal solid waste MW megawatts MY mileage year

N 2 O nitrous oxide
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

NF 3 nitrogen trifluoride NGLs natural gas liquids NSPS new source performance standards

NSR New Source Review NTTAA National Technology Transfer and

Advancement Act of 1995

O 3 ozone ODS ozone-depleting substance(s) OMB Office of Management and Budget ORIS Office of Regulatory Information

Systems PFCs perfluorocarbons PIN personal identification number PSD Prevention of Significant Deterioration QA quality assurance QA/QC quality assurance/quality control QAPP quality assurance performance plan R&D research and development RFA Regulatory Flexibility Act RGGI Regional Greenhouse Gas Initiative RICE reciprocating internal combustion

engine RIA regulatory impact analysis SBREFA Small Business Regulatory

Enforcement Fairness Act


### 56263 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

scf standard cubic feet

SF 6 sulfur hexafluoride SIP State Implementation Plan SOP standard operating procedure SSM startup, shutdown, and malfunction TCR The Climate Registry TRI Toxic Release Inventory 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
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 (SF 6 ) 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 (CO 2 )
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,


### 56264 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

1 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 (Consolidated Appropriations Act, 2009, Public Law 110–329, 122 Stat. 3574– 3716). 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
nine 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 greenhouse gas emissions above appropriate thresholds in all sectors of the economy of the
United States.’’ Consolidated Appropriations Act, 2008, Public Law 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 1 (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 andmanufacturers of heavy-duty and offroad 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, regional 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 rule 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 (CO 2 ), methane (CH4 ), nitrous oxide (N 2 O), sulfur hexafluoride (SF 6 ), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and other fluorinated gases (e.g., nitrogen trifluoride (NF 3 ) 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 or more of CO 2 equivalent (CO 2 e) GHG emissions per 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.
As discussed further below and in ‘‘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.

Sections 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) 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


### 56265 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

2 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. new motor vehicle engines). 2 Section 208 of the CAA provides EPA with similar broad authority regarding the
manufacturers of new motor vehicles or new motor vehicle engines, and other persons subject to the requirements of parts A and C of title II. We note that while climate change legislation approved by the U.S. House of Representatives 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. 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)regarding improvements in nonregulatory strategies and technologies for preventing or reducing air pollutants (e.g., EPA’s voluntary GHG reduction programs such as the non-CO 2 partnership programs and ENERGY 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 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). 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 facilitieswithin those industries. The facilityspecific 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, including under traditional and more flexible programs.

As 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). Forexample, EPA anticipates that facilitylevel 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


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3 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/ ) 4 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. 5 Unless otherwise noted, years and dates in this notice refer to calendar years and dates.play an important role in achieving lowcost reductions in GHG emissions.

In addition to 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. 3 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 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 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 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 preempt any other

programs.

EPA’s GHG reporting rule is a specific single action that was 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 CO 2 , CH 4 , N 2 O, SF 6 , 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 4 level, except that certain suppliers of fossil fuels and industrial gases would report at the corporate
level.

In addition, GHG reporting bymanufacturers of heavy-duty and offroad 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 source category (as defined in 40 CFR part 98, subparts C through JJ) that is listed below in any calendar year starting in 2010. 5 For these facilities, the annual GHG report covers all 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 report CO 2 mass emissions year-round through 40 CFR part 75. —Adipic acid production. —Aluminum production. —Ammonia manufacturing. —Cement production. —HCFC–22 production. —HFC–23 destruction processes that are

not co-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.


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6 This does not include portable equipment, emergency generators, or emergency equipment as
defined in the rule. 7 Supplied means produced, imported, or exported. —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 CO 2 e or more per year, as determined according to 40 CFR part 98, subpart

HH. —Manure management systems that

emit CH4 and N 2 0 (combined) in amounts equivalent to 25,000 metric

tons CO 2 e or more per year, as determined according to 40 CFR part 98, subpart JJ.

• Any facility that contains any source category (as defined in 40 CFR part 98, subparts C through JJ) that is listed below and that emits 25,000

metric tons CO 2 e 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 must cover all source categories and 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 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

CO 2 e or more per year from all stationary fuel combustion sources. 6

• 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-to-liquid fuels; importers and exporters of coal-to-liquid fuels with annual imports or annual exports that are equivalent to 25,000 metric tons

CO 2 e or more per year.

—Petroleum products: All petroleum

refiners that distill crude oil; importers and exporters of petroleum products with annual imports or annual exports that are equivalent to 25,000 metric tons CO 2 e 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 and exporters of industrial GHGs with annual bulk imports or exports of

N 2 O, fluorinated GHGs, and CO 2 that in combination are equivalent to 25,000 metric tons CO 2 e or more per
year.

— CO 2 : All producers of CO 2 ; importers and exporters of CO 2 with annual bulk imports or exports of N 2 O, fluorinated GHGs, and CO 2 that in combination are equivalent to 25,000

metric tons CO 2 e 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. 7 For example, while a facility’s emissions may be below 25,000 metric tons CO 2 e in January, if the cumulative emissions for the calendar year are 25,000 metric

tons CO 2 e 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 facility’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, reporters must continue to report CO 2 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 are either (1) less than 25,000
metric tons of CO 2 e per year for five consecutive years or (2) less than 15,000
metric tons of CO 2 e per year for three consecutive years. The reporter must notify EPA that they intend to cease reporting and explain 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 CO 2 e threshold). The reporter must keep records for all five 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 CO 2 e 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:


### 56268 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

8 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.

9 ‘‘Use’’ for purposes of industrial GHGs presumes that there will be 100 percent release of the GHG. 10 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 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. 11 For more information about the reporting format please see Section V of this preamble. • Facility name or supplier name (as appropriate) and physical street address including the city, State, and zip code.

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

• For facilities that directly emit

GHG: —Annual facility emissions (excluding

biogenic CO 2 ), expressed in metric
tons of CO 2 e 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 CO 2

(i.e., CO 2 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: CO 2 (excluding biogenic CO 2 ), biogenic

CO 2 , CH 4 , N 2 O, 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 for each individual unit or each process line). —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. —Total pounds of synthetic fertilizer

produced through nitric acid or ammonia production and total nitrogen contained in that fertilizer.

• For suppliers: 8 —Annual quantities of each GHG that

would be emitted from combustion or

use 9 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 CO 2 e, 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 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 withheld as CBI. 10

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 methodologies 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 CO 2 , CH 4 , N 2 O, and CO 2 e. 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 must 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. 11 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 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


### 56269 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

12 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 (SF 6 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). 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 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 ‘‘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. 12

• Added a mechanism in 40 CFR 98.2 to allow facilities and suppliers that report less than 25,000 metric tons of

CO 2 e for five 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 five 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 three years instead of five 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 ‘‘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: CO 2 , CH 4 , N 2 O, HFCs, PFCs, SF 6 , 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 CO 2 emissions data reported by EGUs subject to the ARP,
data on their emissions are also not reported under mandatory Federal programs. CO 2 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 CH 4 , N 2 O, HFCs, PFCs, SF 6 , and the other fluorinated compounds are also


### 56270 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

13 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: http://www.ipcc.ch/ipccreports/methodologyreports.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). 14 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. significant: About 40 percent as large as
the CO 2 heating effect according to the Fourth Assessment Report of the IPCC.

The IPCC focuses on CO 2 , CH 4 , N 2 O, HFCs, PFCs, and SF 6 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 (O 3 ) 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. 13 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 SF 6 . 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 O 3 , 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 ‘‘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 ‘‘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 require 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 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:

• Electronics manufacturing

• Ethanol production

• Fluorinated GHG production

• Food processing

• Magnesium production

• Oil and natural gas systems

• SF 6 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 addition, 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. 14 Calculation and reporting of net emissions (emissions at a facility less any sequestration occurring at the facility) 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 proposed rule (74 FR 16465). In total, the rule is estimated to


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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 theability to accurately measure all facilitylevel 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. 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 GHG 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 canonly be applied upstream, whereas enduse 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 ‘‘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 CO 2 e 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 CO 2 e 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 CO 2 e to enable
collection of emissions data for smaller


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15 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.

16 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 CO 2 e. sources. Some of these commenters also noted that a 10,000 metric ton CO 2 e threshold is more appropriate in order to monitor leakage of emissions to smaller sources (since 25,000 metric
tons of CO 2 e 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 CO 2 e 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 CO 2 e for many source categories, and capacity-based or ‘‘all in’’ thresholds for other categories. 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 ‘‘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 a range of GHG policies and

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 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 coalfired units larger than 30 mmBtu per hour). 15 And, as mentioned previously, this level is consistent with (or higher than) the majority of other GHG reporting programs. Furthermore, having a uniform threshold 16 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 Section 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 CO 2 e) and from 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 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 CO 2 e 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 CO 2 e 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 CO 2 e per year.

The lower threshold alternatives that we considered were 1,000 metric tons of

CO 2 e per year, and 10,000 metric tons
of CO 2 e 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 CO 2 e/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 CO 2 e/ yr threshold would approximately double the number of reporters, but would only increase national emissions coverage by one 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 H.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 CO 2 e per year as an alternative
threshold but concluded that it fails to satisfy key objectives. It excludes 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

CO 2 e per year, reporting for some 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 CO 2 e threshold will cover many of the types of facilities and suppliers typically regulated under the CAA, while appropriately balancing


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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, this 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 CO 2 e 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 ‘‘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. Thereasons they gave included: Facilitylevel 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 are more likely to be

CBI.

Response: In response to comments, EPA reviewed our initial views outlined in Sections IV.D and V 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 NSPS. The data collected from facility-level reporting under this rule will improve our 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. (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 managersare already experienced with facilitylevel 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. With 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 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,


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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 six 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 EPA’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 facilityspecific 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 EPA’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


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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 will 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 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


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17 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. 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 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 CO 2 e per year annual threshold. Others suggested a level different from 25,000 metric tons CO 2 e 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 CO 2 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 provisions to allow facilities and suppliers to stop submitting annual reports under certain conditions. These provisions apply to facilities and suppliers regardless of their applicability threshold as it is based on the annual report.

• Under the first provision, if any facility’s annual GHG reports
demonstrate emissions of less than 25,000 metric tons of CO 2 e per year for five 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

CO 2 e per year for five consecutive years, they can cease submitting annual reports.

• Under the second provision, if any facility’s or supplier’s annual GHG reports demonstrate emissions of less than 15,000 metric tons CO 2 e 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 CO 2 e 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 provisions 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 CO 2 e. 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 CO 2 e per year because it is the same as the general applicability threshold for this rule. 17 We selected a 5-year period, instead of a shorter time frame, because it allows reporters that consistently report less than 25,000 metric tons CO 2 e 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.

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


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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 orsuppliers that stop operating their GHGemitting 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 CO 2 e per year (or the 3-year period needed to
demonstrate emissions are less than 15,000 metric tons CO 2 e 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 CO 2 e per year for five consecutive calendar years or less than 15,000 metric tons CO 2 e 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 CO 2 e per year for five consecutive years (or less than 15,000 metric tons of CO 2 e 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 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 CO 2 e and to separately present annual mass
emissions of each individual GHG emitted from each source category at the facility. Reporting of CO 2 e allows a comparison of total GHG emissions across facilities in varying categories which emit different GHGs. Knowledge of both individual gases emitted and
total CO 2 e 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 relevant 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 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 ‘‘Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments, Subpart A: Applicability and Reporting Schedule’’, ‘‘Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments, Subpart


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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 date 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 throughout 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 addedthat given the stringency of the selfcertification 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 three 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.


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18 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 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. 18 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 programallows up to three percent of facilitylevel 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. For example, TCR allows reporters to use simplified calculation methods of their own design for calculating up to five 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
CO 2 e/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 CO 2 e 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). 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 CO 2 e 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 source 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 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


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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 CO 2 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 five 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 relevant 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 finalized 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 CO 2 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 CO 2 emissions. We have made it clear that the reporter can elect to monitor and report process CO 2 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 CO 2 emissions would be reported under the source category subpart. The source category subparts have also been revised to specify that if process CO 2 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 CO 2 emissions and the reporter would not be able to accurately separate
the fraction of the CO 2 emissions that
came from the combustion units and process emission points that are comingled in the same stack.


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19 As described earlier in this section, facilities or suppliers that have emissions or products with emission less than 25,000 metric tons CO 2 e 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 CO 2 e for three years is a row may cease reporting, and must have records to cover those three years of

emissions. 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 directfired 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 CO 2 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 CO 2 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 CO 2 emissions, or (2) calculate process CO 2 emissions using the source category-specific monitoring and calculation procedures contained in the subpart. If reporters don’t haveCEMS and choose the source categoryspecific calculation approach, then they report process CO 2 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 CFR 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 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 three years rather than the five years specified in the proposed
rule. Some of these commenters stated that three 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 five years rather than three years is overly burdensome and is not necessary. They indicated that three years of records is sufficient
to allow verification of annual GHG reports. A smaller number of commenters supported record retention for five 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 five years to three years. 19 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 three 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’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 commenters’ concerns that monitoring plan information is already contained in
other documents.

The final rule also contains a provision to update the monitoring plan. Reporters 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


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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 ‘‘Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments, Approach to Verification and Missing Data.’’

Comment: Many commenters, including most facilities and suppliers required to report under the rule and several other stakeholders, supportedEPA’s proposal to require selfcertification 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.

Other 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 State 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 rulewould cause reporters to take selfcertification 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, EPAconsidered three alternatives: (1) Selfcertification without independent verification, (2) self-certification withthird party verification, and (3) selfcertification with EPA verification. For this particular program, EPA is not changing the verification approach fromthe proposal and is requiring selfcertification 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 ensurecollection and dissemination of highquality 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


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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 ‘‘Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments, Legal Issues’’). We determined that the third party verification approach could take from
three to six 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 approach 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 beensubstantial. By finalizing selfcertification 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 preempt 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 ofcomments in support of selfcertification 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 could serve a 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 ‘‘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 preempt 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 preempt 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.


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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 regional 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 preempt 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 delegation, particularly in light of the leadership and experience of several States 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 States would take
additional time and would not be available for 2010 reporting, and we also determined that a significant number of States 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 regional 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–2008–0508–054).) 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 ‘‘Mandatory Greenhouse Gas Reporting Rule: EPA’s


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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 CO 2 e 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 simplified 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

CO 2 e 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 in 40 CFR 98.2 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. 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 CO 2 e will be less than 25,000 metric tons of CO 2 e 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—


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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 consumption level and maximum heat input capacity that correlates with emissions of 25,000 metric tons per year
of CO 2 e. For non-combustion source categories with a 25,000 metric ton CO 2 e 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 CO 2 e. 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 ‘‘Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments, Legal

Issues’’.

Comment: EPA received numerous
comments on whether the CAA 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 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 GHGs under the CAA and hence, is issuing a comprehensive reporting rule.

Moreover, as noted above, CAA
sections 114 and 208 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 ‘‘Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to 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


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20 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). CAA, as well as for potential efforts to
address GHG emissions at downstream sources. Information from suppliers of
industrial GHGs 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 ‘‘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 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. 20 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 ‘‘Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments, Legal Issues,’’ EPA has adequate authority to issue this 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 ‘‘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 Section 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 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 treatment 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 ‘‘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 GHGs ‘‘regulated pollutants’’ under the 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 memorandum.

Response: As we noted in the proposal, EPA is reconsidering the PSD Interpretive Memo and will be seeking public comment on the issues raised in it. That proceeding, not this rulemaking, is the appropriate venue for submitting
comments on the substantive issue of whether monitoring regulations under the CAA should make GHGs subject to regulation. At this time however, the PSD Interpretive Memo reflects EPA’s current position, and hence, this final rule does not make GHGs subject to regulation under the CAA.

Comment: EPA also received
numerous comments about whether the requirements imposed by this rule are


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‘‘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. 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’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 its facility or supply operation meets any of the reporting rule applicability criteria in 40 CFR 98.2(a), the reporter must calculate and report GHG
emissions or alternate information as required (e.g., suppliers report quantities supplied and the quantity of

CO 2 e 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 Section III.X of the preamble), should also review Sections 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 Section 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 CO 2 e emission based on purchased electricity.

While 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. As 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,


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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 GHG emissions. To this end, EPA has in place several programs in which corporations and individual facilities can participate to
reduce their contribution to GHG 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 globalenvironment by completing a corporatewide inventory of their GHG 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 GHG 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 CO 2 e) 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 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, 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, and EPA has discussed in an
earlier Federal Register notice what
data elements constitute emissions data that cannot be considered CBI (56 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


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required by the provisions of another subpart of part 98.

Reporters must submit annual GHG reports for stationary fuel 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 CO 2 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:

• CO 2 , CH 4 , and N 2 O emissions from each stationary fuel combustion unit. For each unit, CO 2 , CH 4 , and N 2 O emissions must be reported for each fuel combusted (including biomass). Reporters can aggregate emissions from multiple units in certain cases.

• Facility-level CO 2 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 CO 2 Emissions from
Combustion: Calculate CO 2 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, CO 2 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 CO 2 emission factors.

— Tier 2: Use annual fuel consumption

(from company records) together with measured fuel-specific high heat
values and default CO 2 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 CO 2 mass emissions using part 75 calculation methods.

• Calculating CO 2 Emissions From Sorbent Use . For fluidized bed boilers that use sorbent injection and units equipped with wet flue gas desulfurization systems, calculate CO 2 emissions from sorbent use using methods provided in the rule, except
when CO 2 emissions are measured with

CEMS.

• Calculating CO 2 Emissions From Biomass Fuel Combustion . Calculate

CO 2 emissions from biomass combustion for only the specific types
of biomass that are listed in the rule. The approach used for most units is to use a default high heat value and default

CO 2 emission factor to estimate emissions. For determining the biomass
fraction of CO 2 emissions from units that burn MSW or mixed fuels, and from
units that co-fire biomass with fossil
fuels and measure CO 2 emissions using CEMS, use the specific methods provided in the rule.

• Calculating N 2 O and CH 4 Emissions From Combustion . Calculate N 2 O and

CH 4 emissions only for units that are required to report CO 2 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 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 ‘‘Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments, Subpart C: General Stationary Fuel Combustion Sources.’’

• Exemptions to GHG emissions reporting have been added for unconventional types of fuel. Reporters are required to calculate GHG emissions only 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 for any 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 CO 2 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 CO 2 mass emissions, to use
established Part 75 CO 2 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)(4)(ii) and all of the
conditions listed in 40 CFR 98.33(b)(4)(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 N 2 O 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

CO 2 emissions is extended to other solid
fuels in addition to MSW. These


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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

CO 2 emissions from combustion of mixed biomass fuels has been expanded
to include the combustion of other
biomass fuels in 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 ‘‘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.

• For 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 ‘‘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 CO 2 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 CO 2 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 CO 2 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 CO 2 mass emissions, be allowed to implement established Part

75 CO 2 emissions calculation methods in lieu of using Tiers 1 through 4. Finally, EPA received diverse comments on the proposed calculation method for

CH 4 and N 2 O emissions. Several
commenters recommended that these emissions either not be reported at all, or that emissions reporting should be


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excluded for certain fuel types. Others asked for flexibility in determining the appropriate emission factors for CH4 and N 2 O. 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 MSW, 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 higher 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 methods that can be used as alternatives 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 CO 2 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 CO 2 emissions calculation methodologies in part 75 to meet 40 CFR part 98 CO 2 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 CO 2 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 CO 2 emissions. Sources using 40 CFR part 75 flow rate and CO 2 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 CO 2 mass emissions.

The methodology for calculating CH4 and N 2 O 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

N 2 O emissions is required only for units that are required to report CO 2 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 of40 CFR part 98, subpart C are both fuelspecific 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 N 2 O emissions. Consequently, when CEMS (which are not fuel-specific) are used to
monitor the CO 2 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 CO 2 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 CO 2 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 CO 2 concentrations. Therefore, sources that


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monitor CO 2 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 ARP 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 unitlevel 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 CO 2 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 appliedcorrectly without unit-level data. If unitlevel 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 CO 2 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.
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 CO 2 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 CO 2 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 N 2 O 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 CO 2 mass emissions, rather than daily CO 2 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 QA 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 CO 2 mass emissions yearround 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 CO 2 , N 2 O, and CH 4 mass emissions from each

EGU.

GHG Emissions Calculation and Monitoring. For EGUs subject to the ARP and other EGUs that are required to monitor and report to EPA CO 2 mass emissions year-round according to 40


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CFR part 75, the reporter must continue

to monitor CO 2 emissions according to 40 CFR part 75. The cumulative CO 2 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 N 2 O and CH 4 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 thispreamble, reporters must submit unitlevel 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 ‘‘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 CO 2 mass emissions yearround 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 CO 2 calculation methology was provided for units that are not in the ARP, but report CO 2 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

CO 2 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 RICE 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 States 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 ARP but are required by other regulatory programs to report part 75 emissions and heat input data, EPA should expand the four-tiered
calculation method for CO 2 mass emissions in 40 CFR 98.33(a) to allow
the use of CO 2 emissions calculation methods based on Appendices D and G of part 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 CO 2 mass emissions year-round according to 40 CFR part 75 (e.g., RGGI units). The final subpart D provides a CO 2 calculation methodology for such EGUs that are not in the ARP, but report to EPA CO 2 mass emissions year-round using part 75 methodologies. For the purposes of part 98, the CO 2 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 N 2 O 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 CO 2 , N 2 O, and CH 4 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. Unless an alternative method of determining N 2 O emissions is requested, calculate N 2 O process emissions from adipic acid production


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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 N 2 O emissions from the waste gas stream of each oxidation process and the production rate recorded during the test.

When N 2 O abatement devices (such as nonselective catalytic reduction) are used, adjust the N 2 O process emissions for the amount of N 2 O removed using the destruction efficiency for the control
device and the fraction of annual production for which the control device is operating. The destruction efficiency can be specified by the abatement
device manufacturer 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 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 in this section or ‘‘Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments, Subpart E: Adipic
Acid Production.’’

• The re-testing trigger was changed. Performance testing to determine the

N 2 O 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 40 CFR 98.57 to 40 CFR 98.56, and some data elements that a reporter must already use to calculate GHGs as specified in 40 CFR 98.53 were added to 40 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 ‘‘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 40 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. 40 CFR part 98, subpart E provides methods for reporting only the process

N 2 O emissions. Also see Section III.C of this preamble for responses to comments related to 40 CFR part 98, subpart C (General Stationary Combustion).

Selection of Proposed GHG Emissions Calculations and Monitoring Methods

Comment: One commenter stated that
emissions of N 2 O do not correlate with the production of adipic acid at their facility. A portion of the process off gas,
which contains N 2 O, 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 N 2 O emitted from the production of adipic acid that
is sold or transferred offsite is not covered in the proposed rule. The final rule has been changed to require this
amount of N 2 O to be reported. Allowing for this additional reporting requirement ensures that the reported N 2 O emissions attributed to the adipic acid facility are accurate. Reporting of the N 2 O 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 N 2 O
emissions factor is sufficient to accurately calculate N 2 O 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 N 2 O emissions from adipic acid production. Specifically the commenters asked that
EPA allow the use of N 2 O and flow CEMS to directly measure N 2 O 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 N 2 O analyzers to determine
the amount of N 2 O 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

N 2 O 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 N 2 O emissions (such as N 2 O CEMS).

EPA understands the need to further
evaluate and establish alternative comparable methods for sources to use in accurately calculating N 2 O 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 the destruction factor of N 2 O abatement technologies. This parameter is often based on site-specific knowledge and operations. We believe


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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 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 manufactureprimary aluminum using the HallHe

 ́ roult manufacturing process. The primary aluminum manufacturing process consists of the following operations:

• Electrolysis in prebake and

S < derberg 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 (CF 4 ) emissions and perfluoroethane (C 2F 6 ) emissions from anode effects in all prebake and

S < derberg electrolysis cells combined.

• CO 2 emissions from anode consumption during electrolysis in all prebake and S < derberg cells.

• All CO 2 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 CO 2 , N 2 O, and CH 4 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:

• CF 4 from anode effects: Calculate
annual CF 4 emissions based on the frequency and duration of anode effects in the aluminum electrolytic reduction process for each prebake and S < derberg electrolysis cell using the following parameters:—Anode effect minutes (AEM) per cellday calculated monthly. —Aluminum metal production calculated monthly. —A slope coefficient relating CF 4

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 EPA’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 1.4mVovervoltage, can use either smelterspecific 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.

• C 2F

6 from anode effects: Calculate
annual C 2F 6 emissions from anode effects from each prebake and S < derberg electrolysis cell using the calculated CF 4 emissions and the mass ratio of C 2F 6 to
CF 4 emissions, as determined during the same test during which the slope
coefficient is determined.

• Process CO 2 emissions—general approaches. Most reporters can elect to calculate and report process CO 2 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 CO 2 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 CO 2 emissions, then the CEMS must be used to measure and report
combined CO 2 emissions from that stack, instead of using the calculation procedures specified below.

• CO 2 emissions from anode consumption in prebake cells: Calculate
annual CO 2 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.

• CO 2 emissions from S< derberg cells:
Calculate CO 2 emissions from paste consumption in S < derberg 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 S < derberg
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.

• CO 2 emissions from anode baking of prebake cells: Calculate CO 2 emissions at the facility level separately for pitch volatiles combustion and for bake furnace packing material.

• To calculate CO 2 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 CO 2 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 CO 2 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


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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 ‘‘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 CO 2 emissions
from S < derberg cells (paste consumption) was corrected.

• Language was updated to request reporting of all CO 2 emissions from onsite anode baking.

• Language was updated to request reporting of smelter-specific slope
coefficient s (plural).

• A new equation was added in 40 CFR 98.63 (Eq. F–3) to calculate CF 4 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 ‘‘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 Aluminum 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 CO 2 -eq in PFCs, these errors result in absolute
uncertainties of ± 88,000 MTCO 2 e and

± 26,000 MTCO 2 e, respectively. The reduction in uncertainty associated with moving from default to smelter-specific slope coefficients, 62,000 MTCO 2 e, 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 Greenhouse Gas
Inventories. These values are identical
to the ‘‘Aluminum Sector Greenhouse Gas Protocol (Addendum to the WRI/ WBCSD Greenhouse Gas Protocol),’’
October 2006 default coefficients.

Comment: Several commenters arguedthe requirement to re-measure smelterspecific slope coefficients every three 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 the 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 currentlyrecommends that smelter operators remeasure 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 CF 4 and C 2F 6 if one ormore of the following apply: (1) Thirtysix 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 recentlyupdated their measurements of smelterspecific 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,


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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 fossilbased 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:

• CO 2 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.

• CO 2 , CH 4 , and N 2 O 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 CO 2 collected and transferred off site, report these emissions under 40 CFR part 98, subpart PP (Suppliers of

CO 2 ) 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. Reporters must use one of
two methods to calculate CO 2 process emissions, as appropriate:

• Most reporters can elect to calculate and report process CO 2 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 CO 2 emissions from an ammonia manufacturing process unit are emitted through the
same stack as CO 2 emissions from a combustion unit or process equipment
that uses a CEMS and follows Tier 4 methodology to report CO 2 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 CO 2 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 are 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 ‘‘Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments, Subpart G: Ammonia 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 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 40 CFR 98.77 to 40 CFR 98.76, and some data elements that a reporter must already use to calculate GHGs as specified in 40
CFR 98.73 were added to 40 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), and responses to those comments are provided in Section III.C of this preamble. Responses to significant comments received can be found in ‘‘Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to


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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 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 CO 2 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)(4)(ii) or (iii), then process or combined process and combustion

CO 2 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 CO 2 emissions from ammonia processing units, then facilities must calculate and report process CO 2 emissions under this subpart by using equations provided in 40 CFR 98.73(b)(1) through (b)(4). CO 2 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), and Section III.C of this preamble.

Comment: One commenter noted that
most ammonia facilities utilize natural gas combustion combined with approximately five 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 is 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 CO 2 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 are 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 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 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 CO 2 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

CO 2 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 CO 2 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

CO 2 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 manufacturing, 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.


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GHGs to Report. For cement production, report the following

emissions:

• CO 2 process emissions from calcination, reported for each kiln.

• CO 2 combustion emissions from
each kiln.

• N 2 O and CH 4 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.

• CO 2 , N 2 O, and CH 4 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 CO 2 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 CO 2 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 CO 2 emissions or (2) calculate process CO 2 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 bemeasured); and a quarterly kilnspecific factor 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 CO 2 emissions from

each kiln under 40 CFR part 98, subpart H (Cement Production), and report combustion CO 2 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 ‘‘Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments, Subpart H: Cement
Production.’’

• The CO 2 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 CKD, non-calcined content of clinker and CKD, and organic carbon
content of raw materials.

• Requirements in 40 CFR 98.81 through 40 CFR 98.87 were revised to clarify which requirements apply to reporters who elect to report CO 2 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), 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 ‘‘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 provisions to cease reporting if annual reports demonstrate emissions less than specified levels for multiple years. These 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 CO 2 e, 10,000 metric
tons CO 2 e, 25,000 metric tons CO 2 e, and 100,000 metric tons CO 2 e. All of these
emission thresholds covered more than 99.9 percent of CO 2 e 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 CO 2 e. Therefore, we


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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 Cement CO 2 Protocol as the basis for the Proposed Rule.
Commenters further stated that the

Cement CO 2 Protocol 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-basedcalculation to account for any noncarbonated 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 Cement CO 2 Protocol 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 Cement CO 2 Protocol and compared its requirements to our requirements. We feel that the rule closely mirrors the GHG calculation methods and requirements of the

Cement CO 2 Protocol with some minor differences. For example, our rulerequires cement plants to use plantspecific emission factors to calculate

CO 2 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-levelemissions estimates than facilityspecific 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 CO 2 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 CO 2 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 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 rule 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 CO 2 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 40 CFR part 98, subpart H (Cement Production) to define which requirements apply to facilities using

CEMS to monitor CO 2 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 CO 2 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 are redundant if the facility is continuously monitoring CO 2 emissions. Another commenter recommended that EPA state within 40 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 CO 2 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, plants using CEMS are not completely excluded from the requirements in 40 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 CO 2 emissions. Specifically, we created separate lists of reporting requirements and recordkeeping requirements for cement plants using

CEMS.


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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 CO 2 /metric ton clinker produced)’’ required to be reported under proposed 40 CFR 98.86(h), and
how that factor would be calculated.

Response: We agree with the
commenter that there were
inconsistencies between 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 CO 2 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 CO 2 e 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 TSDs 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 CO 2 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.

• CO 2 , N 2 O, and CH 4 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 CO 2 emissions from EAFs, reporters can use one of two methods, as appropriate:

• Most reporters can elect to calculate and report process CO 2 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 CO 2 process emissions from an EAF are emitted through the
same stack as CO 2 emissions from a combustion unit or process equipment
that uses a CEMS and follows Tier 4 methodology to report CO 2 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


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mass balance calculation procedure for calculating process CO 2 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 ‘‘Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments, Subpart K: Ferroalloy Production.’’

• 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 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 40 CFR 98.117 to 40 CFR 98.116, and some data elements that a reporter must already use to calculate GHGs as specified in 40
CFR 98.173 were added to 40 CFR 98.116 for clarity. See 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 ‘‘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 CO 2 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 CO 2 emissions from based on the World Resources Institute (WRI) aluminum smelting protocol.

Response: We reviewed the WRI aluminum smelting protocol, which was publicly available and we 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 ‘‘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 TSDs 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 CO 2 e 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 TSDs 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.


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

emissions:

• CO 2 process emissions from each continuous glass melting furnace.

• CO 2 combustion emissions from each continuous glass melting furnace,

• CH 4 and N 2 O 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.

• CO 2 , CH 4 , and N 2 O 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 CO 2 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 CO 2 emissions.

• For other glass melting 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 CO 2 emissions or (2) calculate process CO 2 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

CO 2 emissions from each glass melting furnace under 40 CFR part 98, subpart N (Glass Production), and report combustion CO 2 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 ‘‘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 definitions 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 40 CFR 98.147 to 40 CFR 98.146, and some data elements that a reporter must already use to calculate GHGs as specified in 40
CFR 98.143 were added to 40 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 ‘‘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 CO 2 e, 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 GHG 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 CO 2 e threshold, which should preclude small facilities from having to report GHGs. This
threshold remains in the final rule. Thus, any small fiber glass and rock and slag wool insulation facilities with low
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 provisions to cease reporting if annual reports demonstrate emissions less than specified levels for multiple 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


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between 1,000 and 100,000 metric tons

CO 2 e. We selected the 25,000 metric

tons CO 2 e 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 CO 2 e threshold, 98 percent of emissions would be covered, with about 58 percent of facilities being required to report. Compared to the 100,000 metric tons CO 2 e threshold, the proposed 25,000 metric tons CO 2 e 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 CO 2 e threshold, the 25,000 metric

tons CO 2 e 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 metric tons CO 2 e 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 metric tons CO 2 e 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 contains a general discussion of the selection of the 25,000 metric tons CO 2 e threshold.

Method for Calculating GHG Emissions

Comment: One commenter fully supports EPA’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 40 CFR part 98, subpart N, other than the annual process emissions of CO 2 , 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 40 CFR 98.146 that reads: ‘‘No information required to be reported by this section, other than the information required by 40 CFR 98.146(a), is considered to be emission data under 40 CFR 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 40 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 ‘‘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 CHClF 2 ) 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 CO 2 , N 2 O, and CH 4 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


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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 ‘‘Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments, Subpart O: HCFC–22
Production and HFC–23 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.

• A term has been added to the massbalance 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 theprescribed method will over- or underestimate 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 ‘‘Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments, Subpart O: HCFC–22
Production and HFC–23 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 five 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


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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 GHG 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. 40 CFR part 98, subpart O was intended to address HFC–23 generation and emissions from HCFC–22 production. 40 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 CO 2 - 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., 40 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:

• CO 2 process emissions from hydrogen production.

• CO 2 , N 2 O, and CH 4 emissions from each stationary combustion unit on site by following the requirements of 40 CFR part 98, subpart C (General Stationary Fuel Combustion Sources).

• CO 2 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 CO 2 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 CO 2 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 CO 2 emissions from hydrogen production are vented through the same stack as a combustion unit or process equipment that uses a CEMS to follow Tier 4 methodology to report CO 2 emissions, then the CEMS must be used to measure and report
combined CO 2 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 40 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 ‘‘Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments, Subpart P: Hydrogen
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 CO 2 , CH 4 , and N 2 O
emissions.

• In 40 CFR 98.163(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


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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 distinguish between CEMS recordkeeping and feedstock method recordkeeping.

• 40 CFR 98.166 was reorganized and updated to improve the emissions verification process. Some data
elements were moved from 40 CFR 98.167 to 40 CFR 98.166, and some data elements that a reporter must already use to calculate GHGs as specified in
40 CFR 98.163 were added to 40 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 ‘‘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, any hydrogen production process unit that is not part of a larger facility covered by another subpart of this rule is a merchant hydrogen production facility which reports emissions under 40 CFR part 98, subpart P. On the other hand, a hydrogen production process unit that is part of a larger facility covered by another subpart of this rule is a captive hydrogen production facility that does not report emissions under 40 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 the rule applies to a facility that contains any source category listed in 40 CFR 98.2(a)(2) (which includes hydrogen production) and that emits 25,000

metric tons CO 2 e or more per year in combined emissions from stationary fuel combustion units, miscellaneous uses of carbonates, and all source categories 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 CO 2 emission reporting obligation as combined ‘‘process’’ and ‘‘combustion’’

CO 2 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 CO 2 emissions for each hydrogen production process unit whether or not it meets the conditions in 40 CFR 98.33(b)(4)(ii) 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 acrossthe rule (both general and subpartspecific comments) and our response is
discussed in Section II.R of this preamble and in ‘‘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 CO 2 , but rather inthe form of other products or coproducts 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 CO 2 , but rather as products (such as synthesis gas, CO,

CH 4 ) that are manufactured which
contain carbon.

Response: EPA generally concurs with
the need to account for ‘‘carbon other
than CO 2 ’’ that exits the facility. EPA considered several options for reporting
such carbon and chose to have facilities report CO 2 and ‘‘carbon other than CO 2 ’’ 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 CO 2 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

CO 2 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’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


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and solid hydrocarbon fuels of commerce to be characterized upon delivery if delivered by bulk transport(e.g., by truck or rail). Other nonstandard 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 40 CFR part 98, subpart P to refer to the less stringent monitoring and QA/QC requirements for the Tier 3 methodology included in 40 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 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
40 CFR 98.165 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.

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 CO 2 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 Section 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 ‘‘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. Report the following emissions annually:

• CO 2 , CH 4 , and N 2 O 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).

• CO 2 emissions from flares according to the requirements in 40 CFR part 98, subpart Y (Petroleum Refineries) and

CH 4 and N 2 O emissions from flares using the default emission factors for coke oven gas and blast furnace gas.

• CO 2 process emissions from each taconite indurating furnace, basic oxygen furnace, nonrecovery coke oven


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battery combustion stack, coke pushingprocess, sinter process, EAF, argonoxygen 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 CO 2 process emissions at each taconite indurating furnace, basic oxygen furnace, nonrecovery cokeoven battery, sinter process, EAF, argonoxygen 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 CO 2 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 CO 2 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 CO 2 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 CO 2 emissions from a taconite indurating furnace, basic oxygen furnace, nonrecovery coke ovenbattery, sinter process, EAF, argonoxygen decarburization vessel, and
direct reduction furnace are emitted through the same stack as CO 2 emissions from a combustion unit or process equipment that uses a CEMS and follows the Tier 4 methodology to report CO 2 emissions, then the CEMS must be used to measure and report
combined CO 2 emissions from that stack. In such cases, the reporter cannot use the other process CO 2 calculation approaches outlined above.

• For coke oven pushing, facilities

must use a CO 2 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 ‘‘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 CO 2 emissions at the different conditions is more than 20 percent, and (4) adding a provision to clarify testingrequirements when the EAF and argonoxygen decarburization vessel are
ducted to the same control device and
stack.

• To improve the emissions verification process, 40 CFR 98.176 was reorganized and updated. Some data
elements were moved from 40 CFR 98.177 to 40 CFR 98.176, and some data elements that a reporter must already use to calculate GHGs as specified in 40
CFR 98.173 were added to 40 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), and responses to those comments are provided in Section 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 ‘‘Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments, Subpart Q: Iron and 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 CO 2 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 ofcarbon in the most significant carboncontaining inputs entering the plant andin the most significant carboncontaining 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

CO 2 . 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 CO 2 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


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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 theseguidelines and protocols are processspecific 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) sitespecific 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 CO 2 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 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

CO 2 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 usedby any laboratory, and we note that inhouse 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 nine hours (or from nine production cycles for batch processes), (3) clarify that a separate test is not required for each grade of steel, and (4) remove the


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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 nine production cycles for certain small specialty steel producers would require 27 hours of testing for each grade of steel because each production cycle is
three 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 statedthat the 10 percent threshold for retesting 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 three hours or three production cycles. We also agree with the commenters who noted that different routine operating modes may result in different levels of

CO 2 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 CO 2 emissions by 20 percent

or more.

We disagree that annual re-testing is excessive because testing for CO 2 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 N 2 O emissions do not have to be reported for iron and steel production processes, and other commenters requested that CH4 and N 2 O emissions reporting not be required for the combustion of coke oven gas and blast furnace gas.
Commenters noted that default emission
factors for CO 2 , CH 4 , and N 2 O 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 N 2 O 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 CO 2 and

N 2 O 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:

• CO 2 process emissions from each smelting furnace used for lead production.

• CO 2 combustion emissions from each smelting furnace used for lead production.

• N 2 O and CH 4 emissions from each smelting furnace under 40 CFR part 98, subpart C (General Stationary Fuel Combustion Sources) using the methodologies in subpart C.

• CO 2 , N 2 O, and CH 4 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

CO 2 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 CO 2 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 CO 2 emissions or (2) calculate annual process CO 2 emissions using a carbon mass balance procedure specified in 40 CFR part 98, subpart R. If using approach (2):


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—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 CO 2 emissions from

each smelting furnace under 40 CFR part 98, subpart H (Cement Production), and report combustion

CO 2 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 CO 2 emissions from affected smelting
furnaces. The rationale for these and any other significant changes can be found below or in ‘‘Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments, Subpart
R: Lead Production.’’

• 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 one percent of the total carbon into the smelting furnace in
the carbon mass balance calculations. • Data reporting procedures (40 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 40 CFR 98.187 to 40 CFR 98.186, and some data elements that a reporter must already use to calculate GHGs as specified in 40
CFR 98.183 were added to 40 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 ‘‘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’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’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. 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 CO 2 e and only lead production facilities with emissions that equal or exceed 25,000

metric tons CO 2 e will have to report emissions. In addition, the final rule now contains provisions allowing a reporter to cease reporting if the annual reports for a given facility demonstrate emissions less than specified levels for multiple years. 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 CO 2 e. We selected the 25,000 metric tons CO 2 e 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 CO 2 e threshold, 99 percent of emissions would be covered, with about 63


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percent of facilities being required to report. The 100,000 metric tons CO 2 e threshold captures no emissions or facilities while the proposed 25,000

metric tons CO 2 e 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 CO 2 e represents the best option for ensuring that the majority of emissions are reported without imposing an unreasonable burden on the industry. 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 CO 2 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 CO 2 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

CO 2 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 CO 2 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 CO 2 emissions calculations while minimizing the monitoring burden on 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

CO 2 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 CO 2 process emissions from
all lime kilns combined.

• CO 2 combustion emissions from
lime kilns.

• N 2 O and CH 4 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.

• CO 2 , N 2 O, and CH 4 emissions from each stationary combustion unit other than kilns under 40 CFR part 98, subpart C (General Stationary Fuel Combustion Sources).

• CO 2 collected and transferred off site under 40 CFR part 98, subpart PP (Suppliers of CO 2 ).

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 CO 2 emissions from kilns, facilities must use one of two methods, as appropriate:

• If 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 measure and report under the Lime Manufacturing subpart (40 CFR part 98, subpart S) combined process and combustion CO 2 emissions.

• If 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 CO 2 emissions from all lime kilns or (2) calculate CO 2 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 CO 2 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.


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—The mass of each lime byproduct/

waste not sold (such as lime kiln dust and scrubber sludge) must be recorded annually. —Report process CO 2 emissions from all

kilns combined under 40 CFR part 98, subpart S (Lime Manufacturing), and report combustion CO 2 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 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 ‘‘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. • 40 CFR 98.196 was reorganized and updated. Some data elements were
moved from 40 CFR 98.197 to 40 CFR 98.196, and some data elements that a reporter must already use to calculate GHGs as specified in 40 CFR 98.193 were added to 40 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 ‘‘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. The rule defines the source category as a facility that contains ‘‘a rotary lime kiln to produce a lime product.’’ 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 in 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 CO 2 , CH 4 , and N 2 O 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 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. 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
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 kilns 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


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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 stoichiometric 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 since 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 usedby any laboratory, and we note that inhouse 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 agree that the production capacity, product quality (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 CO 2 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 quality be maintained as records rather than be reported. Emission factors and product quality are
used in calculations to establish the site specific rate of CO 2 emissions generated for each type of lime produced. Therefore these data are required in order to verify the CO 2 emissions that are being reported. This internal verification system ensures that the GHG emissions reported are accurate.

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 GHGs from magnesium production are sufficiently covered by the reporting requirements under 40 CFR part 98, subpart OO for Industrial Gas Supply. This information on U.S. production, imports, and exports of SF 6will provide at least a general, order-ofmagnitude check on consumption of SF 6 by magnesium production and other
uses of SF 6 . 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.
Facilities are considered to emit CO 2 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 CO 2 emissions from these processes are covered
elsewhere in 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 CO 2 process emissions for
all miscellaneous uses of carbonates as specified in this subpart.

• CO 2 , N 2 O, and CH 4 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


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which calculation methods are provided in the rule, as applicable.

GHG Emissions Calculation and Monitoring. Calculate process CO 2 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,

CO 2 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 ‘‘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 40 CFR 98.217 to 40 CFR 98.216, and some data elements that a reporter must already use to calculate GHG as specified in 40
CFR 98.213 were added to 40 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 ‘‘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 nonemissive 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 CO 2 emissions, such as adding
sodium carbonate to a water softener system. Acid-induced releases of CO 2 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 CO 2 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 CO 2 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.

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 CO 2 emissions
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 CO 2 emission factor to
determine CO 2 emissions.

The carbonate fraction method
calculates the amount of CO 2 emissions as a mass balance between the input and output amount of each type of
carbonate. The masses are measured and
used with a default CO 2 emission factor
to determine CO 2 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 one can
be used as the calcination fraction.

Data Reporting Requirements and
Records That Must Be Retained

Comment: One commenter requested that recordkeeping and reporting


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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 CO 2 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 CO 2 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 proposed 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, 40 CFR 98.216 was reorganized and updated. Some data elements were
moved from 40 CFR 98.217 to 40 CFR 98.216, and some data elements that a reporter must already use to calculate GHG as specified in 40 CFR 98.213 were added to 40 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 N 2 O 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 CO 2 , N 2 O, and CH 4 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

N 2 O 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 N 2 O from the absorber tail gas vent and the production rate for that train.

When N 2 O abatement devices (such as nonselective catalytic reduction) are used, adjust the N 2 O process emissions
for the amount of N 2 O removed using a destruction efficiency factor. The
destruction factor is the destruction efficiency and can be specified by the
abatement device manufacturer 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 ‘‘Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments, Subpart V: Nitric
Acid Production.’’

• The re-testing trigger was changed. Performance testing to determine the

N 2 O 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 40 CFR 98.226 to improve the emissions verification process. Some data
elements were moved from 40 CFR 98.227 to 40 CFR 98.226, and some data elements that a reporter must already use to calculate GHGs as specified in 40
CFR 98.223 were added to 40 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 ‘‘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 40 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 Subpart V provides methods for reporting only the process 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


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annual determination of the N 2 O emissions factor is sufficient to accurately calculate N 2 O 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 N 2 O emissions from nitric acid production. Specifically
the commenters asked that EPA allow
the use of N 2 O and flow CEMS to directly measure N 2 O emissions and use the performance test to evaluate the CEMS accuracy. They also requested that EPA allow use of existing process flow meters, process N 2 O analyzers to
determine the amount of N 2 O sent to control devices and conduct a performance test measuring control device destruction efficiency for each
control device and then calculate N 2 O
emissions.

Commenters also asked that finalizing a methodology for N 2 O 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

N 2 O emissions, such as N 2 O 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 N 2 O CEMS. EPA understands the
need to further evaluate and establish alternative comparable or potentially
more accurate methods for sources to use in calculating N 2 O emissions from nitric acid production and will address this 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 N 2 O emissions (including N 2 O CEMS).

The final rule allows the use of existing process flow meters and process knowledge in the determination of the destruction efficiency of N 2 O abatement technologies. This parameter is often based on site-specific knowledge 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 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 ‘‘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 N 2 O 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. Nitric acid production is a parameter in the method for determining annual N 2 O emissions so we need production rate in order to verify the N 2 O 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. We agree that capacities are not used
in the calculation of N 2 O emissions; however, this is still an important parameter for verifying emissions. 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 40 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 40 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 40 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 GHG emissions in the oil and gas sector, while concurrently taking into account industry burden. As stated in Section V.W of the preamble to the proposed rule (74 FR 166606, April 10, 2009),
EPA will also consider the inclusion of GHG 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


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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 CO 2 , CH 4 , and N 2 O process emissions from each petrochemical production unit. Process
emissions include CO 2 generated by reaction in the process. Process
emissions also include CO 2 , CH 4 , and

N 2 O 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 CO 2 , N 2 O, and CH 4 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

CO 2 captured must also be reported by following the requirements of 40 CFR part 98, subpart PP.

GHG Emissions Calculation and Monitoring. CO 2 process emissions from petrochemical production must be determined by one of three methods.
Process emissions include emissions
from CO 2 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 CO 2 emitted from each stack (except flare stacks). For each
stack that includes emissions from combustion of process off-gas, reporters
must calculate CH4 and N 2 O emissions by the procedures specified in 40 CFR part 98, subpart C. For each flare, the final rule requires CO 2 , CH 4 , and N 2 O emissions to be calculated using the procedures in 40 CFR 98.253(b) (Petroleum Refineries). If CO 2 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 thisoption, the quantity of each carboncontaining feedstock added to theprocess and the quantity of each carboncontaining 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 CO 2 , CH 4 , and N 2 O 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 ‘‘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 40 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.


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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 ‘‘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 CO 2 emissions only when combusted. Another commenter noted that off-gasfrom ethylene processes that are colocated 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 ethyleneprocess off-gases are not mixed with offgas 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 CO 2 , 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 CO 2 emissions (i.e., the Tier 4 methodology in 40 CFR part 98, subpart C) is also a good way to measure CO 2 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 CO 2 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 CO 2 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 CO 2 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 CO 2 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.


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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: 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 CO 2 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 other 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 in 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, 40 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.


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TABLE 

### Y–1—GHG S 

### T O 

### R EPORT

For this refinery process . . . Report emissions of the listed GHGs by following the requirements of the 40 CFR part 98, subpart indicated . . .

CO 2 CH 4 N 2 O

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 CO 2 , CH 4 and N 2 O emissions using the
calculation methods described below for each refinery process.

For CO 2 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 CO 2 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 CO 2 emissions according to the requirements specified in 40 CFR part 98, subpart C or (2) calculate CO 2 emissions using the
methods summarized below.

Flares. CO 2 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

CO 2 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 N 2 O 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. CO 2 emissions must be calculated using the volumetric flow rate of the exhaust gas (measured or calculated) and hourly measured carbon monoxide (CO) and CO 2 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 requiredflow and gas monitors if they are inplace, but may use engineering estimates for determining CO 2 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

N 2 O emissions may be measured or may be calculated using the CO 2 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.

CO 2 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. CO 2 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 N 2 O emissions from coke calcining units may be measured or calculated using the calculated CO 2 emissions and default emission factors.

Asphalt Blowing Operations. For uncontrolled asphalt blowing operations or asphalt blowing operations controlled by vapor scrubbing, CH4 and CO 2 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 CO 2 emissions must be calculated by assuming 98 percent of the CH4 and other hydrocarbons generated by the asphalt blowing operation are converted

to CO 2
.

Delayed Coking Units. CH 4 emissions from the depressurization of delayed


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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

CO 2 , CH 4 , or N 2 O 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. CH 4 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. CH 4 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

CH 4 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 CH 4 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. CH 4 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 ‘‘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 CO 2 emissions for catalytic cracking units and fluid coking units below 10,000 bbl/stream day that do not have CO 2 /CO/O 2 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 CO 2 , CH 4 and N 2 O 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 ‘‘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 includechemical facilities that use petroleumbased 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


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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 TSD for the Petroleum Refining Sector: Proposed Rule for Mandatory Reporting of Greenhouse Gases, indicates that 92.9 percent of the refining sector’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 TSD 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

CH 4 and N 2 O emissions within the Petroleum Refinery source category. Many commenters cited the TSD, which
indicated that N 2 O emissions account for 0.09 percent of the GHG emissions
and CH 4 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 TSD estimates for CH4 and N 2 O 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 NO X emissions, but we have no data to
determine the fraction of NO X that is

N 2 O. With the increased use at
refineries of NO X control devices, such
as low-NO X burners, low excess air, selective catalytic reduction (SCR) systems, and selective non-catalytic reduction (SNCR) systems, it seems plausible that N 2 O may be a more significant portion of a refinery’s NO X 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. Consequently, we have provided
additional alternatives that allow the
use of measured N 2 O (and CH 4 ) 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 N 2 O 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 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 CO 2 emissions from flares.

Response: EPA needs accurate data on
flare emissions to better understand this emission source, as flare use can varysignificantly from day-to-day and yearto-year. Use of flares is too episodic and
variable to allow a one-time calculation. However, we recognize that flares may contribute about two 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 State 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 CO 2 and CH 4 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 CO 2 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


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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 CO 2 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 rulespecifically provides a simple processbased 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 40 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 CO 2 emissions for catalytic cracking units below 10,000 bbl/stream day that do not have CO 2 /
CO/O 2 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 CO 2 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 CO 2 , N 2 O, and CH 4 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 CO 2 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 CO 2 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 CO 2 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 CO 2 emissions,
then the CEMS must be used to measure and report combined CO 2 emissions from that stack. In such cases, the reporter cannot use the CO 2 calculation methodology outlined in approach (2) 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 ‘‘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 basedon the origin of the phosphorouscontaining 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 40 CFR 98.267 to 40 CFR 98.266, and some data elements that are already used to calculate GHG emissions as specified in
40 CFR 98.263 were added to 40 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.


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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 provisions to cease reporting if annual reports demonstrate emissions less than specified levels for multiple years. These provisions apply to all reporting facilities, including those with phosphoric acid production processes. 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 GHG 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 P 2 O 5 ). 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 CO 2 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 are
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 are available. Facilities 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—GHG S 

### T O 

### R EPORT

For pulp and paper mills ... Report emissions of the listed GHGs by following the requirements of the 40 CFR part 98, subpart indicated ...

CO 2 Biogenic CO 2 CH 4 N 2 O Biogenic CH 4 Biogenic N 2 O

Chemical recovery furnace 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


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21 Biogenic CO 2 from the conversion of CaCO 3 to CaO in kraft or soda pulp mill lime kilns is accounted for in the biogenic CO 2 emission factor for the recovery furnace. 

### TABLE 

### AA–1—GHG S 

### T O 

### R EPORT

### —Continued

For pulp and paper mills ... Report emissions of the listed GHGs by following the requirements of the 40 CFR part 98, subpart indicated ...

CO 2 Biogenic CO 2 CH 4 N 2 O Biogenic CH 4 Biogenic N 2 O

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 part 98, subpart AA, reporters must calculate emissions from pulp and paper manufacturing facilities as follows:

• Chemical recovery furnaces: Calculate biogenic CO 2 emissions from combustion of biomass in spent pulping liquor using:
—Measured quantities of spent liquor

solids fired, site-specific high heatingvalue (HHV), and default or sitespecific 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 CO 2 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 N 2 O 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 sitespecific emission factors.

—Lime kilns at kraft and soda facilities.

• Lime kilns: Calculate CO 2 , CH 4 , and

N 2 O emissions from combustion 21 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 CO 2 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 CO 2 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 ‘‘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 ‘‘Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments, Subpart AA: Pulp and 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 of 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.’’


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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 (CaCO 3 and Na 2 CO 3 ) 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 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 EPA’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


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applicability criteria in the General Provisions (40 CFR 98.2) summarized in Section II.A of this preamble.

GHGs to Report. Report process CO 2 and CH 4 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 CO 2 , N 2 O, and CH 4 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 CO 2 emissions, reporters must use one of the following methods, as appropriate:

• Most reporters can elect to calculate and report process CO 2 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 CO 2 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 CO 2 emissions, then the CEMS must be used to measure and report combined CO 2 emissions from that stack. In such cases, the reporter cannot use the CO 2 calculation approach (2) outlined in the
above bullet.

For CH 4 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 ‘‘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.

• 40 CFR 98.286 was reorganized and updated to improve the emissions verification process. Some data
elements were moved from 40 CFR 98.287 to 40 CFR 98.286, and some data elements that a reporter must already use to calculate GHGs as specified in 40
CFR 98.283 were added to 40 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 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 CO 2 . 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 CO 2 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:

• CO 2 process emissions from soda ash manufacturing, reported for each manufacturing line.

• CO 2 combustion emissions from each soda ash manufacturing line.

• N 2 O and CH 4 emissions from fuel
combustion at each soda ash manufacturing line under 40 CFR part 98, subpart C (General Stationary Fuel Combustion Sources) using the methodologies in subpart C.

• CO 2 , N 2 O, and CH 4 emissions from each stationary combustion unit other than 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 CO 2 emissions from soda ash manufacturing lines, reporters must select one of the following methods, as appropriate:


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• For each 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 CO 2 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 CO 2 emissions or (2)
calculate CO 2 process emissions using the procedures specified in 40 CFR part 98, subpart CC and summarized below.

• If using approach 2, calculate process CO 2 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 bemeasured), the average monthly massfraction of inorganic carbon in the trona (required to be measured weekly), and the ratio of CO 2 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 CO 2 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 CO 2 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 CO 2 emissions from

each soda ash manufacturing line under 40 CFR part 98, subpart CC (Soda Ash Manufacturing), and report
combustion CO 2 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 ‘‘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 40 CFR 98.297 to 40 CFR 98.296, and some data elements that a reporter must already use to calculate GHGs as specified in 40
CFR 98.293 were added to 40 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 ‘‘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 CO 2 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

CO 2 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 CO 2 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 CO 2 emissions from this production method are likely to be significant and exceed 25,000 metric

tons CO 2 e. 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 40 CFR part 98, subpart CC for calculating, monitoring and QA/QC, and reporting of process CO 2 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

CO 2 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, which is the ratio of carbon dioxide to carbon, from Equations CC– 2 and CC–3. Equations CC–2 and CC–3


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provide results directly for CO 2 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. The 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 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 (SF 6 ) 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 TSDs under 40 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 CO 2 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 CO 2 , N 2 O, and CH 4 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

CO 2 process emissions using one of two methods, as appropriate:

• Most reporters can elect to calculate and report process CO 2 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 CO 2 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 CO 2 emissions, then the reporter must use the CEMS to measure and report combined CO 2 emissions from that stack instead of using the calculation procedures
described below.

• If using approach #2, calculate the process CO 2 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 ‘‘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


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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 40 CFR 98.317 to 40 CFR 98.316, and some data elements that a reporter must already use to calculate GHGs as specified in 40
CFR 98.313 were added to 40 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 ‘‘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 TiO 2 . 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 maintains 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 40 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

TiO 2 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 ‘‘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

CO 2 emissions. Production capacity and annual production of titanium dioxide are required for EPA to verify annual

CO 2 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 CO 2 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 TSDs 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:

• CO 2 process emissions from each
Waelz kiln and electrothermic furnace used for zinc production.

• CO 2 , N 2 O, and CH 4 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.


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GHG Emissions Calculation and Monitoring. Facilities must calculate

CO 2 process emissions using one of two methods, as appropriate:

• Most reporters can elect to calculate and report process CO 2 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 CO 2 emissions
from a Waelz kiln or electrothermic furnace are emitted through the same stack as a combustion unit or process equipment that uses a CEMS and follows Tier 4 methodology to report

CO 2 emissions, then the CEMS must be used to measure and report combined

CO 2 emissions from that stack, instead of the calculation procedure described
below.

• If using approach #2, calculate process CO 2 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 one percent of the total carbon into Waelz
kiln or electrothermic furnaces. These
materials do not need to be included in
carbon mass balance calculations.

• 40 CFR 98.336 was reorganized and updated to improve the emissions verification process. Some data
elements were moved from 40 CFR 98.337 to 40 CFR 98.336, and some data elements that a reporter must already use to calculate GHGs as specified in 40
CFR 98.333 were added to 40 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 Section 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 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 CH 4 destruction (for landfills with gas collection and control systems).

• Annual CO 2 , CH 4 , and N 2 O 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 CO 2 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

CH 4 emissions in two ways and report
both results. Emissions must be calculated by:

1. Subtracting the measured amount
of CH 4 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 CH 4 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


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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 identified in the following list. The rationale for these and any other significant changes can be founds below or in ‘‘Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments, Subpart HH:
Landfills.’’

• Industrial landfills were removed from the applicability provisions of 40 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 in 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 ‘‘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. In response to the proposal, EPA received numerous detailed public comments on the preamble, rule and TSDs under 40 CFR part 98, subpart HH.
Comments addressed the appropriateness, coverage, and methodology for addressing GHG
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 closedlandfills to lessen the burden on longclosed 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 GHG 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


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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 GHG 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 values, 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 five field studies for clay covers (the predominant soil cover type used in the U.S.) were included in the SWICS report. Four of the five field studies had oxidation factors ranging from 0.08 to 0.21, and the median of all
five 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


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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 nonmethane 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 (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 subpart.

Based on careful review of comments received on the preamble, rule and TSDs 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 volatile 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. A livestock facility that emits 25,000

metric tons CO 2 e or more per year from manure management systems 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.

• Drylots, including feedlots.

• High-rise houses for poultry production (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. 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


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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 N 2 O emissions from the system components listed above. For those manure management systems that include digesters, CH4 generated and destroyed, as well as any

CH 4 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 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 by weight for each animal type managed in each system component (assumed to be equal to the fraction of volatile solids/nitrogen handled in each system component).

• 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.

• N 2 O 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 CH 4 generated and destroyed based on the following inputs and data:

• Continuous monitoring of CH4 concentration, flow rate, temperature, and pressure of the digester gas.

• CH 4 destruction efficiency of the destruction device and fugitive (leakage)

emissions.

• The CH 4 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, facilities 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, facilities 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 ‘‘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. 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 were 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. 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
calculations for CH4 and N 2 O emissions from manure management systems to account for volatile solids and nitrogen removal through solid separation. If solid separation occurs prior to the manure management system component, 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 ‘‘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 systems 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 U.S. that should
be addressed.

However, other commenters stated
that livestock facilities should not be required to report GHG emissions.
These commenters noted that a small
number of facilities would be covered by the proposed rule, and these facilities would represent a very small percentage
of the total number of livestock 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


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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. 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 CO 2 e, and N 2 O emissions were 14.7 million metric tons CO 2 e in 2007; manure management systems account for 7.5 percent of total anthropogenic CH4 emissions and 4.7 percent of N 2 O 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 valuable. For example, these data will help to improve the understanding of emission
rates and actions that facilities take to reduce emissions and may improve the effectiveness and design of voluntary and/or mandatory programs 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 used
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 reduce the burden to comply with the reporting rule, while only minimally impacting
the estimates of GHG emissions. The variation in sampling techniques from facility to facility when characterizing
manure ‘‘as excreted’’ from the various animal populations on the facility (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 time, effort, and expense, outweighed the merits at this time.

Comment: 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 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. In addition, some commenters suggested that other data sources should be considered, such
as the ASABE manure standards.

Response: After a thorough review of available information, EPA has determined that the methodologies and
data sources used to calculate emissions in 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
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 GHG 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 allows the use of default factors, such as a system emission factor, for certain elements of the calculation, and encourages the use of some site-specific data. 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


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Management Project Reporting Protocol. For these offset programs, 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 lookup 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 CO 2 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 TSDs under proposed 40 CFR part 98, subpart 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-toliquid products). A producer of coal-toliquid products is any owner or operator who converts coal into liquid products(e.g., gasoline, diesel) using the FischerTropsch 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-toliquid products must report the CO 2 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 N 2 O.

GHG Emissions Calculation and Monitoring. For each type of coal-toliquid product, suppliers must calculate

CO 2 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 40 CFR part 98, subpart LL with references to the 40 CFR part 98, subpart MM procedures
and calculations. As a result of
considerable comment and EPA analysis, 40 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 40 CFR part 98, subpart MM in 40 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 40 CFR part 98, subpart MM based on public comments provided and EPA analysis conducted.


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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 NGLs 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 NGLs 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:

• CO 2 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.

• CO 2 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 N 2 0.

GHG Emissions Calculation and Monitoring. Suppliers of petroleum products must choose one of two
methods to calculate CO 2 emissions that
would result from the combustion or oxidation of each petroleum product and natural gas liquid:

• Method 1: Use the default CO 2 emission factors provided in the regulations for a given petroleum product 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 CO 2 emissions that
would result from the combustion or oxidation of biomass co-processed with petroleum feedstock, reporters must use

a CO 2 emission factor that is provided in the regulations for each type of
biomass.

In calculating total CO 2 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 to be further refined or used on
site as well as biomass and biomassbased 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 ‘‘Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments, Subpart MM: Suppliers of Petroleum Products.’’

• We established a reporting threshold for importers and exporters of 25,000 metric tons of CO 2 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 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


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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 40 CFR 98.396. First, we made 40 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 40 CFR 98.393 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 thatethanol contains 2.5 percent petroleumbased denaturant because we want to ensure that reporters account for the

CO 2 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 percentdenaturant is blended with petroleumbased 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 ‘‘Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments, Subpart MM: Suppliers of 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 CO 2 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 CO 2 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 CO 2 per year for importers and exporters of petroleum products and natural gas liquids; the threshold is
based on a calculation of CO 2 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 40 CFR part 98, MM as importers. Through this analysis, we found that at a threshold of 25,000 metric tons CO 2 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 CO 2 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 Federal 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 CO 2 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 CO 2 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 40 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 CO 2 threshold
because we conclude that it will not significantly diminish the amount of information received by the agency;


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overall, exports of refined and semirefined 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

CO 2 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

CO 2 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 thatindustry uses a much larger and evergrowing 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 toproducts that have potentially nonemissive 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 facilitylevel 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,


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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 CO 2 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 productsenter and leave the country in wideranging 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

ton CO 2 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 CO 2 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 CO 2 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 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 Federal 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 CAA (see the general provisions preamble for addition discussion on CBI). 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 comprehensive and accurate data on the

CO 2 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., aviation gasoline and kerosene) while some products are classified differently on one list than on the other (i.e., EPA’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 EPA’s product list carefully and we feel that each category has the potential to have a unique carbon share and/or density. 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 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:

• 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)


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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 fractionators must report CO 2 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 CO 2 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 N 2 0.

GHG Emissions Calculation and Monitoring. Reporters must use one of
two methods to calculate the CO 2 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 CO 2 emissions factor. This method is most appropriate for liquid fuels.

• The second method uses either a
measured or default CO 2 emissions factor. This method is most appropriate for gaseous fuels.

• A NGL fractionator must then follow two additional equations, if applicable, to subtract the CO 2 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 CO 2 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 ‘‘Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments, Subpart NN: Suppliers of Natural Gas and 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.

• 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.

• 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 40 CFR 98.406. First, we made 40 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 40 CFR 98.403 to
40 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. 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 ‘‘Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments, Subpart NN: Suppliers of Natural Gas and 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 40 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 40 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


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policy on products with potential nonemissive 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 sections 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 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 CO 2 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 anyremaining potential for doublecounting, we provide an equation for a
fractionator 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 40 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 QA 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 40 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 40 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 N 2 O, except those that produce


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only HFC–23 generated as a byproduct during HCFC–22 production.

• Bulk importers of fluorinated GHGs

or N 2 O, if the total combined imports of
industrial GHGs and CO 2 exceed 25,000
metric tons of CO 2 e per year.

• Bulk exporters of fluorinated GHGs

or N 2 O, if the total combined exports of
industrial GHGs and CO 2 exceed 25,000

metric tons CO 2 e 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 N 2 O and each fluorinated GHG produced, imported, exported, transformed, or destroyed during the calendar year. Importers and exporters
of CO 2 must calculate and report annual
amounts of CO 2 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 N 2 O 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 ‘‘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 destruction 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’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 CO 2 e.

• 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 GHGproduction facilities to submit a onetime 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.


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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 ‘‘Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments, Subpart OO: Suppliers of Industrial GHGs.’’

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 three 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 A.

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 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 GHG by adding an exemption for ‘‘substances with a vapor pressure of less than 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 SF 6 and

NF 3 ) 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 A 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 CO 2 e. For purposes of determining whether or not the 25,000

metric ton CO 2 e 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 A 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 A 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 CO 2 e. 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 A should be periodically updated through a visible and participative process. EPA anticipatesthat as GWPs are evaluated or reevaluated 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 thatGWPs are appropriately evaluated or reevaluated.

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 ofreporting would be small because precharged 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 offluorinated GHGs imported in precharged 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


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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 onEPA’s reporting requirements for ozonedepleting 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 (CO 2)

1. Summary of the Final Rule

Source Category Definition. Under the rule, suppliers of CO 2 consist of the following:

• Facilities with production process units that capture and supply CO 2 for commercial applications or that capture and maintain custody of a CO 2 stream in order to sequester or otherwise inject it underground.

• Facilities with CO 2 production
wells that extract a CO 2 stream for the purpose of supplying CO 2 for commercial applications.

• Importers of bulk CO 2 , if total combined imports of CO 2 and other GHGs exceed 25,000 metric tons of CO 2 equivalent (CO 2 e) per year.

• Exporters of bulk CO 2 , if total combined exports of CO 2 and other GHGs exceed 25,000 metric tons CO 2 e
per year.

This source category is focused on upstream supply. It does not cover: Storage of CO 2 above ground or in geologic formations; use of CO 2 in enhanced oil and gas recovery; transportation or distribution of CO 2 ; or purification, compression, on-site use of

CO 2 captured on site, or processing of

CO 2. This source category does not
include CO 2 imported or exported in equipment, such as fire extinguishers.

Suppliers of CO 2 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 CO 2 must report the mass of CO 2 in a stream captured from production process units and extracted from production wells,
and the mass of CO 2 in containers that is imported and exported.

GHG Emissions Calculation and Monitoring. While this source category is focused on upstream supply of CO 2 , EPA recognizes that all CO 2 supplied to the economy does not necessarily result in an emission. There are a variety of downstream applications for CO 2—some applications are emissive and some are non-emissive. Under this rulemaking, a

CO 2 supplier facility must calculate the
mass of CO 2 supplied quarterly by measuring the mass or volumetric flow of gas and multiplying by the CO 2 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 CO 2 concentration of the stream varies throughout the year, and a quarterly concentration number multiplied by a quarterly volume will generate more
accurate calculation of CO 2 supply than annual measurements. EPA requires these quarterly numbers to be reported so that EPA can electronically verify the
calculations. The CO 2 supplier must also provide information on the
downstream CO 2 application, if known. Reporters must use the following methodologies, as applicable, for calculating CO 2 supplied:

• For suppliers that make measurements with mass flow meters, calculate quarterly for each meter the
total mass of CO 2 in a CO 2 stream in metric tons, 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 CO 2 in a CO 2 stream in metric tons, 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 according to methods specified in Equation PP–3 in

40 CFR 98.423.

• Importers or exporters that import or export CO 2 in containers must
calculate the total mass of CO 2 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 CO 2 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

CO 2 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 CO 2 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 ‘‘Mandatory Greenhouse Gas


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Reporting Rule: EPA’s Response to Public Comments, Subpart PP: Suppliers of Carbon Dioxide.’’

• We added equations and QA requirements to allow reporters to
determine CO 2 quantity using volumetric flow meters, weigh bills, scales, or load cells, as appropriate. These additions supplement the proposed equations and quality assurance requirements to determine

CO 2 quantity using mass flow meters.

• We revised the reporting procedures for missing data in 40 CFR 98.425. Facilities must use quarterly values as substitute data as they 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 40 CFR 98.427 to 40 CFR 98.426, and added some data elements that a reporter must already use to calculate GHGs as specified in 40 CFR 98.423 to 40 CFR 98.426 for clarity.

• 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

CO 2 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 CO 2
. 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 CO 2 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 PP: Suppliers of 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 CO 2 supplied to the economy should not be
characterized as an emission. Some in this group of comments specified that much of the supplied CO 2 is stored at enhanced oil recovery (EOR) sites, which are ‘‘closed systems’’, rather than emitted. In general, these same commenters stated that any CO 2 reporting requirements placed by EPA on industry should be placed on
downstream CO 2 users, such as EOR facilities, rather than CO 2 suppliers and should be for actual emissions only.
Other comments echoed that EPA needs to collect data from recipients of supplied CO 2 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 CO 2 . 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 CO 2 geologic sequestration effectiveness; and tracking
the CO 2 throughout the entire carbon dioxide capture and sequestration (CCS) chain for the purposes of adjusting CO 2 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 CO 2 supplied to the economy as emissions and recognizes that there are a variety of applications
for CO 2, both emissive and nonemissive. CO 2 supplied to the economy
would result in an emission if the CO 2 were used in an application which would ultimately result in release of the

CO 2 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 CO 2 has been or will be released to the atmosphere (e.g., emitted), the Agency
needs information on the downstream

CO 2 end-use. In today’s final rulemaking, CO 2 suppliers must provide
information on the downstream CO 2 application, if known. EPA believes information on the end-use will provide
some idea of the amounts of CO 2 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

CO 2 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 CO 2 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 CO 2 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 CO 2 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 CO 2 securely sequestered and the potential for release of CO 2 during EOR operations.

Given the comments in support of downstream data collection, particularly with respect to EOR systems and CO 2 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 CO 2 emitted and geologically sequestered at active EOR facilities and geologic sequestration sites where CO 2 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 subsequent regulatory actions and the data reported under today’s rulemaking will together enable EPA to understand
the amount of CO 2 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 CO 2 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 CO 2 ,


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22 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. 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 CO 2 . However, SDWA is focused on permitting sites for protection of ground and drinking water; the new proposal discussed above will be designed to
address issues related to the CAA. EPA intends 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 CO 2 suppliers and the reporting requirements in new rulemaking for CO 2 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 CO 2 supply will assist EPA in developing future climate policy. Commenters stated that they do not believe CO 2 supply data will provide EPA with
useful information. Commenters stated
that data collection from CO 2 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 CO 2 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, this data will enable EPA to evaluate the appropriate actionto take under section 103 regarding nonregulatory strategies for pollution prevention. It will also inform evaluation of possible CAA regulation of the supplier and/or recipient of the CO 2 Data on CO 2 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

CO 2 as an end-user.

Though CO 2 capture and geologic sequestration are occurring now on a relatively small scale, CCS is expected to play a major role in mitigating GHG 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 CO 2 emissions from fossil fuel combustion in 2007. The stationary sources represent a wide variety of sectors amenable to CO 2 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 the 500 largest stationary sources are
within 50 miles of a candidate CO 2 reservoir. 22

With this rule, EPA will begin building capacity to track the growth in

CO 2 supply and learn about its disposition throughout the economy.
EPA has concluded that we need data
now from CO 2 suppliers—both
industrial facilities and CO 2 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 CO 2 captured from
industrial facilities will offset or displace CO 2 produced from natural formations. Even after EPA begins collecting data on CO 2 geologic sequestration under the proposed new rulemaking (discussed above), EPA will
continue to need data from CO 2 suppliers in order to track any CO 2 that is not sequestered.

Comment: EPA received some comments asking whether a specific situation results in coverage under 40 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 CO 2 that is not supplied to downstream customers is a covered facility. Another asked that a pulp and paper mill that transfers a CO 2 stream to an adjacent facility by pipeline be exempt from 40 CFR part 98, subpart PP. Several commenters requested clarification on specific scenarios such as taking ownership of an already separated CO 2 stream for further processing, separating CO 2 for their own use, and operating versus owning the separation unit.

Response: EPA did not intend for 40 CFR part 98, subpart PP to cover facilities that take ownership of a CO 2 stream that has already been separated and removed from a manufacturing process or that has already been
extracted from CO 2 production wells in order to do any of the following: Store it in above ground storage of CO 2 ; transport or distribute it via pipelines, vessels, motor carriers, or other means; purify, compress, or process it; or sell it to other commercial applications. 40 CFR part 98, subpart PP covers facilities that own or operate the equipment that physically separates and removes CO 2 from an industrial or manufacturing process or physically extracts CO 2 from production wells because we concluded that the entity with first touch of the

CO 2 supply was the most logical point of coverage. We wanted to minimize any unnecessary duplicative reporting of the

same CO 2 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 CO 2 for further processing or use within the fence line of the facility (e.g., for their own use). EPA proposed that 40 CFR part 98, subpart PP only

cover CO 2 that is captured or extracted for purposes of sequestration or supply
to other facilities for commercial applications because we concluded that

CO 2 captured and used on-site is equivalent to an intermediary step in production rather than an actual supply
of CO 2
.

Comment: EPA received a comment requesting that ethanol plants and other facilities capturing CO 2 from biomass be exempt from Subpart PP.

Response: A long standing inventory convention adopted by the IPCC, the UNFCCC, the US GHG Inventory, and many other reporting programs is separate treatment of emissions of CO 2 from the combustion of biomass and
biomass-based fuels from emissions of

CO 2 from the combustion of fossil-based products. In national inventories,
emissions from the combustion of
biomass-based fuels are accounted for as part of a comprehensive system-wide tracking of carbon dioxide emissionsand sequestration in the land-use, landuse change and forestry sector and the agriculture sector, rather than at the point of fuel combustion. Consistent with this approach, in the proposed and final rule, downstream emitters must only consider non-biogenic emissions when conducting a threshold analysis; however, downstream emitters must report both biogenic and non-biogenic emissions once they trigger the reporting threshold because data on non-biogenic emissions is useful and
informative.

For the final rule, EPA has decided not to apply the same approach to


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23 Manufacturers of light-duty vehicles, light-duty trucks, and medium-duty passenger vehicles are not
covered in this final rule.

24 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.

25 For aircraft engine manufacturers, reporting requirements will apply for the engine models in production in 2011.

26 Small business manufacturers will continue to be subject to measurement and/or reporting requirements for compliance with existing regulations.

27 But see Ford Motor Co. v. EPA, 604 F. 2d 685 (D.C. Cir. 1979) (permissible for EPA to regulate

CH 4 under CAA section 202 (b)). In addition, although CH 4 is not itself regulated, manufacturers subject to ‘‘non-methane hydrocarbon’’ standards
have needed to determine CH 4 emission levels, in some cases by using a default value and in many cases by way of testing. suppliers of CO 2 . We have concluded that data on capture of biogenic CO 2 would be useful and informative because biogenic CO 2 can potentially be stored in GS sites, or displace fossil CO 2 applications. We need a full picture of
the CO 2 being supplied into the economy. Though CO 2 capture and sequestration is occurring now on a relatively small scale, it is expected to play a major role in mitigating GHG
emissions. Therefore information on all potential sources of CO 2 for sequestration is necessary for a complete picture. Thus, a facility that captures CO 2 from biomass and otherwise meets the applicability test is covered under 40 CFR part 98, subpart PP and is required to report all CO 2 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 CO 2 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 CO 2 as long as the CBI is protected. Some
commenters indicated that CO 2 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 CO 2 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 40 CFR part 98, subpart PP in today’s rule in order
to ensure that all covered CO 2 can be reported, irrespective of technical or physical conditions. Therefore, a reporter that measures CO 2 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 CO 2 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 CO 2 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 CO 2 already operate mass or volumetric flow meters, or already determine quantities of CO 2 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, 23 this rule includes new requirements for reporting emission
rates of GHGs. 24 Mobile source engine manufacturers have been measuring CO 2 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 CO 2 for all engines beginning with model year 2011 and other GHGs in subsequent model

years. 25 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. 26 In addition to CO 2 , most manufacturers will now be required to report on two other major GHGs emitted by mobile sources, nitrous oxide (N 2 O) and methane (CH4 ). Although most current engines have relatively low emission rates of these GHGs compared

to CO 2 , these compounds have global warming potentials significantly higher
than CO 2 . 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 N 2 O are related to catalytic treatment of engine exhaust, specifically aftertreatment of NO X emissions. Therefore, we will require that manufacturers begin to measure and report N 2 O emissions, but only for engine models that incorporate NO X aftertreatment technology (as shown in Table IV–1 of this preamble). The program will not require N 2 O reporting before model year 2013, and the requirements will only apply to new engines equipped with NO X aftertreatment technology. (Manufacturers of some engine categories have employed aftertreatment for many years to meet NO X standards; for other engine categories, manufacturers are unlikely to introduce

NO X 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. 27 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

N 2 O and CH 4 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


### 56353 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

28 Aerodyne, Rich Miake-Lye, AAFEX Methane presentation at the Seventh Meeting of Primary

Contributors for the Aviation Emissions Characterization Roadmap, June 9–10, 2009. 29 IPCC, Aviation and the Global Atmosphere,

1999, at 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. 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 N 2 O and CH 4 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 N 2 O 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 N 2 O test data from relevant testing programs (by such sources as industry collaboratives and/or from the suppliers of the catalytic NO X 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

CO 2 emission rates beginning in 2011 (for aircraft engines, they will report

CO 2 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

N 2 O or CH 4 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 N 2 O and CH 4 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 NO X after
treatment devices in the foreseeable future, we did not propose requiring

N 2 O 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. 28 However, unlike NO X emissions from most mobile sources, NO X emissions
from aircraft have been shown to make a potential contribution to climate change. 29 For this reason, we are requiring that aircraft engine manufacturers report the NO X 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

NO X as part of current criteria pollutant certification requirements. NO X emissions rate data from LTO modes will support modeling of overall NO X 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 State and local governments to report in-use travel activity or other emissions-related data
in this final rule.

Table IV–1 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 ‘‘Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments, Motor Vehicle and Engine Manufacturing.’’



### TABLE 

### IV–1—F IRST 

### M ODEL 

### Y EAR FOR 

### GHG R EPORTING 

### R EQUIREMENTS

Engine category CO 2 N 2 O aCH 4

Highway Heavy-Duty (engine and vehicle) ............................................................ 2011 2013 or NO X AT ................. 2012
Nonroad Diesel ....................................................................................................... 2011 2013 or NO X AT ................. 2012 Marine Diesel (other than C3) ................................................................................ 2011 2013 or NO X AT ................. 2012
C3 Marine ............................................................................................................... 2011 No ne ................................... None
Locomotives ............................................................................................................ 2011 201 3 or NO X AT ................. 2012 Small Spark-Ignition ................................................................................................ 2011 2013 o r NO X AT ................. 2012 Large Spark-Ignition ............................................................................................... 2011 2013 orNO X AT ................. 2012 Marine Spark-Ignition .............................................................................................. 2011 2013 orNO X AT ................. 2012
Snowmobiles ........................................................................................................... 2011 2013or NO X AT ................. 2012 Highway Motorcycles .............................................................................................. 2011 2013 or N O X AT ................. 2012 Off Highway Motorcycles/ATVs .............................................................................. 2011 2013 or NO X AT ................. 2012
Aircraft b ................................................................................................................... 2011 None ... ................................ None

a N 2 O reporting for new engines begins in 2013 or when the manufacturer introduces NO X 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 NO X also required.


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30 Modes of the landing and takeoff cycle are taxi/ idle, takeoff, climb out, and approach. 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 ‘‘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 CAFE 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 N 2 O for all of their engines, and instead will require N 2 O reporting only for engines that use NO X exhaust aftertreatment technology.

• We have delayed the proposed MY 2011 start year for N 2 O reporting until MY 2013, and later for categories where the manufacturer has not applied NO X aftertreatment technology.

• We have added additional emission
test methods that manufacturers can choose for measuring N 2 O, to assure that an appropriate method is available for any foreseeable circumstance (including the need to measure very low N 2 O emission rates).

• The final rule incorporates an opportunity for a manufacturer to provide EPA with appropriate
alternative information in lieu of N 2 O 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 NO X emissions data they already collect, since, at altitude, NO X 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 CO 2 and NO X 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 ‘‘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 near 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 N 2 O and

CH 4 , was too aggressive; and commented that the proposed test procedure for N 2 O was not adequate.

Response: We still conclude that there is significant value to collecting CO 2 , N 2 O, and CH 4 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

N 2 O and CH 4 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 N 2 O and CH 4 , we agree that revisions in the proposed provisions are
warranted. We have limited the reporting requirements for N 2 O to engines equipped with NO X 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 N 2 O are related to catalytic treatment of engine exhaust, specifically
aftertreatment of NO X emissions, and we have concluded that collecting N 2 O emissions data from engines without

NO X aftertreatment technology would provide marginal value to the agency. We expanded the number of approved
test methods for N 2 O measurement
since we learned from comments and
our own technical research that our proposed test methods for N 2 O were not appropriate for every foreseeable circumstance, including measurement of very low levels of N 2 O. We also
extended the lead time available to
manufacturers before N 2 O and CH 4 reporting is required. We are providing this flexibility based on our conclusion
that we can reduce the burden of purchasing and installing the required

CH 4 and N 2 O 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 N 2 O 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 CO 2 emissions from each
mode of the LTO 30 cycle used in the emission certification test, as proposed, is acceptable as long as existing
methods for CO 2 are retained. In particular, commenters noted that reporting would result in minimal


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burden as long as CO 2 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 CO 2 from the LTO cycle is unjustified because LTO measurements
do not include CO 2 emissions from an entire aircraft flight, which is affected by the propulsion system, drag, etc.

Response: We determined that calculating aircraft engine CO 2 emissions from fuel mass flow rate measurements is an appropriate method for reporting CO 2 emissions. Therefore, for turbofan and turbojet engines of rated output greater than 26.7 kilonewtons, we are finalizing that manufacturers report CO 2 separately for each mode of the LTO cycle by
calculation of CO 2 from fuel mass flow rate measurements or, alternatively, according to the measurement criteria
for CO 2 in Appendices 3 and 5 to ICAO Annex 16, volume II. Comprehensive and consistent reporting of LTO CO 2 emissions, along with knowledge of aircraft aerodynamic performance, will support modeling of full-flight CO 2 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

CH 4 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

CH 4 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 NO X emissions
in the four LTO test modes and for the overall LTO cycle. Manufacturers
commented that NO X 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 NO X since they currently do not report the data to EPA. In addition, environmental organizations commented that NO X 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 NO X emissions in the
four LTO test modes and for the overall LTO cycles. As discussed in the proposal and earlier in this final rule,

NO X from aircraft have been shown to make a potential contribution to climate change at high altitude. As required in 40 CFR part 87, manufacturers must already measure and record NO X emissions in each of the four LTO test modes in order to comply with the LTO

NO X 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 NO X emissions rate data will support modeling of overall NO X 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 Section V.B of this preamble or in ‘‘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 and 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 facilities 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 representative 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 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.


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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 representative, 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 propermatching between databases, e.g., EPAassigned 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 consistencywith existing State-level and Federallevel GHG 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 kg or metric tons per unit of time.

Conversion of Emissions to CO 2 e

. 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

N 2 O) per unit of time and CO 2 e 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 reducing 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’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 Section 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


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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 ‘‘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. Further, EPA is not requiring 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 one 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 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 this approach in the ARP and found that it provides a high degree of both data quality and consistency and accountability.

2. Certificate of Representation

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 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 does not agree that certificates of representation are unnecessary or overly burdensome or that there should be any uncertainty as to whether a certificate of representation is complete. The information required on the certificate of representation is


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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. 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 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 a unique facility record. The FRS database is publicly available to queries from the EPA.GOV Web site
under the Envirofacts Data Warehouse home page: http://www.epa.gov/enviro/ html/fii/fii

_ query

_ java.html . Descriptive
information about FRS can be found at: 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 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.


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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 or scanned 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 datasubmission, EPA will provide a Webbased reporting system to guide reporters through the data entry, emission calculation, and submission process. This reporting system will conform 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 in 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 Web 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 system that will be used for the GHG reporting rule. 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


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31 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. 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, 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 agencies that
are able to assist EPA to define their 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. 31

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 ‘‘Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments, Compliance and 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 Section 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 Section 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


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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 Web site, http://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 includea warning to the source that it is in noncompliance 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 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 final rule can be found in the text of the Regulatory Impact Analysis (RIA) for the final rule (EPA– HQ–OAR–2008–0508).

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 ‘‘Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments, Cost and Economic Impacts of the 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


### 56362 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

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 seven 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 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 CO 2 e 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 appropriate 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 CO 2 e). 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


### 56363 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

are clearly documented in the RIA for
the final rule.



### TABLE 

### VII–1—E STIMATED 

### C OVERED 

### E NTITIES 

### , E MISSIONS AND 

### C OSTS BY 

### S UBPART 

### (2006$)

Subpart Number covered of

entities Downstream emissions First year capital costs First year total annualized costs 2

(Million of MtCO 2 e) Share (percent) (Million) Share (percent) (Million) Share (percent)

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 3Subpart 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 (CO 2 ) 13 0.0 0 0.0 0 0.0 0Subpart 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 equipmen t lifetime and interest rate (see additional details in section 4 of the RIA for the final rule).



### TABLE 

### VII–2—T HRESHOLD 

### C OST 

### -E FFECTIVENESS 

### A NALYSIS 

### (2006$)

Threshold (tons CO 2 e) Facilities required to report Total
costs (million $2006) Downstream emissions reported (MtCO 2 e/

year) Percentage of totaldownstream emissions reported (percent) Average reporting

cost ($2006/

ton) Incremental

cost ($/metric

ton)

100,000 .................................................................................................... 6,269 $89 3,738 53 $ 0.02 25,000 ...................................................................................................... 10,152 132 3,827 540.03 0.49 10,000 ...................................................................................................... 16,718 160 3,861 550.04 0.83 1,000 ........................................................................................................ 54,229 398 3,926 5 6 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).


### 56364 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

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 CO 2 e 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—U PSTREAM 

### V ERSUS 

### D OWNSTREAM 

### C OSTS

Upstream 1 Downstream 234

Source category No. of reporters Emissions

coverage

(%) 10 First year
cost (millions) Source category No. of reporters 2 Emissions

coverage 3 7 10 (%) First year
cost 3 (millions)

Coal Supply ................................. 0 0 $0.00 Coal 5 6 Combustion .................... N/A 99 .0 N/A Petroleum Supply ........................ 315 100 3.66 Petroleum 5 Combustion 9 ........... N/A 20 .0 N/A Natural Gas Supply ..................... 1,502 68 6.76 Natural Gas 5 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
Vehicle 8 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 si de 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/biolo gical 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-c ounted’’ 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 ofCO 2 e/yr).

5 Estimates for the number of reporters and total cost for downstream stationary combustion do not distinguish between fuels. Nat ional level data on the number of reporters could be estimated. However, estimating the number of reporters by fuel was not possible becaus e 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 electrici ty generating units under the ARP.

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 thi s rule. To estimate total emissions coverage downstream, by fuel, we added total emissions resulting from the respective fuel combusted in the indu strial 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 sa les covered by manufacturer reporting in this proposal rather than emissions coverage. The ‘‘threshold’’ for mobile sources is based o n manufacturer size rather than total emissions. In this rule, all heavy-duty highway and nonroad vehicle and engine manufacturers, except tho se that meet EPA’s definition of ‘‘small business’’ or ‘‘small volume manufacturers’’, would report emissions rates of CO 2 , CH 4 , and N 2 O from the products they supply. This source category is neither upstream nor downstream, but is included in the downstream column for illustrativepurposes.

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 des ignations 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 CO 2 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 approximat ely one 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 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 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 relevant 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 RIA for the


### 56365 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

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 in the
docket. The final rule retains selfcertification 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 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 is a largenumber of affected entities, but perentity costs are low. Average cost-tosales 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—E STIMATED 

### C OST



### - TO 

### -S ALES 

### R ATIOS FOR 

### A FFECTED 

### E NTITIES

NAICS NAICS description Average cost per entity ($1,000/entity) Average entity cost-to-sales ratio 1 (percent)

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

1 This ratio reflects first year costs. Subsequent year costs will be slightly lower because they do not include initial start-upactivities.

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


### 56366 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

32 EPA’s RFA guidance for rule writers suggests the ‘‘sales’’ test continues to be the preferred quantitative metric for economic impact screening analysis. 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 one 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 CO 2 e 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 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 costsfor affected industry sectors to industryspecific 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., one percent or three percent). 32 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—E STIMATED 

### C OST



### - TO 

### -S ALES 

### R ATIOS BY 

### I NDUSTRY AND 

### E NTERPRISE 

### S IZE a

Industry NAICS NAICS description SBA sizestandard (effective March

11, 2008) Average cost per

entity ($1,000/ entity) All enterprises (percent) Owned by enterprises with:

<20 employees f (percent) 20 to 99employees (percent) 100 to499 employees (percent) 500 to749 employees (percent) 750 to999 employees (percent) 1,000 to 1,499employees (percent)

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 0.1Ferroalloys ............ 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


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TABLE 

### VII–5—E STIMATED 

### C OST



### - TO 

### -S ALES 

### R ATIOS BY 

### I NDUSTRY AND 

### E NTERPRISE 

### S IZE a

### —Continued

Industry NAICS NAICS description SBA sizestandard (effective March

11, 2008) Average cost per

entity ($1,000/ entity) All enterprises (percent) Owned by enterprises with:

<20 employees f (percent) 20 to 99employees (percent) 100 to499 employees (percent) 500 to749 employees (percent) 750 to999 employees (percent) 1,000 to 1,499employees (percent)

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 c ompany forms one enterprise—the enterprise employment and annual payroll are summed from the associated establishments. Enterprise size designations are determin ed 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 an alyses.

b NAICS codes 221111, 221112, 221113, 221119, 221121, 221122—A firm is small if, including its affiliates, it is primarily engage d 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 fourmillion 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 nomore than 1,500 employees nor more than 125,000 barrels per calendar day total Operable Atmospheric Crude Oil Distillation capacity. Capacity include s 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 b e 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 48 6990 = $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 fol lowing 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 Govern ment 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, re medial action, removal of contaminated materials, storage of contaminated materials and security and site closeouts. If one of such activities accounts for 50 percentor more of a concern’s total revenues, employees, or other related factors, the concern’s primary industry is that of the particular industry and not the Environmenta l Remediation Services Industry.

(2) For purposes of classifying a Government procurement as Environmental Remediation Services, the general purpose of the proc urement must be to restore a contaminated environment and also the procurement must be composed of activities in three or more separate industries with sepa rate NAICS codes or, in some instances (e.g., engineering), smaller sub-components of NAICS codes with separate, distinct size standards. These activities mayinclude, but are not limited to, separate activities in industries such as: Heavy Construction; Special Trade Construction; Engineering Services; Architectural Serv ices; 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 s ize 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 particu lar 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 p rogram. NA: Not available. SUSB did not report the data necessary to calculate this ratio.

EPA was not able to calculate a costto-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 CO 2 e reported of $0.07.

As shown, the cost-to-sales ratios are less than 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


### 56368 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

33 Nicholas Institute for Environmental Policy Solutions, Duke University. 2008. Size Thresholds for Greenhouse Gas Regulation: Who Would be Affected by a 10,000-ton CO 2 Emissions Rule?
Available at: http://www.nicholas.duke.edu/ institute/10Kton.pdf. these small businesses will be covered by the rule, we performed several case studies for manufacturing industries where the cost-to-receipt ratio exceeded one percent. For each industry, we used and applied emission data from a recent study examining emission thresholds 33

. This study provides industry-average

CO 2 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 one percent.

For the other enterprise categories
identified with ratios between one percent and three 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 one 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 boundestimate, summing typical perrespondent 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 ofgovernments less than 50,000, the costto-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 CO 2 e 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 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 CO 2 e 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 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 CO 2 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


### 56369 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

34 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. 35 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. 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 RIA 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, 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 2300.03.

EPA plans to collect complete andaccurate economy-wide data on facilitylevel 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. 34

The projected cost and hour burden for non-Federal respondents is $86.3 million and 1.21 million hours per year. The estimated average burden per response is two 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 35 . 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


### 56370 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

36 U.S. Small Business Administration (SBA).
2008. Firm Size Data from the Statistics of U.S. Businesses: U.S. Detail Employment Sizes: 2002. http://www.census.gov/csd/susb/
download

_susb02.htm. 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 final rule will not have a significant economic impact on a substantial
number of small entities.

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., one percent or 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 one 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. 36 For the few sectors where the preliminary screening showed a cost-to-sales ratio exceedingone percent, EPA’s examination of firmspecific sales information showed that no affected entity was likely to incur costs exceeding one 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. SeeTable VII–5 of this preamble for sectorspecific 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 one 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 EPA’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 Unfunded 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


### 56371 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

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 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 State, 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 GHGs
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 GHGs 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


### 56372 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

regulation applies directly to facilities that supply fuel or chemicals that when
used emit GHGs 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 air coordinators in April 2009 and prepared a guidance sheet for Tribal governments on the proposed rule. It was posted on the MRR Web 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 FR 19885, April 23, 1997) as applying only to those regulatory actions that concern health or safety risks, such that the analysis required under section 5–501 of the EO has the potential to influence the regulation. This action is not subject to
EO 13045 because it does not establish
an environmental standard intended to mitigate health or safety risks. H. Executive Order 13211: Actions That Significantly Affect Energy Supply, Distribution, or Use

This 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 GHGs 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 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 60 voluntary consensus standards from 10 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
GHG emissions. No new test methods were developed for this rule. Instead, from existing rules for source categories and voluntary GHG programs, EPA identified existing means of monitoring, reporting, and keeping records of GHG 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

GHG 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 U.S. prior to publication of the rule in the Federal Register. A major rule cannot take effect until 60 days after it is published in the Federal Register . This action is a ‘‘major rule’’ as defined by 5 U.S.C. 804(2). This rule will be effective December 29, 2009.

List of Subjects

40 CFR Part 86

Environmental protection, Administrative practice and procedure,


### 56373 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

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 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.

Dated: September 22, 2009.
Lisa P. Jackson,

Administrator.

■ For the reasons stated in the preamble, title 40, chapter I, of the Code of Federal Regulations is amended as follows:

**PART 86—[AMENDED]**

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

Authority: 42 U.S.C. 7401–7671q.

**Subpart A—[Amended]**

■ 2. Section 86.007–23 is amended by adding paragraph (n) to read as follows:

**§ 86.007–23 Required data.**

* * * * *

(n) Measure CO 2 , N 2 O, and CH 4 with
each low-hour certification test for heavy-duty engines using the procedures specified in 40 CFR part 1065 as specified in this paragraph (n). Report these values in your application for certification. The requirements of this paragraph (n) apply starting with model year 2011 for CO 2 and 2012 for

CH 4 . The requirements of this paragraph (n) related to N 2 O emissions apply for engine families that depend on NO

x aftertreatment to meet emission standards starting with model year
2013. These measurements are not required for NTE testing. Use the same units and calculations as for your other results to report a single weighted value
for CO 2 , N 2 O, and CH 4 for each test.
Round the final values as follows:

(1) Round CO 2 to the nearest 1 g/bhphr.

(2) Round N 2 O to the nearest 0.001 g/ bhp-hr.

(3) Round CH4 to the nearest 0.001 g/ bhp-hr.

■ 3. Section 86.078–3 is amended by removing the paragraph designation ‘‘(a)’’ and adding the abbreviations CH4 and N 2 O in alphanumeric order to read
as follows: **§ 86.078–3 Abbreviations.**

* * * * *

* * * * *

CH 4 methane.

* * * * *

N 2 O nitrous oxide.

* * * * *

**Subpart E—[Amended]**

■ 4. Section 86.403–78 is amended by adding the abbreviations CH4 and N 2 O in alphanumeric order to read as
follows:

**§ 86.403–78 Abbreviations.**

* * * * *

* * * * *

CH 4 methane.

* * * * *

N 2 O nitrous oxide.

* * * * *

■ 5. Section 86.431–78 is amended by adding paragraph (e) to read as follows:

**§ 86.431–78 Data submission.**

* * * * *

(e) Measure CO 2 , N 2 O, and CH 4 as described in this paragraph (e) with each zero kilometer certification test (if one is conducted) and with each test conducted at the applicable minimum test distance as defined in § 86.427–78. Use the analytical equipment and procedures specified in 40 CFR part
1065 as needed to measure N 2 O and

CH 4 . Report these values in your application for certification. The requirements of this paragraph (e) apply starting with model year 2011 for CO 2 and 2012 for CH4 . The requirements of this paragraph (e) related to N 2 O emissions apply for engine families that depend on NO X aftertreatment to meet emission standards starting with model year 2013. Small-volume manufacturers (as defined in § 86.410–2006(e)) may
omit measurement of N 2 O and CH 4 ; other manufacturers may provide appropriate data and/or information and
omit measurement of N 2 O and CH 4 as described in 40 CFR 1065.5. Use the same measurement methods as for your other results to report a single value for

CO 2 , N 2 O, and CH 4 . Round the final
values as follows:

(1) Round CO 2 to the nearest 1 g/km. (2) Round N 2 O to the nearest 0.001 g/
km.

(3) Round CH4 to the nearest 0.001 g/
km.

**PART 87—[AMENDED]**

■ 6. The authority citation for part 87 is
revised to read as follows:

Authority: 42 U.S.C. 7401–7671q.


### 56374 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

**Subpart A—[Amended]**

■ 7. Section 87.2 is amended by revising the section heading and adding the
abbreviation CO 2 in alphanumeric order
to read as follows:

**§ 87.2 Acronyms and abbreviations.**

* * * * *

CO 2 Carbon dioxide.

* * * * *

■ 8. Section 87.64 is revised to read as
follows:

**§ 87.64 Sampling and analytical procedures for measuring gaseous exhaust** 
**emissions.**

(a) The system and procedures for sampling and measurement of gaseous emissions shall be as specified by Appendices 3 and 5 to ICAO Annex 16 (incorporated by reference in § 87.8).

(b) Starting January 1, 2011, report

CO 2 values along with your emission levels of regulated NO X to the Administrator for engines of a type or
model of which the date of manufacture of the first individual production model was on or after January 1, 2011. By January 1, 2011, report CO 2 values along with your emission levels of regulated

NO X to the Administrator for engines currently in production and of a type or
model for which the date of manufacture of the individual engine was before January 1, 2011. Round CO 2 to the nearest 1 g/kilonewton rO.

(c) Report CO 2 by calculation from
fuel mass flow rate measurements in Appendices 3 and 5 to ICAO Annex 16, volume II or alternatively, according to
the measurement criteria of CO 2 in Appendices 3 and 5 to ICAO Annex 16,
volume II.

**PART 89—[AMENDED]**

■ 9. The authority citation for part 89
continues to read as follows:

Authority: 42 U.S.C. 7401–7671q.

**Subpart B—[Amended]**

■ 10. Section 89.115 is amended by revising paragraph (d)(9) to read as
follows:

**§ 89.115 Application for certificate.**

* * * * *

(d) * * *
(9) All test data obtained by the manufacturer on each test engine, including CO 2 as specified in § 89.407(d)(1);

* * * * * **Subpart E—[Amended]**

■ 11. Section 89.407 is amended by revising paragraph (d)(1) to read as
follows:

**§ 89.407 Engine dynamometer test run.**

* * * * *

(d) * * * (1) Measure HC, CO, CO 2 , and NO

x concentrations in the exhaust sample.
Use the same units and modal calculations as for your other results to report a single weighted value for CO 2 ; round CO 2 to the nearest 1 g/kW-hr.

* * * * *

**PART 90—[AMENDED]**

■ 12. The authority citation for part 90
continues to read as follows:

Authority: 42 U.S.C. 7401–7671q.

**Subpart B—[Amended]**

■ 13. Section 90.107 is amended by revising paragraph (d)(8) to read as
follows:

**§ 90.107 Application for certification.**

* * * * *

(d) * * * (8) All test data obtained by the manufacturer on each test engine, including CO 2 as specified in § 90.409(c)(1);

* * * * *

**Subpart E—[Amended]**

■ 14. Section 90.409 is amended by revising paragraph (c)(1) to read as
follows:

**§ 90.409 Engine dynamometer test run.**

* * * * *

(c) * * * (1) Measure HC, CO, CO 2 , and NO X concentrations in the exhaust sample.
Use the same units and modal calculations as for your other results to report a single weighted value for CO 2 ; round CO 2 to the nearest 1 g/kW–hr.

* * * * *

**PART 94—[AMENDED]**

■ 15. The authority citation for part 94
continues to read as follows:

Authority: 42 U.S.C. 7401–7671q.

**Subpart A—[Amended]**

■ 16. Section 94.3 is amended by adding
the abbreviation CH4 in alphanumeric
order to read as follows:

**§ 94.3 Abbreviations.**

* * * * *

CH 4 methane.

* * * * * **Subpart B—[Amended]**

■ 17. Section 94.103 is amended by adding paragraph (c) to read as follows:

**§ 94.103 Test procedures for Category 1 marine engines.** 

* * * * *

(c) Measure CH4 as specified in 40 CFR 1042.235 starting in the 2012 model year.

■ 18. Section 94.104 is amended by adding paragraph (e) to read as follows:

**§ 94.104 Test procedures for Category 2 marine engines.** 

* * * * *

(e) Measure CO 2 as described in 40 CFR 92.129 through the 2010 model year. Measure CO 2 as specified in 40 CFR 1042.235 starting in the 2011 model year. Measure CH4 as specified in 40 CFR 1042.235 starting in the 2012 model year.

**Subpart C—[Amended]**

■ 19. Section 94.203 is amended by revising paragraph (d)(10) to read as
follows:

**§ 94.203 Application for certification.**

* * * * *

(d) * * * (10) All test data obtained by the manufacturer on each test engine, including CO 2 and CH 4 as specified in 40 CFR 89.407(d)(1) and § 94.103(c) for Category 1 engines, § 94.104(e) for Category 2 engines, and § 94.109(d) for Category 3 engines. Small-volume manufacturers may omit measurement and reporting of CH4
. * * * * *

■ 20. Add part 98 to read as follows:

**PART 98—MANDATORY**
**GREENHOUSE GAS REPORTING**

Sec.

**Subpart A—General Provisions**
98.1 Purpose and scope. 98.2 Who must report? 98.3 What are the general monitoring, reporting, recordkeeping and verification requirements of this part? 98.4 Authorization and responsibilities of the designated representative. 98.5 How is the report submitted?
98.6 Definitions.
98.7 What standardized methods are incorporated by reference into this part? 98.8 What are the compliance and enforcement provisions of this part?
98.9 Addresses. Table A–1 to Subpart A of Part 98—Global Warming Potentials (100-Year Time Horizon) Table A–2 to Subpart A of Part 98—Units of

Measure Conversions


### 56375 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

**Subpart B—[RESERVED]**

**Subpart C—General Stationary Fuel**
**Combustion Sources**
98.30 Definition of the source category. 98.31 Reporting threshold. 98.32 GHGs to report. 98.33 Calculating GHG emissions. 98.34 Monitoring and QA/QC requirements. 98.35 Procedures for estimating missing
data. 98.36 Data reporting requirements.
98.37 Records that must be retained.
98.38 Definitions. Table C–1 to Subpart C of Part 98—Default

CO 2 Emission Factors and High Heat Values for Various Types of Fuel Table C–2 to Subpart C of Part 98—Default

CH 4 and N 2 O Emission Factors for Various Types of Fuel

**Subpart D—Electricity Generation**
98.40 Definition of the source category. 98.41 Reporting threshold. 98.42 GHGs to report. 98.43 Calculating GHG emissions. 98.44 Monitoring and QA/QC requirements 98.45 Procedures for estimating missing
data. 98.46 Data reporting requirements.
98.47 Records that must be retained.
98.48 Definitions.

**Subpart E—Adipic Acid Production**
98.50 Definition of source category. 98.51 Reporting threshold. 98.52 GHGs to report. 98.53 Calculating GHG emissions. 98.54 Monitoring and QA/QC requirements 98.55 Procedures for estimating missing
data. 98.56 Data reporting requirements.
98.57 Records that must be retained.
98.58 Definitions.

**Subpart F—Aluminum Production**
98.60 Definition of the source category. 98.61 Reporting threshold. 98.62 GHGs to report. 98.63 Calculating GHG emissions. 98.64 Monitoring and QA/QC requirements. 98.65 Procedures for estimating missing
data. 98.66 Data reporting requirements.
98.67 Records that must be retained.
98.68 Definitions. Table F–1 to Subpart F of Part 98—Slope and Overvoltage Coefficients for the
Calculation of PFC Emissions From
Aluminum Production Table F–2 to Subpart F of Part 98—Default
Data Sources for Parameters Used for

CO 2 Emissions

**Subpart G—Ammonia Manufacturing**
98.70 Definition of source category. 98.71 Reporting threshold. 98.72 GHGs to report. 98.73 Calculating GHG emissions. 98.74 Monitoring and QA/QC requirements. 98.75 Procedures for estimating missing
data. 98.76 Data reporting requirements.
98.77 Records that must be retained. 98.78 Definitions.

**Subpart H—Cement Production**
98.80 Definition of the source category. 98.81 Reporting threshold. 98.82 GHGs to report. 98.83 Calculating GHG emissions. 98.84 Monitoring and QA/QC requirements. 98.85 Procedures for estimating missing
data. 98.86 Data reporting requirements. 98.87 Records that must be retained.
98.88 Definitions.

**Subpart I—[RESERVED]**

**Subpart J—[RESERVED]**

**Subpart K—Ferroalloy Production**
98.110 Definition of the source category. 98.111 Reporting threshold. 98.112 GHGs to report. 98.113 Calculating GHG emissions. 98.114 Monitoring and QA/QC requirements. 98.115 Procedures for estimating missing
data. 98.116 Data reporting requirements.
98.117 Records that must be retained.
98.118 Definitions. Table K–1 to Subpart K of Part 98—Electric Arc Furnace (EAF) CH4 Emission Factors

**Subpart L—[RESERVED]**

**Subpart M—[RESERVED]**

**Subpart N—Glass Production**
98.140 Definition of the source category. 98.141 Reporting threshold. 98.142 GHGs to report. 98.143 Calculating GHG emissions. 98.144 Monitoring and QA/QC requirements. 98.145 Procedures for estimating missing
data. 98.146 Data reporting requirements.
98.147 Records that must be retained.
98.148 Definitions. Table N–1 to Subpart N of Part 98—CO 2 Emission Factors for Carbonate-Based
Raw Materials

**Subpart O—HCFC–22 Production and HFC–**
**23 Destruction**
98.150 Definition of the source category. 98.151 Reporting threshold. 98.152 GHGs to report. 98.153 Calculating GHG emissions. 98.154 Monitoring and QA/QC requirements. 98.155 Procedures for estimating missing
data. 98.156 Data reporting requirements.
98.157 Records that must be retained.
98.158 Definitions. Table O–1 to Subpart O of Part 98—Emission Factors for Equipment Leaks

**Subpart P—Hydrogen Production**
98.160 Definition of the source category. 98.161 Reporting threshold. 98.162 GHGs to report. 98.163 Calculating GHG emissions. 98.164 Monitoring and QA/QC requirements. 98.165 Procedures for estimating missing
data. 98.166 Data reporting requirements.
98.167 Records that must be retained.
98.168 Definitions.

**Subpart Q—Iron and Steel Production**
98.170 Definition of the source category. 98.171 Reporting threshold. 98.172 GHGs to report. 98.173 Calculating GHG emissions. 98.174 Monitoring and QA/QC requirements. 98.175 Procedures for estimating missing
data. 98.176 Data reporting requirements.
98.177 Records that must be retained.
98.178 Definitions.

**Subpart R—Lead Production**
98.180 Definition of the source category. 98.181 Reporting threshold. 98.182 GHGs to report. 98.183 Calculating GHG emissions. 98.184 Monitoring and QA/QC requirements. 98.185 Procedures for estimating missing
data. 98.186 Data reporting procedures.
98.187 Records that must be retained.
98.188 Definitions.

**Subpart S—Lime Manufacturing**
98.190 Definition of the source category. 98.191 Reporting threshold. 98.192 GHGs to report. 98.193 Calculating GHG emissions. 98.194 Monitoring and QA/QC requirements. 98.195 Procedures for estimating missing
data. 98.196 Data reporting requirements.
98.197 Records that must be retained.
98.198 Definitions. Table S–1 to Subpart S of Part 98—Basic
Parameters for the Calculation of
Emission Factors for Lime Production

**Subpart T—[RESERVED]**

**Subpart U—Miscellaneous Uses of**
**Carbonate**
98.210 Definition of the source category. 98.211 Reporting threshold. 98.212 GHGs to report. 98.213 Calculating GHG emissions. 98.214 Monitoring and QA/QC requirements. 98.215 Procedures for estimating missing
data. 98.216 Data reporting requirements.
98.217 Records that must be retained.
98.218 Definitions. Table U–1 to Subpart U of Part 98—CO 2 Emission Factors for Common
Carbonates

**Subpart V—Nitric Acid Production**
98.220 Definition of source category. 98.221 Reporting threshold. 98.222 GHGs to report. 98.223 Calculating GHG emissions. 98.224 Monitoring and QA/QC requirements. 98.225 Procedures for estimating missing
data. 98.226 Data reporting requirements.
98.227 Records that must be retained.
98.228 Definitions.


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**Subpart W—[RESERVED]**

**Subpart X—Petrochemical Production**
98.240 Definition of the source category. 98.241 Reporting threshold. 98.242 GHGs to report. 98.243 Calculating GHG emissions. 98.244 Monitoring and QA/QC requirements. 98.245 Procedures for estimating missing
data. 98.246 Data reporting requirements.
98.247 Records that must be retained.
98.248 Definitions.

**Subpart Y—Petroleum Refineries**
98.250 Definition of source category. 98.251 Reporting threshold. 98.252 GHGs to report. 98.253 Calculating GHG emissions. 98.254 Monitoring and QA/QC requirements. 98.255 Procedures for estimating missing
data. 98.256 Data reporting requirements.
98.257 Records that must be retained.
98.258 Definitions.

**Subpart Z—Phosphoric Acid Production**
98.260 Definition of the source category. 98.261 Reporting threshold. 98.262 GHGs to report. 98.263 Calculating GHG emissions. 98.264 Monitoring and QA/QC requirements. 98.265 Procedures for estimating missing
data. 98.266 Data reporting requirements.
98.267 Records that must be retained.
98.268 Definitions. Table Z–1 to Subpart Z of Part 98—Default Chemical Composition of Phosphate Rock by Origin

**Subpart AA—Pulp and Paper Manufacturing**
98.270 Definition of source category. 98.271 Reporting threshold. 98.272 GHGs to report. 98.273 Calculating GHG emissions. 98.274 Monitoring and QA/QC requirements. 98.275 Procedures for estimating missing
data. 98.276 Data reporting requirements.
98.277 Records that must be retained.
98.278 Definitions. Table AA–1 to Subpart AA of Part 98—Kraft Pulping Liquor Emissions Factors for
Biomass-Based CO 2 , CH 4 , and N 2 O Table AA–2 to Subpart AA of Part 98—Kraft
Lime Kiln and Calciner Emissions
Factors for Fossil Fuel-Based CO 2 , CH 4 , and N 2 O

**Subpart BB—Silicon Carbide Production**
98.280 Definition of the source category. 98.281 Reporting threshold. 98.282 GHGs to report. 98.283 Calculating GHG emissions. 98.284 Monitoring and QA/QC requirements. 98.285 Procedures for estimating missing
data. 98.286 Data reporting requirements.
98.287 Records that must be retained.
98.288 Definitions. **Subpart CC—Soda Ash Manufacturing**
98.290 Definition of the source category. 98.291 Reporting threshold. 98.292 GHGs to report. 98.293 Calculating GHG emissions. 98.294 Monitoring and QA/QC requirements. 98.295 Procedures for estimating missing
data. 98.296 Data reporting requirements.
98.297 Records that must be retained.
98.298 Definitions.

**Subpart DD—[RESERVED]**

**Subpart EE—Titanium Dioxide Production**
98.310 Definition of the source category. 98.311 Reporting threshold. 98.312 GHGs to report. 98.313 Calculating GHG emissions. 98.314 Monitoring and QA/QC requirements. 98.315 Procedures for estimating missing
data. 98.316 Data reporting requirements.
98.317 Records that must be retained.
98.318 Definitions.

**Subpart FF—[RESERVED]**

**Subpart GG—Zinc Production**
98.330 Definition of the source category. 98.331 Reporting threshold. 98.332 GHGs to report. 98.333 Calculating GHG emissions. 98.334 Monitoring and QA/QC requirements. 98.335 Procedures for estimating missing
data. 98.336 Data reporting requirements.
98.337 Records that must be retained.
98.338 Definitions.

**Subpart HH—Municipal Solid Waste**
**Landfills**
98.340 Definition of the source category. 98.341 Reporting threshold. 98.342 GHGs to report. 98.343 Calculating GHG emissions. 98.344 Monitoring and QA/QC requirements. 98.345 Procedures for estimating missing
data. 98.346 Data reporting requirements.
98.347 Records that must be retained.
98.348 Definitions. Table HH–1 to Subpart HH of Part 98— Emissions Factors, Oxidation Factors
and Methods Table HH–2 to Subpart HH of Part 98—U.S. Per Capita Waste Disposal Rates Table HH–3 to Subpart HH of Part 98—
Landfill Gas Collection Efficiencies

**Subpart II—[RESERVED]**

**Subpart JJ—Manure Management**
98.360 Definition of the source category. 98.361 Reporting threshold. 98.362 GHGs to report. 98.363 Calculating GHG emissions. 98.364 Monitoring and QA/QC requirements. 98.365 Procedures for estimating missing
data. 98.366 Data reporting requirements.
98.367 Records that must be retained.
98.368 Definitions. Table JJ–1 to Subpart JJ of Part 98—Animal Population Threshold Level Below which Facilities are not required to report Emissions under Subpart JJ Table JJ–2 to Subpart JJ of Part 98—Waste
Characteristics DataTable JJ–3 to Subpart JJ of Part 98—StateSpecific Volatile Solids (VS) and Nitrogen (N) Excretion Rates for Cattle Table JJ–4 to Subpart JJ of Part 98—Volatile Solids and Nitrogen Removal through Solids Separation Table JJ–5 to Subpart JJ of Part 98—Methane

Conversion Factors Table JJ–6 to Subpart JJ of Part 98—Collection Efficiencies of Anaerobic Digesters Table JJ–7 to Subpart JJ of Part 98—Nitrous Oxide Emission Factors (kg N 2 O–N/kg Kjdl N)

**Subpart KK—[RESERVED]**

**Subpart LL—Suppliers of Coal-based Liquid**

**Fuels**
98.380 Definition of the source category. 98.381 Reporting threshold. 98.382 GHGs to report. 98.383 Calculating GHG emissions. 98.384 Monitoring and QA/QC requirements. 98.385 Procedures for estimating missing
data. 98.386 Data reporting requirements.
98.387 Records that must be retained.
98.388 Definitions.

**Subpart MM—Suppliers of Petroleum**

**Products**
98.390 Definition of the source category. 98.391 Reporting threshold. 98.392 GHGs to report. 98.393 Calculating GHG emissions. 98.394 Monitoring and QA/QC requirements. 98.395 Procedures for estimating missing
data. 98.396 Data reporting requirements.
98.397 Records that must be retained.
98.398 Definitions. Table MM–1 to Subpart MM—Default CO 2 Factors for Petroleum Products Table MM–2 to Subpart MM—Default Factors
for Biomass-Based Fuels and Biomass

**Subpart NN—Suppliers of Natural Gas and Natural Gas Liquids** 
98.400 Definition of the source category. 98.401 Reporting threshold. 98.402 GHGs to report. 98.403 Calculating GHG emissions. 98.404 Monitoring and QA/QC requirements. 98.405 Procedures for estimating missing
data. 98.406 Data reporting requirements.
98.407 Records that must be retained.
98.408 Definitions. Table NN–1 to Subpart NN of Part 98—
Default Factors for Calculation Methodology 1 of this Subpart Table NN–2 to Subpart NN of Part 98— Lookup Default Values for Calculation Methodology 2 of this Subpart

**Subpart OO—Suppliers of Industrial**
**Greenhouse Gases**
98.410 Definition of the source category.


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98.411 Reporting threshold. 98.412 GHGs to report. 98.413 Calculating GHG emissions. 98.414 Monitoring and QA/QC requirements. 98.415 Procedures for estimating missing
data. 98.416 Data reporting requirements.
98.417 Records that must be retained.
98.418 Definitions.

**Subpart PP—Suppliers of Carbon Dioxide**
98.420 Definition of the source category. 98.421 Reporting threshold. 98.422 GHGs to report. 98.423 Calculating CO 2 supply. 98.424 Monitoring and QA/QC requirements. 98.425 Procedures for estimating missing
data. 98.426 Data reporting requirements.
98.427 Records that must be retained.
98.428 Definitions.

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

.
**Subpart A—General Provisions**

**§ 98.1 Purpose and scope.**

(a) This part establishes mandatory greenhouse gas (GHG) reporting requirements for owners and operators of certain facilities that directly emit
GHG as well as for certain fossil fuel suppliers and industrial GHG suppliers. For suppliers, the GHGs reported are the quantity that would be emitted from combustion or use of the products supplied.

(b) Owners and operators of facilities and suppliers that are subject to this part must follow the requirements of subpart A and all applicable subparts of this part. If a conflict exists between a provision in subpart A and any other applicable subpart, the requirements of the subparts B through PP of this part shall take precedence.

**§ 98.2 Who must report?**

(a) The GHG reporting requirements and related monitoring, recordkeeping, and reporting requirements of this part apply to the owners and operators of any facility that is located in the United States and that meets the requirements of either paragraph (a)(1), (a)(2), or (a)(3) of this section; and any supplier that meets the requirements of paragraph (a)(4) of this section:

(1) A facility that contains any source category (as defined in subparts C through JJ of this part) that is listed in this paragraph (a)(1) in any calendar year starting in 2010. For these facilities, the annual GHG report must cover all source categories and GHGs for which calculation methodologies are provided in subparts C through JJ of this part.

(i) Electricity generation (units that report CO 2 emissions year-round through 40 CFR part 75). (ii) Adipic acid production. (iii) Aluminum production. (iv) Ammonia manufacturing. (v) Cement production. (vi) HCFC–22 production. (vii) HFC–23 destruction processes
that are not collocated with a HCFC–22 production facility and that destroy
more than 2.14 metric tons of HFC–23

per year.

(viii) Lime manufacturing. (ix) Nitric acid production. (x) Petrochemical production. (xi) Petroleum refineries. (xii) Phosphoric acid production. (xiii) Silicon carbide production. (xiv) Soda ash production. (xv) Titanium dioxide production. (xvi) Municipal solid waste landfills that generate CH4 in amounts equivalent to 25,000 metric tons CO 2 e or more per year, as determined according to subpart HH of this part.

(xvii) Manure management systems
with combined CH4 and N 2 O emissions in amounts equivalent to 25,000 metric

tons CO 2 e or more per year, as determined according to subpart JJ of this part.

(2) A facility that contains any source category (as defined in subparts C through JJ of this part) that is listed in this paragraph (a)(2) in any calendar year starting in 2010 and that emits 25,000 metric tons CO 2 e or more per year in combined emissions from stationary fuel combustion units, miscellaneous uses of carbonate, and all source categories that are listed in this paragraph. For these facilities, the annual GHG report must cover all source categories and GHGs for which calculation methodologies are provided in subparts C through JJ of this part.

(i) Ferroalloy Production. (ii) Glass Production. (iii) Hydrogen Production. (iv) Iron and Steel Production. (v) Lead Production. (vi) Pulp and Paper Manufacturing. (vii) Zinc Production. (3) A facility that in any calendar year starting in 2010 meets all three of the conditions listed in this paragraph (a)(3) . For these facilities, the annual GHG report must cover emissions from stationary fuel combustion sources only.

(i) The facility does not meet the requirements of either paragraph (a)(1) or (a)(2) of this section.

(ii) The aggregate maximum rated heat input capacity of the stationary fuel combustion units at the facility is 30 mmBtu/hr or greater.

(iii) The facility emits 25,000 metric

tons CO 2 e or more per year in combined emissions from all stationary fuel
combustion sources.

(4) A supplier (as defined in subparts KK through PP of this part) that provides products listed in this paragraph (a)(4) in any calendar year starting in 2010. For these suppliers, the annual GHG report must cover all applicable products for which calculation methodologies are provided in subparts KK through PP of this part.

(i) Coal-to-liquids suppliers, as specified in this paragraph (a)(4)(i).

(A) All producers of coal-to-liquid products.

(B) Importers of an annual quantity of coal-to-liquid products that is equivalent to 25,000 metric tons CO 2 e or

more.

(C) Exporters of an annual quantity of coal-to-liquid products is equivalent to 25,000 metric tons CO 2 e or more.

(ii) Petroleum product suppliers, as specified in this paragraph (a)(4)(ii):

(A) All petroleum refineries that
distill crude oil.

(B) Importers of an annual quantity of petroleum products that is equivalent to 25,000 metric tons CO 2 e or more.

(C) Exporters of an annual quantity of petroleum products that is equivalent to 25,000 metric tons CO 2 e or more.

(iii) Natural gas and natural gas liquids suppliers, as specified in this paragraph (a)(4)(iii):

(A) All natural gas fractionators. (B) All local natural gas distribution companies.

(iv) Industrial greenhouse gas suppliers, as specified in this paragraph (a)(4)(iv):

(A) All producers of industrial greenhouse gases.

(B) Importers of industrial greenhouse gases with annual bulk imports of N 2 O, fluorinated GHG, and CO 2 that in combination are equivalent to 25,000

metric tons CO 2 e or more.

(C) Exporters of industrial greenhouse gases with annual bulk exports of N 2 O, fluorinated GHG, and CO 2 that in combination are equivalent to 25,000

metric tons CO 2 e or more.

(v) Carbon dioxide suppliers, as specified in this paragraph (a)(4)(v).

(A) All producers of CO 2
. (B) Importers of CO 2 with annual bulk imports of N 2 O, fluorinated GHG, and

CO 2 that in combination are equivalent to 25,000 metric tons CO 2 e or more.

(C) Exporters of CO 2 with annual bulk exports of N 2 O, fluorinated GHG, and

CO 2 that in combination are equivalent to 25,000 metric tons CO 2 e or more.

(5) Research and development activities are not considered to be part of any source category defined in this part.

(b) To calculate GHG emissions for comparison to the 25,000 metric ton

CO 2 e per year emission threshold in paragraph (a)(2) of this section, the owner or operator shall calculate annual


### 56378 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

CO 2 e emissions, as described in paragraphs (b)(1) through (b)(4) of this

section.

(1) Calculate the annual emissions of

CO 2 , CH 4 , N 2 O,and each fluorinated GHG in metric tons from all applicable source categories listed in paragraph (a)(2) of this section. The GHG emissions shall be calculated using the calculation methodologies specified in each applicable subpart and available company records. Include emissions from only those gases listed in Table A– 1 of this subpart.

(2) For each general stationary fuel combustion unit, calculate the annual

CO 2 emissions in metric tons using any of the four calculation methodologies specified in § 98.33(a). Calculate the
annual CH4 and N 2 O emissions from the stationary fuel combustion sources in metric tons using the appropriate equation in § 98.33(c). Exclude carbon
dioxide emissions from the combustion of biomass, but include emissions of

CH 4 and N 2 O from biomass combustion.

(3) For miscellaneous uses of carbonate, calculate the annual CO 2 emissions in metric tons using the procedures specified in subpart U of this part.

(4) Sum the emissions estimates from paragraphs (b)(1), (b)(2), and (b)(3) of
this section for each GHG and calculate
metric tons of CO 2 e using Equation A–
1 of this section.



### CO e GHG x GWP i i

i n

2

1 

### =

=



# ∑ (Eq. A-1)

Where:

CO 2 e = Carbon dioxide equivalent, metric tons/year.

GHGi = Mass emissions of each greenhouse gas listed in Table A–1 of this subpart, metric tons/year.

GWP i = Global warming potential for each greenhouse gas from Table A–1 of this subpart. n = The number of greenhouse gases emitted.

(5) For purpose of determining if an emission threshold has been exceeded, include in the emissions calculation any

CO 2 that is captured for transfer off site.

(c) To calculate GHG emissions for comparison to the 25,000 metric ton

CO 2 e/year emission threshold for stationary fuel combustion under paragraph (a)(3) of this section, calculate

CO 2 , CH 4 , and N 2 O emissions from each stationary fuel combustion unit by following the methods specified in paragraph (b)(2) of this section. Then,
convert the emissions of each GHG to

metric tons CO 2 e per year using Equation A–1 of this section, and sum the emissions for all units at the facility.

(d) To calculate GHG quantities for comparison to the 25,000 metric ton CO 2 per year threshold for importers and exporters of coal-to-liquid products under paragraph (a)(4)(i) of this section, calculate the mass in metric tons per year of CO 2 that would result from the complete combustion or oxidation of the quantity of coal-to-liquid products that are imported during the reporting year and that are exported during the reporting year. Calculate the emissions using the methodology specified in subpart LL of this part.

(e) To calculate GHG quantities for comparison to the 25,000 metric ton

CO 2 e per year threshold for importers and exporters of petroleum products under paragraph (a)(4)(ii) of this section, calculate the mass in metric tons per year of CO 2 that would result from the complete combustion or oxidation of the volume of petroleum products and natural gas liquids that are imported during the reporting year and that are exported during the reporting year. Calculate the emissions using the methodology specified in subpart MM of this part.

(f) To calculate GHG quantities for comparison to the 25,000 metric ton

CO 2 e per year threshold under paragraph (a)(4) of this section for importers and exporters of industrial greenhouse gases and for importers and exporters of CO 2, the owner or operator
shall calculate the mass in metric tons per year of CO 2 e imports and exports as described in paragraphs (f)(1) through (f)(3) of this section.

(1) Calculate the mass in metric tons per year of CO 2 , N 2 O, and each fluorinated GHG that is imported and the mass in metric tons per year of CO 2 , N 2 O, and each fluorinated GHG that is exported during the year. Include only those gases listed in Table A–1 of this subpart.

(2) Convert the mass of each imported and each GHG exported from paragraph (f)(1) of this section to metric tons of

CO 2 e using Equation A–1 of this section.

(3) Sum the total annual metric tons
of CO 2 e in paragraph (f)(2) of this section for all imported GHGs. Sum the
total annual metric tons of CO 2 e in paragraph (f)(2) of this section for all exported GHGs.

(g) If a capacity or generation reporting threshold in paragraph (a)(1) of this section applies, the owner or operator shall review the appropriate records and perform any necessary
calculations to determine whether the
threshold has been exceeded.

(h) An owner or operator of a facility or supplier that does not meet the applicability requirements of paragraph (a) of this section is not subject to this rule. Such owner or operator would become subject to the rule and reporting requirements § 98.3(b)(3), if a facility or supplier exceeds the applicability requirements of paragraph (a) of this section at a later time. Thus, the owner or operator should reevaluate the applicability to this part (including the revising of any relevant emissions calculations or other calculations) whenever there is any change that could cause a facility or supplier to meet the applicability requirements of paragraph (a) of this section. Such changes include but are not limited to process modifications, increases in operating hours, increases in production, changes in fuel or raw material use, addition of equipment, and facility expansion.

(i) Except as provided in this paragraph, once a facility or supplier is subject to the requirements of this part, the owner or operator must continue for each year thereafter to comply with all requirements of this part, including the requirement to submit annual GHG reports, even if the facility or supplier does not meet the applicability requirements in paragraph (a) of this section in a future year.

(1) If reported emissions are less than 25,000 metric tons CO 2 e per year for five consecutive years, then the owner or operator may discontinue complying with this part provided that the owner or operator submits a notification to the
Administrator that announces the cessation of reporting and explains the
reasons for the reduction in emissions.
The notification shall be submitted no later than March 31 of the year immediately following the fifth consecutive year of emissions less than 25,000 tons CO 2 e per year. The owner or operator must maintain the corresponding records required under § 98.3(g) for each of the five consecutive years and retain such records for three years following the year that reporting
was discontinued. The owner or operator must resume reporting if annual emissions in any future calendar year increase to 25,000 metric tons CO 2 e
per year or more.

(2) If reported emissions are less than 15,000 metric tons CO 2 e per year for three consecutive years, then the owner or operator may discontinue complying with this part provided that the owner or operator submits a notification to the
Administrator that announces the cessation of reporting and explains the
reasons for the reduction in emissions.
The notification shall be submitted no later than March 31 of the year immediately following the third consecutive year of emissions less than 15,000 tons CO 2 e per year. The owner or operator must maintain the corresponding records required under § 98.3(g) for each of the three


### 56379 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

consecutive years and retain such records for three years following the year that reporting was discontinued. The owner or operator must resume reporting if annual emissions in any future calendar year increase to 25,000

metric tons CO 2 e per year or more.

(3) If the operations of a facility or supplier are changed such that all applicable GHG-emitting processes and operations listed in paragraphs (a)(1) through (a)(4) of this section cease to operate, then the owner or operator is exempt from reporting in the years following the year in which cessation of such operations occurs, provided that the owner or operator submits a
notification to the Administrator that announces the cessation of reporting
and certifies to the closure of all GHGemitting processes and operations. This paragraph (i)(2) does not apply to seasonal or other temporary cessation of operations. This paragraph (i)(2) does not apply to facilities with municipal
solid waste landfills. The owner or operator must resume reporting for any future calendar year during which any of the GHG-emitting processes or operations resume operation.

(j) Table A–2 of this subpart provides
a conversion table for some of the common units of measure used in part

98.

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

The owner or operator of a facility or supplier that is subject to the requirements of this part must submit GHG reports to the Administrator, as specified in this section.

(a) General . Except as provided in paragraph (d) of this section, follow the procedures for emission calculation, monitoring, quality assurance, missing data, recordkeeping, and reporting that are specified in each relevant subpart of this part.

(b) Schedule . The annual GHG report
must be submitted no later than March 31 of each calendar year for GHG emissions in the previous calendar year.

(1) For an existing facility or supplier that began operation before January 1, 2010, report emissions for calendar year 2010 and each subsequent calendar

year.

(2) For a new facility or supplier that begins operation on or after January 1, 2010, report emissions beginning with the first operating month and ending on December 31 of that year. Each subsequent annual report must cover emissions for the calendar year, beginning on January 1 and ending on
December 31. (3) For any facility or supplier that becomes subject to this rule because of a physical or operational change that is made after January 1, 2010, report emissions for the first calendar year in which the change occurs, beginning with the first month of the change and ending on December 31 of that year. For a facility or supplier that becomes subject to this rule solely because of an increase in hours of operation or level of production, the first month of the change is the month in which the increased hours of operation or level of production, if maintained for the remainder of the year, would cause the facility or supplier to exceed the applicable threshold. Each subsequent annual report must cover emissions for the calendar year, beginning on January 1 and ending on December 31.

(c) Content of the annual report

. Except as provided in paragraph (d) of this section, each annual GHG report shall contain the following information:

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

(2) Year and months covered by the report.

(3) Date of submittal. (4) For facilities, report annual
emissions of CO 2, CH 4, N 2 O, and each fluorinated GHG (as defined in § 98.6) as
follows:

(i) Annual emissions (excluding biogenic CO 2 ) aggregated for all GHG from all applicable source categories in subparts C through JJ of this part and expressed in metric tons of CO 2 e calculated using Equation A–1 of this subpart.

(ii) Annual emissions of biogenic CO 2 aggregated for all applicable source categories in subparts C through JJ of this part.

(iii) Annual emissions from each applicable source category in subparts C through JJ of this part, expressed in
metric tons of each GHG listed in paragraphs (c)(4)(iii)(A) through (c)(4)(iii)(E) of this section.

(A) Biogenic CO 2
. (B) CO 2 (excluding biogenic CO 2 ). (C) CH4
. (D) N 2 O. (E) Each fluorinated GHG (including
those not listed in Table A–1 of this subpart).

(iv) Emissions and other data for individual units. processes, activities, and operations as specified in the ‘‘Data reporting requirements’’ section of each applicable subpart of this part.

(5) For suppliers, report annual quantities of CO 2, CH 4, N 2 O, and each fluorinated GHG (as defined in § 98.6)
that would be emitted from combustion or use of the products supplied, imported, and exported during the year. Calculate and report quantities at the following levels:

(i) Total quantity of GHG aggregated for all GHG from all applicable supply categories in subparts KK through PP of this part and expressed in metric tons of

CO 2 e calculated using Equation A–1 of this subpart.

(ii) Quantity of each GHG from each applicable supply category in subparts KK through PP of this part, expressed in
metric tons of each GHG. For fluorinated GHG, report emissions of all fluorinated GHG, including those not listed in Table A–1 of this subpart.

(iii) Any other data specified in the ‘‘Data reporting requirements’’ section of each applicable subpart of this part.

(6) A written explanation, as required under § 98.3(e), if you change emission calculation methodologies during the reporting period.

(7) A brief description of each ‘‘best available monitoring method’’ used according to paragraph (d) of this section, the parameter measured using the method, and the time period during which the ‘‘best available monitoring
method’’ was used.

(8) 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.

(9) A signed and dated certification statement provided by the designated representative of the owner or operator, according to the requirements of § 98.4(e)(1).

(d) Special provisions for reporting year 2010.

(1) Best available monitoring
methods . During January 1, 2010 through March 31, 2010, owners or operators 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 owner or operator must use the calculation methodologies 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 owner or operator must discontinue using best available methods and begin following all applicable monitoring and QA/QC requirements of this part, except as


### 56380 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

provided in paragraphs (d)(2) and (d)(3)
of this section. Best available monitoring methods means any of the following methods specified in this paragraph:

(i) Monitoring methods currently used by the facility that do not meet the specifications of an relevant subpart.

(ii) Supplier data. (iii) Engineering calculations. (iv) Other company records. (2) Requests for extension of the use of best available monitoring methods

. The owner or operator may submit a request to the Administrator to use one or more best available monitoring methods beyond March 31, 2010.

(i) Timing of request. The extension request must be submitted to EPA no later than 30 days after the effective date of the GHG reporting rule.

(ii) Content of request. Requests must contain the following information:

(A) 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.

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

(C) A description of the reasons why the needed equipment could not be obtained and installed before April 1,

2010.

(D) 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.

(E) 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 practicable to isolate the equipment and install the monitoring instrument without a full process unit shutdown. 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 part and April 1, 2010, include a justification of why the equipment
could not be obtained and installed during that shutdown. (F) 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.

(iii) Approval criteria . To obtain approval, the owner or operator must
demonstrate 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. The use of
best available methods will not be approved beyond December 31, 2010.

(3) Abbreviated emissions report for facilities containing only general stationary fuel combustion sources . In lieu of the report required by paragraph (c) of this section, the owner or operator of an existing facility that is in operation on January 1, 2010 and that meets the conditions of § 98.2 (a)(3) may submit an abbreviated GHG report for the facility for GHGs emitted in 2010. The abbreviated report must be submitted by March 31, 2011. An owner or operator that submits an abbreviated report must submit a full GHG report according to the requirements of paragraph (c) of this section beginning in calendar year 2011. The abbreviated facility report must include the following information:

(i) Facility name and physical street address including the city, state and zip
code.

(ii) The year and months covered by the report.

(iii) Date of submittal. (iv) Total facility GHG emissions aggregated for all stationary fuel combustion units calculated according to any method specified in § 98.33(a) and expressed in metric tons of CO 2, CH 4, N 2 O, and CO 2 e.

(v) Any facility operating data or process information used for the GHG
emission calculations.

(vi) A signed and dated certification statement provided by the designated representative of the owner or operator, according to the requirements of paragraph (e)(1) of this section.

(e) Emission calculations . In preparing the GHG report, you must use the calculation methodologies specified in the relevant subparts, except as specified in paragraph (d) of this section. For each source category, you
must use the same calculation methodology throughout a reporting period unless you provide a written explanation of why a change in methodology was required.

(f) Verification . To verify the completeness and accuracy of reported GHG emissions, the Administrator may
review the certification statements described in paragraphs (c)(8) and (d)(3)(vi) of this section and any other credible evidence, in conjunction with a comprehensive review of the GHG reports and periodic audits of selected reporting facilities. Nothing in this section prohibits the Administrator from using additional information to verify the completeness and accuracy of the reports.

(g) Recordkeeping. An owner or operator that is required to report GHGs under this part must keep records as specified in this paragraph. Retain all required records for at least 3 years. The records shall be kept in an electronic or hard-copy format (as appropriate) and
recorded in a form that is suitable for expeditious inspection and review. Upon request by the Administrator, the records required under this section must be made available to EPA. Records may
be retained off site if the records are readily available for expeditious inspection and review. For records that are electronically generated or maintained, the equipment or software necessary to read the records shall be made available, or, if requested by EPA,
electronic records shall be converted to paper documents. You must retain the following records, in addition to those records prescribed in each applicable subpart of this part:

(1) A list of all units, operations, processes, and activities for which GHG
emission were calculated.

(2) 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 following information in this paragraph (g)(2):

(i) The GHG emissions calculations
and methods used.

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

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

(iv) Any facility operating data or process information used for the GHG
emission calculations.

(3) The annual GHG reports. (4) 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.

(5) A written GHG Monitoring Plan. (i) At a minimum, the GHG Monitoring Plan shall include the elements listed in this paragraph (g)(5)(i).


### 56381 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

(A) Identification of positions of responsibility (i.e., job titles) for
collection of the emissions data.

(B) Explanation of the processes and methods used to collect the necessary
data for the GHG calculations.

(C) Description of the procedures and methods that are used for quality assurance, maintenance, and repair of all continuous monitoring systems, flow meters, and other instrumentation used to provide data for the GHGs reported under this part.

(ii) The GHG Monitoring Plan may rely on references to existing corporate documents (e.g., standard operating procedures, quality assurance programs under appendix F to 40 CFR part 60 or appendix B to 40 CFR part 75, and other documents) provided that the elements required by paragraph (g)(5)(i) of this section are easily recognizable.

(iii) The owner or operator shall revise the GHG Monitoring Plan as needed to reflect changes in production processes, monitoring instrumentation, and quality assurance procedures; or to improve procedures for the maintenance and repair of monitoring systems to reduce the frequency of monitoring equipment downtime.

(iv) Upon request by the Administrator, the owner or operator
shall make all information that is
collected in conformance with the GHG Monitoring Plan available for review during an audit. Electronic storage of the information in the plan is permissible, provided that the
information can be made available in hard copy upon request during an audit.

(6) The results of all required certification and quality assurance tests of continuous monitoring systems, fuel flow meters, and other instrumentation used to provide data for the GHGs reported under this part.

(7) Maintenance records for all continuous monitoring systems, flow meters, and other instrumentation used to provide data for the GHGs reported under this part.

(h) Annual GHG report revisions . The owner or operator shall submit a revised report within 45 days of discovering or being notified by EPA of errors in an annual GHG report. The revised report
must correct all identified errors. The owner or operator shall retain documentation for 3 years to support any revisions made to an annual GHG report.

(i) Calibration accuracy requirements

. The owner or operator of a facility or supplier that is subject to the requirements of this part must meet the calibration accuracy requirements of this paragraph (i). (1) Except as provided paragraphs (i)(4) through (i)(6) of this section, flow meters and other devices (e.g., belt scales) that measure data used to
calculate GHG emissions shall be calibrated prior to April 1, 2010 using the procedures specified in this paragraph and each relevant subpart of this part. All measurement devices must be calibrated according to the
manufacturer’s recommended procedures, an appropriate industry consensus standard, or a method specified in a relevant subpart of this part. All measurement devices shall be calibrated to an accuracy of 5 percent. For facilities and suppliers that become subject to this part after April 1, 2010,
the initial calibration shall be conducted
on the date that data collection is required to begin. Subsequent calibrations shall be performed at the frequency specified in each applicable subpart.

(2) For flow meters, perform all calibrations at measurement points that are representative of normal operation of the meter. Except for the orifice, nozzle, and venturi flow meters described in paragraph (i)(3) of this section, calculate the calibration error at each measurement point using Equation
A–2 of this section. The terms ‘‘R’’ and ‘‘A’’ in Equation A–2 must be expressed in consistent units of measure (e.g., gallons/minute, ft 3 /min). The
calibration error at each measurement point shall not exceed 5.0 percent of the
reference value.



### CE R A

R x 100 (Eq. A-2) = −

Where:
CE = Calibration error (%)
R = Reference value A = Flow meter response to the reference
value
(3) For orifice, nozzle, and venturi flow meters, the initial quality
assurance consists of in-situ calibration of the differential pressure (delta-P), total pressure, and temperature
transmitters. Calibrate each transmitter at a zero point and at least one upscale point. Fixed reference points, such as the freezing point of water, may be used for temperature transmitter calibrations.
Calculate the calibration error of each transmitter at each measurement point, using Equation A–3 of this subpart. The terms ‘‘R’’, ‘‘A’’, and ‘‘FS’’ in Equation A–3 of this subpart must be in consistent units of measure (e.g., milliamperes, inches of water, psi, degrees). For each transmitter, the CE value at each measurement point shall not exceed 2.0 percent of full-scale. Alternatively, the results are acceptable if the sum of the calculated CE values
for the three transmitters at each calibration level (i.e., at the zero level and at each upscale level) does not exceed 5.0 percent.



### CE R A

FS x 100 (Eq. A-3) = −

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

(4) Fuel billing meters are exempted from the calibration requirements of this section, provided that the fuel supplier and any unit combusting the fuel do not have any common owners and are not owned by subsidiaries or affiliates of the

same company.

(5) For a flow meter or other
measurement device that has been previously calibrated in accordance with this part, an initial calibration is not required by the date specified in paragraph (i)(1) of this section if, as of the date required for the initial calibration, the previous calibration is still active (i.e., the device is not yet due
for recalibration because the time
interval between successive calibrations, as required by this part, has not elapsed).

(6) For units and processes that operate continuously with infrequent outages, it may not be possible to meet the April 1, 2010 deadline for the initial
calibration of a flow meter or other measurement device without removing the device from service and shipping it to a remote location, thereby disrupting normal process operation. In such cases, the owner or operator may postpone the
initial calibration until the next scheduled maintenance outage, and may similarly postpone the subsequent recalibrations. Such postponements shall be documented in the monitoring plan that is required under § 98.3(g)(5).

**§ 98.4 Authorization and responsibilities of the designated representative.** 

(a) General. Except as provided under paragraph (f) of this section, each facility, and each supplier, that is subject to this part, shall have one and only one designated representative, who shall be responsible for certifying, signing, and submitting GHG emissions reports and any other submissions for such facility and supplier respectively to the Administrator under this part. If the facility is required under any other part of title 40 of the Code of Federal Regulations to submit to the Administrator any other emission report that is subject to any requirement in 40


### 56382 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

CFR part 75, the same individual shall be the designated representative responsible for certifying, signing, and submitting the GHG emissions reports and all such other emissions reports under this part.

(b) Authorization of a designated representative. The designated representative of the facility or supplier shall be an individual selected by an agreement binding on the owners and operators of such facility or supplier
and shall act in accordance with the certification statement in paragraph (i)(4)(iv) of this section.

(c) Responsibility of the designated representative. Upon receipt by the Administrator of a complete certificate of representation under this section for a facility or supplier, the designated representative identified in such certificate of representation shall represent and, by his or her representations, actions, inactions, or submissions, legally bind each owner and operator of such facility or supplier in all matters pertaining to this part, notwithstanding any agreement between the designated representative and such owners and operators. The owners and operators shall be bound by any
decision or order issued to the designated representative by the
Administrator or a court.

(d) Timing. No GHG emissions report or other submissions under this part for a facility or supplier will be accepted
until the Administrator has received a complete certificate of representation under this section for a designated representative of the facility or supplier. Such certificate of representation shall be submitted at least 60 days before the deadline for submission of the facility’s or supplier’s initial emission report under this part.

(e) Certification of the GHG emissions report. Each GHG emission report and any other submission under this part for a facility or supplier shall be certified, signed, and submitted by the designated representative or any alternate designated representative of the facility or supplier in accordance with this section and § 3.10 of this chapter.

(1) Each such submission shall include the following certification statement signed by the designated representative or any alternate designated representative: ‘‘I am
authorized to make this submission on behalf of the owners and operators of the facility or supplier, as applicable, for which the submission is made. I certify under penalty of law that I have personally examined, and am familiar with, the statements and information
submitted in this document and all its attachments. Based on my inquiry of those individuals with primary responsibility for obtaining the information, I certify that the statements and information are to the best of my knowledge and belief true, accurate, and complete. I am aware that there are significant penalties for submitting false statements and information or omitting required statements and information, including the possibility of fine or imprisonment.’’

(2) The Administrator will accept a GHG emission report or other submission for a facility or supplier under this part only if the submission is certified, signed, and submitted in
accordance with this section.

(f) Alternate designated representative . A certificate of representation under this section for a facility or supplier may designate one alternate designated representative, who shall be an individual selected by an agreement binding on the owners and operators, and may act on behalf of the designated representative, of such facility or supplier. The agreement by which the alternate designated representative is selected shall include a procedure for authorizing the alternate designated representative to act in lieu of the designated representative.

(1) Upon receipt by the Administrator of a complete certificate of representation under this section for a facility or supplier identifying an alternate designated representative.

(i) The alternate designated representative may act on behalf of the designated representative for such facility or supplier.

(ii) Any representation, action, inaction, or submission by the alternate designated representative shall be deemed to be a representation, action, inaction, or submission by the designated representative.

(2) Except in this section, whenever the term ‘‘designated representative’’ is used in this part, the term shall be construed to include the designated representative or any alternate designated representative.

(g) Changing a designated representative or alternate designated representative . The designated representative or alternate designated representative identified in a complete certificate of representation under this section for a facility or supplier received by the Administrator may be changed at any time upon receipt by the Administrator of another later signed, complete certificate of representation under this section for the facility or supplier. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous designated representative or the previous alternate designated representative of the facility or supplier
before the time and date when the Administrator receives such later signed certificate of representation shall be binding on the new designated representative and the owners and operators of the facility or supplier.

(h) Changes in owners and operators

. In the event an owner or operator of the facility or supplier is not included in the list of owners and operators in the certificate of representation under this section for the facility or supplier, such owner or operator shall be deemed to be subject to and bound by the certificate of representation, the representations, actions, inactions, and submissions of the designated representative and any alternate designated representative of the facility or supplier, as if the owner or operator were included in such list. Within 90 days after any change in the owners and operators of the facility or supplier (including the addition of a new owner or operator), the designated representative or any alternate designated representative shall submit a certificate of representation that is complete under this section except that
such list shall be amended to reflect the change. If the designated representative or alternate designated representative determines at any time that an owner or operator of the facility or supplier is not
included in such list and such exclusion is not the result of a change in the owners and operators, the designated representative or any alternate designated representative shall submit, within 90 days of making such determination, a certificate of representation that is complete under this section except that such list shall be
amended to include such owner or operator.

(i) Certificate of representation . A certificate of representation shall be complete if it includes the following elements in a format prescribed by the
Administrator in accordance with this

section:

(1) Identification of the facility or supplier for which the certificate of representation is submitted.

(2) The name, address, e-mail address (if any), telephone number, and facsimile transmission number (if any) of the designated representative and any alternate designated representative.

(3) A list of the owners and operators of the facility or supplier identified in paragraph (i)(1) of this section, provided that, if the list includes the operators of the facility or supplier and the owners with control of the facility or supplier, the failure to include any other owners
shall not make the certificate of representation incomplete.


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(4) The following certification statements by the designated representative and any alternate designated representative:

(i) ‘‘I certify that I was selected as the designated representative or alternate designated representative, as applicable, by an agreement binding on the owners and operators of the facility or supplier, as applicable.’’

(ii) ‘‘I certify that I have all the necessary authority to carry out my duties and responsibilities under 40 CFR part 98 on behalf of the owners and operators of the facility or supplier, as applicable, and that each such owner and operator shall be fully bound by my representations, actions, inactions, or
submissions.’’

(iii) ‘‘I certify that the owners and operators of the facility or supplier, as applicable, shall be bound by any order issued to me by the Administrator or a court regarding the facility or supplier.’’

(iv) ‘‘If there are multiple owners and operators of the facility or supplier, as applicable, I certify that I have given a written notice of my selection as the ‘designated representative’ or ‘alternate designated representative’, as applicable, and of the agreement by
which I was selected to each owner and operator of the facility or supplier.’’

(5) The signature of the designated representative and any alternate designated representative and the dates signed.

(j) Documents of agreement. Unless otherwise required by the Administrator, documents of agreement
referred to in the certificate of representation shall not be submitted to
the Administrator. The Administrator shall not be under any obligation to review or evaluate the sufficiency of such documents, if submitted.

(k) Binding nature of the certificate of representation . Once a complete certificate of representation under this section for a facility or supplier has been received, the Administrator will rely on the certificate of representation unless and until a later signed, complete certificate of representation under this section for the facility or supplier is received by the Administrator.

(l) Objections Concerning a Designated Representative

(1) Except as provided in paragraph (g) of this section, no objection or other
communication submitted to the Administrator concerning the authorization, or any representation, action, inaction, or submission, of the designated representative or alternate designated representative shall affect any representation, action, inaction, or submission of the designated representative or alternate designated representative, or the finality of any decision or order by the Administrator under this part.

(2) The Administrator will not adjudicate any private legal dispute concerning the authorization or any representation, action, inaction, or submission of any designated representative or alternate designated representative.

(m) Delegation by designated representative and alternate designated representative

.

(1) A designated representative or an alternate designated representative may delegate his or her own authority, to one or more individuals, to submit an
electronic submission to the Administrator provided for or required under this part, except for a submission under this paragraph.

(2) In order to delegate his or her own authority, to one or more individuals, to
submit an electronic submission to the
Administrator in accordance with paragraph (m)(1) of this section, the designated representative or alternate designated representative must submit electronically to the Administrator a notice of delegation, in a format prescribed by the Administrator, that includes the following elements:

(i) The name, address, e-mail address (if any), telephone number, and facsimile transmission number (if any) of such designated representative or alternate designated representative.

(ii) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of each such individual (referred to as an ‘‘agent’’).

(iii) For each such individual, a list of the type or types of electronic submissions under paragraph (m)(1) of this section for which authority is delegated to him or her.

(iv) For each type of electronic
submission listed in accordance with paragraph (m)(2)(iii) of this section, the facility or supplier for which the electronic submission may be made.

(v) The following certification statements by such designated representative or alternate designated representative:

(A) ‘‘I agree that any electronic
submission to the Administrator that is by an agent identified in this notice of delegation and of a type listed, and for a facility or supplier designated, for such agent in this notice of delegation
and that is made when I am a designated representative or alternate designated representative, as applicable, and before this notice of delegation is superseded by another notice of delegation under § 98.4(m)(3) shall be deemed to be an electronic submission certified, signed, and submitted by me.’’

(B) ‘‘Until this notice of delegation is superseded by a later signed notice of delegation under § 98.4(m)(3), I agree to
maintain an e-mail account and to notify the Administrator immediately of any change in my e-mail address unless all delegation of authority by me under § 98.4(m) is terminated.’’

(vi) The signature of such designated representative or alternate designated representative and the date signed.

(3) A notice of delegation submitted in accordance with paragraph (m)(2) of this section shall be effective, with regard to the designated representative or alternate designated representative identified in such notice, upon receipt of such notice by the Administrator and until receipt by the Administrator of another such notice that was signed later by such designated representative or alternate designated representative, as applicable. The later signed notice of delegation may replace any previously identified agent, add a new agent, or eliminate entirely any delegation of authority.

(4) Any electronic submission covered by the certification in paragraph (m)(2)(iv)(A) of this section and made in accordance with a notice of delegation effective under paragraph (m)(3) of this
section shall be deemed to be an electronic submission certified, signed, and submitted by the designated representative or alternate designated representative submitting such notice of delegation.

**§ 98.5 How is the report submitted?**

Each GHG report and certificate of representation for a facility or supplier must be submitted electronically in accordance with the requirements of § 98.4 and in a format specified by the
Administrator.

**§ 98.6 Definitions.**

All terms used in this part shall have the same meaning given in the Clean Air
Act and in this section.

Accuracy of a measurement at a specified level (e.g., one percent of full scale or one percent of the value measured) means that the mean of repeat measurements made by a device or technique are within 95 percent of the range bounded by the true value plus or minus the specified level.

Acid Rain Program means the program established under title IV of the Clean Air Act, and implemented under parts 72 through 78 of this chapter for
the reduction of sulfur dioxide and nitrogen oxides emissions.

Administrator means the
Administrator of the United States


### 56384 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

Environmental Protection Agency or the
Administrator’s authorized representative.

AGA means the American Gas

Association

Alkali bypass means a duct between
the feed end of the kiln and the preheater tower through which a portion of the kiln exit gas stream is withdrawn and quickly cooled by air or water to avoid excessive buildup of alkali, chloride and/or sulfur on the raw feed. This may also be referred to as the ‘‘kiln exhaust gas bypass.’’

Anaerobic digester means the system
where wastes are collected and anaerobically digested in large containment vessels or covered lagoons. Anaerobic digesters stabilize waste by the microbial reduction of complex organic compounds to CO2 and CH4, which is captured and may be flared or used as fuel. Anaerobic digestion systems, include but are not limited to covered lagoon, complete mix, plug flow, and fixed film digesters.

Anaerobic lagoon means a type of liquid storage system component, either at manure management system or a wastewater treatment system, that is designed and operated to stabilize wastes using anaerobic microbial processes. Anaerobic lagoons may be designed for combined stabilization and storage with varying lengths of retention time (up to a year or greater), depending on the climate region, the volatile solids loading rate, and other operational
factors.

Anode effect is a process upset condition of an aluminum electrolysis cell caused by too little alumina dissolved in the electrolyte. The anode effect begins when the voltage rises rapidly and exceeds a threshold voltage, typically 8 volts.

Anode Effect Minutes per Cell Day (24 hours) are the total minutes during which an electrolysis cell voltage is above the threshold voltage, typically 8
volts.

ANSI means the American National
Standards Institute.

API means the American Petroleum

Institute.

Argon-oxygen decarburization (AOD)
vessel means any closed-bottom, refractory-lined converter vessel with submerged tuyeres through which gaseous mixtures containing argon and oxygen or nitrogen may be blown into molten steel for further refining to
reduce the carbon content of the steel.

ASABE means the American Society of Agricultural and Biological Engineers.

ASME means the American Society of Mechanical Engineers. ASTM means the American Society of Testing and Materials.

Asphalt means a dark brown-to-black cement-like material obtained by petroleum processing and containing bitumens as the predominant component. It includes crude asphalt as well as the following finished products: cements, fluxes, the asphalt content of emulsions (exclusive of water), and petroleum distillates blended with asphalt to make cutback asphalts.

Aviation Gasoline means a complex mixture of volatile hydrocarbons, with or without additives, suitably blended to be used in aviation reciprocating engines. Specifications can be found in ASTM Specification D910–07a, Standard Specification for Aviation Gasolines (incorporated by reference, see § 98.7).

B0 means the maximum CH4 producing capacity of a waste stream, kg

CH 4 /kg COD.

Basic oxygen furnace means anyrefractory-lined vessel in which highpurity oxygen is blown under pressure through a bath of molten iron, scrap metal, and fluxes to produce steel.

bbl means barrel. Biodiesel means a mono-akyl ester derived from biomass and conforming to ASTM D6751–08, Standard Specification for Biodiesel Fuel Blend Stock (B100) for Middle Distillate Fuels.

Biogenic CO2 means carbon dioxide emissions generated as the result of
biomass combustion from combustion
units for which emission calculations are required by an applicable part 98 subpart.

Biomass means non-fossilized and biodegradable organic material originating from plants, animals or micro-organisms, including products, by-products, residues and waste from agriculture, forestry and related
industries as well as the non-fossilized and biodegradable organic fractions of industrial and municipal wastes, including gases and liquids recoveredfrom the decomposition of nonfossilized and biodegradable organic
material.

Blast furnace means a furnace that is located at an integrated iron and steel plant and is used for the production of molten iron from iron ore pellets and other iron bearing materials.

Blendstocks are petroleum products used for blending or compounding into finished motor gasoline. These include RBOB (reformulated blendstock for oxygenate blending) and CBOB (conventional blendstock for oxygenate blending), but exclude oxygenates, butane, and pentanes plus.

Blendstocks—Others are products used for blending or compounding into finished motor gasoline that are not
defined elsewhere. Excludes Gasoline Treated as Blendstock (GTAB), Diesel Treated as Blendstock (DTAB), conventional blendstock for oxygenate blending (CBOB), reformulated blendstock for oxygenate blending (RBOB), oxygenates (e.g. fuel ethanol and methyl tertiary butyl ether), butane, and pentanes plus.

Blowdown mean the act of emptying or depressuring a vessel. This may also
refer to the discarded material such as
blowdown water from a boiler or cooling tower.

British Thermal Unit or Btu means the quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit at about 39.2 degrees Fahrenheit.

Bulk, with respect to industrial GHG suppliers and CO2 suppliers, means the transfer of a product inside containers, including but not limited to tanks, cylinders, drums, and pressure vessels.

Bulk natural gas liquid or NGL refers to mixtures of hydrocarbons that have been separated from natural gas as liquids through the process of absorption, condensation, adsorption, or other methods at lease separators and field facilities. Generally, such liquids consist of ethane, propane, butanes, and pentanes plus. Bulk NGL is sold to
fractionators or to refineries and petrochemical plants where the fractionation takes place.

Butane , or n-Butane, is a paraffinic straight-chain hydrocarbon with
molecular formula C 4H 10
.

Butylene , or n-Butylene, is an olefinic straight-chain hydrocarbon with
molecular formula C 4H 8
.

By-product coke oven battery means a group of ovens connected by common walls, where coal undergoes destructive distillation under positive pressure to produce coke and coke oven gas from which by-products are recovered.

Calcination means the process of thermally treating minerals to decompose carbonates from ore.

Calculation methodology means a methodology prescribed under the section ‘‘Calculating GHG Emissions’’ in any subpart of part 98.

Carbon dioxide equivalent or CO2 e means the number of metric tons of CO 2 emissions with the same global warming potential as one metric ton of another greenhouse gas, and is calculated using Equation A–1 of this subpart.

Carbon dioxide production well means any hole drilled in the earth for the primary purpose of extracting carbon dioxide from a geologic formation or group of formations which contain deposits of carbon dioxide.


### 56385 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

Carbon dioxide production well facility means one or more carbon dioxide production wells that are located on one or more contiguous or adjacent properties, which are under the control of the same entity. Carbon dioxide production wells located on different oil and gas leases, mineral fee tracts, lease tracts, subsurface or surface unit areas, surface fee tracts, surface lease tracts, or separate surface sites, whether or not connected by a road, waterway, power line, or pipeline, shall be considered part of the same CO 2 production well facility if they
otherwise meet the definition.

Carbon dioxide stream means carbon dioxide that has been captured from an emission source (e.g. a power plant or other industrial facility) or extracted from a carbon dioxide production well plus incidental associated substances
either derived from the source materials and the capture process or extracted
with the carbon dioxide.

Carbon share means the percent of total mass that carbon represents in any product.

Carbonate means compounds containing the radical CO 3 ¥ 2 . Upon calcination, the carbonate radical decomposes to evolve carbon dioxide (CO 2 ). Common carbonates consumed in the mineral industry include calcium carbonate (CaCO 3 ) or calcite; magnesium carbonate (MgCO 3 ) or magnesite; and calcium-magnesium carbonate (CaMg(CO 3 ) 2 ) or dolomite.

Carbonate-based mineral means any of the following minerals used in the manufacture of glass: Calcium carbonate (CaCO 3 ), calcium magnesium carbonate (CaMg(CO 3 ) 2 ), and sodium carbonate (Na 2 CO 3 ).

Carbonate-based mineral mass fraction means the following: For limestone, the mass fraction of CaCO 3 in the limestone; for dolomite, the mass fraction of CaMg(CO 3 ) 2 in the dolomite; and for soda ash, the mass fraction of

Na 2 CO 3 in the soda ash.

Carbonate-based raw material means any of the following materials used in the manufacture of glass: Limestone, dolomite, and soda ash.

Catalytic cracking unit means a refinery process unit in which petroleum derivatives are continuously charged and hydrocarbon molecules in the presence of a catalyst are fractured into smaller molecules, or react with a contact material suspended in a fluidized bed to improve feedstock quality for additional processing and the catalyst or contact material is continuously regenerated by burning off coke and other deposits. Catalytic cracking units include both fluidized bed systems, which are referred to as fluid catalytic cracking units (FCCU), and moving bed systems, which are also referred to as thermal catalytic cracking units. The unit includes the riser, reactor, regenerator, air blowers, spent catalyst or contact material stripper, catalyst or contact material recovery equipment, and regenerator equipment for controlling air pollutant emissions and for heat recovery.

Deep bedding systems for cattle swine means a manure management system in which, as manure accumulates, bedding is continually added to absorb moisture over a production cycle and possibly for as long as 6 to 12 months. This manure management system also is known as a bedded pack manure management system and may be combined with a dry lot or pasture.

CBOB-Summer (conventional blendstock for oxygenate blending) means a petroleum product which, when blended with a specified type and percentage of oxygenate, meets the
definition of Conventional-Summer.

CBOB-Winter (conventional blendstock for oxygenate blending) means a petroleum product which, when blended with a specified type and percentage of oxygenate, meets the
definition of Conventional-Winter.

Certified standards means calibration gases certified by the manufacturer of the calibration gases to be accurate to within 2 percent of the value on the label or calibration gases.

CH 4 means methane. 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.

Chemical recovery furnace means an enclosed combustion device where concentrated spent liquor produced by the kraft or soda pulping process is burned to recover pulping chemicals and produce steam. Includes any recovery furnace that burns spent pulping liquor produced from both the kraft and soda pulping processes.

Chloride process means a production process where titanium dioxide is produced using calcined petroleum
coke and chlorine as raw materials.

City gate means a location at which natural gas ownership or control passes from one party to another, neither of
which is the ultimate consumer. In this rule, in keeping with common practice, the term refers to a point or measuring station at which a local gas distribution utility receives gas from a natural gas pipeline company or transmission system. Meters at the city gate station measure the flow of natural gas into the local distribution company system and typically are used to measure local distribution company system sendout to

customers.

CO 2 means carbon dioxide.
Coal means all solid fuels classified as anthracite, bituminous, sub-bituminous, or lignite by the American Society for Testing and Materials Designation
ASTM D388–05 Standard Classification of Coals by Rank (incorporated by reference, see § 98.7).

COD means the chemical oxygen demand as determined using methods specified pursuant to 40 CFR part 136.

Coke burn-off means the coke removed from the surface of a catalyst by combustion during catalyst regeneration. Coke burn-off also means the coke combusted in fluid coking unit
burner.

Cokemaking means the production of coke from coal in either a by-product coke oven battery or a non-recovery coke oven battery.

Commercial applications means executing a commercial transaction subject to a contract. A commercial application includes transferring custody of a product from one facility to
another if it otherwise meets the
definition.

Company records means, in reference to the amount of fuel consumed by a stationary combustion unit (or by a group of such units), a complete record of the methods used, the measurements made, and the calculations performed to quantify fuel usage. Company records may include, but are not limited to,
direct measurements of fuel consumption by gravimetric or volumetric means, tank drop measurements, and calculated values of fuel usage obtained by measuring auxiliary parameters such as steam generation or unit operating hours. Fuel billing records obtained from the fuel supplier qualify as company records.

Connector means to flanged, screwed, or other joined fittings used to connect pipe line segments, tubing, pipe components (such as elbows, reducers, ‘‘T’s’’ or valves) or a pipe line and a piece of equipment or an instrument to a pipe, tube or piece of equipment. A common connector is a flange. Joined fittings welded completely around the
circumference of the interface are not considered connectors for the purpose of this part.

Container glass means glass made of soda-lime recipe, clear or colored, which is pressed and/or blown into bottles, jars, ampoules, and other products listed in North American Industry Classification System 327213 (NAICS 327213).


### 56386 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

Continuous emission monitoring system or CEMS means the total equipment required to sample, analyze, measure, and provide, by means of readings recorded at least once every 15 minutes, a permanent record of gas concentrations, pollutant emission rates, or gas volumetric flow rates from stationary sources.

Continuous glass melting furnace means a glass melting furnace that operates continuously except during periods of maintenance, malfunction, control device installation, reconstruction, or rebuilding.

Conventional-Summer refers to finished gasoline formulated for use in motor vehicles, the composition and properties of which do not meet the requirements of the reformulated gasoline regulations promulgated by the U.S. Environmental Protection Agency under 40 CFR 80.40, but which meet summer RVP standards required under 40 CFR 80.27 or as specified by the

state. Note: This category excludes conventional gasoline for oxygenate blending (CBOB) as well as other
blendstock.

Conventional-Winter refers to finished gasoline formulated for use in motor vehicles, the composition and properties of which do not meet the requirements of the reformulated gasoline regulations promulgated by the U.S. Environmental Protection Agency
under 40 CFR 80.40 or the summer RVP standards required under 40 CFR 80.27 or as specified by the state. Note: This category excludes conventional blendstock for oxygenate blending (CBOB) as well as other blendstock.

Crude oil means a mixture of hydrocarbons that exists in the liquid phase in the underground reservoir and remains liquid at atmospheric pressure after passing through surface separating
facilities.

Daily spread means a manure management system component in which manure is routinely removed from a confinement facility and is applied to cropland or pasture within 24
hours of excretion.

Day means any consistently designated 24 hour period during which an emission unit is operated.

Degradable organic carbon (DOC)
means the fraction of the total mass of a waste material that can be biologically degraded.

Delayed coking unit means one or more refinery process units in which high molecular weight petroleum derivatives are thermally cracked and petroleum coke is produced in a series of closed, batch system reactors. A delayed coking unit consists of the coke drums and ancillary equipment associated with a single fractionator.

Density means the mass contained in a given unit volume (mass/volume).

Destruction means: (1) With respect to landfills and manure management, the combustion of methane in any on-site or off-site combustion technology. Destroyed methane includes, but is not limited to, methane combusted by flaring, methane destroyed by thermal oxidation,
methane combusted for use in on-site energy or heat production technologies, methane that is conveyed through pipelines (including natural gas pipelines) for off-site combustion, and methane that is collected for any other
on-site or off-site use as a fuel.

(2) With respect to fluorinated GHGs, the expiration of a fluorinated GHG to the destruction efficiency actually
achieved. Such destruction does not result in a commercially useful end product.

Destruction Efficiency means the efficiency with which a destruction device reduces the GWP-weighted mass of greenhouse gases fed into the device, considering the GWP-weighted masses of both the greenhouse gases fed into the
device and those exhausted from the device. Destruction efficiency, or flaring destruction efficiency, refers to the fraction of the gas that leaves the flare partially or fully oxidized. The Destruction Efficiency is expressed in Equation A–2 of this section:



### DE tCO e

tCO e OUT

IN 

### = −

1 2

2 

### (Eq. A-2)

Where: DE = Destruction Efficiency

tCO 2 e IN = The GWP-weighted mass of GHGs

fed into the destruction device

tCO 2 e OUT = The GWP-weighted mass of

GHGs exhausted from the destruction device, including GHGs formed during the destruction process

Diesel—Other is any distillate fuel oil not defined elsewhere, including Diesel Treated as Blendstock (DTAB).

DIPE (diisopropyl ether, (CH 3 ) 2 CHOCH(CH 3 ) 2 ) is an ether as described in ‘‘Oxygenates.’’

Direct liquefaction means the conversion of coal directly into liquids, rather than passing through an intermediate gaseous state.

Direct reduction furnace means a high temperature furnace typically fired with natural gas to produce solid iron from iron ore or iron ore pellets and coke, coal, or other carbonaceous materials.

Distillate Fuel Oil means a classification for one of the petroleum fractions produced in conventional distillation operations and from crackers and hydrotreating process units. The generic term distillate fuel oil includes kerosene, diesel fuels (Diesel Fuels No. 1, No. 2, and No. 4), and fuel oils (Fuel Oils No. 1, No. 2, and No. 4).

Distillate Fuel No. 1 has a maximum distillation temperature of 550 ° F at the 90 percent recovery point and a minimum flash point of 100 ° F and includes fuels commonly known as Diesel Fuel No. 1 and Fuel Oil No. 1,
but excludes kerosene. This fuel is further subdivided into categories of sulfur content: High Sulfur (greater than 500 ppm), Low Sulfur (less than or equal to 500 ppm and greater than 15 ppm), and Ultra Low Sulfur (less than or equal to 15 ppm).

Distillate Fuel No. 2 has a minimum and maximum distillation temperature
of 540 ° F and 640 ° F at the 90 percent recovery point, respectively, and includes fuels commonly known as
Diesel Fuel No. 2 and Fuel Oil No. 2.
This fuel is further subdivided into categories of sulfur content: High Sulfur (greater than 500 ppm), Low Sulfur (less than or equal to 500 ppm and greater than 15 ppm), and Ultra Low Sulfur (less than or equal to 15 ppm).

Distillate Fuel No. 4 is a distillate fuel oil made by blending distillate fuel oil and residual fuel oil, with a minimum flash point of 131 ° F.

DOC f means the fraction of DOC that actually decomposes under the (presumably anaerobic) conditions
within the landfill.

Dry lot means a manure management system component consisting of a paved or unpaved open confinement area without any significant vegetative cover where accumulating manure may be removed periodically.

Electric arc furnace (EAF) means a furnace that produces molten alloy metal and heats the charge materials
with electric arcs from carbon
electrodes.

Electric arc furnace steelmaking means the production of carbon, alloy, or specialty steels using an EAF. This
definition excludes EAFs at steel foundries and EAFs used to produce
nonferrous metals.

Electrothermic furnace means a furnace that heats the charged materials
with electric arcs from carbon
electrodes.

Emergency generator means a stationary combustion device, such as a reciprocating internal combustion engine or turbine that serves solely as a secondary source of mechanical or electrical power whenever the primary energy supply is disrupted or discontinued during power outages or natural disasters that are beyond the control of the owner or operator of a


### 56387 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

facility. An emergency generator operates only during emergency situations, for training of personnel under simulated emergency conditions, as part of emergency demand response procedures, or for standard performance testing procedures as required by law or by the generator manufacturer. A generator that serves as a back-up power
source under conditions of load shedding, peak shaving, power interruptions pursuant to an interruptible power service agreement, or scheduled facility maintenance shall not be considered an emergency generator.

Emergency equipment means any auxiliary fossil fuel-powered equipment, such as a fire pump, that is used only in emergency situations.

ETBE (ethyl tertiary butyl ether, (CH 3 ) 3 COC 2H) is an ether as described in ‘‘Oxygenates.’’

Ethane is a paraffinic hydrocarbon
with molecular formula C 2H 6

.

Ethanol is an anhydrous alcohol with
molecular formula C 2H 5 OH.

Ethylene is an olefinic hydrocarbon
with molecular formula C 2H 4
.

Ex refinery gate means the point at which a petroleum product leaves the refinery.

Experimental furnace means a glass melting furnace with the sole purpose of operating to evaluate glass melting processes, technologies, or glass products. An experimental furnace does not produce glass that is sold (except for further research and development purposes) or that is used as a raw material for non-experimental furnaces.

Export means to transport a product from inside the United States to persons outside the United States, excluding any such transport on behalf of the United States military including foreign military sales under the Arms Export
Control Act.

Exporter means any person, company or organization of record that transfers for sale or for other benefit, domestic products from the United States to another country or to an affiliate in another country, excluding any such
transfers on behalf of the United States military or military purposes including foreign military sales under the Arms Export Control Act. An exporter is not the entity merely transporting the domestic products, rather an exporter is the entity deriving the principal benefit
from the transaction.

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.

Feed means the prepared and mixed materials, which include but are not limited to materials such as limestone, clay, shale, sand, iron ore, mill scale, cement kiln dust and flyash, that are fed
to the kiln. Feed does not include the fuels used in the kiln to produce heat to form the clinker product.

Feedstock means raw material inputs to a process that are transformed by reaction, oxidation, or other chemical orphysical methods into products and byproducts. Supplemental fuel burned to provide heat or thermal energy is not a
feedstock.

Fischer-Tropsch process means a catalyzed chemical reaction in which synthesis gas, a mixture of carbon monoxide and hydrogen, is converted into liquid hydrocarbons of various
forms.

Flare means a combustion device, whether at ground level or elevated, that uses an open flame to burn combustible gases with combustion air provided by
uncontrolled ambient air around the
flame.

Flat glass means glass made of sodalime recipe and produced into
continuous flat sheets and other products listed in NAICS 327211.

Flowmeter means a device that
measures the mass or volumetric rate of flow of a gas, liquid, or solid moving through an open or closed conduit (e.g. flowmeters include, but are not limited to, rotameters, turbine meters, coriolis meters, orifice meters, ultra-sonic flowmeters, and vortex flowmeters).

Fluid coking unit means one or more refinery process units in which high molecular weight petroleum derivatives are thermally cracked and petroleum coke is continuously produced in a fluidized bed system. The fluid coking unit includes equipment for controlling air pollutant emissions and for heat recovery on the fluid coking burner exhaust vent. There are two basic types of fluid coking units: A traditional fluid coking unit in which only a small portion of the coke produced in the unit
is burned to fuel the unit and the fluid coking burner exhaust vent is directed to the atmosphere (after processing in a CO boiler or other air pollutant control equipment) and a flexicoking unit in which an auxiliary burner is used to partially combust a significant portion of the produced petroleum coke to generate a low value fuel gas that is used as fuel in other combustion sources at the refinery.

Fluorinated greenhouse gas means sulfur hexafluoride (SF 6 ), nitrogen trifluoride (NF 3 ), and any fluorocarbon except for controlled substances as defined at 40 CFR part 82, subpart A and substances with vapor pressures of less than 1 mm of Hg absolute at 25 degrees C. With these exceptions,
‘‘fluorinated GHG’’ includes but is not limited to any hydrofluorocarbon, any perfluorocarbon, any fully fluorinated linear, branched or cyclic alkane, ether, tertiary amine or aminoether, any perfluoropolyether, and any hydrofluoropolyether.

Fossil fuel means natural gas, petroleum, coal, or any form of solid, liquid, or gaseous fuel derived from such material, including for example, consumer products that are derived
from such materials and are combusted.

Fossil fuel-fired means powered by combustion of fossil fuel, alone or in combination with any other fuel, regardless of the percentage of fossil fuel
consumed.

Fractionators means plants that produce fractionated natural gas liquids (NGLs) extracted from produced natural gas and separate the NGLs individual component products: ethane, propane, butanes and pentane-plus (C5+). Plants that only process natural gas but do not
fractionate NGLs further into component products are not considered
fractionators. Some fractionators do not process production gas, but instead
fractionate bulk NGLs received from natural gas processors. Some fractionators both process natural gas
and fractionate bulk NGLs received from other plants.

Fuel means solid, liquid or gaseous
combustible material.

Fuel gas means gas generated at a petroleum refinery, petrochemical plant, or similar industrial process unit, and that is combusted separately or in any combination with any type of gas.

Fuel gas system means a system of compressors, piping, knock-out pots, mix drums, and, if necessary, units used
to remove sulfur contaminants from the fuel gas (e.g., amine scrubbers) that collects fuel gas from one or more sources for treatment, as necessary, and transport to a stationary combustion unit. A fuel gas system may have an overpressure vent to a flare but the primary purpose for a fuel gas system is to provide fuel to the various combustion units at the refinery or petrochemical plant.

Gas collection system or landfill gas collection system means a system of pipes used to collect landfill gas from
different locations in the landfill to a


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single location for treatment (thermal destruction) or use. Landfill gas collection systems may also include knock-out or separator drums and/or a

compressor.

Gas-fired unit means a stationary combustion unit that derives more than 50 percent of its annual heat input from the combustion of gaseous fuels, and the remainder of its annual heat input from
the combustion of fuel oil or other liquid fuels.

Gas monitor means an instrument that continuously measures the concentration of a particular gaseous species in the effluent of a stationary

source.

Gaseous fuel means a material that is in the gaseous state at standard atmospheric temperature and pressure
conditions and that is combusted to produce heat and/or energy.

Gasification means the conversion of a solid or liquid raw material into a gas.

Gasoline—Other is any gasoline that is not defined elsewhere, including GTAB (gasoline treated as blendstock).

Glass melting furnace means a unit comprising a refractory-lined vessel in which raw materials are charged and melted at high temperature to produce molten glass.

Glass produced means the weight of glass exiting a glass melting furnace.

Global warming potential or GWP means the ratio of the time-integrated radiative forcing from the instantaneous release of one kilogram of a trace
substance relative to that of one kilogram- of a reference gas, i.e., CO 2
.

GPA means the Gas Processors

Association.

Greenhouse gas or GHG means carbon dioxide (CO 2 ), methane (CH4 ), nitrous oxide (N 2 O), sulfur hexafluoride (SF6), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and other fluorinated greenhouse gases as defined
in this section.

GTBA (gasoline-grade tertiary butyl alcohol, (CH 3 ) 3 COH), or t-butanol, is an alcohol as described in ‘‘Oxygenates.’’

Heavy Gas Oils are petroleum distillates with an approximate boiling range from 651 ° F to 1,000 ° F.

Heel means the amount of gas that remains in a shipping container after it is discharged or off-loaded (that is no more than ten percent of the volume of the container).

High heat value or HHV means the high or gross heat content of the fuel with the heat of vaporization included. The water is assumed to be in a liquid

state.

Hydrofluorocarbons or HFCs means a class of GHGs consisting of hydrogen, fluorine, and carbon.

Import means, to land on, bring into, or introduce into, any place subject to the jurisdiction of the United States whether or not such landing, bringing,
or introduction constitutes an importation within the meaning of the customs laws of the United States, with the following exemptions:

(1) Off-loading used or excess
fluorinated GHGs or nitrous oxide of U.S. origin from a ship during servicing.

(2) Bringing fluorinated GHGs or
nitrous oxide into the U.S. from Mexico
where the fluorinated GHGs or nitrous
oxide had been admitted into Mexico in bond and were of U.S. origin.

(3) Bringing fluorinated GHGs or
nitrous oxide into the U.S. when transported in a consignment of personal or household effects or in a
similar non-commercial situation normally exempted from U.S. Customs

attention.

(4) Bringing fluorinated GHGs or nitrous into U.S. jurisdiction exclusively for U. S. military purposes.

Importer means any person, company, or organization of record that for any reason brings a product into the United States from a foreign country, excluding introduction into U.S. jurisdiction exclusively for United States military purposes. An importer is the person, company, or organization primarily liable for the payment of any duties on the merchandise or an authorized agent acting on their behalf. The term includes, as appropriate:

(1) The consignee. (2) The importer of record. (3) The actual owner. (4) The transferee, if the right to draw
merchandise in a bonded warehouse has
been transferred.

Indurating furnace means a furnace where unfired taconite pellets, called green balls, are hardened at high temperatures to produce fired pellets for use in a blast furnace. Types of indurating furnaces include straight gate and grate kiln furnaces.

Industrial greenhouse gases means nitrous oxide or any fluorinated greenhouse gas.

In-line kiln/raw mill means a system in a portland cement production process where a dry kiln system is integrated with the raw mill so that all or a portion of the kiln exhaust gases are used to perform the drying operation of the raw mill, with no auxiliary heat source used. In this system the kiln is capable of operating without the raw mill operating, but the raw mill cannot operate without the kiln gases, and consequently, the raw mill does not generate a separate exhaust gas stream.

Isobutane is a paraffinic branch chain hydrocarbon with molecular formula

C 4H 10. Isobutylene is an olefinic branch chain hydrocarbon with molecular
formula C 4H 8.

Kerosene is a light petroleum
distillate with a maximum distillation temperature of 400 ° F at the 10-percent recovery point, a final maximum boiling point of 572 ° F, a minimum flash point
of 100 ° F, and a maximum freezing point of

¥ 22 ° F. Included are No. 1–K and No. 2–K, distinguished by maximum sulfur content (0.04 and 0.30 percent of total mass, respectively), as well as all other grades of kerosene called range or stove oil. Excluded is kerosene-type jet fuel (see definition herein).

Kerosene-type jet fuel means a kerosene-based product used in commercial and military turbojet and turboprop aircraft. The product has a maximum distillation temperature of

400 ° F at the 10 percent recovery point and a final maximum boiling point of

572 ° F. Included are Jet A, Jet A–1, JP–5, and JP–8.

Kiln means an oven, furnace, or heated enclosure used for thermally processing a mineral or mineral-based
substance.

Landfill means an area of land or an excavation in which wastes are placed for permanent disposal and that is not a land application unit, surface impoundment, injection well, or waste pile as those terms are defined under 40

CFR 257.2.

Landfill gas means gas produced as a result of anaerobic decomposition of
waste materials in the landfill. Landfill gas generally contains 40 to 60 percent methane on a dry basis, typically less than 1 percent non-methane organic chemicals, and the remainder being
carbon dioxide.

Lime is the generic term for a variety of chemical compounds that are produced by the calcination of limestone or dolomite. These products
include but are not limited to calcium oxide, high-calcium quicklime, calcium hydroxide, hydrated lime, dolomitic quicklime, and dolomitic hydrate.

Liquid/Slurry means a manure management component in which
manure is stored as excreted or with
some minimal addition of water to facilitate handling and is stored in either tanks or earthen ponds, usually for periods less than one year.

Lubricants include all grades of lubricating oils, from spindle oil to cylinder oil to those used in greases. Petroleum lubricants may be produced
from distillates or residues.

Makeup chemicals means carbonate chemicals (e.g., sodium and calcium carbonates) that are added to the chemical recovery areas of chemical


### 56389 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

pulp mills to replace chemicals lost in the process.

Manure composting means the biological oxidation of a solid waste including manure usually with bedding or another organic carbon source typically at thermophilic temperatures produced by microbial heat production. There are four types of composting employed for manure management: Static, in vessel, intensive windrow and passive windrow. Static composting typically occurs in an enclosed channel,
with forced aeration and continuous mixing. In vessel composting occurs in piles with forced aeration but no mixing. Intensive windrow composting occurs in windrows with regular turning for mixing and aeration. Passive windrow composting occurs in windrows with infrequent turning for mixing and aeration.

Maximum rated heat input capacity means the hourly heat input to a unit (in mmBtu/hr), when it combusts the maximum amount of fuel per hour that it is capable of combusting on a steady state basis, as of the initial installation of the unit, as specified by the
manufacturer.

Maximum rated input capacity means the maximum charging rate of a municipal waste combustor unit expressed in tons per day of municipal solid waste combusted, calculated according to the procedures under 40 CFR 60.58b(j).

Mcf means thousand cubic feet. Methane conversion factor means the
extent to which the CH4 producing capacity (B

o ) is realized in each type of treatment and discharge pathway and system. Thus, it is an indication of the degree to which the system is anaerobic.

Methane correction factor means an adjustment factor applied to the methane generation rate to account for portions of the landfill that remain
aerobic. The methane correction factor
can be considered the fraction of the
total landfill waste volume that is ultimately disposed of in an anaerobic state. Managed landfills that have soil or
other cover materials have a methane
correction factor of 1.

Methanol (CH 3 OH) is an alcohol as described in ‘‘Oxygenates.’’

Midgrade gasoline has an octane rating greater than or equal to 88 and less than or equal to 90. This definition applies to the midgrade categories ofConventional-Summer, ConventionalWinter, Reformulated-Summer, and Reformulated-Winter. For midgradecategories of RBOB-Summer, RBOBWinter, CBOB-Summer, and CBOBWinter, this definition refers to the expected octane rating of the finished gasoline after oxygenate has been added
to the RBOB or CBOB.

Miscellaneous products include all refined petroleum products not defined elsewhere. It includes, but is not limited to, naphtha-type jet fuel (Jet B and JP– 4), petrolatum lube refining by-products (aromatic extracts and tars), absorption oils, ram-jet fuel, petroleum rocket fuels, synthetic natural gas feedstocks, waste feedstocks, and specialty oils. It excludes organic waste sludges, tank bottoms, spent catalysts, and sulfuric
acid.

MMBtu means million British thermal

units.

Motor gasoline (finished) means a complex mixture of volatile hydrocarbons, with or without additives, suitably blended to be used in spark ignition engines. Motor gasoline includes conventional gasoline, reformulated gasoline, and all types of oxygenated gasoline. Gasoline also has
seasonal variations in an effort to control ozone levels. This is achieved by lowering the Reid Vapor Pressure (RVP) of gasoline during the summer driving season. Depending on the region of the country the RVP is lowered to below 9.0 psi or 7.8 psi. The RVP may be further lowered by state regulations.

Mscf means million standard cubic
feet.

MTBE (methyl tertiary butyl ether, (CH 3 ) 3 COCH 3 ) is an ether as described in ‘‘Oxygenates.’’

Municipal solid waste landfill or MSW landfill means an entire disposal facility in a contiguous geographical space where household waste is placed in or on land. An MSW landfill may also receive other types of RCRA Subtitle D wastes (40 CFR 257.2) such as commercial solid waste, nonhazardous sludge, conditionally exempt small quantity generator waste,
and industrial solid waste. Portions of an MSW landfill may be separated by access roads, public roadways, or other public right-of-ways. An MSW landfill may be publicly or privately owned.

Municipal solid waste or MSW means solid phase household, commercial/ retail, and/or institutional waste, such as, but not limited to, yard waste and
refuse.

N

2 O means nitrous oxide. Naphthas (< 401 ° F) is a generic term applied to a petroleum fraction with an approximate boiling range between 122

° F and 400 ° F. The naphtha fraction of crude oil is the raw material for gasoline and is composed largely of paraffinic hydrocarbons.

Natural gas means a naturally occurring mixture of hydrocarbon and non-hydrocarbon gases found in geologic formations beneath the earth’s surface, of which its constituents include, but are not limited to, methane, heavier hydrocarbons and carbon dioxide. Natural gas may be field quality (which varies widely) or pipeline quality. For the purposes of this subpart, the definition of natural gas includes similarly constituted fuels such as field production gas, process gas, and fuel

gas.

Natural gas liquids (NGLs) means those hydrocarbons in natural gas that are separated from the gas as liquids through the process of absorption, condensation, adsorption, or other methods at lease separators and field facilities. Generally, such liquids consist of ethane, propane, butanes, and pentanes plus. Bulk NGLs refers to
mixtures of NGLs that are sold or delivered as undifferentiated product from natural gas processing plants.

Natural gasoline means a mixture of liquid hydrocarbons (mostly pentanes and heavier hydrocarbons) extracted from natural gas. It includes isopentane.

NIST means the United States
National Institute of Standards and Technology.

Nitric acid production line means a series of reactors and absorbers used to produce nitric acid.

Nitrogen excreted is the nitrogen that is excreted by livestock in manure and

urine.

Non-crude feedstocks means any petroleum product or natural gas liquid that enters the refinery as a feedstock to
be further refined or otherwise used on

site.

Non-recovery coke oven battery means a group of ovens connected by common walls and operated as a unit, where coal undergoes destructive distillation under negative pressure to produce coke, and which is designed for the combustion ofthe coke oven gas from which byproducts are not recovered.

Oil-fired unit means a stationary
combustion unit that derives more than 50 percent of its annual heat input from the combustion of fuel oil, and the remainder of its annual heat input from the combustion of natural gas or other gaseous fuels.

Open-ended valve or lines (OELs) means any valve, except pressure relief valves, having one side of the valve seat in contact with process fluid and one side open to atmosphere, either directly or through open piping.

Operating hours means the duration of time in which a process or process unit is utilized; this excludes shutdown, maintenance, and standby.

Operational change means, for purposes of § 98.3(b), a change in the type of feedstock or fuel used, a change


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in operating hours, or a change in process production rate.

Operator means any person who operates or supervises a facility or supplier.

Other oils (> 401 ° F) are oils with a boiling range equal to or greater than

401 ° F that are generally intended for use as a petrochemical feedstock and are
not defined elsewhere.

Owner means any person who has legal or equitable title to, has a leasehold interest in, or control of a facility or supplier, except a person whose legal or equitable title to or leasehold interest in the facility or supplier arises solely because the person is a limited partner in a partnership that has legal or equitable title to, has a leasehold interest in, or control of the facility or supplier shall
not be considered an ‘‘owner’’ of the facility or supplier.

Oxygenates means substances which, when added to gasoline, increase the oxygen content of the gasoline. Common oxygenates are ethanol, methyl tertiary butyl ether (MTBE), ethyl tertiary butyl ether (ETBE), tertiary amyl methyl ether (TAME), diisopropyl ether (DIPE), and
methanol.

Pasture/Range/Paddock means the manure from pasture and range grazing animals is allowed to lie as deposited, and is not managed.

Pentanes plus, or C5+, is a mixture of hydrocarbons that is a liquid at ambient temperature and pressure, and consists mostly of pentanes (five carbon chain) and higher carbon number hydrocarbons. Pentanes plus includes, but is not limited to, normal pentane, isopentane, hexanes-plus (natural gasoline), and plant condensate.

Perfluorocarbons or PFCs means a class of greenhouse gases consisting on
the molecular level of carbon and
fluorine.

Petrochemical means methanol, acrylonitrile, ethylene, ethylene oxide, ethylene dichloride, and any form of
carbon black.

Petrochemical feedstocks means feedstocks derived from petroleum for the manufacture of chemicals, synthetic rubber, and a variety of plastics. This category is usually divided into naphthas less than 401 ° F and other oils greater than 401 ° F.

Petroleum means oil removed from
the earth and the oil derived from tar
sands and shale.

Petroleum coke means a black solid residue, obtained mainly by cracking and carbonizing of petroleum derived feedstocks, vacuum bottoms, tar and pitches in processes such as delayed coking or fluid coking. It consists mainly of carbon (90 to 95 percent), has low ash content, and may be used as a feedstock in coke ovens. This product is
also known as marketable coke or catalyst coke.

Petroleum product means all refined and semi-refined products that are produced at a refinery by processing crude oil and other petroleum-based feedstocks, including petroleum products derived from co-processing biomass and petroleum feedstock together, but not including plastics or plastic products. Petroleum products may be combusted for energy use, or they may be used either for non-energy processes or as non-energy products. The definition of petroleum product for importers and exporters excludes

waxes.

Pit storage below animal confinement (deep pits) means the collection and storage of manure typically below a
slatted floor in an enclosed animal confinement facility. This usually
occurs with little or no added water for periods less than one year.

Portable means designed and capable of being carried or moved from one
location to another. Indications of portability include but are not limited to wheels, skids, carrying handles, dolly, trailer, or platform. Equipment is not portable if any one of the following
conditions exists:

(1) The equipment is attached to a
foundation.

(2) The equipment or a replacement
resides at the same location for more
than 12 consecutive months.

(3) The equipment is located at a seasonal facility and operates during the full annual operating period of the seasonal facility, remains at the facility for at least two years, and operates at that facility for at least three months each year.

(4) The equipment is moved from one location to another in an attempt to circumvent the portable residence time requirements of this definition.

Poultry manure with litter means a manure management system component that is similar to cattle and swine deep bedding except usually not combined with a dry lot or pasture. The system is typically used for poultry breeder flocks and for the production of meat type chickens (broiler) and other fowl.

Poultry manure without litter means a manure management system component that may manage manure in a liquid form, similar to open pits in enclosed
animal confinement facilities. These systems may alternatively be designed and operated to dry manure as it
accumulates. The latter is known as a high-rise manure management system and is a form of passive windrow manure composting when designed and operated properly.

Precision of a measurement at a specified level (e.g., one percent of full scale or one percent of the value measured) means that 95 percent of repeat measurements made by a device or technique are within the range bounded by the mean of the measurements plus or minus the specified level.

Premium grade gasoline is gasoline having an antiknock index, i.e., octane rating, greater than 90. This definition applies to the premium grade categoriesof Conventional-Summer, ConventionalWinter, Reformulated-Summer, and Reformulated-Winter. For premium grade categories of RBOB-Summer, RBOB-Winter, CBOB-Summer, and CBOB-Winter, this definition refers to the expected octane rating of the finished gasoline after oxygenate has
been added to the RBOB or CBOB.

Pressed and blown glass means glass which is pressed, blown, or both, into products such as light bulbs, glass fiber, technical glass, and other products
listed in NAICS 327212.

Pressure relief device or pressure relief valve or pressure safety valve means a safety device used to prevent operating pressures from exceeding the maximum allowable working pressure of the process equipment. A common pressure relief device is but not limited to a spring-loaded pressure relief valve. Devices that are actuated either by a pressure of less than or equal to 2.5 psig or by a vacuum are not pressure relief
devices.

Process emissions means the emissions from industrial processes (e.g., cement production, ammonia production) involving chemical or physical transformations other than fuel combustion. For example, the
calcination of carbonates in a kiln during cement production or the
oxidation of methane in an ammonia process results in the release of process

CO 2 emissions to the atmosphere.
Emissions from fuel combustion to provide process heat are not part of process emissions, whether the
combustion is internal or external to the process equipment.

Process unit means the equipment assembled and connected by pipes and ducts to process raw materials and to manufacture either a final product or an
intermediate used in the onsite production of other products. The process unit also includes the purification of recovered byproducts.

Process vent means means a gas stream that: Is discharged through a conveyance to the atmosphere either directly or after passing through a


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control device; originates from a unit operation, including but not limited to reactors (including reformers, crackers, and furnaces, and separation equipment for products and recovered byproducts); and contains or has the potential to contain GHG that is generated in the process. Process vent does not include safety device discharges, equipment leaks, gas streams routed to a fuel gas system or to a flare, discharges from storage tanks.

Propane is a paraffinic hydrocarbon
with molecular formula C 3 H 8
.

Propylene is an olefinic hydrocarbon
with molecular formula C 3 H 6

.

Pulp mill lime kiln means the combustion units (e.g., rotary lime kiln or fluidized bed calciner) used at a kraft or soda pulp mill to calcine lime mud, which consists primarily of calcium carbonate, into quicklime, which is
calcium oxide.

Pushing means the process of removing the coke from the coke oven at the end of the coking cycle. Pushing begins when coke first begins to fall from the oven into the quench car and ends when the quench car enters the quench tower.

Raw mill means a ball and tube mill,
vertical roller mill or other size reduction equipment, that is not part of an in-line kiln/raw mill, used to grind feed to the appropriate size. Moisture may be added or removed from the feed during the grinding operation. If the raw
mill is used to remove moisture from feed materials, it is also, by definition, a raw material dryer. The raw mill also includes the air separator associated
with the raw mill.

RBOB-Summer (reformulated blendstock for oxygenate blending) means a petroleum product which, when blended with a specified type and percentage of oxygenate, meets the
definition of Reformulated-Summer.

RBOB-Winter (reformulated blendstock for oxygenate blending) means a petroleum product which, when blended with a specified type and percentage of oxygenate, meets the
definition of Reformulated-Winter.

Reformulated-Summer refers to finished gasoline formulated for use in motor vehicles, the composition and properties of which meet the requirements of the reformulated gasoline regulations promulgated by the U.S. Environmental Protection Agency under 40 CFR 80.40 and 40 CFR 80.41, and summer RVP standards required under 40 CFR 80.27 or as specified by the state. Reformulated gasoline
excludes Reformulated Blendstock for Oxygenate Blending (RBOB) as well as
other blendstock. Reformulated-Winter refers to finished gasoline formulated for use in motor vehicles, the composition and properties of which meet the requirements of the reformulated gasoline regulations promulgated by the U.S. Environmental Protection Agency under 40 CFR 80.40 and 40 CFR 80.41,
but which do not meet summer RVP standards required under 40 CFR 80.27 or as specified by the state. Note: This category includes Oxygenated Fuels Program Reformulated Gasoline (OPRG). Reformulated gasoline excludes Reformulated Blendstock for Oxygenate Blending (RBOB) as well as other
blendstock.

Regular grade gasoline is gasoline having an antiknock index, i.e., octane rating, greater than or equal to 85 and less than 88. This definition applies to the regular grade categories ofConventional-Summer, ConventionalWinter, Reformulated-Summer, and Reformulated-Winter. For regular gradecategories of RBOB-Summer, RBOBWinter, CBOB-Summer, and CBOBWinter, this definition refers to the expected octane rating of the finished gasoline after oxygenate has been added
to the RBOB or CBOB.

Rendered animal fat, or tallow, means
fats extracted from animals which are generally used as a feedstock in making
biodiesel.

Research and development means those activities conducted in process units or at laboratory bench-scale settings whose purpose is to conduct research and development 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.

Residual Fuel Oil No. 5 (Navy Special) is a classification for the heavier fuel oil generally used in steam powered vessels in government service and inshore power plants. It has a minimum flash point of 131 ° F.

Residual Fuel Oil No. 6 (a.k.a. Bunker C) is a classification for the heavier fuel oil generally used for the production of electric power, space heating, vessel bunkering and various industrial purposes. It has a minimum flash point
of 140 ° F.

Residuum is residue from crude oil after distilling off all but the heaviest components, with a boiling range greater than 1,000 ° F.

Road oil is any heavy petroleum oil, including residual asphaltic oil used as a dust palliative and surface treatment on roads and highways. It is generally produced in six grades, from 0, the most liquid, to 5, the most viscous.

Rotary lime kiln means a unit with an inclined rotating drum that is used to produce a lime product from limestone by calcination.

Safety device means a closure device such as a pressure relief valve, frangible disc, fusible plug, or any other type of device which functions exclusively to prevent physical damage or permanent
deformation to a unit or its air emission control equipment by venting gases or vapors directly to the atmosphere during unsafe conditions resulting from an unplanned, accidental, or emergency event. A safety device is not used for routine venting of gases or vapors from the vapor headspace underneath a cover such as during filling of the unit or to adjust the pressure in response to normal daily diurnal ambient temperature fluctuations. A safety device is designed to remain in a closed position during normal operations and open only when the internal pressure, or another relevant parameter, exceeds the device threshold setting applicable to the air emission control equipment as determined by the owner or operator
based on manufacturer recommendations, applicable regulations, fire protection and prevention codes and practices, or other requirements for the safe handling of flammable, combustible, explosive, reactive, or hazardous materials.

Semi-refined petroleum product means all oils requiring further processing. Included in this category are unfinished oils which are produced by the partial refining of crude oil and include the following: Naphthas and lighter oils; kerosene and light gas oils; heavy gas oils; and residuum, and all products that require further processing
or the addition of blendstocks.

Sendout means, in the context of a local distribution company, the total deliveries of natural gas to customers over a specified time interval (typically hour, day, month, or year). Sendout is the sum of gas received through the city gate, gas withdrawn from on-system storage or peak shaving plants, and gas produced and delivered into the distribution system; and is net of any natural gas injected into on-system storage. It comprises gas sales, exchange, deliveries, gas used by company, and unaccounted for gas. Sendout is measured at the city gate station, and other on-system receipt points from storage, peak shaving, and production.

Sensor means a device that measures a physical quantity/quality or the change in a physical quantity/quality, such as temperature, pressure, flow rate, pH, or liquid level.

SF 6 means sulfur hexafluoride.


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Shutdown means the cessation of operation of an emission source for any

purpose.

Silicon carbide means an artificial abrasive produced from silica sand or quartz and petroleum coke.

Sinter process means a process thatproduces a fused aggregate of fine ironbearing materials suited for use in a
blast furnace. The sinter machine is composed of a continuous traveling grate that conveys a bed of ore fines and other finely divided iron-bearing material and fuel (typically coke breeze), a burner at the feed end of the grate for ignition, and a series of downdraft windboxes along the length of the strand to support downdraft
combustion and heat sufficient to produce a fused sinter product.

Site means any combination of one or more graded pad sites, gravel pad sites, foundations, platforms, or the immediate physical location upon which equipment is physically located.

Smelting furnace means a furnace inwhich lead-bearing materials, carboncontaining reducing agents, and fluxes are melted together to form a molten mass of material containing lead and slag.

Solid storage is the storage of manure, typically for a period of several months, in unconfined piles or stacks. Manure is able to be stacked due to the presence of a sufficient amount of bedding material or loss of moisture by evaporation.

Sour gas means any gas that contains significant concentrations of hydrogen sulfide. Sour gas may include untreated fuel gas, amine stripper off-gas, or sour water stripper gas.

Special naphthas means all finished products with the naphtha boiling range (290 ° to 470 ° F) that are generally used as paint thinners, cleaners or solvents. These products are refined to a specified flash point. Special naphthas include all commercial hexane and cleaning solvents conforming to ASTM Specification D1836–07, Standard Specification for Commercial Hexanes, and D235–02 (Reapproved 2007), Standard Specification for Mineral Spirits (Petroleum Spirits) (Hydrocarbon Dry Cleaning Solvent), respectively. Naphthas to be blended or marketed as motor gasoline or aviation gasoline, or that are to be used as petrochemical and synthetic natural gas (SNG) feedstocks
are excluded.

Spent liquor solids means the dry weight of the solids in the spent pulping liquor that enters the chemical recovery furnace or chemical recovery
combustion unit.

Spent pulping liquor means the residual liquid collected from on-site pulping operations at chemical pulp facilities that is subsequently fired in chemical recovery furnaces at kraft and soda pulp facilities or chemical recovery
combustion units at sulfite or semichemical pulp facilities.

Standard conditions or standard temperature and pressure (STP) means 68 degrees Fahrenheit and 14.7 pounds per square inch absolute.

Steam reforming means a catalytic process that involves a reaction between natural gas or other light hydrocarbons
and steam. The result is a mixture of hydrogen, carbon monoxide, carbon dioxide, and water.

Still gas means any form or mixture of gases produced in refineries by distillation, cracking, reforming, and other processes. The principal constituents are methane, ethane, ethylene, normal butane, butylene, propane, and propylene.

Storage tank means a vessel (excluding sumps) that is designed to contain an accumulation of crude oil, condensate, intermediate hydrocarbon liquids, or produced water and that is constructed entirely of non-earthen materials (e.g., wood, concrete, steel, plastic) that provide structural support.

Sulfur recovery plant means all process units which recover sulfur or produce sulfuric acid from hydrogen sulfide (H 2 S) and/or sulfur dioxide (SO 2 ) from a common source of sour gas at a petroleum refinery. The sulfur recovery plant also includes sulfur pits
used to store the recovered sulfur product, but it does not include secondary sulfur storage vessels or loading facilities downstream of the sulfur pits. For example, a Claus sulfur recovery plant includes: Reactor furnace and waste heat boiler, catalytic reactors, sulfur pits, and, if present, oxidation or reduction control systems, or incinerator, thermal oxidizer, or similar combustion device. Multiple sulfur recovery units are a single sulfur recovery plant only when the units share the same source of sour gas. Sulfur recovery units that receive source gas from completely segregated sour gas treatment systems are separate sulfur recovery plants.

Supplemental fuel means a fuel burned within a petrochemical process that is not produced within the process
itself.

Supplier means a producer, importer, or exporter of a fossil fuel or an industrial greenhouse gas.

Taconite iron ore processing means an industrial process that separates and concentrates iron ore from taconite, a low grade iron ore, and heats the taconite in an indurating furnace to produce taconite pellets that are used as the primary feed material for the production of iron in blast furnaces at integrated iron and steel plants.

TAME means tertiary amyl methyl ether, (CH 3 ) 2 (C 2H 5 )COCH 3 ).

Trace concentrations means concentrations of less than 0.1 percent by mass of the process stream. Transform means to use and entirely consume (except for trace concentrations) nitrous oxide or fluorinated GHGs in the manufacturing
of other chemicals for commercial purposes. Transformation does not include burning of nitrous oxide.

Transshipment means the continuous shipment of nitrous oxide or a fluorinated GHG from a foreign state of origin through the United States or its territories to a second foreign state of final destination, as long as the shipment does not enter into United States jurisdiction. A transshipment, as it moves through the United States or its territories, cannot be re-packaged, sorted or otherwise changed in condition.

Trona means the raw material (mineral) used to manufacture soda ash; hydrated sodium bicarbonate carbonate (e.g., Na2CO 3 .NaHCO 3 .2H 2 O).

Ultimate analysis means the determination of the percentages of carbon, hydrogen, nitrogen, sulfur, and chlorine and (by difference) oxygen in the gaseous products and ash after the complete combustion of a sample of an organic material.

Unfinished oils are all oils requiring further processing, except those requiring only mechanical blending.

United States means the 50 states, the District of Columbia, and U.S. possessions and territories.

Unstabilized crude oil means, for the purposes of this part, crude oil that is pumped from the well to a pipeline or pressurized storage vessel for transport to the refinery without intermediate storage in a storage tank at atmospheric pressures. Unstabilized crude oil is characterized by having a true vapor pressure of 5 pounds per square inch absolute (psia) or greater.

Valve means any device for halting or regulating the flow of a liquid or gas through a passage, pipeline, inlet, outlet, or orifice; including, but not limited to, gate, globe, plug, ball, butterfly and needle valves. Vegetable oil means oils extracted from vegetation that are generally used as a feedstock in making biodiesel.

Volatile solids are the organic material
in livestock manure and consist of both biodegradable and non-biodegradable
fractions.

Waelz kiln means an inclined rotary kiln in which zinc-containing materials are charged together with a carbon


### 56393 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

reducing agent (e.g., petroleum coke, metallurgical coke, or anthracite coal).

Waxes means a solid or semi-solid
material at 77 ° F consisting of a mixture of hydrocarbons obtained or derived from petroleum fractions, or through a Fischer-Tropsch type process, in which the straight chained paraffin series predominates. This includes all marketable wax, whether crude or refined, with a congealing point between 80 (or 85) and 240 ° F and a maximum oil content of 50 weight percent.

Wool fiberglass means fibrous glass of random texture, including fiberglass insulation, and other products listed in

NAICS 327993.

You means an owner or operator subject to Part 98.

Zinc smelters means a facility engaged in the production of zinc metal, zinc oxide, or zinc alloy products from zinc sulfide ore concentrates, zinc calcine, or zinc-bearing scrap and recycled materials through the use of pyrometallurgical techniques involving
the reduction and volatization of zincbearing feed materials charged to a
furnace.

**§ 98.7 What standardized methods are incorporated by reference into this part?** 

The materials listed in this section are incorporated by reference in the corresponding sections noted. These incorporations by reference were approved by the Director of Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. These materials are incorporated as they exist on the date of approval, and a notice of any change in the materials will be published in the Federal Register . The materials are available for purchase at the corresponding address in this
section. The materials are available for inspection at the EPA Docket Center, Public Reading Room, EPA West Building, Room 3334, 1301 Constitution Avenue, NW., Washington, DC, phone (202) 566–1744 and at the National
Archives and Records Administration (NARA). For information on the availability of this material at NARA, call 202–741–6030, or go to: http:// www.archives.gov/federal

_register/
code

_ of

_ federal

_regulations/
ibr

_locations.html

. (a) The following material is available for purchase from the Association of Fertilizer and Phosphate Chemists (AFPC), P.O. Box 1645, Bartow, Florida

33831, http://afpc.net

.

(1) Phosphate Mining States Methods Used and Adopted by the Association of Fertilizer and Phosphate Chemists
AFPC Manual 10th Edition 2009— Version 1.9, incorporation by reference (IBR) approved for § 98.264(a) and § 98.264(b).

(2) [Reserved] (b) The following material is available for purchase from the American Gas Association (AGA), 400 North Capitol Street, NW., 4th Floor, Washington, DC 20001, (202) 824–7000, http://

www.aga.org

.

(1) AGA Report No. 3 Orifice Metering
of Natural Gas and Other Related Hydrocarbon Fluids Part 1: General Equations & Uncertainty Guidelines (1990), incorporation by reference (IBR) approved for § 98.34(b) and § 98.244(b).

(2) AGA Report No. 3 Orifice Metering
of Natural Gas and Other Related Hydrocarbon Fluids Part 2: Specification and Installation Requirements (2000), IBR approved for § 98.34(b) and § 98.244(b).

(3) AGA Report No. 11 Measurement of Natural Gas by Coriolis Meter (2003), IBR approved for § 98.244(b) and § 98.254(c).

(4) AGA Transmission Measurement Committee Report No. 7 Measurement of Natural Gas by Turbine Meter (2006)/ February, IBR approved for § 98.34(b) and § 98.244(b).

(c) The following material is available for purchase from the ASM International, 9639 Kinsman Road, Materials Park, OH 44073, (440) 338–

5151, http://www.asminternational.org

.

(1) ASM CS–104 UNS No. G10460— Alloy Digest April 1985 (Carbon Steel of Medium Carbon Content), incorporation by reference (IBR) approved for § 98.174(b).

(2) [Reserved] (d) The following material is available for purchase from the American Society of Mechanical Engineers (ASME), Three Park Avenue, New York, NY 10016– 5990, (800) 843–2763, http://

www.asme.org

.

(1) ASME MFC–3M–2004 Measurement of Fluid Flow in Pipes Using Orifice, Nozzle, and Venturi, incorporation by reference (IBR) approved for § 98.34(b), § 98.244(b), § 98.254(c), § 98.344(c), and § 98.364(e).

(2) ASME MFC–4M–1986 (Reaffirmed 1997) Measurement of Gas Flow by Turbine Meters, IBR approved for § 98.34(b), § 98.244(b), § 98.254(c), § 98.344(c), and § 98.364(e).

(3) ASME MFC–5M–1985 (Reaffirmed 1994) Measurement of Liquid Flow in Closed Conduits Using Transit-Time Ultrasonic Flowmeters, IBR approved for § 98.34(b) and § 98.244(b).

(4) ASME MFC–6M–1998 Measurement of Fluid Flow in Pipes Using Vortex Flowmeters, IBR approved for § 98.34(b), § 98.244(b), § 98.254(c), § 98.344(c), and § 98.364(e). (5) ASME MFC–7M–1987 (Reaffirmed 1992) Measurement of Gas Flow by Means of Critical Flow Venturi Nozzles, IBR approved for § 98.34(b), § 98.244(b), § 98.254(c), § 98.344(c), and § 98.364(e).

(6) ASME MFC–9M–1988 (Reaffirmed 2001) Measurement of Liquid Flow in Closed Conduits by Weighing Method, IBR approved for § 98.34(b) and § 98.244(b).

(7) ASME MFC–11M–2006 Measurement of Fluid Flow by Means of Coriolis Mass Flowmeters, IBR approved for § 98.244(b), § 98.254(c), and § 98.344(c).

(8) ASME MFC–14M–2003 Measurement of Fluid Flow Using Small Bore Precision Orifice Meters, IBR approved for § 98.244(b), § 98.254(c), § 98.344(c), and § 98.364(e).

(9) ASME MFC–16–2007 Measurement of Liquid Flow in Closed Conduits with Electromagnetic Flowmeters, IBR approved for § 98.244(b).

(10) ASME MFC–18M–2001 Measurement of Fluid Flow Using Variable Area Meters, IBR approved for § 98.244(b), § 98.254(c),§ 98.344(c), and § 98.364(e).

(11) ASME MFC–22–2007 Measurement of Liquid by Turbine Flowmeters, IBR approved for § 98.244(b).

(e) The following material is available for purchase from the American Society for Testing and Material (ASTM), 100 Barr Harbor Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428–B2959, (800) 262–1373, http:// www.astm.org

.

(1) ASTM C25–06 Standard Test Method for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime, incorporation by reference (IBR) approved for § 98.114(b), § 98.174(b), § 98.184(b), § 98.194(c), and § 98.334(b).

(2) ASTM C114–09 Standard Test Methods for Chemical Analysis of Hydraulic Cement, IBR approved for § 98.84(a), § 98.84(b), and § 98.84(c).

(3) ASTM D235–02 (Reapproved 2007) Standard Specification for Mineral Spirits (Petroleum Spirits) (Hydrocarbon Dry Cleaning Solvent), IBR approved for § 98.6.

(4) ASTM D240–02 (Reapproved 2007) Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter, IBR approved for § 98.34(a) and § 98.254(e).

(5) ASTM D388–05 Standard Classification of Coals by Rank, IBR approved for § 98.6.

(6) ASTM D910–07a Standard Specification for Aviation Gasolines, IBR approved for § 98.6.

(7) ASTM D1298–99 (Reapproved 2005) Standard Test Method for Density,


### 56394 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

Relative Density (Specific Gravity), or API Gravity of Crude Petroleum and Liquid Petroleum Products by Hydrometer Method, IBR approved for § 98.33(a).

(8) ASTM D1826–94 (Reapproved 2003) Standard Test Method for Calorific (Heating) Value of Gases in Natural Gas Range by Continuous Recording Calorimeter, IBR approved for § 98.34(a) and § 98.254(e).

(9) ASTM D1836–07 Standard Specification for Commercial Hexanes, IBR approved for § 98.6.

(10) ASTM D1945–03 Standard Test Method for Analysis of Natural Gas by Gas Chromatography, IBR approved for § 98.34(b), § 98.74(c), § 98.164(b), § 98.244(b), § 98.254(d), and § 98.344(b).

(11) ASTM D1946–90 (Reapproved 2006) Standard Practice for Analysis of Reformed Gas by Gas Chromatography, IBR approved for § 98.34(b), § 98.74(c), § 98.164(b), § 98.254(d), § 98.344(b), and § 98.364(c).

(12) ASTM D2013–07 Standard Practice for Preparing Coal Samples for Analysis, IBR approved for § 98.164(b).

(13) ASTM D2234/D2234M–07
Standard Practice for Collection of a Gross Sample of Coal, IBR approved for § 98.164(b).

(14) ASTM D2502–04 Standard Test
Method for Estimation of Mean Relative
Molecular Mass of Petroleum Oils From Viscosity Measurements, IBR approved for § 98.34(b) and § 98.74(c).

(15) ASTM D2503–92 (Reapproved 2007) Standard Test Method for Relative Molecular Mass (Molecular Weight) of Hydrocarbons by Thermoelectric Measurement of Vapor Pressure, IBR approved for § 98.34(b) and § 98.74(c).

(16) ASTM D2505–88 (Reapproved 2004)e1 Standard Test Method for Ethylene, Other Hydrocarbons, and Carbon Dioxide in High-Purity Ethylene by Gas Chromatography, IBR approved for § 98.244(b).

(17) ASTM D2597–94 (Reapproved 2004) Standard Test Method for Analysis of Demethanized Hydrocarbon Liquid Mixtures Containing Nitrogen and Carbon Dioxide by Gas Chromatography, IBR approved for § 98.164(b).

(18) ASTM D3176–89 (Reapproved 2002) Standard Practice for Ultimate Analysis of Coal and Coke, IBR approved for § 98.74(c), § 98.164(b), § 98.244(b), § 98.254(i), § 98.284(c), § 98.284(d), § 98.314(c), § 98.314(d), and § 98.314(f).

(19) ASTM D3238–95 (Reapproved 2005) Standard Test Method for
Calculation of Carbon Distribution and Structural Group Analysis of Petroleum Oils by the n-d-M Method, IBR approved for § 98.34(b), § 98.74(c), and § 98.164(b).

(20) ASTM D3588–98 (Reapproved 2003) Standard Practice for Calculating Heat Value, Compressibility Factor, and Relative Density of Gaseous Fuels, IBR approved for § 98.34(a) and § 98.254(e).

(21) ASTM D3682–01 (Reapproved 2006) Standard Test Method for Major
and Minor Elements in Combustion
Residues from Coal Utilization Processes, IBR approved for § 98.144(b).

(22) ASTM D4057–06 Standard Practice for Manual Sampling of Petroleum and Petroleum Products, IBR approved for § 98.164(b).

(23) ASTM D4177–95 (Reapproved 2005) Standard Practice for Automatic Sampling of Petroleum and Petroleum Products, IBR approved for § 98.164(b).

(24) ASTM D4809–06 Standard Test
Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method), IBR approved for § 98.34(a) and § 98.254(e).

(25) ASTM D4891–89 (Reapproved 2006), Standard Test Method for Heating Value of Gases in Natural Gas Range by Stoichiometric Combustion, IBR approved for § 98.34(a) and § 98.254(e).

(26) ASTM D5291–02 (Reapproved 2007) Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants, IBR approved for § 98.34(b), § 98.74(c), § 98.164(b), § 98.244(b), § 98.254(i).

(27) ASTM D5373–08 Standard Test
Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal, IBR approved for § 98.34(b), § 98.74(c), § 98.114(b), § 98.164(b), § 98.174(b), § 98.184(b), § 98.244(b), § 98.254(i), § 98.274(b), § 98.284(c), § 98.284(d), § 98.314(c), § 98.314(d), § 98.314(f), and § 98.334(b).

(28) ASTM D5865–07a Standard Test
Method for Gross Calorific Value of Coal and Coke, IBR approved for § 98.34(a).

(29) ASTM D6060–96 (Reapproved 2001) Standard Practice for Sampling of
Process Vents With a Portable Gas Chromatograph, IBR approved for § 98.244(b).

(30) ASTM D6348–03 Standard Test
Method for Determination of Gaseous Compounds by Extractive Direct
Interface Fourier Transform Infrared (FTIR) Spectroscopy, IBR approved for § 98.54(b) and § 98.224(b).

(31) ASTM D6609–08 Standard Guide for Part-Stream Sampling of Coal, IBR approved for § 98.164(b).

(32) ASTM D6751–08 Standard Specification for Biodiesel Fuel Blend Stock (B100) for Middle Distillate Fuels, IBR approved for § 98.6. (33) ASTM D6866–08 Standard Test Methods for Determining the Biobased Content of Solid, Liquid, and Gaseous Samples Using Radiocarbon Analysis, IBR approved for § 98.33(e), § 98.34(d), § 98.34(e), and § 98.36(e).

(34) ASTM D6883–04 Standard Practice for Manual Sampling of Stationary Coal from Railroad Cars, Barges, Trucks, or Stockpiles, IBR approved for § 98.164(b).

(35) ASTM D7430–08ae1 Standard Practice for Mechanical Sampling of Coal, IBR approved for § 98.164(b).

(36) ASTM D7459–08 Standard Practice for Collection of Integrated Samples for the Speciation of Biomass (Biogenic) and Fossil-Derived Carbon Dioxide Emitted from Stationary Emissions Sources, IBR approved for § 98.33(e), § 98.34(d), § 98.34(e), and § 98.36(e).

(37) ASTM E359–00 (Reapproved 2005)e1 Standard Test Methods for Analysis of Soda Ash (Sodium Carbonate), IBR approved for § 98.294(a) and § 98.294(b).

(38) ASTM E1019–08 Standard Test Methods for Determination of Carbon, Sulfur, Nitrogen, and Oxygen in Steel, Iron, Nickel, and Cobalt Alloys by
Various Combustion and Fusion Techniques, IBR approved for § 98.174(b).

(39) ASTM E1747–95 (Reapproved 2005) Standard Guide for Purity of Carbon Dioxide Used in Supercritical Fluid Applications, IBR approved for 98.424(b).

(40) ASTM E1915–07a Standard Test Methods for Analysis of Metal Bearing Ores and Related Materials by Combustion Infrared-Absorption Spectrometry, IBR approved for § 98.174(b).

(41) ASTM E1941–04 Standard Test
Method for Determination of Carbon in Refractory and Reactive Metals and Their Alloys, IBR approved for § 98.114(b), § 98.184(b), § 98.334(b).

(42) ASTM UOP539–97 Refinery Gas Analysis by Gas Chromatography, IBR approved for § 98.164(b), § 98.244(b), and § 98.254(d), and § 98.344(b).

(f) The following material is available for purchase from the Gas Processors Association (GPA), 6526 East 60th Street, Tulsa, Oklahoma 74143, (918)

493–3872, http://

www.gasprocessors.com

.

(1) GPA 2172–09 Calculation of Gross Heating Value, Relative Density, Compressibility and Theoretical Hydrocarbon Liquid Content for Natural Gas Mixtures for Custody Transfer, IBR approved for § 98.34(a).

(2) GPA 2261–00 Analysis for Natural Gas and Similar Gaseous Mixtures by Gas Chromatography, IBR approved for


### 56395 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

§ 98.34(a), § 98.164(b), § 98.254(d), and § 98.344(b).

(g) The following material is available for purchase from the International Standards Organization (ISO), 1, ch. de la Voie-Creuse, Case postale 56, CH– 1211 Geneva 20, Switzerland, +41 22

749 01 11, http://www.iso.org/iso/
home.htm

.

(1) ISO 3170: Petroleum liquids— Manual sampling—Third Edition 2004– 02–01, IBR approved for § 98.164(b).

(2) ISO 3171: Petroleum Liquids— Automatic pipeline sampling—Second Edition 1988–12–01, IBR approved for § 98.164(b).

(3) ISO 8316: Measurement of Liquid Flow in Closed Conduits— Method by Collection of the Liquid in a Volumetric Tank (1987–10–01)—First Edition, IBR approved for § 98.244(b).

(4) ISO/TR 15349–1: 1998, Unalloyed
steel—Determination of low carbon content. Part 1: Infrared absorption
method after combustion in an electric resistance furnace (by peak separation) (1998–10–15)—First Edition, IBR approved for § 98.174(b).

(5) ISO/TR 15349–3: 1998, Unalloyed
steel—Determination of low carbon content. Part 3: Infrared absorption
method after combustion in an electric resistance furnace (with preheating) (1998–10–15)—First Edition, IBR approved for § 98.174(b).

(h) The following material is available for purchase from the National Lime Association (NLA), 200 North Glebe Road, Suite 800, Arlington, Virginia 22203, (703) 243–5463, http:// www.lime.org

.

(1) CO 2 Emissions Calculation Protocol for the Lime Industry—English Units Version, February 5, 2008 Revision—National Lime Association, incorporation by reference (IBR) approved for § 98.194(c) and § 98.194(e).

(2) [Reserved] (i) The following material is available for purchase from the National Institute of Standards and Technology (NIST), 100 Bureau Drive, Stop 1070, Gaithersburg, MD 20899–1070, (800)

877–8339, http://www.nist.gov/
index.html

.

(1) Specifications, Tolerances, and Other Technical Requirements For Weighing and Measuring Devices, NIST Handbook 44 (2009), incorporation by reference (IBR) approved for § 98.244(b), § 98.254(h), and § 98.344(a).

(2) [Reserved] (j) The following material is available for purchase from the Technical Association of the Pulp and Paper Industry (TAPPI), 15 Technology Parkway South, Norcross, GA 30092, (800) 332–8686, http://www.tappi.org

.

(1) T650 om-05 Solids Content of Black Liquor, TAPPI, incorporation by reference (IBR) approved for § 98.276(c) and § 98.277(d).

(2) T684 om-06 Gross Heating Value of Black Liquor, TAPPI, incorporation by reference (IBR) approved for § 98.274(b).

**§ 98.8 What are the compliance and enforcement provisions of this part?** 

Any violation of any requirement of this part shall be a violation of the Clean Air Act, including section 114 (42 U.S.C. 7414). A violation includes but is not limited to failure to report GHG emissions, failure to collect data needed to calculate GHG emissions, failure to continuously monitor and test as required, failure to retain records needed to verify the amount of GHG emissions, and failure to calculate GHG emissions following the methodologies specified in this part. Each day of a violation constitutes a separate
violation.

**§ 98.9 Addresses.**

All requests, notifications, and
communications to the Administrator pursuant to this part, other than submittal of the annual GHG report, shall be submitted to the following
address:

(a) For U.S. mail. Director, Climate Change Division, 1200 Pennsylvania Ave., NW., Mail Code: 6207J, Washington, DC 20460.

(b) For package deliveries. Director, Climate Change Division, 1310 L St, NW., Washington, DC 20005.



### TABLE 

### A–1 TO 

### S UBPART 

### A OF 

### P ART 

### 98—G LOBAL 

### WARMING 

### P OTENTIALS

[100-Year Time Horizon]

Name CAS No. Chemical formula Global warming potential (100 yr.)

Carbon dioxide ......................................................... 124–38–9 CO 2 ........................................................................... 1 Methane .................................................................... 74–82–8 CH 4 ........................................................................... 21
Nitrous oxide ............................................................. 10024–97–2 N 2 O ........................................................................... 310
HFC–23 .................................................................... 75–46–7 CHF 3 ......................................................................... 11,700 HFC–32 .................................................................... 75–10–5 CH 2 F 2 ........................................................................ 650 HFC–41 .................................................................... 593–53–3 CH 3 F ......................................................................... 150
HFC–125 .................................................................. 354–33–6 C 2 HF 5 ....................................................................... 2,800 HFC–134 .................................................................. 359–35–3 C 2 H 2 F 4 ...................................................................... 1,000 HFC–134a ................................................................ 811–97–2 CH 2 FCF 3 ................................................................... 1,300 HFC–143 .................................................................. 430–66–0 C 2 H 3 F 3 ...................................................................... 300 HFC–143a ................................................................ 420–46–2 C 2 H 3 F 3 ...................................................................... 3,800 HFC–152 .................................................................. 624–72–6 CH 2 FCH 2 F ................................................................ 53
HFC–152a ................................................................ 75–37–6 CH 3 CHF 2 .................................................................. 140 HFC–161 .................................................................. 353–36–6 CH 3 CH 2 F .................................................................. 12
HFC–227ea .............................................................. 431–89–0 C 3 HF 7 ........................................................................ 2,900 HFC–236cb ............................................................... 677–56–5 CH 2 FCF 2 CF 3 ............................................................. 1,340 HFC–236ea .............................................................. 431–63–0 CHF 2 CHFCF 3 ........................................................... 1,370 HFC–236fa ............................................................... 690–39–1 C 3 H 2 F 6 ...................................................................... 6,300 HFC–245ca ............................................................... 679–86–7 C 3 H 3 F 5 ...................................................................... 560 HFC–245fa ............................................................... 460–73–1 CHF 2 CH 2 CF 3 ............................................................ 1,030 HFC–365mfc ............................................................. 406–58–6 CH 3 CF 2 CH 2 CF 3 ........................................................ 794 HFC–43–10mee ....................................................... 138495–42–8 CF 3 CFHCFHCF 2 CF 3 ................................................ 1,300 Sulfur hexafluoride .................................................... 2551–62–4 SF 6 ............................................................................ 23,900 Trifluoromethyl sulphur pentafluoride ....................... 373–80–8 SF 5 CF 3 ...................................................................... 17,700 Nitrogen trifluoride .................................................... 7783–54–2 NF 3 ............................................................................ 17,200 PFC–14 (Perfluoromethane) .................................... 75–73–0 CF 4 ............................................................................ 6,500 PFC–116 (Perfluoroethane) ..................................... 76–16–4 C 2 F 6 .......................................................................... 9,200 PFC–218 (Perfluoropropane) ................................... 76–19–7 C 3 F 8 .......................................................................... 7,000


### 56396 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

TABLE 

### A–1 TO 

### S UBPART 

### A OF 

### P ART 

### 98—G LOBAL 

### WARMING 

### P OTENTIALS

### —Continued

[100-Year Time Horizon]

Name CAS No. Chemical formula Global warming potential (100 yr.)

Perfluorocyclopropane .............................................. 931–91–9 C-C 3 F 6 ...................................................................... 17,340 PFC–3–1–10 (Perfluorobutane) ............................... 355–25–9 C 4 F 10 ......................................................................... 7,000 Perfluorocyclobutane ................................................ 115–25–3 C-C 4 F 8 ...................................................................... 8,700 PFC–4–1–12 (Perfluoropentane) ............................. 678–26–2 C 5 F 12 ......................................................................... 7,500
PFC–5–1–14 ............................................................. (Perfluorohexane) ..................................................... 355–42–0 C 6 F 14 ......................................................................... 7,400

PFC–9–1–18 ............................................................. 306–94–5 C 10 F 18 ....................................................................... 7,500 HCFE–235da2 (Isoflurane) ....................................... 26675–46–7 CHF 2 OCHClCF 3 ....................................................... 350 HFE–43–10pccc (H–Galden 1040x) ........................ E1730133 CHF 2 OCF 2 OC 2 F 4 OCHF 2 .......................................... 1,870
HFE–125 ................................................................... 3822–68–2 CHF 2 OCF 3 ................................................................ 14,900
HFE–134 ................................................................... 1691–17–4 CHF 2 OCHF 2 ............................................................. 6,320
HFE–143a ................................................................. 421–14–7 CH 3 OCF 3 .................................................................. 756
HFE–227ea ............................................................... 2356–62–9 CF 3 CHFOCF 3 ........................................................... 1,540 HFE–236ca12 (HG–10) ............................................ 78522–47–1 CHF 2 OCF 2 OCHF 2 .................................................... 2,800 HFE–236ea2 (Desflurane) ........................................ 57041–67–5 CHF 2 OCHFCF 3 ......................................................... 989
HFE–236fa ................................................................ 20193–67–3 CF 3 CH 2 OCF 3 ............................................................ 487
HFE–245cb2 ............................................................. 22410–44–2 CH 3 OCF 2 CF 3 ............................................................ 708
HFE–245fa1 .............................................................. 84011–15–4 CHF 2 CH 2 OCF 3 ......................................................... 286
HFE–245fa2 .............................................................. 1885–48–9 CHF 2 OCH 2 CF 3 ......................................................... 659
HFE–254cb2 ............................................................. 425–88–7 CH 3 OCF 2 CHF 2 ......................................................... 359
HFE–263fb2 .............................................................. 460–43–5 CF 3 CH 2 OCH 3 ............................................................ 11
HFE–329mcc2 .......................................................... 67490–36–2 CF 3 CF 2 OCF 2 CHF 2 .................................................... 919
HFE–338mcf2 ........................................................... 156053–88–2 CF 3 CF 2 OCH 2 CF 3 ...................................................... 552 HFE–338pcc13 (HG–01) .......................................... 188690–78–0 CHF 2 OCF 2 CF 2 OCHF 2 .............................................. 1,500
HFE–347mcc3 .......................................................... 28523–86–6 CH 3 OCF 2 CF 2 CF 3 ...................................................... 575 HFE–347mcf2 ........................................................... E1730135 CF 3 CF 2 OCH 2 CHF 2 ................................................... 374 HFE–347pcf2 ............................................................ 406–78–0 CHF 2 CF 2 OCH 2 CF 3 ................................................... 580
HFE–356mec3 .......................................................... 382–34–3 CH 3 OCF 2 CHFCF 3 ..................................................... 101 HFE–356pcc3 ........................................................... 160620–20–2 CH 3 OCF 2 CF 2 CHF 2 ................................................... 110 HFE–356pcf2 ............................................................ E1730137 CHF 2 CH 2 OCF 2 CHF 2 ................................................. 265 HFE–356pcf3 ............................................................ 35042–99–0 CHF 2 OCH 2 CF 2 CHF 2 ................................................. 502
HFE–365mcf3 ........................................................... 378–16–5 CF 3 CF 2 CH 2 OCH 3 ..................................................... 11 HFE–374pc2 ............................................................. 512–51–6 CH 3 CH 2 OCF 2 CHF 2 ................................................... 557 HFE–449sl (HFE–7100) ...........................................
Chemical blend ......................................................... 163702–07–6

163702–08–7 C 4 F 9 OCH 3

................................................................. (CF 3 ) 2 CFCF 2 OCH 3

................................................... 297

HFE–569sf2 (HFE–7200) .........................................
Chemical blend ......................................................... 163702–05–4

163702–06–5 C 4 F 9 OC 2 H 5

............................................................... (CF 3 ) 2 CFCF 2 OC 2 H 5

.................................................. 59

Sevoflurane ............................................................... 28523–86–6 CH 2 FOCH(CF 3 ) 2 ....................................................... 345 HFE–356mm1 ........................................................... 13171–18–1 (CF 3 ) 2 CHOCH 3 ......................................................... 27
HFE–338mmz1 ......................................................... 26103–08–2 CHF 2 OCH(CF 3 ) 2 ....................................................... 380 (Octafluorotetramethy-lene)hydroxymethyl group .... NA X-(CF 2 ) 4 CH(OH)-X .................................................... 73 HFE–347mmy1 ......................................................... 22052–84–2 CH 3 OCF(CF 3 ) 2 .......................................................... 343 Bis(trifluoromethyl)-methanol .................................... 920–66–1 (CF 3 ) 2 CHOH ............................................................. 195 2,2,3,3,3-pentafluoropropanol ................................... 422–05–9 CF 3 CF 2 CH 2 OH ......................................................... 42
PFPMIE .................................................................... NA CF 3 OCF(CF 3 )CF 2 OCF 2 OCF 3 ................................... 10,300

NA = not available.



### TABLE 

### A–2 TO 

### S UBPART 

### A OF 

### P ART 

### 98—U NITS OF 

### M EASURE 

### C ONVERSIONS

To convert from To Multiply by

Kilograms (kg) ....................................................................... Pounds (lbs) .............................. ........................................... 2.20462 Pounds (lbs) .......................................................................... Kilograms (kg) ........................... ........................................... 0.45359 Pounds (lbs) .......................................................................... Metric tons .............................. ............................................. 4.53592 × 10

¥ 4 Short tons .............................................................................. Pounds (lbs) ........................... .............................................. 2,000
Short tons .............................................................................. Metric tons ............................ ............................................... 0.90718
Metric tons ............................................................................. Short tons ............................. ............................................... 1.10231 Metric tons ............................................................................. Kilograms (kg) ......................... ............................................. 1,000 Cubic meters (m 3 ) ................................................................. Cubic feet (ft 3 ) ..................................................................... 35.31467 Cubic feet (ft 3 ) ....................................................................... Cubic meters (m 3 ) ............................................................... 0.028317 Gallons (liquid, US) ............................................................... Liters (l) .................................. .............................................. 3.78541 Liters (l) ................................................................................. Gallons (liquid, US) ................ .............................................. 0.26417 Barrels of Liquid Fuel (bbl) .................................................... Cubic meters (m 3 ) ............................................................... 0.15891 Cubic meters (m 3 ) ................................................................. Barrels of Liquid Fuel (bbl) ................................. ................. 6.289 Barrels of Liquid Fuel (bbl) .................................................... Gallons (liquid, US) ........................... ................................... 42 Gallons (liquid, US) ............................................................... Barrels of Liquid Fuel (bbl) ................ .................................. 0.023810 Gallons (liquid, US) ............................................................... Cubic meters (m 3 ) ............................................................... 0.0037854 Liters (l) ................................................................................. Cubic meters (m 3 ) ............................................................... 0.001


### 56397 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

TABLE 

### A–2 TO 

### S UBPART 

### A OF 

### P ART 

### 98—U NITS OF 

### M EASURE 

### C ONVERSIONS

### —Continued

To convert from To Multiply by

Feet (ft) .................................................................................. Meters (m) .......................... ................................................. 0.3048 Meters (m) ............................................................................. Feet (ft) ............................... ................................................. 3.28084 Miles (mi) ............................................................................... Kilometers (km) ....................... ............................................. 1.60934 Kilometers (km) ..................................................................... Miles (mi) ................................. ............................................ 0.62137 Square feet (ft 2 ) ..................................................................... Acres .................................................... ................................ 2.29568 × 10

¥ 5 Square meters (m 2 ) ............................................................... Acres .......................................................... .......................... 2.47105 × 10

¥ 4 Square miles (mi 2 ) ................................................................ Square kilometers (km 2 ) ...................................................... 2.58999 Degrees Celsius ( ° C) ............................................................ Degrees Fahrenheit ( ° F) ...................................................... ° C = ( 5 ⁄ 9 ) × ( ° F

¥ 32) Degrees Fahrenheit ( ° F) ....................................................... Degrees Celsius ( ° C) ........................................................... ° F = ( 9 ⁄ 5 ) × ° C + 32 Degrees Celsius ( ° C) ............................................................ Kelvin (K) ....................................................... ...................... K = ° C + 273.15 Kelvin (K) ............................................................................... Degrees Rankine ( ° R) ......................................................... 1.8
Joules .................................................................................... Btu .................................. ...................................................... 9.47817 × 10

¥ 4
Btu ......................................................................................... MMBtu .............................. .................................................... 1 × 10

¥ 6 Pascals (Pa) .......................................................................... Inches of Mercury (in Hg) ................ .................................... 2.95334 × 10

¥ 4 Inches of Mercury (inHg) ....................................................... Pounds per square inch (psi) .................... .......................... 0.49110 Pounds per square inch (psi) ................................................ Inches of Mercury (in Hg) .......................... .......................... 2.03625

**Subpart B—[Reserved]**

**Subpart C—General Stationary Fuel**
**Combustion Sources**

**§ 98.30 Definition of the source category.**

(a) Stationary fuel combustion sources are devices that combust solid, liquid, or gaseous fuel, generally for the purposes of producing electricity, generating steam, or providing useful heat or energy for industrial, commercial, or institutional use, or reducing the volume of waste by removing combustible matter. Stationary fuel combustion sources include, but are not limited to, boilers, simple and combined-cycle combustion turbines, engines, incinerators, and process heaters.

(b) This source category does not
include:

(1) Portable equipment, as defined in § 98.6.

(2) Emergency generators and emergency equipment, as defined in § 98.6.

(3) Irrigation pumps at agricultural operations. (4) Flares, unless otherwise required by provisions of another subpart of 40 CFR part 98 to use methodologies in this subpart.

(5) Electricity generating units that are subject to subpart D of this part.

(c) For a unit that combusts hazardous waste (as defined in 40 CFR 261.3), reporting of GHG emissions is not required unless either of the following conditions apply:

(1) Continuous emission monitors (CEMS) are used to quantify CO 2 mass emissions.

(2) Any fuel listed in Table C–1 of this subpart is also combusted in the unit. In this case, report GHG emissions from
combustion of all fuels listed in Table C–1 of this subpart.

**§ 98.31 Reporting threshold.**

You must report GHG emissions under this subpart if your facility contains one or more stationary fuel combustion sources and the facility meets the applicability requirements of either §§ 98.2(a)(1), 98.2(a)(2), or 98.2(a)(3). **§ 98.32 GHGs to report.**

You must report CO 2 , CH 4 , and N 2 O mass emissions from each stationary
fuel combustion unit.

**§ 98.33 Calculating GHG emissions.**

You must calculate CO 2 emissions according to paragraph (a) of this section, and calculate CH4 and N 2 O emissions according to paragraph (c) of
this section.

(a) CO2 emissions from fuel
combustion. Calculate CO 2 emissions by using one of the four calculation methodologies in this paragraph (a) subject to the conditions, requirements, and restrictions set forth in paragraph (b) of this section. If you co-fire biomass fuels with fossil fuels, report CO 2 emissions from the combustion of biomass separately using the methods in paragraph (e) of this section.

(1) Tier 1 Calculation Methodology.
Calculate the annual CO 2 mass emissions for each type of fuel by using Equation C–1 of this section.



### CO x Fuel HHV EF 2 3 

### 1 10 = ∗∗ ∗ − 

### (Eq. C-1)

Where:

CO 2 = Annual CO 2 mass emissions for the specific fuel type (metric tons). Fuel = Mass or volume of fuel combusted per year, from company records as defined in § 98.6 (express mass in short tons for solid fuel, volume in standard cubic feet for gaseous fuel, and volume in gallons for liquid fuel). HHV = Default high heat value of the fuel, from Table C–1 of this subpart (mmBtu per mass or mmBtu per volume, as applicable). EF = Fuel-specific default CO 2 emission factor, from Table C–1 of this subpart (kg

CO 2 /mmBtu).

1 × 10

¥ 3 = Conversion factor from kilograms

to metric tons.

(2) Tier 2 Calculation Methodology.
Calculate the annual CO 2 mass emissions for each type of fuel by using either Equation C2a or C2c of this section, as appropriate.

(i) Equation C–2a of this section applies to any type of fuel listed in Table C–1 of the subpart, except for municipal solid waste (MSW). For MSW combustion, use Equation C–2c of this

section.


### 56398 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

CO x Fuel HHV EF 2 3 

### 1 10 = ∗∗ ∗ − 

### (Eq. C-2a)

Where:

CO 2 = Annual CO 2 mass emissions for a specific fuel type (metric tons).

Fuel = Mass or volume of the fuel combusted during the year, from company records as defined in § 98.6 (express mass in short tons for solid fuel, volume in standard cubic feet for gaseous fuel, and volume in gallons for liquid fuel). HHV = Annual average high heat value of the fuel from all valid samples for the year (mmBtu per mass or volume). The average HHV shall be calculated according to the requirements of paragraph (a)(2)(ii) of this section. EF = Fuel-specific default CO 2 emission factor, from Table C–1 of this subpart (kg

CO 2 /mmBtu).

1 × 10

¥ 3 = Conversion factor from kilograms

to metric tons.
(ii) The minimum number of HHV samples for determining annual average HHV is specified (e.g., monthly, quarterly, semi-annually, or by lot) in § 98.34. The method for computing the annual average HHV is a function of how frequently you perform or receive from the fuel supplier the results of fuel sampling for HHV. The method is specified in paragraph (a)(2)(ii)(A) or (a)(2)(ii)(B) of this section, as applicable.

(A) If the results of fuel sampling are received monthly or more frequently, then the annual average HHV shall be calculated using Equation C–2b of this section. If multiple HHV determinations are made in any month, average the values for the month arithmetically.



### HHV HHV Fuel

Fuel annual i i

i n

i

i n 

## ( )

= ∗

=

= 

# ∑

∑ ( )( )

( ) 1

1 

### (Eq. C-2b)

Where:
(HHV) annual = Weighted annual average high heat value of the fuel (mmBtu per mass or volume). (HHV) i = High heat value of the fuel, for month ‘‘i’’ (mmBtu per mass or volume). (Fuel) i = Mass or volume of the fuel combusted during month ‘‘i’’ (express mass in short tons for solid fuel, volume in standard cubic feet for gaseous fuel, and volume in gallons for liquid fuel). n = Number of months in the year that fuel

is burned in the unit.

(B) If the results of fuel sampling are received less frequently than monthly, then the annual average HHV shall be computed as the arithmetic average HHV for all values for the year (including valid samples and substitute data values under § 98.35). (iii) For units that combust municipal solid waste (MSW) and that produce steam, use Equation C–2c of this section. Equation C–2c of this section may also be used for any other solid fuel listed in Table C–1 of this subpart provided that steam is generated by the

unit.



### CO x Steam B EF (Eq. C-2c) 2 3 

### 1 10 = ∗∗ −

Where:

CO 2 = Annual CO 2 mass emissions from MSW or solid fuel combustion (metric tons). Steam = Total mass of steam generated by MSW or solid fuel combustion during the reporting year (lb steam). B = Ratio of the boiler’s maximum rated heat input capacity to its design rated steam output capacity (mmBtu/lb steam). EF = Fuel-specific default CO 2 emission factor, from Table C–1 of this subpart (kg

CO 2 /mmBtu).

1 × 10

¥ 3 = Conversion factor from kilograms

to metric tons. (3) Tier 3 Calculation Methodology.
Calculate the annual CO 2 mass emissions for each fuel by using either Equation C3, C4, or C5 of this section, as appropriate.

(i) For a solid fuel, use Equation C–
3 of this section.



### CO Fuel CC 0.91 (Eq. C-3) 2 

### 44

12 =∗ ∗ ∗

Where:

CO 2 = Annual CO 2 mass emissions from the combustion of the specific solid fuel (metric tons).
Fuel = Annual mass of the solid fuel combusted, from company records as defined in § 98.6 (short tons). CC = Annual average carbon content of the solid fuel (percent by weight, expressed as a decimal fraction, e.g., 95% = 0.95). The annual average carbon content shall be determined using the same procedures as specified for HHV in paragraph (a)(2)(ii) of this section. 44/12 = Ratio of molecular weights, CO 2 to carbon.
0.91 = Conversion factor from short tons to

metric tons.

(ii) For a liquid fuel, use Equation C–
4 of this section.



### CO Fuel CC 0.001 (Eq. C-4) 2 

### 44

12 =∗ ∗ ∗


### 56399 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

Where:

CO 2 = Annual CO 2 mass emissions from the combustion of the specific liquid fuel (metric tons). Fuel = Annual volume of the liquid fuel combusted (gallons). The volume of fuel combusted must be measured directly, using fuel flow meters calibrated according to § 98.3(i). Fuel billing meters may be used for this purpose. Tank drop measurements may also be used. CC = Annual average carbon content of the liquid fuel (kg C per gallon of fuel). The annual average carbon content shall be determined using the same procedures as specified for HHV in paragraph (a)(2)(ii)
of this section. 44/12 = Ratio of molecular weights, CO 2 to carbon. 0.001 = Conversion factor from kg to metric

tons. (iii) For a gaseous fuel, use Equation
C–5 of this section.



### CO 2 

### 44

12 0 001 =∗ ∗ ∗ ∗ Fuel CC MW

MVC . (Eq. C-5)

Where:

CO 2 = Annual CO 2 mass emissions from combustion of the specific gaseous fuel (metric tons). Fuel = Annual volume of the gaseous fuel combusted (scf). The volume of fuel combusted must be measured directly, using fuel flow meters calibrated according to § 98.3(i). Fuel billing meters may be used for this purpose. CC = Annual average carbon content of the liquid fuel (kg C per gallon of fuel). The annual average carbon content shall be determined using the same procedures as specified for HHV in paragraph (a)(2)(ii)
of this section. MW = Annual average molecular weight of the gaseous fuel (kg/kg-mole). The annual average carbon content shall be determined using the same procedures as specified for HHV in paragraph (a)(2)(ii)
of this section.
MVC = Molar volume conversion factor (849.5 scf per kg-mole at standard conditions, as defined in § 98.6). 44/12 = Ratio of molecular weights, CO 2 to carbon. 0.001 = Conversion factor from kg to metric

tons.
(iv) Fuel flow meters that measure mass flow rates may be used for liquid fuels, provided that the fuel density is used to convert the readings to volumetric flow rates. The density shall be measured at the same frequency as the carbon content, using ASTM D1298– 99 (Reapproved 2005) ‘‘Standard Test Method for Density, Relative Density (Specific Gravity), or API Gravity of Crude Petroleum and Liquid Petroleum Products by Hydrometer Method’’ (incorporated by reference, see § 98.7).

(v) The following default density values may be used for fuel oil, in lieu of using the ASTM method in paragraph (a)(3)(iv) of this section: 6.8 lb/gal for No. 1 oil; 7.2 lb/gal for No. 2 oil; 8.1 lb/ gal for No. 6 oil.

(4) Tier 4 Calculation Methodology.
Calculate the annual CO 2 mass emissions from all fuels combusted in a unit, by using quality-assured data from continuous emission monitoring systems (CEMS).

(i) This methodology requires a CO 2 concentration monitor and a stack gas volumetric flow rate monitor, except as otherwise provided in paragraph (a)(4)(iv) of this section. Hourly
measurements of CO 2 concentration and stack gas flow rate are converted to CO 2 mass emission rates in metric tons per
hour.

(ii) When the CO 2 concentration is measured on a wet basis, Equation C–6
of this section is used to calculate the hourly CO 2 emission rates:



### CO x C Q CO 2 7 

### 5 18 10 = ∗∗ −



### . 2 

### (Eq. C-6)

Where:

CO 2 = CO 2 mass emission rate (metric tons/ hr).

C CO2 = Hourly average CO 2 concentration (%

CO 2 ). Q = Hourly average stack gas volumetric flow rate (scfh).

5.18 × 10

¥ 7 = Conversion factor (metric tons/ scf/% CO 2 ).

(iii) If the CO 2 concentration is measured on a dry basis, a correction for the stack gas moisture content is required. You shall either continuously monitor the stack gas moisture content as described in § 75.11(b)(2) of this chapter or, for certain types of fuel, use a default moisture percentage from § 75.11(b)(1) of this chapter. For each unit operating hour, a moisture correction must be applied to Equation
C–6 of this section as follows:



### CO CO H O

2 2 2 

### 100

100 * 

### %

= − ⎛ ⎝ ⎜ ⎞ ⎠ ⎟ (Eq. C-7)

Where:

CO 2 * = Hourly CO 2 mass emission rate, corrected for moisture (metric tons/hr).

CO 2 = Hourly CO 2 mass emission rate from Equation C-6 of this section, uncorrected (metric tons/hr). %H 2 O = Hourly moisture percentage in the stack gas (measured or default value, as appropriate).
(iv) An oxygen (O 2 ) concentration monitor may be used in lieu of a CO 2 concentration monitor to determine the hourly CO 2 concentrations, in accordance with Equation F–14a or F– 14b (as applicable) in appendix F to 40 CFR part 75, if the effluent gas stream monitored by the CEMS consists solely of combustion products (i.e., no process

CO 2 emissions are mixed with the combustion products) and if only fuels
that are listed in Table 1 in section 3.3.5 of appendix F to 40 CFR part 75 are
combusted in the unit. If the O 2monitoring option is selected, the Ffactors used in Equations F–14a and F– 14b shall be determined according to
section 3.3.5 or section 3.3.6 of appendix F to 40 CFR part 75, as applicable. If Equation F–14b is used, the hourly moisture percentage in the stack gas shall be either a measured value in accordance with § 75.11(b)(2) of this chapter, or, for certain types of fuel,
a default moisture value from § 75.11(b)(1) of this chapter.

(v) Each hourly CO 2 mass emission rate from Equation C–6 or C–7 of this section is multiplied by the operating time to convert it from metric tons per hour to metric tons. The operating time is the fraction of the hour during which fuel is combusted (e.g., the unit operating time is 1.0 if the unit operates
for the whole hour and is 0.5 if the unit operates for 30 minutes in the hour). For common stack configurations, the operating time is the fraction of the hour during which effluent gases flow through the common stack.

(vi) The hourly CO 2 mass emissions are then summed over each calendar quarter and the quarterly totals are
summed to determine the annual CO 2 mass emissions.

(vii) If both biomass and fossil fuel are combusted during the year, determine and report the biogenic CO 2 mass emissions separately, as described in paragraph (e) of this section.

(5) Alternative methods for units with continuous monitoring systems. Units not subject to the Acid Rain Program that report data to EPA according to 40 CFR part 75 may use the alternative methods in this paragraph in lieu of using any of the four calculation methodology tiers.

(i) For a unit that combusts only natural gas and/or fuel oil, is not subject to the Acid Rain Program, monitors and reports heat input data year-round according to appendix D to 40 CFR part


### 56400 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

75, but is not required by the applicable 40 CFR part 75 program to report CO 2 mass emissions data, calculate the
annual CO 2 mass emissions for the purposes of this part as follows:

(A) Use the hourly heat input data from appendix D to 40 CFR part 75, together with Equation G–4 in appendix G to 40 CFR part 75 to determine the hourly CO 2 mass emission rates, in units of tons/hr;

(B) Use Equations F–12 and F–13 in appendix F to 40 CFR part 75 to calculate the quarterly and cumulative
annual CO 2 mass emissions, respectively, in units of short tons; and

(C) Divide the cumulative annual CO 2 mass emissions value by 1.1 to convert

it to metric tons.

(ii) For a unit that combusts only natural gas and/or fuel oil, is not subject to the Acid Rain Program, monitors and reports heat input data year-round according to 40 CFR 75.19 of this chapter but is not required by the applicable 40 CFR part 75 program to report CO 2 mass emissions data,
calculate the annual CO 2 mass emissions for the purposes of this part
as follows:

(A) Calculate the hourly CO 2 mass emissions, in units of short tons, using Equation LM–11 in 40 CFR 75.19(c)(4)(iii).

(B) Sum the hourly CO 2 mass emissions values over the entire reporting year to obtain the cumulative
annual CO 2 mass emissions, in units of
short tons.

(C) Divide the cumulative annual CO 2 mass emissions value by 1.1 to convert

it to metric tons.

(iii) For a unit that is not subject to the Acid Rain Program, uses flow rate
and CO 2 (or O 2 ) CEMS to report heat input data year-round according to 40 CFR part 75, but is not required by the applicable 40 CFR part 75 program to report CO 2 mass emissions data,
calculate the annual CO 2 mass emissions as follows:

(A) Use Equation F–11 or F–2 (as applicable) in appendix F to 40 CFR part 75 to calculate the hourly CO 2 mass emission rates from the CEMS data. If an

O 2 monitor is used, convert the hourly average O 2 readings to CO 2 using Equation F–14a or F–14b in appendix F to 40 CFR part 75 (as applicable), before applying Equation F–11 or F–2.

(B) Use Equations F–12 and F–13 in appendix F to 40 CFR part 75 to calculate the quarterly and cumulative
annual CO 2 mass emissions, respectively, in units of short tons.

(C) Divide the cumulative annual CO 2 mass emissions value by 1.1 to convert

it to metric tons. (D) If both biomass and fossil fuel are combusted during the year, determine and report the biogenic CO 2 mass emissions separately, as described in paragraph (e) of this section.

(b) Use of the four tiers. Use of the
four tiers of CO 2 emissions calculation methodologies described in paragraph (a) of this section is subject to the following conditions, requirements, and

restrictions:

(1) The Tier 1 Calculation Methodology:

(i) May be used for any fuel listed in Table C–1 of this subpart that is
combusted in a unit with a maximum rated heat input capacity of 250 mmBtu/
hr or less.

(ii) May be used for MSW in a unit of any size that does not produce steam, if the use of Tier 4 is not required.

(iii) May be used for solid, gaseous, or liquid biomass fuels in a unit of any size provided that the fuel is listed in Table C–1 of this subpart.

(iv) May not be used if you routinely perform fuel sampling and analysis for the fuel high heat value (HHV) or routinely receive the results of HHV sampling and analysis from the fuel supplier at the minimum frequency specified in § 98.34(a), or at a greater frequency. In such cases, Tier 2 shall be
used.

(2) The Tier 2 Calculation Methodology:

(i) May be used for the combustion of any type of fuel in a unit with a maximum rated heat input capacity of 250 mmBtu/hr or less provided that the
fuel is listed in Table C–1 of this subpart.

(ii) May be used in a unit with a maximum rated heat input capacity greater than 250 mmBtu/hr for the combustion of pipeline quality natural gas and distillate fuel oil.

(iii) May be used for MSW in a unit of any size that produces steam, if the use of Tier 4 is not required.

(3) The Tier 3 Calculation Methodology:

(i) May be used for a unit of any size that combusts any type of fuel listed in Table C–1 of this subpart (except for MSW), unless the use of Tier 4 is required.

(ii) Shall be used for a unit with a maximum rated heat input capacity greater than 250 mmBtu/hr that combusts any type of fuel listed in Table C–1 of this subpart (except MSW), unless either of the following conditions apply:

(A) The use of Tier 1 or 2 is permitted, as described in paragraphs (b)(1)(iii) and (b)(2)(ii) of this section.

(B) The use of Tier 4 is required. (iii) Shall be used for a fuel not listed in Table C–1 of this subpart if the fuel is combusted in a unit with a maximum rated heat input capacity greater than 250 mmBtu/hr provided that both of the following conditions apply:

(A) The use of Tier 4 is not required. (B) The fuel provides 10% or more of the annual heat input to the unit or, if § 98.36(c)(3) applies, to a group of units served by common supply pipe.

(4) The Tier 4 Calculation Methodology:

(i) May be used for a unit of any size, combusting any type of fuel.

(ii) Shall be used if the unit meets all six of the conditions specified in paragraphs (b)(4)(ii)(A) through (b)(4)(ii)(F) of this section:

(A) The unit has a maximum rated heat input capacity greater than 250 mmBtu/hr, or if the unit combusts municipal solid waste and has a maximum rated input capacity greater than 250 tons per day of MSW.

(B) The unit combusts solid fossil fuel or MSW, either as a primary or secondary fuel.

(C) The unit has operated for more than 1,000 hours in any calendar year

since 2005.

(D) The unit has installed CEMS that are required either by an applicable Federal or State regulation or the unit’s operating permit.

(E) The installed CEMS include a gas monitor of any kind or a stack gas volumetric flow rate monitor, or both and the monitors have been certified,
either in accordance with the requirements of 40 CFR part 75, part 60 of this chapter, or an applicable State continuous monitoring program.

(F) The installed gas or stack gas
volumetric flow rate monitors are required, either by an applicable Federal or State regulation or by the unit’s operating permit, to undergo periodic quality assurance testing in accordance with either appendix B to 40 CFR part 75, appendix F to 40 CFR part 60, or an applicable State continuous monitoring

program.

(iii) Shall be used for a unit with a maximum rated heat input capacity of
250 mmBtu/hr or less and for a unit that combusts municipal solid waste with a maximum rated input capacity of 250 tons of MSW per day or less, if the unit meets all of the following three
conditions:

(A) The unit has both a stack gas
volumetric flow rate monitor and a CO 2 concentration monitor.

(B) The unit meets the conditions specified in paragraphs (b)(4)(ii)(B) through (b)(4)(ii)(D) of this section.

(C) The CO 2 and stack gas volumetric
flow rate monitors meet the conditions specified in paragraphs (b)(4)(ii)(E) and (b)(4)(ii)(F) of this section.


### 56401 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

(5) The Tier 4 Calculation Methodology shall be used beginning

on:

(i) January 1, 2010, for a unit that is required to report CO 2 mass emissions beginning on that date, if all of the
monitors needed to measure CO 2 mass emissions have been installed and certified by that date.

(ii) January 1, 2011, for a unit that is required to report CO 2 mass emissions beginning on January 1, 2010, if all of
the monitors needed to measure CO 2 mass emissions have not been installed and certified by January 1, 2010. In this case, you may use Tier 2 or Tier 3 to report GHG emissions for 2010. (6) You may elect to use any applicable higher tier for one or more of
the fuels combusted in a unit. For example, if a 100 mmBtu/hr unit combusts natural gas and distillate fuel oil, you may elect to use Tier 1 for natural gas and Tier 3 for the fuel oil, even though Tier 1 could have been used for both fuels. However, for units
that use either the Tier 4 or the alternative calculation methodology specified in paragraph (a)(5) of this
section, CO 2 emissions from the
combustion of all fuels shall be based solely on CEMS measurements. (c) Calculation of CH 4 and N 2 O emissions from stationary combustion

sources. You must calculate annual CH4 and N 2 O mass emissions only for units that are required to report CO 2 emissions using the calculation methodologies of this subpart and for only those fuels that are listed in Table C–2 of this subpart.

(1) Use Equation C–8 of this section

to estimate CH4 and N 2 O emissions for any fuels for which you use the Tier 1 or Tier 3 calculation methodologies for

CO 2 . Use the same values for fuel combustion that you use for the Tier 1
or Tier 3 calculation.



### CH or N O x Fuel HHV EF 4 2



### 1 10 (Eq. C-8) = ∗∗ ∗ −3

Where:

CH 4 or N 2 O = Annual CH 4 or N 2 O emissions from the combustion of a particular type of fuel (metric tons). Fuel = Mass or volume of the fuel combusted, either from company records or directly measured by a fuel flow meter, as applicable (mass or volume per year). HHV = Default high heat value of the fuel from Table C–1 of this subpart (mmBtu per mass or volume). EF = Fuel-specific default emission factor for

CH 4 or N 2 O, from Table C–2 of this subpart (kg CH4 or N 2 O per mmBtu).

1 × 10

¥ 3 = Conversion factor from kilograms

to metric tons. (2) Use Equation C–9a of this section

to estimate CH4 and N 2 O emissions for any fuels for which you use the Tier 2 Equation C–2a of this section to estimate

CO 2 emissions. Use the same values for fuel combustion and HHV that you use
for the Tier 1 or Tier 3 calculation.



### CH or N O 1 x 10 HHV EF Fuel (Eq. C-9a) 4 2 

### = ∗ ∗∗ −3

Where:

CH 4 or N 2 O = Annual CH 4 or N 2 O emissions from the combustion of a particular type of fuel (metric tons).
Fuel = Mass or volume of the fuel combusted during the reporting year. HHV = High heat value of the fuel, averaged
for all valid measurements for the reporting year (mmBtu per mass or volume). EF = Fuel-specific default emission factor for

CH 4 or N 2 O, from Table C–2 of this subpart (kg CH4 or N 2 O per mmBtu).

1 × 10

¥ 3 = Conversion factor from kilograms

to metric tons. (3) Use Equation C–9b of this section

to estimate CH4 and N 2 O emissions for any fuels for which you use Equation
C–2c of this section to calculate the CO 2 emissions. Use the same values for steam generation and the ratio ‘‘B’’ that you use for Equation C–2c.



### CH or N O x Steam B EF (Eq. C-9b) 4 2 

### = ∗∗ − 

### 1 10 3

Where:

CH 4 or N 2 O = Annual CH 4 or N 2 O emissions

from the combustion of a solid fuel (metric tons). Steam = Total mass of steam generated by solid fuel combustion during the reporting year (lb steam). B = Ratio of the boiler’s maximum rated heat input capacity to its design rated steam output (mmBtu/lb steam). EF = Fuel-specific emission factor for CH4 or N 2 O, from Table C–2 of this subpart (kg

CH 4 or N 2 O per mmBtu).

1 × 10

¥ 3 = Conversion factor from kilograms

to metric tons. (4) Use Equation C–10 of this section for units in the Acid Rain Program, units that monitor and report heat input on a year-round basis according to 40 CFR part 75, and units that use the Tier 4 Calculation Methodology.



### CH or N O (HI) EF (Eq. C-10) 42 A 

### =∗ ∗

0 001

.

Where:

CH 4 or N 2 O = Annual CH 4 or N 2 O emissions from the combustion of a particular type of fuel (metric tons). (HI) A = Cumulative annual heat input from the fuel, derived from the electronic data reports required under § 75.64 of this chapter or, for Tier 4 units, from the best
available information as described in paragraph (c)(4)(ii) of this section (mmBtu). EF = Fuel-specific emission factor for CH4 or
N 2 O, from Table C–2 of this section (kg

CH 4 or N 2 O per mmBtu). 0.001 = Conversion factor from kg to metric

tons. (i) If only one type of fuel listed in Table C–2 of this subpart is combusted during normal operation, substitute the cumulative annual heat input from combustion of the fuel into Equation
C–10 of this section to calculate the
annual CH4 or N 2 O emissions.


### 56402 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

(ii) If more than one type of fuel listed in Table C–2 of this subpart is combusted during normal operation, use Equation C–10 of this section separately for each type of fuel. If flow rate and diluent gas monitors are used to measure the unit heat input, use the best available information (e.g., fuel feed rate measurements, fuel heating values, engineering analysis) to estimate the annual heat input from each type of
fuel.

(5) When multiple fuels are combusted during the reporting year, sum the fuel-specific results from Equations C–8, C–9a, C–9b, or C–10 of this section (as applicable) to obtain the
total annual CH4 and N 2 O emissions, in
metric tons. (d) Calculation of CO 2 from sorbent.

(1) When a unit is a fluidized bed boiler, is equipped with a wet flue gas desulfurization system, or uses other acid gas emission controls with sorbent injection, use Equation C–11 of this
section to calculate the CO 2 emissions from the sorbent, if those CO 2 emissions are not monitored by CEMS:



### CO S R MW

MW CO

S 2 

### 0 91

= ∗∗∗ ⎛
⎝ ⎜ ⎞
⎠ ⎟

. 2 

### (Eq. C-11)

Where:

CO 2 = CO 2 emitted from sorbent for the reporting year (metric tons).
S = Limestone or other sorbent used in the reporting year, from company records (short tons). R = 1.00, the calcium-to-sulfur stoichiometric

ratio.

MW CO2 = Molecular weight of carbon dioxide (44).

MW S = Molecular weight of sorbent (100 if calcium carbonate).
0.91 = Conversion factor from short tons to

metric tons.
(2) The annual CO 2 mass emissions for the unit shall be the sum of the CO 2 emissions from the combustion process
and the CO 2 emissions from the sorbent.

(e) CO 2 emissions from combustion of
biomass. Use the procedures of this paragraph (e) to estimate biogenic CO 2 emissions from units that combust a
combination of biomass and fossil fuels. Reporting of CO 2 emissions from combustion of biomass is required only
for those biomass fuels listed in Table C–1 of this section, unless emissions are measured using CEMS.

(1) If CEMS are not used to measure

CO 2 , use Equation C–1 of this subpart to
calculate the annual CO 2 mass emissions from the combustion of biomass (except MSW) for a unit of any
size. Determine the mass of biomass combusted using one of the following procedures in this paragraph (e)(1), as appropriate.

(i) Use company records. (ii) Follow the procedures in paragraph (e)(5) of this section.

(iii) For premixed fuels that contain biomass and fossil fuels (e.g., mixtures containing biodiesel), use best available
information to determine the mass of
biomass fuels and document the procedure used in the GHG Monitoring Plan required by § 98.3(g)(5).

(2) If a CO 2 CEMS (or a surrogate O 2 monitor) and a stack gas flow rate
monitor are used to determine the
annual CO 2 mass emissions either according to 40 CFR part 75, the Tier 4 Calculation Methodology, or the alternative calculation methodology specified in paragraph (a)(5)(iii); and if both fossil fuel and biomass (except for MSW) are combusted in the unit during the reporting year, you may use the following procedure to determine the annual biogenic CO 2 mass emissions. If MSW is combusted in the unit, follow the procedures in paragraph (e)(3) of
this section.

(i) For each operating hour, use Equation C–12 of this section to
determine the volume of CO 2 emitted.



### V CO Q t

CO h h h h 2 

### = 

## ( )

∗ ∗ % 2



### 100 (Eq. C-12)

Where:

V CO2h = Hourly volume of CO 2 emitted (scf). (%CO 2 ) h = Hourly average CO 2 concentration, measured by the CO 2 concentration monitor, or, if applicable, calculated from the hourly average O 2 concentration (%CO 2 ). Q

h = Hourly average stack gas volumetric flow rate, measured by the stack gas volumetric flow rate monitor (scfh).

th = Source operating time (decimal fraction of the hour during which the source combusts fuel, i.e., 1.0 for a full operating hour, 0.5 for 30 minutes of operation, etc.). 100 = Conversion factor from percent to a
decimal fraction.

(ii) Sum all of the hourly V CO2h values for the reporting year, to obtain Vtotal , the total annual volume of CO 2 emitted.

(iii) Calculate the annual volume of

CO 2 emitted from fossil fuel combustion using Equation C–13 of this section. If two or more types of fossil fuel are combusted during the year, perform a separate calculation with Equation C–13
of this section for each fuel and sum the
results.



### V Fuel F HHV (Eq. C-13)

ff c



### = ∗ ∗

10 6

Where:

Vff = Annual volume of CO 2 emitted from combustion of a particular fossil fuel (scf). Fuel = Total quantity of the fossil fuel combusted in the reporting year, from company records, as defined in § 98.6 (lb for solid fuel, gallons for liquid fuel, and scf for gaseous fuel).

F

c = Fuel-specific carbon based F-factor,
either a default value from Table 1 in section 3.3.5 of appendix F to 40 CFR part 75 or a site-specific value
determined under section 3.3.6 of appendix F to 40 CFR part 75 (scf CO 2 / mmBtu). HHV = High heat value of the fossil fuel, from fuel sampling and analysis (annual average value in Btu/lb for solid fuel, Btu/gal for liquid fuel and Btu/scf for gaseous fuel, sampled as specified (e.g., monthly, quarterly, semi-annually, or by lot) in § 98.34(a)(2)). The average HHV shall be calculated according to the requirements of paragraph (a)(2)(ii) of

this section.

10 6 = Conversion factor, Btu per mmBtu.

(iv) Subtract Vff from Vtotal to obtain

Vbio , the annual volume of CO 2 from the
combustion of biomass. If a CEMS is being used to measure the combined combustion and process emissions from a unit that is subject to another subpart of part 98, then also subtract CO 2 process emissions from Vtotal to determine Vbio . The CO 2 process emissions must be calculated according to the requirements of the applicable subpart.


### 56403 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

(v) Calculate the biogenic percentage
of the annual CO 2 emissions,expressed as a decimal fraction, using Equation C–
14 of this section:



### % Biogenic V

V bio

total 

### = (Eq. C-14)

(vi) Calculate the annual biogenic CO 2 mass emissions, in metric tons, by multiplying the results obtained from Equation C–14 of this section by the
annual CO 2 mass emissions in metric tons, as determined:

(A) Under paragraph (a)(4)(vi) of this section, for units using the Tier 4 Calculation Methodology.

(B) Under paragraph (a)(5)(iii)(B) of this section, for units using the alternative calculation methodology specified in paragraph (a)(5)(iii).

(C) From the electronic data report required under § 75.64 of this chapter, for units in the Acid Rain Program and other units using CEMS to monitor and report CO 2 mass emissions according to 40 CFR part 75. However, before calculating the annual biogenic CO 2 mass emissions, multiply the
cumulative annual CO 2 mass emissions by 0.91 to convert from short tons to

metric tons.

(3) For a unit that combusts MSW, the annual biogenic CO 2 emissions shall be calculated using the procedures in this paragraph (e)(3).

(i) If the Tier 1 or Tier 2 Calculation Methodology is used to quantify CO 2 mass emissions: (A) Use Equation C–1 or C–2c of this subpart, as appropriate, to calculate the
annual CO 2 mass emissions from MSW
combustion.

(B) Determine the relative proportions of biogenic and non-biogenic CO 2 emissions on a quarterly basis using the method specified in § 98.34(d).

(C) Determine the annual biogenic

CO 2 mass emissions from MSW combustion by multiplying the annual

CO 2 mass emissions by the annual average biogenic decimal fraction obtained from § 98.34(d).

(ii) If the unit uses Tier 4 to quantify

CO 2 emissions:

(A) Follow the procedures in paragraphs (e)(2)(i) and (ii) of this section, to determine Vtotal

.

(B) If any fossil fuel was combusted during the year, follow the procedures in paragraph (e)(2)(iii) of this section, to
determine Vff

.

(C) Subtract Vff from Vtotal , to obtain

VMSW , the annual volume of CO 2 emissions from MSW combustion.

(D) Determine the annual volume of biogenic CO 2 emissions (Vbio ) from MSW combustion as follows. Multiply
the annual volume of CO 2 emissions from MSW combustion (VMSW ) by the annual average biogenic decimal
fraction obtained from ASTM D6866–08
and ASTM D7459–08.

(E) Calculate the biogenic percentage
of the annual CO 2 emissions from the unit, using Equation C–14 of this section. For the purposes of this calculation, the term ‘‘Vbio ’’ in the numerator of Equation C–14 of this
section shall be the results of the calculation performed under paragraph (e)(3)(ii)(D) of this section.

(F) Calculate the annual biogenic CO 2 mass emissions according to paragraph (e)(2)(vi)(A) of this section.

(4) As an alternative to the procedures in paragraph (e)(2) of this section, use
ASTM Methods D7459–08 and D6866– 08 to determine the biogenic portion of
the annual CO 2 emissions, as described in § 98.34(e). If this option is selected,
the results of each determination shall be expressed as a decimal fraction (e.g., 0.30, if 30 percent of the CO 2 is biogenic), and the values shall be averaged over the reporting year. The annual biogenic CO 2 mass emissions shall be calculated by multiplying the
the total annual CO 2 mass emissions by the annual average biogenic fraction
obtained from ASTM D6866–08 and

ASTM D7459–08.

(5) If Equation C–1 of this section is selected to calculate the annual biogenic mass emissions for wood, wood waste, or other solid biomass-derived fuel, Equation C–15 of this section may be used to quantify biogenic fuel consumption, provided that all of the required input parameters are accurately quantified. Similar equations and calculation methodologies based on steam generation and boiler efficiency may be used, provided that they are documented in the GHG Monitoring Plan required by § 98.3(g)(5).



### ( ) [ ]( )

( ) Fuel H S HI

HHV p nb

bio 

### = ∗ −

2000 ( ) (Eq. C-15) Eff bio

Where:

(Fuel) p = Quantity of biomass consumed

during the measurement period ‘‘p’’ (tons/ year or tons/month, as applicable). H = Average enthalpy of the boiler steam for

the measurement period (Btu/lb). S = Total boiler steam production for the

measurement period (lb/month or lb/year, as applicable). (HI) nb = Heat input from co-fired fossil fuels

and non-biomass-derived fuels for the measurement period, based on company records of fuel usage and default or measured HHV values (Btu/month or Btu/ year, as applicable). (HHV) bio = Default or measured high heat

value of the biomass fuel (Btu/lb). (Eff) bio = Percent efficiency of biomass-toenergy conversion, expressed as a decimal

fraction. 2000 = Conversion factor (lb/ton). **§ 98.34 Monitoring and QA/QC requirements.** 

The CO 2 mass emissions data for stationary fuel combustion sources shall
be monitored as follows:

(a) For the Tier 2 Calculation Methodology:

(1) All fuel samples shall be taken at a location in the fuel handling system that provides a sample representative of the fuel combusted. The fuel sampling and analysis may be performed by either the owner or operator or the supplier of
the fuel.

(2) The minimum required frequency of the HHV sampling and analysis for each type of fuel is specified in this paragraph. When the specified frequency is based on a specified time period (i.e., weekly, monthly, quarterly, or semiannually), fuel sampling and analysis is required only for those periods in which the unit operates. (i) For natural gas, semiannual sampling and analysis is required (i.e., twice in a calendar year, with consecutive samples taken at least four months apart).

(ii) For coal and fuel oil, analysis of at least one representative sample from each fuel lot is required. For the purposes of this section, a fuel lot is defined as a shipment or delivery of a single fuel (e.g., ship load, barge load, group of trucks, group of railroad cars, etc.).

(iii) For liquid fuels other than fuel oil, for fossil fuel-derived gaseous fuels, and for biogas; sampling and analysis is required at least once per calendar quarter. To the extent practicable, consecutive quarterly samples shall be taken at least 30 days apart.

(iv) For solid fuels other than coal and MSW, weekly sampling is required to


### 56404 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

obtain composite samples, which are then analyzed monthly.

(3) If different types of fuel (e.g.,
different ranks of coal or different grades of fuel oil) are blended prior to combustion, use one of the following procedures in this paragraph.

(i) Use a weighted HHV value in the emission calculations, based on the relative proportions of each fuel in the
blend.

(ii) Take a representative sample of the blend and analyze it for HHV.

(4) If, for a particular type of fuel, HHV sampling and analysis is performed more often than the minimum frequency specified in paragraph (a)(2) of this section, the results of all valid fuel analyses shall be
used in the GHG emission calculations.

(5) If, for a particular type of fuel,
valid HHV values are obtained at less than the minimum frequency specifed in paragraph (a)(2) of this section, appropriate substitute data values shall be used in the emissions calculations, in accordance with missing data procedures of § 98.35.

(6) Use any applicable fuel sampling and analysis methods in this paragraph (a)(6) to determine the high heat values. Alternatively, for gaseous fuels, the HHV may be calculated using chromatographic analysis together with standard heating values of the fuel constituents, provided that the gas chromatograph is operated, maintained, and calibrated according to the
manufacturer’s instructions.

(i) ASTM D4809–06 Standard Test
Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method) (incorporated by reference, see § 98.7).

(ii) ASTM D240–02 (Reapproved 2007) Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter (incorporated by reference, see § 98.7).

(iii) ASTM D1826–94 (Reapproved 2003) Standard Test Method for Calorific (Heating) Value of Gases in Natural Gas Range by Continuous Recording Calorimeter (incorporated by reference, see § 98.7).

(iv) ASTM D3588–98 (Reapproved 2003) Standard Practice for Calculating Heat Value, Compressibility Factor, and Relative Density of Gaseous Fuels (incorporated by reference, see § 98.7).

(v) ASTM D4891–89 (Reapproved 2006) Standard Test Method for Heating Value of Gases in Natural Gas Range by
Stoichiometric Combustion (incorporated by reference, see § 98.7).

(vi) GPA Standard 2172–09 Calculation of Gross Heating Value, Relative Density, Compressibility and Theoretical Hydrocarbon Liquid Content for Natural Gas Mixtures for Custody Transfer (incorporated by reference, see § 98.7).

(vii) GPA Standard 2261–00, Analysis
for Natural Gas and Similar Gaseous Mixtures by Gas Chromatography (incorporated by reference, see § 98.7).

(viii) ASTM D5865–07a, Standard
Test Method for Gross Calorific Value of Coal and Coke (incorporated by reference, see § 98.7).

(b) For the Tier 3 Calculation Methodology:

(1) Calibrate each oil and gas flow meter according to § 98.3(i) and the provisions of this paragraph (b).

(i) Perform calibrations using any of the test methods and procedures in this paragraph (b)(1)(i):

(A) An applicable flow meter test method listed in paragraphs (b)(4)(i) through (b)(4)(viii) of this section.

(B) The calibration procedures specified by the flow meter
manufacturer.

(C) An industry-accepted or industry standard calibration practice.

(ii) In addition to the initial calibration required by § 98.3(i), recalibrate each fuel flow meter (except for qualifying billing meters under paragraph (b)(1)(iii) of this section) either annually, at the minimum frequency specified by the manufacturer, or at the interval specified by the industry consensus standard practice used.

(iii) Fuel billing meters are exempted from the initial and ongoing calibration requirements of this paragraph, provided that the fuel supplier and the unit combusting the fuel do not have any common owners and are not owned by subsidiaries or affiliates of the same

company.

(iv) For the initial calibration of an orifice, nozzle, or venturi meter; in-situ
calibration of the transmitters is sufficient. A primary element inspection (PEI) shall be performed at least once every three years.

(v) For the continuously-operating units and processes described in § 98.3(i)(6), the required flow meter recalibrations and, if necessary, the PEIs may be postponed until the next scheduled maintenance outage.

(vi) If a mixture of fuels is transported by a common pipe (e.g., still gas and supplementary natural gas), you must either separately meter each of the fuels prior to mixing using flow meters calibrated according to § 98.3(i), or use flow meters calibrated according to § 98.3(i) to measure the mixed fuel at the common pipe and to separately meter an appropriate subset of the fuels prior to mixing. If the latter option is chosen, quantify the fuels that are not measured prior to mixing by subtracting out the fuels measured prior to mixing
from the fuel measured at the common pipe.

(2) Oil tank drop measurements (if used to determine liquid fuel use volume) shall be performed according to any an appropriate method published by a consensus-based standards organization (e.g., the American Petroleum Institute).

(3) The carbon content and, if applicable, molecular weight of the fuels shall be determined according to the procedures in this paragraph (b)(3).

(i) All fuel samples shall be taken at a location in the fuel handling system that provides a sample representative of the fuel combusted. The fuel sampling and analysis may be performed by either the owner or operator or by the supplier
of the fuel.

(ii) At a minimum, fuel samples shall be collected at the frequency specified in this paragraph. When sampling is required at a specified time interval (e.g., weekly, monthly, quarterly, or semiannually), fuel sampling and analysis is required for only those specified periods in which the unit operates.

(A) For natural gas, semiannual sampling and analysis is required (i.e., twice in a calendar year, with consecutive samples taken at least four months apart).

(B) For coal and fuel oil, analysis of at least one representative sample from each fuel lot is required. For the purposes of this section, a fuel lot is defined as a shipment or delivery of a single fuel (e.g., ship load, barge load, group of trucks, group of railroad cars, etc.).

(C) For other liquid fuels other than fuel oil, for fossil fuel-derived gaseous fuels, and for biogas; sampling and analysis is required at least once per calendar quarter. To the extent practicable, consecutive quarterly samples shall be taken at least 30 days apart.

(D) For solid fuels other than coal, weekly sampling is required to obtain composite samples, which are then analyzed monthly.

(E) For gaseous fuels other than natural gas and biogas (e.g., refinery gas), daily sampling and analysis to
determine the carbon content and molecular weight of the fuel is required if the necessary equipment is in place to make these measurements. Otherwise, weekly sampling and analysis shall be performed.

(iii) If, for a particular type of fuel, sampling and analysis for carbon content and molecular weight is performed more often than the


### 56405 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

minimum frequency specified in paragraph (b)(3) of this section, the results of all valid fuel analyses shall be
used in the GHG emission calculations.

(iv) If, for a particular type of fuel, sampling and analysis for carbon content and molecular weight is performed at less than the minimum frequency specified in paragraph (b)(3) of this section, appropriate substitute
data values shall be used in the emissions calculations, in accordance with the missing data procedures of § 98.35.

(v) The procedures of paragraph (a)(3) of this section apply to carbon content and molecular weight determinations.

(4) Use any applicable standard method from the following list to quality assure the data from each fuel
flow meter.

(i) AGA Report No. 3, Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids, Part 1: General Equations and Uncertainty Guidelines (1990) and Part 2: Specification and Installation Requirements (2000) (incorporated by reference, see § 98.7).

(ii) AGA Transmission Measurement Committee Report No. 7, Measurement of Gas by Turbine Meters (2006) (incorporated by reference, see § 98.7).

(iii) ASME MFC–3M–2004 Measurement of Fluid Flow in Pipes Using Orifice, Nozzle, and Venturi (incorporated by reference, see § 98.7).

(iv) ASME MFC–4M–1986 (Reaffirmed 1997), Measurement of Gas Flow by Turbine Meters (incorporated by reference, see § 98.7).

(v) ASME MFC–5M–1985 (Reaffirmed 1994), Measurement of Liquid Flow in Closed Conduits Using Transit-Time Ultrasonic Flowmeters (incorporated by reference, see § 98.7).

(vi) ASME MFC–6M–1998 Measurement of Fluid Flow in Pipes Using Vortex Flowmeters (incorporated by reference, see § 98.7).

(vii) ASME MFC–7M–1987 (Reaffirmed 1992), Measurement of Gas Flow by Means of Critical Flow Venturi Nozzles (incorporated by reference, see § 98.7).

(viii) ASME MFC–9M–1988 (Reaffirmed 2001), Measurement of Liquid Flow in Closed Conduits by Weighing Method (incorporated by reference, see § 98.7).

(5) Use any applicable methods from the following list to determine the carbon content and molecular weight (for gaseous fuel) of the fuel. Alternatively, the results of chromatographic analysis of the fuel may be used, provided that the gas chromatograph is operated, maintained, and calibrated according to the
manufacturer’s instructions.

(i) ASTM D1945–03 Standard Test Method for Analysis of Natural Gas by Gas Chromatography (incorporated by reference, see § 98.7).

(ii) ASTM D1946–90 (Reapproved 2006) Standard Practice for Analysis of Reformed Gas by Gas Chromatography (incorporated by reference, see § 98.7).

(iii) ASTM D2502–04 (Reapproved 2002) Standard Test Method for Estimation of Molecular Weight (Relative Molecular Mass) of Petroleum Oils from Viscosity Measurements (incorporated by reference, see § 98.7).

(iv) ASTM D2503–92 (Reapproved 2007) Standard Test Method for Relative Molecular Mass (Relative Molecular Weight) of Hydrocarbons by Thermoelectric Measurement of Vapor Pressure (incorporated by reference, see § 98.7).

(v) ASTM D3238–95 (Reapproved 2005) Standard Test Method for
Calculation of Carbon Distribution and Structural Group Analysis of Petroleum Oils by the n-d-M Method (incorporated by reference, see § 98.7).

(vi) ASTM D5291–02 (Reapproved 2007) Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants (incorporated by reference, see § 98.7).

(vii) ASTM D5373–08 Standard Test
Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal (incorporated by reference, see § 98.7).

(c) For the Tier 4 Calculation Methodology, the CO 2 and flow rate monitors must be certified prior to the applicable deadline specified in § 98.33(b)(5).

(1) For initial certification, you may use any one of the following three procedures in this paragraph.

(i) § 75.20(c)(2) and (4) and appendix A to 40 CFR part 75.

(ii) The calibration drift test and relative accuracy test audit (RATA) procedures of Performance Specification 3 in appendix B to part 60 (for the CO 2 concentration monitor) and Performance Specification 6 in appendix B to part 60 (for the continuous emission rate monitoring system (CERMS)).

(iii) The provisions of an applicable State continuous monitoring program.

(2) If an O 2 concentration monitor is
used to determine CO 2 concentrations, the applicable provisions of 40 CFR part 75, 40 CFR part 60, or an applicable State continuous monitoring program
shall be followed for initial certification and on-going quality assurance, and all required RATAs of the monitor shall be done on a percent CO 2 basis. (3) For ongoing quality assurance, follow the applicable procedures in either appendix B to 40 CFR part 75, appendix F to 40 CFR part 60, or an applicable State continuous monitoring program. If appendix F to 40 CFR part 60 is selected for on-going quality assurance, perform daily calibration
drift assessments for both the CO 2 monitor (or surrogate O 2 monitor) and the flow rate monitor, conduct cylinder gas audits of the CO 2 concentration monitor in three of the four quarters of each year (except for non-operating quarters), and perform annual RATAs of
the CO 2 concentration monitor and the

CERMS.

(4) For the purposes of this part, the stack gas volumetric flow rate monitor RATAs required by appendix B to 40 CFR part 75 and the annual RATAs of the CERMS required by appendix F to 40 CFR part 60 need only be done at one operating level, representing normal load or normal process operating conditions, both for initial certification and for ongoing quality assurance.

(5) If, for any source operating hour, quality assured data are not obtained
with a CO 2 monitor (or surrogate O 2 monitor), flow rate monitor, or (if applicable) moisture monitor, use appropriate substitute data values in accordance with the missing data provisions of § 98.35.

(d) When municipal solid waste (MSW) is combusted in a unit, determine the biogenic portion of the

CO 2 emissions from MSW combustion using ASTM D6866–08 Standard Test Methods for Determining the Biobased Content of Solid, Liquid, and Gaseous Samples Using Radiocarbon Analysis (incorporated by reference, see § 98.7)
and ASTM D7459–08 Standard Practice for Collection of Integrated Samples for the Speciation of Biomass (Biogenic)
and Fossil-Derived Carbon Dioxide Emitted from Stationary Emissions Sources (incorporated by reference, see § 98.7). Perform the ASTM D7459–08 sampling and the ASTM D6866–08 analysis at least once in every calendar quarter in which MSW is combusted in the unit. Collect each gas sample during normal unit operating conditions while MSW is the only fuel being combusted
for at least 24 consecutive hours or for as long as is necessary to obtain a sample large enough to meet the specifications of ASTM D6866–08. Separate CO 2 emissions into the biogenic and non-biogenic fraction using the average proportion of biogenic emissions of all samples analyzed during the reporting year. Express the results as a decimal fraction (e.g., 0.30, if 30 percent of the CO 2 from MSW combustion is biogenic). If there is a


### 56406 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

common fuel source of MSW that feeds multiple units at the facility, performing the testing at only one of the units is
sufficient.

(e) For units that use CEMS to
measure the total CO 2 mass emissions and combust a combination of biogenic fuels (other than MSW) with a fossil fuel, ASTM D6866–08 and ASTM D7459–08 may be used to determine the biogenic portion of the CO 2 emissions. Perform the ASTM D7459–08 sampling and the ASTM D6866–08 analysis at least once in every calendar quarter in which biogenic and non-biogenic fuels
are co-fired in the unit. The relativeproportions of the biogenic and nonbiogenic fuels during the sampling shall be representative of the average fuel blend for a typical operating year. Collect each gas sample using ASTM D7459–08 during normal unit operation
for at least 24 consecutive hours or for as long as is necessary to obtain a sample large enough to meet the specifications of ASTM D6866–08.

(f) Whenever company records are
used in the calculation of CO 2 emissions, the records required under § 98.3(g) shall include both the company records and an explanation of how those
records are used to estimate the following parameters:

(1) Fuel consumption, when the Tier 1 and Tier 2 Calculation Methodologies
are used.

(2) Fuel consumption, when solid fuel
is combusted and the Tier 3 Calculation Methodology is used.

(3) Fossil fuel consumption when § 98.33(e) applies to a unit that uses CEMS to quantify CO 2 emissions and
that combusts both fossil and biomass
fuels.

(4) Sorbent usage, when § 98.33(d) applies.

(5) Quantity of steam generated by a unit when § 98.33(a)(2) applies.

(6) Biogenic fuel consumption under § 98.33(e)(5).

(g) As part of the GHG Monitoring Plan required under § 98.3(g)(5), you must document the procedures used to ensure the accuracy of the estimates of fuel usage, sorbent usage, steam production, and boiler efficiency (as applicable) in paragraph (f) of this section, including but not limited to calibration of weighing equipment, fuel flow meters, steam flow meters, and
other measurement devices. The estimated accuracy of measurements
made with these devices shall also be recorded, and the technical basis for these estimates shall be provided. **§ 98.35 Procedures for estimating missing**
**data.**

Whenever a quality-assured value of a required parameter is unavailable (e.g., if a CEMS malfunctions during unit operation or if a required fuel sample is not taken), a substitute data value for the missing parameter shall be used in
the calculations.

(a) For all units subject to the requirements of the Acid Rain Program, and all other stationary combustion units subject to the requirements of this part that monitor and report emissions and heat input data in accordance with 40 CFR part 75, the missing data substitution procedures in 40 CFR part
75 shall be followed for CO 2 concentration, stack gas flow rate, fuel flow rate, high heating value, and fuel
carbon content.

(b) For units that use the Tier 1, Tier 2, Tier 3, and Tier 4 Calculation Methodologies, perform missing data
substitution as follows for each parameter:

(1) For each missing value of the high heating value, carbon content, or molecular weight of the fuel, substitutethe arithmetic average of the qualityassured values of that parameter immediately preceding and immediately following the missing data incident. If
the ‘‘after’’ value has not been obtained by the time that the GHG emissions report is due, you may use the ‘‘before’’ value for missing data substitution or
the best available estimate of the parameter, based on all available process data (e.g., electrical load, steam production, operating hours). If, for a particular parameter, no quality-assured data are available prior to the missing data incident, the substitute data value shall be the first quality-assured value obtained after the missing data period.

(2) For missing records of CO 2 concentration, stack gas flow rate, percent moisture, fuel usage, and sorbent usage, the substitute data value
shall be the best available estimate of the parameter, based on all available process data (e.g., electrical load, steam production, operating hours, etc.). You
must document and retain records of the procedures used for all such estimates.

**§ 98.36 Data reporting requirements.**

(a) In addition to the facility-level information required under § 98.3, the annual GHG emissions report shall contain the unit-level or process-level emissions data in paragraphs (b) through (d) of this section (as applicable) and the emissions verification data in paragraph (e) of this

section.

(b) Units that use the four tiers . You shall report the following information for stationary combustion units that use the Tier 1, Tier 2, Tier 3, or Tier 4 methodology in § 98.33(a) to calculate

CO 2 emissions, except as otherwise provided in paragraphs (c) and (d) of
this section:

(1) The unit ID number. (2) A code representing the type of

unit.

(3) Maximum rated heat input capacity of the unit, in mmBtu/hr for boilers and process heaters only and
relevant units of measure for other
combustion sources.

(4) Each type of fuel combusted in the unit during the report year.

(5) The tier used to calculate the CO 2 emissions for each type of fuel combusted (i.e., Tier 1, 2, 3, or 4).

(6) For a unit that uses Tiers 1, 2, and 3; the CO 2 , CH 4 , and N 2 O emissions for each type of fuel combusted, expressed in metric tons of each gas and in metric
tons of CO 2 e.

(7) For a unit that uses Tier 4: (i) For units that burn fossil fuels only, the annual CO 2 emissions for all fuels combined. Reporting CO 2 emissions by type of fuel is not required.

(ii) For units that burn both fossil fuels and biomass, the annual CO 2 emissions from combustion of all fossil
fuels combined and the annual CO 2 emissions from combustion of all biomass fuels combined. Reporting CO 2 emissions by type of fuel is not required.

(iii) Annual CH4 and N 2 O emissions for each type of fuel combusted expressed in metric tons of each gas and
in metric tons of CO 2 e.

(8) Annual CO 2 emissions from sorbent (if calculated using Equation C– 11 of this subpart), expressed in metric

tons.

(9) Annual GHG emissions from all fossil fuels burned in the unit (i.e., the
sum of the CO 2 , CH 4 , and N 2 O emissions), expressed in metric tons of

CO 2 e.

(10) Customer meter number for units that combust natural gas.

(c) Reporting alternatives for units using the four Tiers . You may use any of the applicable reporting alternativesof this paragraph to simplify the unitlevel reporting required under paragraph (b) of this section:

(1) Aggregation of units . If a facility contains two or more units (e.g., boilers or combustion turbines), each of which has a maximum rated heat input capacity of 250 mmBtu/hr or less, you may report the combined GHG emissions for the group of units in lieu of reporting GHG emissions from the individual units, provided that the use of Tier 4 is not required or elected for


### 56407 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

any of the units and the units use the same tier for any common fuels combusted. If this option is selected, the following information shall be reported instead of the information in paragraph (b) of this section:

(i) Group ID number, beginning with the prefix ‘‘GP’’.

(ii) An identification number for each unit in the group.

(iii) Cumulative maximum rated heat input capacity of the group (mmBtu/hr).

(iv) The highest maximum rated heat input capacity of any unit in the group (mmBtu/hr).

(v) Each type of fuel combusted in the group of units during the reporting year.

(vi) Annual CO 2 , CH 4 , and N 2 O mass emissions aggregated for each type of fuel combusted in the group of units during the year, expressed in metric tons of each gas and in metric tons of

CO 2 e. If any of the units burn both fossil fuels and biomass, report also the
annual CO 2 emissions from combustion
of all fossil fuels combined and annual

CO 2 emissions from combustion of all biomass fuels combined, expressed in

metric tons.

(vii) The tier used to calculate the CO 2 mass emissions for each type of fuel combusted in the units (i.e., Tier 1, Tier 2, or Tier 3).

(viii) The calculated CO 2 mass emissions (if any) from sorbent.

(ix) Annual GHG emissions from all fossil fuels burned in the group (i.e., the
sum of the CO 2 , CH 4 , and N 2 O emissions), expressed in metric tons of

CO 2 e.

(2) Monitored common stack or duct configurations . When the flue gases from two or more stationary combustion units at a facility are discharged through a common stack or duct before exiting to the atmosphere and if CEMS are used to continuously monitor CO 2 mass emissions at the common stack or duct according to the Tier 4 Calculation Methodology, you may report the
combined emissions from the units sharing the common stack or duct, in lieu of separately reporting the GHG
emissions from the individual units. The following information shall be reported instead of the information in paragraph (b) of this section:

(i) Common stack or duct identification number, beginning with the prefix ‘‘CS’’.

(ii) Identification numbers of the units sharing the common stack or duct.

(iii) Maximum rated heat input capacity of each unit sharing the common stack or duct (mmBtu/hr).

(iv) Each type of fuel combusted in the units during the year.

(v) The methodology used to calculate
the CO 2 mass emissions, i.e., Tier 4. (vi) If the any of the units burn both fossil fuels and biomass, annual CO 2 mass emissions, annual CO 2 emissions from combustion of fossil fuels, and
annual CO 2 emissions from combustion
of biomass measured at the common stack or duct, expressed in metric tons.

(vii) The annual CH4 and N 2 O emissions from the units sharing the common stack or duct, expressed in metric tons of each gas and in metric
tons of CO 2 e.

(viii) Annual GHG emissions from all fossil fuels burned in the group (i.e., the
sum of the CO 2 , CH 4 , and N 2 O emissions), expressed in metric tons of

CO 2 e.

(3) Common pipe configurations

. When two or more liquid-fired or gaseous-fired stationary combustion units at a facility combust the same type
of fuel and the fuel is fed to the individual units through a common supply line or pipe, you may report the
combined emissions from the units served by the common supply line, in lieu of separately reporting the GHG emissions from the individual units, provided that the total amount of fuel combusted by the units is accurately measured at the common pipe or supply line using a fuel flow meter that is calibrated in accordance with § 98.34(a). If a portion of the fuel measured at the common pipe is diverted to a chemical or industrial process where it is used but not combusted, you may subtract
the diverted fuel from the fuel measured at the common pipe prior to performing the GHG emissions calculations, provided that the amount of fuel
diverted is also measured with a calibrated flow meter per § 98.3(i). If the common pipe option is selected, the applicable tier shall be used based on the maximum rated heat input capacity of the largest unit served by the common pipe configuration. The following information shall be reported instead of the information in paragraph (b) of this section:

(i) Common pipe identification number, beginning with the prefix

‘‘CP’’.

(ii) The identification numbers of the units served by the common pipe.

(iii) Maximum rated heat input capacity of each unit served by the common pipe (mmBtu/hr).

(iv) The fuels combusted in the units during the reporting year.

(v) The methodology used to calculate
the CO 2 mass emissions (i.e., Tier 1, Tier 2, or Tier 3).

(vi) If the any of the units burns both fossil fuels and biomass, the annual CO 2 mass emissions from combustion of all
fossil fuels and annual CO 2 emissions
from combustion of all biomass fuels from the units served by the common pipe, expressed in metric tons.

(vii) Annual CH4 and N 2 O emissions from the units served by the common pipe, expressed in metric tons of each gas and in metric tons of CO 2 e.

(viii) Annual GHG emissions from all fossil fuels burned in units served by the common pipe (i.e., the sum of the

CO 2 , CH 4 , and N 2 O emissions), expressed in metric tons of CO 2 e.

(d) Units subject to 40 CFR part 75. (1) For stationary combustion units that are either subject to the Acid Rain Program or not in the Acid Rain Program but monitor and report CO 2 mass emissions year-round according to 40 CFR part 75, you shall report the following unit-level information:

(i) Unit or stack identification numbers. Use exact same unit, common stack, or multiple stack identification numbers that represent the monitored locations (e.g., 1, 2, CS001, MS1A, etc.) that are reported under § 75.64 of this chapter.

(ii) Annual CO 2 , CH 4 , and N 2 O emissions at each monitored location, expressed in metric tons of CO 2 e.

(iii) Identification of the Part 75 methodology used to determine the CO 2 mass emissions.

(2) For units that use the alternative

CO 2 mass emissions calculation
methods for units with continuous monitoring systems provided in § 98.33(a)(5), you shall report the following unit-level information:

(i) Unit, stack, or pipe ID numbers. Use exact same unit, common stack, or multiple stack identification numbers that represent the monitored locations (e.g., 1, 2, CS001, MS1A, etc.) that are reported under § 75.64 of this chapter.

(ii) For units that use the alternative methods specified in § 98.33(a)(5)(i) and (ii) to monitor and report heat input data year-round according to appendix D to 40 CFR part 75 or 40 CFR 75.19:

(A) Each type of fuel combusted in the unit during the reporting year.

(B) The methodology used to calculate
the CO 2 mass emissions for each fuel type.

(C) A code or flag to indicate whether heat input is calculated according to appendix D to 40 CFR part 75 or 40 CFR

75.19.

(D) Annual CO 2 , CH 4 , and N 2 O emissions at each monitored location, across all fuel types, expressed in metric
tons of CO 2 e.

(iii) For units with continuous monitoring systems that use the
alternative method for units with continuous monitoring systems in § 98.33(a)(5)(iii) to monitor heat input year-round according to 40 CFR part 75:

(A) Fuel combusted during the reporting year.


### 56408 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

(B) Methodology used to calculate the

CO 2 mass emissions.

(C) A code or flag to indicate that the heat input data is derived from CEMS

measurements.

(D) The total annual CO 2 , CH 4 , and

N 2 O emissions at each monitored location, expressed in metric tons of

CO 2 e.

(e) Verification data . You must keep on file, in a format suitable for inspection and auditing, sufficient data to verify the reported GHG emissions. This data and information must, where indicated in this paragraph (e), be
included in the annual GHG emissions report.

(1) The applicable verification data specified in this paragraph (e) are not required to be kept on file or reported for units that meet any one of the three following conditions:

(i) Are subject to the Acid Rain Program.

(ii) Use the alternative methods for units with continuous monitoring systems provided in § 98.33(a)(5).

(iii) Are not in the Acid Rain Program, but are required monitor and report CO 2 mass emissions and heat input data year-round, in accordance with 40 CFR part 75.

(2) For stationary combustion sources using the Tier 1, Tier 2, Tier 3, and Tier 4 Calculation Methodologies in § 98.33(a) to quantify CO 2 emissions, the following additional information shall be kept on file and included in the GHG emissions report, where indicated:

(i) For the Tier 1 Calculation Methodology, report the total quantity of each type of fuel combusted in the unit or group of aggregated units (as applicable) during the reporting year, in short tons for solid fuels, gallons for liquid fuels and standard cubic feet for gaseous fuels.

(ii) For the Tier 2 Calculation Methodology, report:

(A) The total quantity of each type of fuel combusted in the unit or group of aggregated units (as applicable) during each month of the reporting year. Express the quantity of each fuel combusted during the measurement period in short tons for solid fuels, gallons for liquid fuels, and scf for gaseous fuels.

(B) The frequency of the HHV determinations (e.g., once a month, once per fuel lot).

(C) The high heat values used in the

CO 2 emissions calculations for each type of fuel combusted, in mmBtu per short ton for solid fuels, mmBtu per gallon for liquid fuels, and mmBtu per scf for gaseous fuels. Specify the date on which each fuel sample was taken.
Indicate whether each HHV is a measured value of a substitute data
value.

(D) If Equation C–2c of this subpart is
used to calculate CO 2 mass emissions, report the total quantity (i.e., pounds) of steam produced from MSW or solid fuel combustion during the year, and the ratio of the maximum rate heat input capacity to the design rated steam output capacity of the unit, in mmBtu per lb of steam.

(iii) For the Tier 2 Calculation Methodology, keep records of the
methods used to determine the HHV for each type of fuel combusted and the date on which each fuel sample was
taken.

(iv) For the Tier 3 Calculation Methodology, report:

(A) The quantity of each type of fuel combusted in the unit or group of units (as applicable) during the year, in short tons for solid fuels, gallons for liquid fuels, and scf for gaseous fuels.

(B) The frequency of carbon content and, if applicable, molecular weight determinations for each type of fuel for the reporting year (e.g., daily, weekly, monthly, semiannually, once per fuel lot).

(C) The carbon content and, if applicable, gas molecular weight values
used in the emission calculations (including both valid and substitute data values). Report all measured values if the fuel is sampled monthly or less frequently. Otherwise, for daily and weekly sampling, report monthly average values determined using the calculation procedures in Equation C– 2b for each variable. Express carbon
content as a decimal fraction for solid fuels, kg C per gallon for liquid fuels, and kg C per kg of fuel for gaseous fuels. Express the gas molecular weights in units of kg per kg-mole.

(D) The total number of valid carbon content determinations and, if applicable, molecular weight determinations made during the reporting year, for each fuel type.

(E) The number of substitute data values used for carbon content and, if applicable, molecular weight used in
the annual GHG emissions calculations.

(v) For the Tier 3 Calculation Methodology, keep records of the following:

(A) For liquid and gaseous fuel combustion, the dates and results of the initial calibrations and periodic recalibrations of the required fuel flow

meters.

(B) For fuel oil combustion, the method from § 98.34(b) used to make tank drop measurements (if applicable).

(C) The methods used to determine the carbon content for each type of fuel
combusted. (D) The methods used to calibrate the fuel flow meters).

(vi) For the Tier 4 Calculation Methodology, report:

(A) The total number of source operating hours in the reporting year.

(B) The cumulative CO 2 mass emissions in each quarter of the reporting year, i.e., the sum of the hourly values calculated from Equation C–6 or C–7 of this subpart (as applicable), in metric tons.

(C) For CO 2 concentration, stack gas flow rate, and (if applicable) stack gas moisture content, the percentage of source operating hours in which a substitute data value of each parameter
was used in the emissions calculations.

(vii) For the Tier 4 Calculation Methodology, keep records of:

(A) Whether the CEMS certification and quality assurance procedures of 40 CFR part 75, 40 CFR part 60, or an applicable State continuous monitoring program were used.

(B) The dates and results of the initial
certification tests of the CEMS.

(C) The dates and results of the major quality assurance tests performed on the CEMS during the reporting year, i.e., linearity checks, cylinder gas audits, and relative accuracy test audits (RATAs).

(viii) If CO 2 emissions that are generated from acid gas scrubbing with sorbent injection are not captured using CEMS, report:

(A) The total amount of sorbent used during the report year, in short tons.

(B) The molecular weight of the
sorbent.

(C) The ratio (‘‘R’’) in Equation C–11 of this subpart.

(ix) For units that combust both fossil fuel and biomass, when CEMS are used to quantify the annual CO 2 emissions and biogenic CO 2 is determined according to § 98.33(e)(2), you shall report the following additional information, as applicable:

(A) The annual volume of CO 2 emitted from the combustion of all fuels, i.e., Vtotal , in scf.

(B) The annual volume of CO 2 emitted from the combustion of fossil fuels, i.e.,

Vff, in scf. If more than one type of fossil fuel was combusted, report the
combustion volume of CO 2 for each fuel separately as well as the total.

(C) The annual volume of CO 2 emitted from the combustion of biomass, i.e.,

Vbio , in scf.

(D) The carbon-based F-factor used in Equation C–13 of this subpart, for each type of fossil fuel combusted, in scf CO 2 per mmBtu.

(E) The annual average HHV value used in Equation C–13 of this subpart, for each type of fossil fuel combusted,


### 56409 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

in Btu/lb, Btu/gal, or Btu/scf, as appropriate.

(F) The total quantity of each type of fossil fuel combusted during the reporting year, in lb, gallons, or scf, as appropriate.

(G) Annual biogenic CO 2 mass emissions, in metric tons.

(x) When ASTM methods D7459–08
and D6866–08 are used to determine the biogenic portion of the annual CO 2 emissions from MSW combustion, report:

(A) The results of each quarterly sample analysis, expressed as a decimal fraction (e.g., if the biogenic fraction of
the CO 2 emissions from MSW combustion is 30 percent, report 0.30).

(B) Annual combined biomass and
fossil fuel CO 2 emissions from MSW combustion, in metric tons of CO 2 e.

(C) The quantities Vff, Vtotal , and VMSW from § 98.33(e)(4)(ii), if CEMS are used

to measure CO 2 emissions.

(D) The annual volume of biogenic

CO 2 emissions from MSW combustion,

in metric tons. (xi) When ASTM methods D7459–08
and D6866–08 are used to determine the biogenic portion of the annual CO 2 emissions from a unit that co-firesbiogenic (other than MSW) and nonbiogenic fuels, you shall report the results of each quarterly sample analysis, expressed as a decimal fraction (e.g., if the biogenic fraction of the CO 2 emissions is 30 percent, report 0.30).

(3) Within 30 days of receipt of a written request from the Administrator, you shall submit explanations of the following:

(i) An explanation of how company records are used to quantify fuel consumption, if the Tier 1 or Tier 2 Calculation Methodology is used to
calculate CO 2 emissions.

(ii) An explanation of how company records are used to quantify fuel consumption, if solid fuel is combusted and the Tier 3 Calculation Methodology
is used to calculate CO 2 emissions.

(iii) An explanation of how sorbent usage is quantified.

(iv) An explanation of how company records are used to quantify fossil fuel consumption in units that uses CEMS to quantify CO 2 emissions and combusts
both fossil fuel and biomass.

(v) An explanation of how company
records are used to measure steam production, when it is used to calculate

CO 2 mass emissions under § 98.33(a)(2)(iii) or to quantify solid fuel usage under § 98.33(c)(3).

(4) Within 30 days of receipt of a written request from the Administrator, you shall submit the verification data
and information described in paragraphs (e)(2)(iii), (e)(2)(v), and (e)(2)(vii) of this section.

**§ 98.37 Records that must be retained.**

In addition to the requirements of § 98.3(g), you must retain the applicable records specified in §§ 98.34(f) and (g), 98.35(b), and 98.36(e).

**§ 98.38 Definitions.**

All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.



### TABLE 

### C–1 TO 

### S UBPART 

### C OF 

### P ART 

### 98—D EFAULT 

### CO 2 

### E MISSION 

### FACTORS AND 

### H IGH 

### H EAT 

### VALUES FOR 

### VARIOUS 

### TYPES OF 

### F UEL

Fuel type Default high heat value Default CO 2 emission factor

Coal and coke mmBtu/short ton kg CO 2/mmBtu

Anthracite ..................................................................................................................... ................................... 25.09 103.54
Bituminous ..................................................................................................................... ................................. 24.93 93.40 Subbituminous .................................................................................................................. .............................. 17.25 97.02 Lignite ........................................................................................................................ ..................................... 14.21 96.36 Coke ........................................................................................................................... ..................................... 24.80 102.04 Mixed (Commercial sector) ...................................................................................................... ....................... 21.39 95.26 Mixed (Industrial coking) ...................................................................................................... ........................... 26.28 93.65 Mixed (Industrial sector) ...................................................................................................... ........................... 22.35 93.91 Mixed (Electric Power sector) .................................................................................................. ....................... 19.73 94.38

Natural gas mmBtu/scf kg CO 2/mmBtu

Pipeline (Weighted U.S. Average) ............................................................................................... ................... 1.028 × 10

¥ 3 53.02

Petroleum products mmBtu/gallon kg CO 2/mmBtu

Distillate Fuel Oil No. 1 ...................................................................................................... ............................. 0.139 73.25
Distillate Fuel Oil No. 2 ...................................................................................................... ............................. 0.138 73.96
Distillate Fuel Oil No. 4 ...................................................................................................... ............................. 0.146 75.04
Residual Fuel Oil No. 5 ........................................................................................................ .......................... 0.140 72.93
Residual Fuel Oil No. 6 ........................................................................................................ .......................... 0.150 75.10
Still Gas ...................................................................................................................... .................................... 0.143 66.72
Kerosene ....................................................................................................................... .................................. 0.135 75.20 Liquefied petroleum gases (LPG) ................................................................................................ ................... 0.092 62.98 Propane ........................................................................................................................ .................................. 0.091 61.46 Propylene ...................................................................................................................... .................................. 0.091 65.95
Ethane ......................................................................................................................... .................................... 0.096 62.64 Ethylene ....................................................................................................................... ................................... 0.100 67.43
Isobutane ...................................................................................................................... .................................. 0.097 64.91 Isobutylene .................................................................................................................... .................................. 0.103 67.74
Butane ......................................................................................................................... .................................... 0.101 65.15 Butylene ....................................................................................................................... ................................... 0.103 67.73 Naphtha (<401 deg F) ........................................................................................................... ......................... 0.125 68.02
Natural Gasoline ............................................................................................................... .............................. 0.110 66.83 Other Oil (>401 deg F) ......................................................................................................... .......................... 0.139 76.22
Pentanes Plus .................................................................................................................. ............................... 0.110 70.02
Petrochemical Feedstocks ....................................................................................................... ....................... 0.129 70.97


### 56410 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

TABLE 

### C–1 TO 

### S UBPART 

### C OF 

### P ART 

### 98—D EFAULT 

### CO 2 

### E MISSION 

### FACTORS AND 

### H IGH 

### H EAT 

### VALUES FOR 

### VARIOUS 

### TYPES OF 

### F UEL

### —Continued

Fuel type Default high heat value Default CO 2 emission factor

Petroleum Coke ................................................................................................................. ............................. 0.143 102.41 Special Naphtha ................................................................................................................ ............................. 0.125 72.34
Unfinished Oils ................................................................................................................ ................................ 0.139 74.49 Heavy Gas Oils ................................................................................................................. .............................. 0.148 74.92
Lubricants ..................................................................................................................... .................................. 0.144 74.27
Motor Gasoline ................................................................................................................. .............................. 0.125 70.22
Aviation Gasoline .............................................................................................................. .............................. 0.120 69.25 Kerosene-Type Jet Fuel ......................................................................................................... ........................ 0.135 72.22 Asphalt and Road Oil ........................................................................................................... .......................... 0.158 75.36
Crude Oil ...................................................................................................................... ................................... 0.138 74.49

Fossil fuel-derived fuels (solid) mmBtu/short ton kg CO 2/mmBtu

Municipal Solid Waste 1

............................................................................................................................... ... 9.95 90.7
Tires .......................................................................................................................... ...................................... 26.87 85.97

Fossil fuel-derived fuels (gaseous) mmBtu/scf kg CO 2/mmBtu

Blast Furnace Gas .............................................................................................................. ............................ 0.092 × 10

¥ 3 274.32
Coke Oven Gas .................................................................................................................. ............................ 0.599 × 10

¥ 3 46.85

Biomass fuels—solid mmBtu/short ton kg CO 2/mmBtu

Wood and Wood Residuals ........................................................................................................ .................... 15.38 93.80 Agricultural Byproducts ........................................................................................................ ........................... 8.25 118.17
Peat ........................................................................................................................... ...................................... 8.00 111.84 Solid Byproducts ............................................................................................................... .............................. 25.83 105.51

Biomass fuels—gaseous mmBtu/scf kg CO 2/mmBtu

Biogas (Captured methane) ...................................................................................................... ..................... 0.841 × 10

¥ 3 52.07

Biomass Fuels—Liquid ........................................................................................................... ........................ mmBtu/gallon kg CO 2/mmBtu

Ethanol (100%) ................................................................................................................. .............................. 0.084 68.44 Biodiesel (100%) ............................................................................................................... .............................. 0.128 73.84
Rendered Animal Fat ............................................................................................................ .......................... 0.125 71.06 Vegetable Oil .................................................................................................................. ................................ 0.120 81.55

1 Allowed only for units that do not generate steam and use Tier 1.



### TABLE 

### C–2 TO 

### S UBPART 

### C OF 

### P ART 

### 98—D EFAULT 

### CH 4 AND 

### N 2 

### O E MISSION 

### FACTORS FOR 

### VARIOUS 

### TYPES OF 

### F UEL

Fuel type Default CH 4 emission factor (kg CH 4/mmBtu) Default N 2 O emission factor (kg N 2 O/mmBtu)

Coal and Coke (All fuel types in Table C–1) .................................................................................... ................ 1.1 × 10

¥ 2 1.6 × 10

¥ 03
Natural Gas .................................................................................................................... .................................... 1.0 × 10

¥ 03 1.0 × 10

¥ 04 Petroleum (All fuel types in Table C–1) ........................................................................................ .................... 3.0 × 10

¥ 03 6.0 × 10

¥ 04 Municipal Solid Waste .......................................................................................................... ............................. 3.2 × 10

¥ 02 4.2 × 10

¥ 03
Tires .......................................................................................................................... ......................................... 3.2 × 10

¥ 02 4.2 × 10

¥ 03
Blast Furnace Gas .............................................................................................................. ............................... 2.2 × 10

¥ 05 1.0 × 10

¥ 04
Coke Oven Gas .................................................................................................................. ............................... 4.8 × 10

¥ 04 1.0 × 10

¥ 04 Biomass Fuels—Solid (All fuel types in Table C–1) .............................................................................. ........... 3.2 × 10

¥ 02 4.2 × 10

¥ 03 Biogas ......................................................................................................................... ....................................... 3.2 × 10

¥ 03 6.3 × 10

¥ 04 Biomass Fuels—Liquid (All fuel types in Table C–1) ............................................................................. ........... 1.1 × 10

¥ 03 1.1 × 10

¥ 04

**Note:** Those employing this table are assumed to fall under the IPCC definitions of the ‘‘Energy Industry’’ or ‘‘Manufacturing Industr ies and Construction’’. In all fuels except for coal the values for these two categories are identical. For coal combustion, those who fall within the IPCC ‘‘Energy Industry’’ category may employ a value of 1g of CH 4/MMBtu.

1 Allowed only for units that do not generate steam and use Tier 1.



### TABLE 

### C–2 TO 

### S UBPART 

### C—D EFAULT 

### CH 4 AND 

### N 2 

### O E MISSION 

### FACTORS FOR 

### VARIOUS 

### TYPES OF 

### F UEL

Fuel type Default CH 4 emission factor (kg CH 4/mmBtu) Default N 2 O emission factor (kg N 2 O/mmBtu)

Coal and Coke (All fuel types in Table C–1) .................................................................................... ................ 1.1 × 10

¥ 2 1.6 × 10

¥ 03
Natural Gas .................................................................................................................... .................................... 1.0 × 10

¥ 03 1.0 × 10

¥ 04


### 56411 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

TABLE 

### C–2 TO 

### S UBPART 

### C—D EFAULT 

### CH 4 AND 

### N 2 

### O E MISSION 

### FACTORS FOR 

### VARIOUS 

### TYPES OF 

### F UEL

### —Continued

Fuel type Default CH 4 emission factor (kg CH 4/mmBtu) Default N 2 O emission factor (kg N 2 O/mmBtu)

Petroleum (All fuel types in Table C–1) ........................................................................................ .................... 3.0 × 10

¥ 03 6.0 × 10

¥ 04 Municipal Solid Waste .......................................................................................................... ............................. 3.2 × 10

¥ 02 4.2 × 10

¥ 03
Tires .......................................................................................................................... ......................................... 3.2 × 10

¥ 02 4.2 × 10

¥ 03
Blast Furnace Gas .............................................................................................................. ............................... 2.2 × 10

¥ 05 1.0 × 10

¥ 04
Coke Oven Gas .................................................................................................................. ............................... 4.8 × 10

¥ 04 1.0 × 10

¥ 04 Biomass Fuels—Solid (All fuel types in Table C–1) .............................................................................. ........... 3.2 × 10

¥ 02 4.2 × 10

¥ 03 Biogas ......................................................................................................................... ....................................... 3.2 × 10

¥ 03 6.3 × 10

¥ 04 Biomass Fuels—Liquid (All fuel types in Table C–1) ............................................................................. ........... 1.1 × 10

¥ 03 1.1 × 10

¥ 04

**Note:** Those employing this table are assumed to fall under the IPCC definitions of the ‘‘Energy Industry’’ or ‘‘Manufacturing Industr ies and Construction’’. In all fuels except for coal the values for these two categories are identical. For coal combustion, those who fall within the IPCC ‘‘Energy Industry’’ category may employ a value of 1 g of CH 4/MMBtu.

**Subpart D—Electricity Generation**

**§ 98.40 Definition of the source category.**

(a) The electricity generation source category comprises electricity generating units that are subject to the requirements of the Acid Rain Program and any other electricity generating units that are required to monitor and report to EPA CO 2 emissions year-round according to 40 CFR part 75.

(b) This source category does not include portable equipment, emergency equipment, or emergency generators, as defined in § 98.6.

**§ 98.41 Reporting threshold.**

You must report GHG emissions under this subpart if your facility contains one or more electricity generating units and the facility meets the requirements of § 98.2(a)(1).

**§ 98.42 GHGs to report.**

(a) For each electricity generating unit that is subject to the requirements of the Acid Rain Program or is otherwise required to monitor and report to EPA

CO 2 emissions year-round according to 40 CFR part 75, you must report under this subpart the annual mass emissions
of CO 2 , N 2 O, and CH 4 by following the requirements of this subpart.

(b) For each electricity generating unit that is not subject to the Acid Rain Program or otherwise required to monitor and report to EPA CO 2 emissions year-round according to 40 CFR part 75, you must report under subpart C of this part (General Stationary Fuel Combustion Sources)
the emissions of CO 2 , CH 4 , and N 2 O by following the requirements of subpart C.

(c) For each stationary fuel combustion unit that does not generate electricity, you must report under subpart C of this part (General Stationary Fuel Combustion Sources)
the emissions of CO 2 , CH 4 , and N 2 O by following the requirements of subpart C of this part. **§ 98.43 Calculating GHG emissions.**

Continue to monitor and report CO 2 mass emissions as required under § 75.13 or section 2.3 of apppendix G to 40 CFR part 75, and § 75.64. Calculate

CO 2 , CH 4 , and N 2 O emissions as
follows:

(a) Convert the cumulative annual

CO 2 mass emissions reported in the fourth quarter electronic data report required under § 75.64 from units of
short tons to metric tons. To convert tons to metric tons, divide by 1.1023.

(b) Calculate and report annual CH4 and N 2 O mass emissions under this subpart by following the applicable method specified in § 98.33(c).

**§ 98.44 Monitoring and QA/QC requirements.** 

Follow the applicable quality assurance procedures for CO 2 emissions in appendices B, D, and G to 40 CFR part 75.

**§ 98.45 Procedures for estimating missing**

**data.**

Follow the applicable missing data substitution procedures in 40 CFR part
75 for CO 2 concentration, stack gas flow rate, fuel flow rate, high heating value,
and fuel carbon content.

**§ 98.46 Data reporting requirements.**

The annual report shall comply with the data reporting requirements specified in § 98.36(b) and, if applicable, § 98.36(c)(2) or (c)(3).

**§ 98.47 Records that must be retained.**

You shall comply with the recordkeeping requirements of §§ 98.3(g) and 98.37.

**§ 98.48 Definitions.**

All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. **Subpart E—Adipic Acid Production**

**§ 98.50 Definition of source category.**

The adipic acid production source category consists of all adipic acid production facilities that use oxidation to produce adipic acid.

**§ 98.51 Reporting threshold.**

You must report GHG emissions under this subpart if your facility contains an adipic acid production process and the facility meets the requirements of either § 98.2(a)(1) or (2).

**§ 98.52 GHGs to report.**

(a) You must report N 2 O process emissions at the facility level.

(b) You must report under subpart C of this part (General Stationary Fuel Combustion Sources) the emissions of

CO 2 , CH 4 , and N 2 O from each stationary combustion unit following the requirements of subpart C.

**§ 98.53 Calculating GHG emissions.**

(a) You must determine annual N 2 O emissions from adipic acid production according to paragraphs (a)(1) or (a)(2)
of this section.

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

section.

(2) Request Administrator approval for an alternative method of determining

N 2 O emissions according to paragraphs (a)(2)(i) and (a)(2)(ii) of this section.

(i) You must submit the request within 45 days following promulgation of this subpart or within the first 30 days of each subsequent reporting year.

(ii) If the Administrator does not approve your requested alternative method within 150 days of the end of the reporting year, you must determine
the N 2 O emissions factor for the current reporting period using the procedures specified in paragraphs (b) through (h)
of this section.

(b) You must conduct an annual performance test according to


### 56412 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

paragraphs (b)(1) through (b)(3) of this

section.

(1) You must conduct the test on the waste gas stream from the nitric acid oxidation step of the process using the methods specified in § 98.54(b) through (d).

(2) You must conduct the performance test under normal process operating conditions and without using

N 2 O abatement technology. (3) You must measure the adipic acid production rate during the test and calculate the production rate for the test period in metric tons per hour.

(c) You must determine an N 2 O emissions factor to use in Equation E– 2 of this section according to paragraphs (c)(1) or (c)(2) of this section.

(1) You may request Administrator approval for an alternative method of determining N 2 O concentration according to the procedures in paragraphs (a)(2)(i) and (a)(2)(ii) of this
section. Alternative methods include
the use of N 2 O CEMs.

(2) Using the results of the performance test in paragraph (b) of thissection, you must calculate a facilityspecific emissions factor according to Equation E–1 of this section:



### EF C Q

P

n N O N O n

2 2



### = ∗× ∗ − 

# ∑ 1 14 10 7

1 

### .

(Eq. E-1)

Where:

EF N2O = Average facility-specific N 2 O emissions factor (lb N 2 O generated/ton adipic acid produced).

C N2O = N 2 O concentration per text run during the performance test (ppm N 2 O).

1.14 × 10

¥ 7 = Conversion factor (lb/dscf-ppm

N 2 O). Q = Volumetric flow rate of effluent gas per test run during the performance test (dscf/hr). P = Production rate per test run during the performance test (tons adipic acid produced/hr).
n = Number of test runs.

(d) If applicable, you must determine the destruction efficiency for each N 2 O abatement technology used at your facility according to paragraphs (d)(1), (d)(2), or (d)(3) of this section.

(1) Use the manufacturer’s specified destruction efficiency.

(2) Estimate the destruction efficiency through process knowledge. Examples
of information that could constitute process knowledge include calculations based on material balances, process stoichiometry, or previous test results provided the results are still relevant to
the current vent stream conditions. You must document how process knowledge
was used to determine the destruction efficiency.

(3) Calculate the destruction efficiency by conducting an additional performance test on the emissions stream following the N 2 O abatement technology.

(e) If applicable, you must determine
the abatement factor for each N 2 O abatement technology used at your facility. The abatement factor is calculated for each adipic acid facility according to Equation E–2 of this

section.



### AF = P N a Abate

a 

### P (Eq. E-2) Where:

AF N = Abatement factor of N 2 O abatement technology (fraction of annual production that abatement technology is operating).

P a Abate = Annual adipic acid production during which N 2 O abatement was used.

P

a = Total annual adipic acid production (ton acid produced).

(f) You must determine the annual amount of adipic acid produced and the annual adipic acid production during
which N 2 O abatement is operating.

(g) You must calculate annual adipic acid production process emissions of

N 2 O by multiplying the emissions factor (determined using Equation E–1 of this section) by the total annual adipic acid production and accounting for N 2 O abatement, according to Equation E–3 of
this section:



### N O EF P DF AF NO a N N N

2 

### (Eq. E-3) = ∗ ∗− ∗ 

## ( ) 

# ( ) ∑ 2

1 

### 1

2205

Where:

N 2 O = Annual N 2 O mass emissions from adipic acid production (metric tons).

EF N2O = Facility-specific N 2 O emissions factor (lb N 2 O generated/ton adipic acid produced).

P

a = Annual adipic acid produced (tons).

DF N = Destruction efficiency of N 2 O abatement technology N (abatement device destruction efficiency, percent of

N 2 O removed from air stream).

AF N = Abatement factor of N 2 O abatement technology N (fraction of annual production abatement technology is operating). 2205 = Conversion factor (lb/metric ton).
N = Number of different N 2 O abatement technologies.
(h) You must determine the amount of process N 2 O emissions that is sold or transferred off site (if applicable). You can determine the amount using existing process flow meters and N 2 O analyzers.

**§ 98.54 Monitoring and QA/QC requirements.** 

(a) You must conduct a new performance test and calculate a new facility-specific emissions factor according to the frequency specified in paragraphs (a)(1) through (a)(3) of this

section.

(1) Conduct the performance test annually.

(2) Conduct the performance test when your adipic acid production process is changed either by altering the ratio of cyclohexanone to cyclohexanol or by installing abatement equipment.

(3) If you requested Administrator approval for an alternative method of determining N 2 O concentration under § 98.53(a)(2), you must conduct the performance test if your request has not been approved by the Administrator within 150 days of the end of the reporting year in which it was
submitted.

(b) You must measure the N 2 O concentration during the performance test using one of the methods in paragraphs (b)(1) through (b)(3) of this

section.

(1) EPA Method 320, Measurement of Vapor Phase Organic and Inorganic Emissions by Extractive Fourier


### 56413 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

Transform Infrared (FTIR) Spectroscopy in 40 CFR part 63, Appendix A;

(2) ASTM D6348–03 Standard Test
Method for Determination of Gaseous Compounds by Extractive Direct
Interface Fourier Transform Infrared (FTIR) Spectroscopy (incorporated by reference, see § 98.7); or

(3) An equivalent method, with Administrator approval.

(c) You must determine the production rate(s) during the performance test according to paragraph (c)(1) or (c)(2) of this section.

(1) Direct measurement (such as using flow meters or weigh scales).

(2) Existing plant procedures used for accounting purposes.

(d) You must conduct all required performance tests according to the methods in § 98.54(b) in conjunction with the applicable EPA methods in 40 CFR part 60, appendices A–1 through
A–4. Conduct three emissions test runs of 1 hour each. All QA/QC procedures specified in the reference test methods and any associated performance specifications apply. For each test, the facility must prepare an emissions factor determination report that must include the items in paragraphs (d)(1) through (d)(3) of this section:

(1) Analysis of samples, determination of emissions, and raw
data.

(2) All information and data used to
derive the emissions factor.

(3) The production rate(s) during the performance test and how each production rate was determined.

(e) You must determine the monthly adipic acid production quantity and the monthly adipic acid production during
which N 2 O abatement technology is operating according to the methods in paragraphs (c)(1) or (c)(2) of this section.

(f) You must determine the annual adipic acid production quantity and the annual adipic production quantity during which N 2 O abatement technology is operating by summing the respective monthly adipic acid production quantities.

**§ 98.55 Procedures for estimating missing**
**data.**

A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter shall be used in the calculations as specified in paragraphs (a) and (b) of this section.

(a) For each missing value of monthly adipic acid production, the substitute
data shall be the best available estimate based on all available process data or data used for accounting purposes (such as sales records).

(b) For missing values related to the performance test, including emission factors, production rate, and N 2 O concentration, you must conduct a new performance test according to the procedures in § 98.54 (a) through (d).

**§ 98.56 Data reporting requirements.**

In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) through (k) of this section at the facility level:

(a) Annual process N 2 O emissions from adipic acid production (metric tons).

(b) Annual adipic acid production (tons).

(c) Annual adipic acid production during which N 2 O abatement technology is operating (tons).

(d) Annual process N 2 O emissions from adipic acid production facility that is sold or transferred off site (metric tons).

(e) Number of abatement technologies (if applicable).

(f) Types of abatement technologies used (if applicable).

(g) Abatement technology destruction efficiency for each abatement technology (percent destruction).

(h) Abatement utilization factor for each abatement technology (fraction of annual production that abatement technology is operating).

(i) Number of times in the reporting year that missing data procedures were followed to measure adipic acid production (months).

(j) If you conducted a performance test and calculated a site-specific emissions factor according to § 98.53(a)(1), each annual report must also contain the information specified in paragraphs (j)(1) through (j)(7) of this section for each adipic acid production facility.

(1) Emissions factor (lb N 2 O/ton adipic acid).

(2) Test method used for performance

test.

(3) Production rate per test run during performance test (tons/hr).

(4) N 2 O concentration per test run during performance test (ppm N 2 O).

(5) Volumetric flow rate per test run during performance test (dscf/hr).

(6) Number of test runs. (7) Number of times in the reporting year that a performance test had to be repeated (number).

(k) If you requested Administrator approval for an alternative method of determining N 2 O concentration under § 98.53(a)(2), each annual report must also contain the information specified in paragraphs (k)(1) through (k)(4) of this section for each adipic acid production facility.

(1) Name of alternative method. (2) Description of alternative method. (3) Request date. (4) Approval date.

**§ 98.57 Records that must be retained.**

In addition to the information required by § 98.3(g), you must retain the records specified in paragraphs (a) through (h) of this section at the facility
level:

(a) Annual adipic acid production capacity (tons).

(b) Records of significant changes to

process.

(c) Number of facility operating hours in calendar year.

(d) Documentation of how accounting procedures were used to estimate production rate.

(e) Documentation of how process knowledge was used to estimate abatement technology destruction efficiency.

(f) Performance test reports of N 2 O
emissions.

(g) Measurements, records and calculations used to determine reported parameters.

(h) Documentation of the procedures used to ensure the accuracy of the measurements of all reported parameters, including but not limited to, calibration of weighing equipment, flow meters, and other measurement devices. The estimated accuracy of
measurements made with these devices must also be recorded, and the technical
basis for these estimates must be provided.

**§ 98.58 Definitions.**

All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.

**Subpart F—Aluminum Production**

**§ 98.60 Definition of the source category.**

(a) A primary aluminum production facility manufactures primary aluminum using the Hall-He  ́ roult manufacturing process. The primary aluminum manufacturing process comprises the following operations:

(1) Electrolysis in prebake and

S < derberg cells.

(2) Anode baking for prebake cells. (b) This source category does not include experimental cells or research and development process units.

**§ 98.61 Reporting threshold.**

You must report GHG emissions under this subpart if your facility contains an aluminum production process and the facility meets the


### 56414 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

requirements of either § 98.2(a)(1) or (a)(2).

**§ 98.62 GHGs to report.**

You must report: (a) Perfluoromethane (CF 4 ), and perfluoroethane (C 2F 6 ) emissions from anode effects in all prebake and

S < derberg electolysis cells.

(b) CO 2 emissions from anode consumption during electrolysis in all prebake and S < derberg electolysis cells.

(c) CO 2 emissions from on-site anode baking.

(d) You must report under subpart C of this part (General Stationary Fuel Combustion Sources) the emissions of

CO 2 , N 2 O, and CH 4 emissions from each stationary fuel combustion unit by following the requirements of subpart C.

**§ 98.63 Calculating GHG emissions.**

(a) The annual value for PFC
emissions shall be estimated from the sum of monthly values using Equation
F–1 of this section:



### E E

PFC m 

### =

= = 

# ∑

m m

1 12 

### (Eq. F-1)

Where: E PFC = Annual PFC emissions from aluminum production (metric tons PFC).

E

m = PFC emissions from aluminum production for the month ‘‘m’’ (metric tons PFC).

(b) Use Equation F–2 of this section to

estimate CF 4 emissions from anode effect duration or Equation F–3 of this

section to estimate CF 4 emissions from overvoltage, and use Equation F–4 of
this section to estimate C 2F 6 emissions from anode effects from each prebake
and S < derberg electolysis cell.



### E CF CF 4 4 

### 0 001

S AEM MP (Eq. F-2)

= × ××

.

Where:

E CF4 = Monthly CF 4 emissions from aluminum production (metric tons CF 4 ). S CF4 = The slope coefficient ((kg CF 4 /metric ton Al)/(AE-Mins/cell-day)). AEM = The anode effect minutes per cell-day (AE-Mins/cell-day). MP = Metal production (metric tons Al),

where AEM and MP are calculated monthly.



### E CF CF 4 4 

### 0 001

EF MP (Eq. F-3)

= ××

.

Where:

E CF4 = Monthly CF 4 emissions from aluminum production (metric tons CF 4 ). EF CF4 = The overvoltage emission factor (kg

CF 4 /metric ton Al). MP = Metal production (metric tons Al), where MP is calculated monthly.



### E EF

C F CF C F CF

26 4 26 4 

### 0 001 (Eq. F-4)

=× × /


### .

Where:

E C2F6 = Monthly C 2F 6 emissions from aluminum production (metric tons C 2F 6 ).

E CF4 = CF 4 emissions from aluminum production (kg CF 4 ).

F C2F6/CF4 = The weight fraction of C 2F 6 /CF 4 (kg C 2F 6 /kg CF 4 ). 0.001 = Conversion factor from kg to metric tons, where E CF4 is calculated monthly. (c) You must calculate and report the annual process CO 2 emissions from anode consumption during electrolysis and anode baking of prebake cells using either the procedures in paragraph (d) of this section or the procedures in paragraphs (e) and (f) of this section.

(d) Calculate and report under this subpart the process CO 2 emissions by operating and maintaining CEMS according to the Tier 4 Calculation Methodology in § 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources).

(e) Use the following procedures to
calculate CO 2 emissions from anode consumption during electrolysis:

(1) For Prebake cells: you must
calculate CO 2 emissions from anode consumption using Equation F–5 of this

section:



### E NAC MP S Ash

CO a a 2 

### 100 100 44 12

= × × −− 

# [ ] 

# ( ) × (Eq. F-5) / (/)

Where:

E CO2 = Annual CO 2 emissions from prebaked anode consumption (metric tons CO 2 ). NAC = Net annual prebaked anode consumption per metric ton Al (metric tons C/metric tons Al). MP = Annual metal production (metric tons Al).

S

a = Sulfur content in baked anode (percent weight).
Ash

a = Ash content in baked anode (percent weight). 44/12 = Ratio of molecular weights, CO 2 to carbon.

(2) For S < derberg cells you must
calculate CO 2 emissions using Equation
F–6 of this section:



### E PC MP CSM MP BC PC

MP S CO

p 2 

### 1000 100

=×− × 

# [ ] − ××

× + ( / /

A sh H BC PC MP

S Ash p p

c c 

### + ⎡ ⎣ ⎤ ⎦

− − 

# [ ] ×× ×

+ 

# [ ] / / 100 100 100

/ ) ( /) 100 44 12 (Eq. F-6)

−× ×

MP CD


### 56415 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

Where:

E CO2 = Annual CO 2 emissions from paste consumption (metric ton CO 2 ). PC = Annual paste consumption (metric ton/ metric ton Al). MP = Annual metal production (metric ton Al). CSM = Annual emissions of cyclohexane soluble matter (kg/metric ton Al). BC = Binder content of paste (percent weight). S p = Sulfur content of pitch (percent weight).
Ashp = Ash content of pitch (percent weight).

Hp = Hydrogen content of pitch (percent weight).

S

c = Sulfur content in calcined coke (percent weight).
Ash

c = Ash content in calcined coke (percent weight).
CD = Carbon in skimmed dust from

S < derberg cells (metric ton C/metric ton Al). 44/12 = Ratio of molecular weights, CO 2 to
carbon.

(f) Use the following procedures to
calculate CO 2 emissions from anode baking of prebake cells:

(1) Use Equation F–7 of this section to calculate emissions from pitch volatiles
combustion.



### E GA H BA WT

CO PV w 2 

### 44 12 = −−− 

## ( ) × (Eq. F-7) ( /)

Where:

E CO2PV = Annual CO 2 emissions from pitch volatiles combustion (metric tons CO 2 ). GA = Initial weight of green anodes (metric tons). H

w = Annual hydrogen content in green anodes (metric tons). BA = Annual baked anode production (metric tons). WT = Annual waste tar collected (metric tons). 44/12 = Ratio of molecular weights, CO 2 to carbon.

(2) Use Equation F–8 of this section to
calculate emissions from bake furnace packing material.



### E PCC BA S Ash

CO PC pc pc 2 

### 100 100 44 12 = ×× −− ⎡ ⎣ ⎤ ⎦ 

# ( ) × (E / ( /) q . F-8)

Where:

E CO2PC = Annual CO 2 emissions from bake furnace packing material (metric tons

CO 2 ). PCC = Annual packing coke consumption (metric tons/metric ton baked anode). BA = Annual baked anode production (metric tons).

S pc = Sulfur content in packing coke (percent weight).
Ashpc = Ash content in packing coke (percent weight). 44/12 = Ratio of molecular weights, CO 2 to carbon. (g) If process CO 2 emissions from anode consumption during electrolysis or anode baking of prebake cells are vented through the same stack as any combustion unit or process equipment that reports CO 2 emissions using a CEMS that complies with the Tier 4 Calculation Methodology in subpart C of this part (General Stationary Fuel Combustion Sources), then the calculation methodology in paragraphs (d) and (e) of this section shall not be used to calculate those process emissions. The owner or operation shall report under this subpart the combined stack emissions according to the Tier 4 Calculation Methodology in § 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources).

**§ 98.64 Monitoring and QA/QC requirements.** 

(a) Effective one year after publication of the rule for smelters with no prior measurement or effective three years after publication for facilities withhistoric measurements, the smelterspecific slope coefficients used in Equations F–2, F–3, and F–4 of this subpart must be measured in
accordance with the recommendations
of the EPA/IAI Protocol for
Measurement of Tetrafluoromethane (CF 4 ) and Hexafluoroethane (C 2F 6 ) Emissions from Primary Aluminum Production (2008), except the minimum frequency of measurement shall be every 10 years unless a change occurs in the control algorithm that affects the mix of types of anode effects or the
nature of the anode effect termination routine. Facilities which operate at less than 0.2 anode effect minutes per cell day or operate with less than 1.4mV anode effect overvoltage can use either smelter-specific slope coefficients or the technology specific default values in Table F–1 of this subpart. (b) The minimum frequency of the measurement and analysis is annually except as follows: Monthly—anode effect minutes per cell day (or anode effect overvoltage and current efficiency), production.

(c) Sources may use either smelterspecific values from annual measurements of parameters needed to complete the equations in § 98.63 (e.g., sulfur, ash, and hydrogen contents) or
the default values shown in Table F–2 of this subpart.

**§ 98.65 Procedures for estimating missing**
**data.**

A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable (e.g., if a meter malfunctions during unit operation or if a required sample measurement is not taken), a substitute data value for the missing parameter shall be used in the calculations, according to the following requirements:

(a) Where anode or paste consumption data are missing, CO 2 emissions can be estimated from aluminum production using Tier 1 method per Equation F–8 of this section.



### ECO EF x MP EF x MP ppss 2 

### = + (Eq. F-8)

Where:

ECO 2 = CO 2 emissions from anode and/or paste consumption, metric tons CO 2
. EF p = Prebake technology specific emission factor (1.6 metric tons CO 2 /metric ton aluminum produced).

MP p = Metal production from prebake process (metric tons Al). EF

s = S < derberg technology specific emission factor (1.7 metric tons CO 2 /metric ton Al produced).

MP

s = Metal production from S < derberg process (metric tons Al).


### 56416 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

(b) For other parameters, use the average of the two most recent data points after the missing data.

**§ 98.66 Data reporting requirements.**

In addition to the information required by § 98.3(c), you must report the following information at the facility
level:

(a) Annual aluminum production in

metric tons.

(b) Type of smelter technology used. (c) The following PFC-specific
information on an annual basis:

(1) Perfluoromethane emissions and perfluoroethane emissions from anode effects in all prebake and all S < derberg electolysis cells combined.

(2) Anode effect minutes per cell-day (AE-mins/cell-day), anode effect frequency (AE/cell-day), anode effect duration (minutes). (Or anode effect overvoltage factor ((kg CF 4 /metric ton Al)/(mV/cell day)), potline overvoltage (mV/cell day), current efficiency (%).)

(3) Smelter-specific slope coefficients (or overvoltage emission factors) and thelast date when the smelter-specificslope coefficients (or overvoltage emission factors) were measured.

(d) Method used to measure the frequency and duration of anode effects (or overvoltage).

(e) The following CO 2 -specific information for prebake cells:

(1) Annual anode consumption. (2) Annual CO 2 emissions from the
smelter.

(f) The following CO 2 -specific
information for S < derberg cells:

(1) Annual paste consumption. (2) Annual CO 2 emissions from the
smelter.

(g) Smelter-specific inputs to the CO 2 process equations (e.g., levels of sulfur and ash) that were used in the calculation, on an annual basis.

(h) Exact data elements required will vary depending on smelter technology (e.g., point-feed prebake or S < derberg) and process control technology (e.g., Pechiney or other).

**§ 98.67 Records that must be retained.**

In addition to the information required by § 98.3(g), you must retain the following records:

(a) Monthly aluminum production in

metric tons.

(b) Type of smelter technology used. (c) The following PFC-specific information on a monthly basis:

(1) Perfluoromethane and perfluoroethane emissions from anode effects in prebake and S < derberg electolysis cells.

(2) Anode effect minutes per cell-day (AE-mins/cell-day), anode effect frequency (AE/cell-day), anode effect duration (minutes). (Or anode effect overvoltage factor ((kg CF 4 /metric ton Al)/(mV/cell day)), potline overvoltage (mV/cell day), current efficiency (%).))

(3) Smelter-specific slope coefficients
and the last date when the smelterspecific-slope coefficients were
measured.

(d) Method used to measure the frequency and duration of anode effects (or to measure anode effect overvoltage and current efficiency).

(e) The following CO 2 -specific information for prebake cells:

(1) Annual anode consumption. (2) Annual CO 2 emissions from the
smelter.

(f) The following CO 2 -specific
information for S < derberg cells:

(1) Annual paste consumption. (2) Annual CO 2 emissions from the
smelter.

(g) Smelter-specific inputs to the CO 2 process equations (e.g., levels of sulfur and ash) that were used in the calculation, on an annual basis.

(h) Exact data elements required will vary depending on smelter technology (e.g., point-feed prebake or S < derberg) and process control technology (e.g., Pechiney or other).

**§ 98.68 Definitions.**

All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.



### TABLE 

### F–1 TO 

### S UBPART 

### F OF 

### P ART 

### 98—S LOPE AND 

### O VERVOLTAGE 

### C OEFFICIENTS FOR THE 

### C ALCULATION OF 

### PFC
E MISSIONS 

### F ROM 

### A LUMINUM 

### P RODUCTION

Technology CF 4 slope coefficient [(kg CF 4/metric

ton Al)/(AEMins/cell-day)] CF 4 overvoltage coefficient [(kg CF 4/metric ton Al)/(mV)] Weight fraction C 2 F 6/CF 4 [(kg C 2 F 6/ kg CF 4 )]

CWPB ........................................................................................................................... ............... 0.143 1.16 0.121
SWPB ........................................................................................................................... ............... 0.272 3.65 0.252
VSS ............................................................................................................................ .................. 0.092 NA 0.053
HSS ............................................................................................................................ .................. 0.099 NA 0.085



### TABLE 

### F–2 TO 

### S UBPART 

### F OF 

### P ART 

### 98—D EFAULT 

### D ATA 

### S OURCES FOR 

### P ARAMETERS 

### U SED FOR 

### CO 2 

### E MISSIONS

Parameter Data source

CO 2 Emissions from Prebake Cells (CWPB and SWPB)

MP: metal production (metric tons Al) .......................................................................................... .................................. Individual facility records. NAC: net annual prebaked anode consumption per metric ton Al (metric tons C/metric tons Al) ................................ Indi vidual facility records.
S

a : sulfur content in baked anode (percent weight) ............................................................................... ........................ 2.0.
Ash

a : ash content in baked anode (percent weight) .................................................................................. .................... 0.4.

CO 2 Emissions from S < derberg Cells (VSS and HSS)

MP: metal production (metric tons Al) .......................................................................................... .................................. Individual facility records. PC: annual paste consumption (metric ton/metric ton Al) ........................................................................ ..................... Individual facility records. CSM: annual emissions of cyclohexane soluble matter (kg/metric ton Al) ......................................................... ........... HSS: 4.0.
VSS: 0.5. BC: binder content of paste (percent weight) ................................................................................... ............................. Dry Paste: 24.
Wet Paste: 27.
S p : sulfur content of pitch (percent weight) ..................................................................................... ............................... 0.6.
Ash p : ash content of pitch (percent weight) ........................................................................................ ........................... 0.2.


### 56417 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

TABLE 

### F–2 TO 

### S UBPART 

### F OF 

### P ART 

### 98—D EFAULT 

### D ATA 

### S OURCES FOR 

### P ARAMETERS 

### U SED FOR 

### CO 2 

### E MISSIONS

### — Continued

Parameter Data source

H p : hydrogen content of pitch (percent weight) ................................................................................... ........................... 3.3.
S

c : sulfur content in calcined coke (percent weight) ............................................................................. ......................... 1.9.
Ash

c : ash content in calcined coke (percent weight) ................................................................................ ..................... 0.2.
CD: carbon in skimmed dust from S < derberg cells (metric ton C/metric ton Al) ........................................................... 0.01.

CO 2 Emissions from Pitch Volatiles Combustion (VSS and HSS)

GA: initial weight of green anodes (metric tons) ............................................................................... ............................. Individual facility records.

H

w : annual hydrogen content in green anodes (metric tons) ........................................................................ ................ 0.005 × GA. BA: annual baked anode production (metric tons) ................................................................................ ......................... Individual facility records. WT: annual waste tar collected (metric tons) ................................................................................... .............................. (a) 0.005 × GA. (a) Riedhammer furnaces ........................................................................................................ ....................................... (b) insignificant. (b) all other furnaces.

CO 2 Emissions From Bake Furnace Packing Materials (CWPB and SWPB)

PCC: annual packing coke consumption (metric tons/metric ton baked anode) ...................................................... ..... 0.015. BA: annual baked anode production (metric tons) ................................................................................ ......................... Individual facility records.
S pc : sulfur content in packing coke (percent weight) .............................................................................. ....................... 2.
Ash pc : ash content in packing coke (percent weight) ................................................................................. .................... 2.5.

**Subpart G—Ammonia Manufacturing**

**§ 98.70 Definition of source category.**

The ammonia manufacturing source category comprises the process units listed in paragraphs (a) and (b) of this

section.

(a) Ammonia manufacturing processes
in which ammonia is manufactured from a fossil-based feedstock produced via steam reforming of a hydrocarbon.

(b) Ammonia manufacturing processes in which ammonia is manufactured through the gasification of solid and liquid raw material.

**§ 98.71 Reporting threshold.**

You must report GHG emissions under this subpart if your facility contains an ammonia manufacturing process and the facility meets the requirements of either § 98.2(a)(1) or (2). **§ 98.72 GHGs to report.** You must report: (a) CO 2 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 in this subpart.

(b) CO 2 , CH 4 , and N 2 O emissions from each stationary fuel combustion unit. You must report these emissions under subpart C of this part (General Stationary Fuel Combustion Sources), by following the requirements of subpart C.

(c) CO 2 emissions collected and transferred off site under subpart PP of this part (Suppliers of CO 2 ), following the requirements of subpart PP.

**§ 98.73 Calculating GHG emissions.**

You must calculate and report the annual process CO 2 emissions from each ammonia manufacturing process unit using the procedures in either paragraph (a) or (b) of this section.

(a) Calculate and report under this subpart the process CO 2 emissions by operating and maintaining CEMS according to the Tier 4 Calculation Methodology specified in § 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources).

(b) Calculate and report under this subpart process CO 2 emissions using the procedures in paragraphs (b)(1) through (b)(6) of this section for gaseous feedstock, liquid feedstock, or solid feedstock, as applicable.

(1) Gaseous feedstock. You must calculate, from each ammonia manufacturing unit, the CO 2 process emissions from gaseous feedstock according to Equation G–1 of this

section:



### CO Fdstk CC MW

MVC Gk nk n 2 

### 44

12 0 001

,, , 

### . = ∗ ∗∗

⎛

⎝ ⎜ ⎜ ⎞

⎠ ⎟ ⎟ ∗ 

# ∑

n=1 12 

### (Eq. G-1 )

Where:

CO 2,G = Annual CO 2 emissions arising from feedstock consumption (metric tons).
Fdstk

n = Volume of the gaseous feedstock used in month n (scf of feedstock).

CC

n = Carbon content of the gaseous feedstock, for month n (kg C per kg of feedstock), determined according to 98.74(c). MW = Molecular weight of the gaseous feedstock (kg/kg-mole).
MVC = Molar volume conversion factor (849.5 scf per kg-mole at standard conditions). 44/12 = Ratio of molecular weights, CO 2 to carbon. 0.001 = Conversion factor from kg to metric

tons. k = Processing unit.
n = Number of month.

(2) Liquid feedstock. You must calculate, from each ammonia manufacturing unit, the CO 2 process emissions from liquid feedstock according to Equation G–2 of this

section:


### 56418 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

CO Fdstk CC Lk nk n 2 

### 44

12 0 001

,, , 

### . =∗ ∗

⎛

⎝ ⎜ ⎜ ⎞

⎠ ⎟ ⎟ ∗ 

# ∑

n=1 12 

### (Eq. G-2)

Where:

CO 2,L = Annual CO 2 emissions arising from feedstock consumption (metric tons).

Fdstk

n = Volume of the liquid feedstock used in month n (gallons of feedstock).

CC

n = Carbon content of the liquid feedstock, for month n (kg C per gallon of feedstock) determined according to 98.74(c). 44/12 = Ratio of molecular weights, CO 2 to carbon. 0.001 = Conversion factor from kg to metric

tons. k = Processing unit.
n = Number of month. (3) Solid feedstock. You must calculate, from each ammonia manufacturing unit, the CO 2 process emissions from solid feedstock according to Equation G–3 of this

section:



### CO Fdstk CC Sk nk n

n 2

1 12 

### 44

12 0 001

,, , 

### . =∗ ∗

⎛

⎝ ⎜ ⎜ ⎞

⎠ ⎟ ⎟ ∗

= 

# ∑ (Eq. G-3)

Where:

CO 2,S = Annual CO 2 emissions arising from feedstock consumption (metric tons).
Fdstk

n = Mass of the solid feedstock used in month n (kg of feedstock).

CC

n = Carbon content of the solid feedstock, for month n (kg C per kg of feedstock), determined according to 98.74(c). 44/12 = Ratio of molecular weights, CO 2 to
carbon. 0.001 = Conversion factor from kg to metric

tons. k = Processing unit.

n = Number of month. (4) You must calculate the annual process CO 2 emissions from each ammonia processing unit k at your facility summing emissions, as applicable from Equation G–1, G–2, and G–3 of this section using Equation G–4.



### E CO G S L 22 2 2 k 

### = + CO + CO CO (Eq. G-4)

,, ,

Where:

E CO2k = Annual CO 2 emissions from each ammonia processing unit k (metric tons). k = Processing unit.

(5) You must determine the combined

CO 2 emissions from all ammonia processing units at your facility using Equation G–5 of this section. 

### CO = E (Eq. G-5) 2 CO2

k=1 n

k 

# ∑

Where:

CO 2 = Annual combined CO 2 emissions from all ammonia processing units (metric tons).

E CO2k = Annual CO 2 emissions from each ammonia processing unit (metric tons). k = Processing unit. n = Total number of ammonia processing

units.

(6) If applicable, ammonia manufacturing facilities that utilize the waste recycle stream as a fuel must
calculate emissions associated with the waste stream for each ammonia process unit according to Equation G–6 of this

section:



### CO cycleStream CC MW

MVC n n 2 

### 44

12 0 001 = ∗ ∗∗

⎛

⎝ ⎜ ⎜ ⎞

⎠ ⎟ ⎟ 

# ∑ Re .

n=1 12 

### (Eq.G -6)

Where:

CO 2 = Annual CO 2 contained in waste recycle stream (metric tons). RecycleStream

n = Volume of the waste recycle stream in month n (scf).

CC

n = Carbon content of the waste recycle stream, for month n (kg C per kg of waste recycle stream) determined according to 98.74(f). MW = Molecular weight of the waste recycle stream (kg/kg-mole).

MVC = Molar volume conversion factor (849.5 scf per kg-mole at standard conditions). 44/12 = Ratio of molecular weights, CO 2 to
carbon. 0.001 = Conversion factor from kg to metric

tons.
n = Number of month (c) If GHG emissions from an ammonia manufacturing unit are vented through the same stack as any combustion unit or process equipment that reports CO 2 emissions using a CEMS that complies with the Tier 4 Calculation Methodology in subpart C of this part (General Stationary Fuel Combustion Sources), then the calculation methodology in paragraph (b) of this section shall not be used to calculate process emissions. The owner or operator shall report under this subpart the combined stack emissions according to the Tier 4 Calculation Methodology in § 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part. **§ 98.74 Monitoring and QA/QC requirements.** 

(a) You must continuously measure the quantity of gaseous or liquid feedstock consumed using a flow meter. The quantity of solid feedstock
consumed can be obtained from company records and aggregated on a monthly basis.

(b) You must document the procedures used to ensure the accuracy
of the estimates of feedstock consumption.

(c) You must determine monthly carbon contents and the average molecular weight of each feedstock consumed from reports from your supplier. As an alternative to using supplier information on carbon


### 56419 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

contents, you can also collect a sample of each feedstock on a monthly basis and analyze the carbon content and molecular weight of the fuel using any of the following methods listed in paragraphs (c)(1) through (c)(8) of this section, as applicable.

(1) ASTM D1945–03 Standard Test Method for Analysis of Natural Gas by Gas Chromatography (incorporated by reference, see § 98.7).

(2) ASTM D1946–90 (Reapproved 2006) Standard Practice for Analysis of Reformed Gas by Gas Chromatography (incorporated by reference, see § 98.7).

(3) ASTM D2502–04 (Reapproved 2002) Standard Test Method for
Estimation of Mean Relative Molecular Mass of Petroleum Oils from Viscosity Measurements (incorporated by reference, see § 98.7).

(4) ASTM D2503–92 (Reapproved 2007) Standard Test Method for Relative Molecular Mass (Molecular Weight) of Hydrocarbons by Thermoelectric Measurement of Vapor Pressure (incorporated by reference, see § 98.7).

(5) ASTM D3238–95 (Reapproved 2005) Standard Test Method for
Calculation of Carbon Distribution and Structural Group Analysis of Petroleum Oils by the n-d-M Method (incorporated by reference, see § 98.7).

(6) ASTM D5291–02 (Reapproved 2007) Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants (incorporated by reference, see § 98.7).

(7) ASTM D3176–89 (Reapproved 2002) Standard Practice for Ultimate Analysis of Coal and Coke (incorporated by reference, see § 98.7).

(8) ASTM D5373–08 Standard
Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal (incorporated by reference, see § 98.7).

(d) Calibrate all oil and gas flow meters (except for gas billing meters) and perform oil tank measurements according to the monitoring and QA/QC requirements for the Tier 3 methodology in § 98.34(b).

(e) For quality assurance and quality control of the supplier data, on an annual basis, you must measure the carbon contents of a representative sample of the feedstocks consumed using the appropriate ASTM Method as listed in paragraphs (c)(1) through (c)(8)
of this section.

(f) Facilities must continuously measure the quantity of waste gas recycled using a flow meter, as applicable. You must determine the
carbon content and the molecular weight of the waste recycle stream by collecting a sample of each waste recycle stream on a monthly basis and analyzing the carbon content using the appropriate ASTM Method as listed in paragraphs (c)(1) through (c)(8) of this

section.

(g) If CO 2 from ammonia production is used to produce urea at the same facility, you must determine the quantity of urea produced using methods or plant instruments used for accounting purposes (such as sales records). You must document the procedures used to ensure the accuracy of the estimates of urea produced.

**§ 98.75 Procedures for estimating missing**
**data.**

A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever the monitoring and quality assurance procedures in § 98.74 cannot be followed (e.g., if a meter malfunctions during unit operation), a substitute data value for the missing parameter shall be used in the calculations following paragraphs (a) and (b) of this section. You must document and keep records of the procedures used for all such estimates.

(a) For missing data on monthly
carbon contents of feedstock or the waste recycle stream, the substitute data value shall be the arithmetic average of the quality-assured values of that carbon content in the month preceding and the month immediately following themissing data incident. If no qualityassured data are available prior to the missing data incident, the substitutedata value shall be the first qualityassured value for carbon content obtained in the month after the missing data period.

(b) For missing feedstock supply rates or waste recycle stream used to determine monthly feedstock consumption or monthly waste recycle stream quantity, you must determine the best available estimate(s) of the parameter(s), based on all available process data.

**§ 98.76 Data reporting requirements.**

In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) and (b) of this section, as applicable for each ammonia manufacturing process unit.

(a) If a CEMS is used to measure CO 2 emissions, then you must report the relevant information required under § 98.37(e)(2)(vi) for the Tier 4 Calculation Methodology and the following information in this paragraph (a):

(1) Annual quantity of each type of
feedstock consumed for ammonia manufacturing (scf of feedstock or gallons of feedstock or kg of feedstock).

(2) Method used for determining quantity of feedstock used.

(b) If a CEMS is not used to measure emissions, then you must report the following information:

(1) Annual CO 2 process emissions (metric tons) for each ammonia manufacturing process unit.

(2) Monthly quantity of each type of
feedstock consumed for ammonia manufacturing for each ammonia processing unit (scf of feedstock or gallons of feedstock or kg of feedstock).

(3) Method used for determining quantity of monthly feedstock used.

(4) Whether carbon content for each
feedstock for month n is based on reports from the supplier or analysis of
carbon content.

(5) If carbon content of feedstock for month n is based on analysis, the test
method used.

(6) Sampling analysis results of carbon content of petroleum coke as determined for QA/QC of supplier data under § 98.74(e).

(7) If a facility uses gaseous feedstock, the carbon content of the gaseous feedstock, for month n, (kg C per kg of feedstock).

(8) If a facility uses gaseous feedstock, the molecular weight of the gaseous feedstock (kg/kg-mole).

(9) If a facility uses gaseous feedstock,
the molar volume conversion factor of the gaseous feedstock (scf per kg-mole).

(10) If a facility uses liquid feedstock, the carbon content of the liquid feedstock, for month n, (kg C per gallon of feedstock).

(11) If a facility uses solid feedstock,
the carbon content of the solid feedstock, for month n, (kg C per kg of feedstock).

(12) Annual CO 2 emissions associated with the waste recycle stream for each ammonia process unit (metric tons)

(13) Carbon content of the waste recycle stream for month n for each ammonia process unit (kg C per kg of waste recycle stream).

(14) Volume of the waste recycle
stream for month n for each ammonia process unit (scf)

(15) Method used for analyzing carbon content of waste recycle stream.

(16) Annual urea production (metric tons) and method used to determine urea production.

(17) Uses of urea produced, if known, such as but not limited to fertilizer, animal feed, manufacturing of plastics or resins, and pollution control technologies.

(c) Total pounds of synthetic fertilizer produced through and total nitrogen
contained in that fertilizer.


### 56420 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

**§ 98.77 Records that must be retained.**

In addition to the records required by § 98.3(g), you must retain the following records specified in paragraphs (a) and (b) of this section for each ammonia manufacturing unit.

(a) If a CEMS is used to measure emissions, retain records of all feedstock purchases in addition to the requirements in § 98.37 for the Tier 4 Calculation Methodology.

(b) If a CEMS is not used to measure process CO 2 emissions, you must also retain the records specified in paragraphs (b)(1) through (b)(2) of this

section:

(1) Records of all analyses and calculations conducted for reported data as listed in § 98.76(b).

(2) Monthly records of carbon content of feedstock from supplier and/or all analyses conducted of carbon content.

**§ 98.78 Definitions.**

All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.

**Subpart H—Cement Production**

**§ 98.80 Definition of the source category.**

The cement production source category consists of each kiln and each in-line kiln/raw mill at any portland cement manufacturing facility including alkali bypasses, and includes kilns and in-line kiln/raw mills that burn
hazardous waste.

**§ 98.81 Reporting threshold.**

You must report GHG emissions under this subpart if your facility contains a cement production process and the facility meets the requirements of either § 98.2(a)(1) or (2).

**§ 98.82 GHGs to report.**

You must report: (a) CO 2 process emissions from
calcination in each kiln.

(b) CO 2 combustion emissions from
each kiln.

(c) CH 4 and N 2 O combustion
emissions from each kiln. You must calculate and report these emissions under subpart C of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart C.

(d) CO 2 , CH 4 , and N 2 O emissions from each stationary combustion unit other than kilns. You must report these emissions under subpart C of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart C.

**§ 98.83 Calculating GHG emissions.**

You must calculate and report the annual process CO 2 emissions from each kiln using the procedure in paragraphs (a) and (b) of this section.

(a) For each cement kiln that meets the conditions specified in § 98.33(b)(4)(ii) or (b)(4)(iii), you must calculate and report under this subpart the combined process and combustion

CO 2 emissions by operating and maintaining a CEMS to measure CO 2 emissions according to the Tier 4 Calculation Methodology specified in § 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources).

(b) For each kiln that is not subject to the requirements in paragraph (a) of this section, calculate and report the process
and combustion CO 2 emissions from the kiln by using the procedure in either paragraph (c) or (d) of this section.

(c) Calculate and report under this subpart the combined process and
combustion CO 2 emissions by operating and maintaining a CEMS to measure

CO 2 emissions according to the Tier 4 Calculation Methodology specified in § 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources).

(d) Calculate and report process and
combustion CO 2 emissions separately using the procedures specified in paragraphs (d)(1) through (d)(4) of this

section.

(1) Calculate CO 2 process emissions from all kilns at the facility using Equation H–1 of this section:



### CO CO CO CMF Cli,m rm

m

k

2 22

1 

### = +

= 

# ∑ (Eq. H-1)

Where:

CO 2 CMF = Annual process emissions of CO 2 from cement manufacturing, metric tons.

CO 2 Cli,m = Total annual emissions of CO 2 from clinker production from kiln m,

metric tons. CO 2 rm = Total annual emissions of CO 2 from raw materials, metric tons.

k = Total number of kilns at a cement manufacturing facility. (2) CO2 emissions from clinker production . Calculate CO 2 emissions from each kiln using Equations H–2 through H–5 of this section.



### CO Cli, EF CKD, EF Cli,m j Cli, j i CKD,i 2 

### 2000

2205 = 

# ( ) ∗ 

# ( ) ∗ ⎡
⎣ ⎢ ⎤
⎦ ⎥ + 

## ( ) ∗ 

# ( ) ∗ ⎡
⎣ ⎢ ⎤
⎦ ⎥

= = 

# ∑ ∑ 2000

2205 1 1 

### (Eq. H-2)

i r

j p

Where:

Cli,j = Quantity of clinker produced in month j from kiln m, tons.

EF Cli,j = Kiln specific clinker emission factor for month j for kiln m, metric tons CO 2 / metric ton clinker computed as specified in Equation H–3 of this section. CKD, i = Cement kiln dust (CKD) not recycled to the kiln in quarter i from kiln m, tons.

EF CKD,i = Kiln specific CKD emission factor for quarter i from kiln m, metric tons

CO 2 /metric ton CKD computed as specified in Equation H–4 of this section. p = Number of months for clinker calculation, 12. r = Number of quarters for CKD calculation,

4. 2000/2205 = Conversion factor to convert

tons to metric tons.

(i) Kiln-Specific Clinker Emission

Factor. (A) Calculate the kiln-specific clinker emission factor using Equation
H–3 of this section.



### EF CLi Cli MR Cli Cli MR CaO ncCaO CaO MgO ncMgO MgO Cli 

### (Eq. = −



## ( ) ∗+ − 

# ( ) ∗ H -3)


### 56421 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

Where:

Cli CaO = Monthly total CaO content of Clinker, wt-fraction.

Cli ncCaO = Monthly non-calcined CaO content of Clinker, wt-fraction.

MRCaO = Molecular-weight Ratio of CO 2 /CaO

= 0.785.
Cli MgO = Monthly total MgO content of Clinker, wt-fraction. Cli ncMgO = Monthly non-calcined MgO content of Clinker, wt-fraction.

MRMgO = Molecular-weight Ratio of CO 2 / MgO = 1.092.

(B) Non-calcined CaO is CaO that
remains in the clinker in the form of

CaCO 3 and CaO in the clinker that
entered the kiln as a non-carbonate species. Non-calcined MgO is MgO that remains in the clinker in the form of MgCO 3 and MgO in the clinker that
entered the kiln as a non-carbonate species.

(ii) Kiln-Specific CKD Emission

Factor. (A) Calculate the kiln-specific
CKD emission factor for CKD not recycled to the kiln using Equation H–
4 of this section.



### EF CKD CKD MR CKD CKD MR CaO ncCaO CaO MgO ncMgO MgO CKD 

### (Eq. = −



## ( ) ∗+ − 

# ( ) ∗ H -4)

Where:

CKD CaO = Quarterly total CaO content of CKD not recycled to the kiln, wt-fraction.

CKD CaO = Quarterly non-calcined CaO content of CKD not recycled to the kiln,
wt-fraction.

MRCaO = Molecular-weight Ratio of CO 2 /CaO

= 0.785.
CKD MgO = Quarterly total MgO content of CKD not recycled to the kiln, wt-fraction. CKD MgO = Quarterly non-calcined MgO content of CKD not recycled to the kiln,
wt-fraction.

MRMgO = Molecular-weight Ratio of CO 2 / MgO = 1.092.

(B) Non-calcined CaO is CaO that
remains in the CKD in the form of

CaCO 3 and CaO in the CKD that entered the kiln as a non-carbonate species. Non-calcined MgO is MgO that remains in the CKD in the form of MgCO 3 and MgO in the CKD that entered the kiln as a non-carbonate species.

(3) CO2 emissions from raw materials.
Calculate CO 2 emissions using Equation
H–5 of this section:



### CO rm TOCrm

rm
im

2 

### 44

12 2000

2205 , 

### = ∗ ∗∗

= 

# ∑ (Eq. H-5)

1

Where:

rm = The amount of raw material i consumed annually, tons/yr (dry basis).

CO 2,rm = Annual CO 2 emissions from raw
materials. TOCrm = Organic carbon content of raw material i (dry basis), as determined in § 98.84(c) or using a default factor of 0.2 percent of total raw material weight.
M = Number of raw materials. 44/12 = Ratio of molecular weights, CO 2 to carbon.
2000/2205 = Conversion factor to convert

tons to metric tons. (4) Calculate and report under subpart C of this part (General Stationary Fuel Combustion Sources) the combustion

CO 2 emissions from the kiln according to the applicable requirements in subpart C.

**§ 98.84 Monitoring and QA/QC requirements.** 

(a) You must determine the weight fraction of total CaO and total MgO in CKD not recycled to the kiln from each kiln using ASTM C114–09, Standard Test Methods for Chemical Analysis of Hydraulic Cement (incoporated by reference, see § 98.7). The monitoring must be conducted quarterly for each kiln from a CKD sample drawn either as CKD is exiting the kiln or from bulk CKD storage.

(b) You must determine the weight fraction of total CaO and total MgO in clinker from each kiln using ASTM
C114–07 Standard Test Methods for Chemical Analysis of Hydraulic Cement (incorporated by reference, see § 98.7). The monitoring must be conducted monthly for each kiln from a clinker sample drawn from bulk clinker storage.

(c) The total organic carbon contents (dry basis) of each raw material must be determined annually using ASTM
C114–09 Standard Test Methods for Chemical Analysis of Hydraulic Cement (incorporated by reference, see § 98.7) or a similar industry standard practice or method approved for total organic
carbon determination in raw mineral materials. The analysis must be conducted on sample material drawn from bulk raw material storage for each category of raw material (i.e., limestone, sand, shale, iron oxide, and alumina). Facilities that opt to use the default total organic carbon factor provided in § 98.83(d)(3), are not required to
monitor for TOC.

(d) The quantity of clinker produced monthly by each kiln must be determined by direct weight measurement using the same plant instruments used for accounting purposes, such as weigh hoppers or belt weigh feeders.

(e) The quantity of CKD not recycled to the kiln by each kiln must be determined quarterly by direct weight measurement using the same plant instruments used for accounting purposes, such as weigh hoppers, truck weigh scales, or belt weigh feeders.

(f) The quantity of each category of raw materials consumed annually by the facility (e.g., limestone, sand, shale, iron oxide, and alumina) must be determined monthly by direct weight measurement using the same plant instruments used for accounting purposes, such as weigh hoppers, truck weigh scales, or belt weigh feeders.

(g) The monthly non-calcined CaO and MgO that remains in the clinker in
the form of CaCO 3 or that enters the kiln as a non-carbonate species may be
assumed to be a default value of 0.0 or may be determined monthly by careful chemical analysis of feed material and clinker material from each kiln using well documented analytical and
calculational methods or the appropriate industry standard practice.

(h) The quarterly non-calcined CaO and MgO that remains in the CKD in the
form of CaCO 3 or that enters the kiln as a non-carbonate species may be
assumed to be a default value of 0.0 or may be determined quarterly by careful chemical analysis of feed material and CKD material from each kiln using well documented analytical and
calculational methods or the appropriate industry standard practice.

**§ 98.85 Procedures for estimating missing**
**data.**

A complete record of all measured parameters used in the GHG emissions calculations in § 98.83 is required. Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for


### 56422 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

the missing parameter shall be used in the calculations. The owner or operator must document and keep records of the procedures used for all such estimates.

(a) If the CEMS approach is used to determine combined process and
combustion CO 2 emissions, the missing data procedures in § 98.35 apply.

(b) For CO 2 process emissions from cement manufacturing facilities calculated according to § 98.83(d), if data on the carbonate content (of clinker or CKD), noncalcined content (of clinker or CKD) or the annual organic carbon content of raw materials are missing, facilities must undertake a new analysis.

(c) For each missing value of monthly clinker production the substitute data
value must be the best available estimate of the monthly clinker production based on information used for accounting purposes, or use the maximum tons per day capacity of the system and the number of days per
month.

(d) For each missing value of monthly raw material consumption the substitute
data value must be the best available estimate of the monthly raw material consumption based on information used for accounting purposes (such as purchase records), or use the maximum tons per day raw material throughput of the kiln and the number of days per
month.

**§ 98.86 Data reporting requirements.**

In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) and (b) of this section, as appropriate.

(a) If a CEMS is used to measure CO 2 emissions, then you must report under this subpart the relevant information required by § 98.36(e)(2)(vi) and the information listed in this paragraph(a):

(1) Monthly clinker production from each kiln at the facility.

(2) Monthly cement production from each kiln at the facility.

(3) Number of kilns and number of operating kilns.

(b) If a CEMS is not used to measure

CO 2 emissions, then you must report the information listed in this paragraph (b)
for each kiln:

(1) Kiln identification number. (2) Monthly clinker production from
each kiln.

(3) Monthly cement production from
each kiln.

(4) Number of kilns and number of operating kilns.

(5) Quarterly quantity of CKD not recycled to the kiln for each kiln at the facility.

(6) Monthly fraction of total CaO, totalMgO, non-calcined CaO and noncalcined MgO in clinker for each kiln (as wt-fractions).

(7) Method used to determine noncalcined CaO and non-calcined MgO in
clinker.

(8) Quarterly fraction of total CaO,total MgO, non-calcined CaO and noncalcined MgO in CKD not recycled to the kiln for each kiln (as wt-fractions).

(9) Method used to determine noncalcined CaO and non-calcined MgO in

CKD.

(10) Monthly kiln-specific clinker CO 2 emission factors for each kiln (metric

tons CO 2 /metric ton clinker produced).

(11) Quarterly kiln-specific CKD CO 2 emission factors for each kiln (metric

tons CO 2 /metric ton CKD produced).

(12) Annual organic carbon content of each raw material (wt-fraction, dry basis).

(13) Annual consumption of each raw material (dry basis).

(14) Number of times missing data procedures were used to determine the following information:

(i) Clinker production (number of months).

(ii) Carbonate contents of clinker (number of months).

(iii) Non-calcined content of clinker (number of months).

(iv) CKD not recycled to kiln (number of quarters).

(v) Non-calcined content of CKD (number of quarters)

(vi) Organic carbon contents of raw materials (number of times).

(vii) Raw material consumption (number of months).

**§ 98.87 Records that must be retained.**

(a) If a CEMS is used to measure CO 2 emissions, then you must retain under this subpart the records required for the Tier 4 Calculation Methodology in § 98.37.

(1) Documentation of monthly calculated kiln-specific clinker CO 2 emission factor.

(2) Documentation of quarterly calculated kiln-specific CKD CO 2 emission factor.

(3) Measurements, records and calculations used to determine reported parameters.

(b) If a CEMS is not used to measure

CO 2 emissions, then in addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) through (b) of this section for each portland cement manufacturing facility.

**§ 98.88 Definitions.**

All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. **Subpart I—[Reserved]**

**Subpart J—[Reserved]**

**Subpart K—Ferroalloy Production**

**§ 98.110 Definition of the source category.**

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

**§ 98.111 Reporting threshold.**

You must report GHG emissions under this subpart if your facility contains a ferroalloy production process and the facility meets the requirements of either § 98.2(a)(1) or (2).

**§ 98.112 GHGs to report.**

You must report: (a) Process CO 2 emissions from each electric arc furnace (EAF) used for the production of any ferroalloy listed in § 98.110.

(b) CO 2 , CH 4 , and N 2 O emissions from each stationary combustion unit following the requirements of subpart C of this part. You must report these emissions under subpart C of this part (General Stationary Fuel Combustion Sources).

**§ 98.113 Calculating GHG emissions.**

You must calculate and report the annual process CO 2 emissions from each EAF using the procedures in either paragraph (a) or (b) of this section.

(a) Calculate and report under this subpart the process CO 2 emissions by operating and maintaining CEMS according to the Tier 4 Calculation Methodology in § 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources).

(b) Calculate and report under this subpart the annual process CO 2 emissions using the procedure in either paragraph (b)(1) or (b)(2) of this section.

(1) Calculate and report under this subpart the annual process CO 2 emissions from EAFs by operating and maintaining a CEMS according to the Tier 4 Calculation Methodology specified in § 98.33(a)(4) and the applicable requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources).

(2) Calculate and report under this subpart the annual process CO 2 emissions from the EAFs using the carbon mass balance procedure specified in paragraphs (b)(2)(i) and (b)(2)(ii) of this section.


### 56423 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

(i) For each EAF, determine the
annual mass of carbon in each carboncontaining input and output material for the EAF and estimate annual process

CO 2 emissions from the EAF using Equation K–1 of this section. Carboncontaining input materials include
carbon electrodes and carbonaceous reducing agents. If you document that a specific input or output material contributes less than 1 percent of the total carbon into or out of the process, you do not have to include the material in your calculation using Equation K–1
of this section.



### E CO2

1 

### 44

12 2000

2205 =× × × 

# ( ) M C

reducing agent reducing agent i

i i 

# ∑

∑ +× × × 

# ( )

+ ×

44

12 2000

2205

44

12 2000

2 1 

### M C electrode electrode m

m m



### 2 05 × × 

# ( ) M C

ore ore

h h 

### (Eq. K-1)

C flux f j 1



### 44

12 2000

2205 h



### M 

# ∑

+× × × l ux j 

# ( )

−× × × 

# ∑

1



### 44

12 2000

2205 j

product outgoing product out 

### M C
k g oing k

non- product outgoing non- p k

l 

### M C 

# ( )

−× × × 

# ∑

1



### 44

12 2000

2205 r oduct outgoing l

l 

# ( ) ∑

1

Where:

E CO2 = Annual process CO 2 emissions from an individual EAF (metric tons). 44/12 = Ratio of molecular weights, CO 2 to carbon.
2000/2205 = Conversion factor to convert

tons to metric tons.

Mreducing agenti = Annual mass of reducing agent i fed, charged, or otherwise introduced into the EAF (tons).

C reducing agenti = Carbon content in reducing agent i (percent by weight, expressed as a decimal fraction).

M electrodem = Annual mass of carbon electrode

m consumed in the EAF (tons).

C electrodem = Carbon content of the carbon
electrode m (percent by weight, expressed as a decimal fraction).

M

oreh = Annual mass of ore h charged to the EAF (tons).

C

oreh = Carbon content in ore h (percent by weight, expressed as a decimal fraction).

M flux j = Annual mass of flux material j fed, charged, or otherwise introduced into the EAF to facilitate slag formation (tons).

C flux j = Carbon content in flux material j (percent by weight, expressed as a decimal fraction).

Mproductk = Annual mass of alloy product k tapped from EAF (tons). C productk = Carbon content in alloy product k

. (percent by weight, expressed as a decimal fraction).

M non-product outgoing l = Annual mass of nonproduct outgoing material l removed from EAF (tons).

C non-product outgoing l = Carbon content in nonproduct outgoing material l (percent by weight, expressed as a decimal fraction).
(ii) Determine the combined annual process CO 2 emissions from the EAFs at your facility using Equation K–2 of this

section.



### CO E CO k

k 2 2

1 

### = 

# ∑ (Eq. K-2)

Where:

CO 2 = Annual process CO 2 emissions from EAFs at facility used for the production of any ferroalloy listed in § 98.110 (metric tons).

E CO2k = Annual process CO 2 emissions
calculated from EAF k calculated using Equation K–1 of this section (metric tons). k = Total number of EAFs at facility used for the production of any ferroalloy listed in § 98.110. (c) If GHG emissions from an EAF are vented through the same stack as any combustion unit or process equipment that reports CO 2 emissions using a CEMS that complies with the Tier 4 Calculation Methodology in subpart C of this part (General Stationary Fuel Combustion Sources), then the calculation methodology in paragraph (b) of this section shall not be used to calculate process emissions. The owner or operator shall report under this subpart the combined stack emissions according to the Tier 4 Calculation Methodology in § 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part.

(d) For the EAFs at your facility used for the production of any ferroalloy listed in Table K–1 of this subpart, you must calculate and report the annual

CH 4 emissions using the procedure specified in paragraphs (d)(1) and (2) of
this section.

(1) For each EAF, determine the
annual CH4 emissions using Equation
K–3 of this section.



### E CH product product i 

### M EF

i i 4

1 

### 2000

2205 = ×× ⎛ ⎝ ⎜ ⎞ ⎠ ⎟ 

# ∑ (Eq. K-3)

Where:

E CH4 = Annual process CH4 emissions from an individual EAF (metric tons). Mproducti = Annual mass of alloy product i produced in the EAF (tons). 2000/2205 = Conversion factor to convert

tons to metric tons.


### 56424 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

EF producti = CH 4 emission factor for alloy product i from Table K–1 in this subpart (kg of CH 4 emissions per metric ton of alloy product i). (2) Determine the combined process

CH 4 emissions from the EAFs at your facility using Equation K–4 of this

section:



### CH E CH j

j 4 4

1 

### = 

# ∑ (Eq. K-4)

Where:

CH 4 = Annual process CH4 emissions from EAFs at facility used for the production of ferroalloys listed in Table K–1 of this subpart (metric tons).

E CH4 j = Annual process CH4 emissions from

EAF j calculated using Equation K–3 of this section (metric tons). j = Total number of EAFs at facility used for the production of ferroalloys listed in Table K–1 of this subpart.

**§ 98.114 Monitoring and QA/QC requirements.** 

If you determine annual process CO 2 emissions using the carbon mass balance procedure in § 98.113(b)(2), you must meet the requirements specified in paragraphs (a) and (b) of this section.

(a) Determine the annual mass for
each material used for the calculations of annual process CO 2 emissions using Equation K–1 of this subpart by summing the monthly mass for the
material determined for each month of the calendar year. The monthly mass may be determined using plant instruments used for accounting purposes, including either direct measurement of the quantity of the material placed in the unit or by calculations using process operating
information.

(b) For each material identified in paragraph (a) of this section, you must determine the average carbon content of the material consumed, used, or produced in the calendar year using the methods specified in either paragraph (b)(1) or (b)(2) of this section. If you document that a specific process input or output contributes less than one percent of the total mass of carbon into or out of the process, you do not have to determine the monthly mass or annual carbon content of that input or output.

(1) Information provided by your material supplier.

(2) Collecting and analyzing at least three representative samples of the material inputs and outputs each year.
The carbon content of the material must be analyzed at least annually using the standard methods (and their QA/QC procedures) specified in paragraphs (b)(2)(i) through (b)(2)(iii) of this section, as applicable. (i) ASTM E1941–04, Standard Test
Method for Determination of Carbon in Refractory and Reactive Metals and Their Alloys (incorporated by reference,

see § 98.7) for analysis of metal ore and alloy product.

(ii) ASTM D5373–08 Standard Test
Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal (incorporated by reference, see § 98.7), for analysis of carbonaceous reducing agents and carbon electrodes.

(iii) ASTM C25–06, Standard Test Methods for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime (incorporated by reference, see § 98.7) for analysis of flux materials
such as limestone or dolomite.

**§ 98.115 Procedures for estimating missing data.** 

A complete record of all measured parameters used in the GHG emissions calculations in § 98.113 is required. Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter shall be used in the calculations as specified in the paragraphs (a) and (b) of this section. You must document and keep records of the procedures used for all such

estimates.

(a) If you determine CO 2 emissions for the EAFs at your facility using the carbon mass balance procedure in § 98.113(b), 100 percent data availability is required for the carbon content of the input and output materials. You must repeat the test for average carbon contents of inputs according to the procedures in § 98.114(b) if data are missing.

(b) For missing records of the monthly mass of carbon-containing inputs and outputs, the substitute data value must
be based on the best available estimate of the mass of the inputs and outputs from on all available process data or data used for accounting purposes, such as purchase records.

(c) If you are required to calculate CH4 emissions for an EAF at your facility as specified in § 98.113(d), the estimate is based an annual quantity of certain alloy products, so 100 percent data availability is required.

**§ 98.116 Data reporting requirements.**

In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) through (e) of this section, as applicable:

(a) Annual facility ferroalloy product production capacity (tons).

(b) Annual production for each ferroalloy product (tons) identified in § 98.110, as applicable. (c) Total number of EAFs at facility used for production of ferroalloy products reported in paragraph (a)(4) of
this section.

(d) If a CEMS is used to measure CO 2 emissions, then you must report under this subpart the relevant information required by § 98.37 for the Tier 4 Calculation Methodology and the following information specified in paragraphs (d)(1) through (d)(3) of this

section.

(1) Annual process CO 2 emissions (in metric tons) from each EAF used for the production of any ferroalloy listed in Table K–1 of this subpart (metric tons).

(2) Annual process CH4 emissions (in metric tons) from each EAF used for the production of any ferroalloy listed in Table K–1 of this subpart (metric tons).

(3) Identification number of each EAF. (e) If a CEMS is not used to measure

CO 2 process emissions, and the carbon mass balance procedure is used to
determine CO 2 emissions according to the requirements in § 98.113(b), then you must report the following information specified in paragraphs (e)(1) through (e)(7) of this section.

(1) Annual process CO 2 emissions (in metric tons) from each EAF used for the production of any ferroalloy listed in Table K–1 of this subpart (metric tons).

(3) Identification number for each
material.

(4) Annual material quantity for each
material included for the calculation of annual process CO 2 emissions for each

EAF.

(5) Annual average of the carbon
content determinations for each material
included for the calculation of annual process CO 2 emissions for each EAF (percent by weight, expressed as a decimal fraction).

(6) List the method used for the
determination of carbon content for each material reported in paragraph (e)(5) of this section (e.g., supplier provided information, analyses of representative samples you collected).

(7) If you use the missing data procedures in § 98.115(b), you mustreport how monthly mass of carboncontaining inputs and outputs with missing data was determined and the number of months the missing data procedures were used.

**§ 98.117 Records that must be retained.**

In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) through (d) of this section for each EAF, as applicable.

(a) If a CEMS is used to measure CO 2 emissions according to the requirements in § 98.113(a), then you must retain under this subpart the records required


### 56425 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

for the Tier 4 Calculation Methodology in § 98.37 and the information specified in paragraphs (a)(1) through (a)(3) of this

section.

(1) Monthly EAF production quantity for each ferroalloy product (tons).

(2) Number of EAF operating hours
each month.

(3) Number of EAF operating hours in a calendar year.

(b) If the carbon mass balance procedure is used to determine CO 2 emissions according to the requirements in § 98.113(b)(2), then you must retain records for the information specified in paragraphs (b)(1) through (b)(5) of this

section.

(1) Monthly EAF production quantity for each ferroalloy product (tons).

(2) Number of EAF operating hours
each month.

(3) Number of EAF operating hours in a calendar year. (4) Monthly material quantity consumed, used, or produced for each
material included for the calculations of annual process CO 2 emissions (tons).

(5) Average carbon content determined and records of the supplier provided information or analyses used
for the determination for each material
included for the calculations of annual process CO 2 emissions.

(c) You must keep records that include a detailed explanation of how company records of measurements are used to estimate the carbon input and output to each EAF, including documentation of specific input or output materials excluded from Equation K–1 of this subpart that contribute less than 1 percent of the total carbon into or out of the process. You also must document the procedures used to ensure the accuracy of the measurements of materials fed, charged, or placed in an EAF including, but not limited to, calibration of weighing equipment and other measurement devices. The estimated accuracy of
measurements made with these devices must also be recorded, and the technical
basis for these estimates must be provided.

(d) If you are required to calculate

CH 4 emissions for the EAF as specified in § 98.113(d), you must maintain records of the total amount of each alloy product produced for the specified reporting period, and the appropriate alloy-product specific emission factor
used to calculate the CH4 emissions.

**§ 98.118 Definitions.**

All terms used of this subpart have the same meaning given in the Clean Air Act and subpart A of this part.



### TABLE 

### K–1 TO 

### S UBPART 

### K OF 

### P ART 

### 98—E LECTRIC 

### A RC 

### F URNACE 

### (EAF) CH 4 

### E MISSION 

### FACTORS

Alloy product produced in EAF CH 4 emission factor (kg CH 4 per metric ton product)

EAF Operation

Batchcharging Sprinklecharging a Sprinklecharging

and >750 ° C b

Silicon metal .................................................................................................................. .......................... 1.5 1.2 0.7
Ferrosilicon 90% ............................................................................................................... ....................... 1.4 1.1 0.6
Ferrosilicon 75% ............................................................................................................... ....................... 1.3 1.0 0.5
Ferrosilicon 65% ............................................................................................................... ....................... 1.3 1.0 0.5

a Sprinkle-charging is charging intermittently every minute.

b Temperature measured in off-gas channel downstream of the furnace hood.

**Subpart L—[Reserved]**

**Subpart M—[Reserved]**

**Subpart N—Glass Production**

**§ 98.140 Definition of the source category.**

(a) A glass manufacturing facility manufactures flat glass, container glass, pressed and blown glass, or wool fiberglass by melting a mixture of raw materials to produce molten glass and form the molten glass into sheets, containers, fibers, or other shapes. A glass manufacturing facility uses one or more continuous glass melting furnaces to produce glass.

(b) A glass melting furnace that is an experimental furnace or a research and development process unit is not subject to this subpart.

**§ 98.141 Reporting threshold.**

You must report GHG emissions under this subpart if your facility contains a glass production process and the facility meets the requirements of either § 98.2(a)(1) or (2). **§ 98.142 GHGs to report.** You must report: (a) CO 2 process emissions from each continuous glass melting furnace.

(b) CO 2 combustion emissions from each continuous glass melting furnace.

(c) CH 4 and N 2 O combustion emissions from each continuous glass melting furnace. You must calculate and report these emissions under subpart C of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart C.

(d) CO 2 , CH 4 , and N 2 O emissions from each stationary fuel combustion unit other than continuous glass melting furnaces. You must report these emissions under subpart C of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart C.

**§ 98.143 Calculating GHG emissions.**

You must calculate and report the annual process CO 2 emissions from each continuous glass melting furnace using the procedure in paragraphs (a) and (b)
of this section. (a) For each continuous glass melting
furnace that meets the conditions specified in § 98.33(b)(4)(ii) or (iii), you must calculate and report under this subpart the combined process and
combustion CO 2 emissions by operating and maintaining a CEMS to measure

CO 2 emissions according to the Tier 4 Calculation Methodology specified in § 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources).

(b) For each continuous glass melting furnace that is not subject to the requirements in paragraph (a) of this section, calculate and report the process
and combustion CO 2 emissions from the glass melting furnace by using either the procedure in paragraph (b)(1) of this section or the procedure in paragraphs (b)(2) through (b)(7) of this section, except as specified in paragraph (c) of
this section.

(1) Calculate and report under this subpart the combined process and
combustion CO 2 emissions by operating


### 56426 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

and maintaining a CEMS to measure

CO 2 emissions according to the Tier 4 Calculation Methodology specified in § 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources).

(2) Calculate and report the process
and combustion CO 2 emissions separately using the procedures specified in paragraphs (b)(2)(i) through (b)(2)(vi) of this section.

(i) For each carbonate-based raw material charged to the furnace, obtain from the supplier of the raw material the
carbonate-based mineral mass fraction.

(ii) Determine the quantity of each carbonate-based raw material charged to
the furnace. (iii) Apply the appropriate emission
factor for each carbonate-based raw material charged to the furnace, as shown in Table N–1 to this subpart.

(iv) Use Equation N–1 of this section to calculate process mass emissions of

CO 2 for each furnace:



### E MF M EF F Eq

CO i i i i 2

1 

### 2000

2205 = ⎛ ⎝ ⎜ ⎞ ⎠ ⎟

= 

# ∑

i i ii

i n 

### (. ) N-1

Where:

E CO2 = Process emissions of CO 2 from the furnace (metric tons).
n = Number of carbonate-based raw materials charged to furnace.

MF i = Annual average mass fraction of
carbonate-based mineral i in carbonatebased raw material i (percentage, expressed as a decimal).

M i = Annual amount of carbonate-based raw material i charged to furnace (tons).
2000/2205 = Conversion factor to convert

tons to metric tons.

EF i = Emission factor for carbonate-based raw material i (metric ton CO 2 per metric ton
carbonate-based raw material as shown in Table N–1 to this subpart).

F i = Fraction of calcination achieved for carbonate-based raw material i, assumed to be equal to 1.0 (percentage, expressed as a decimal).

(v) You must calculate the total process CO 2 emissions from continuous glass melting furnaces at the facility using Equation N–2 of this section:



### CO E Eq CO i

i k

2

1 2



### =

=



# ∑ (. ) N-2

Where:

CO 2 = Annual process CO 2 emissions from glass manufacturing facility (metric tons).

E CO2i = Annual CO 2 emissions from glass melting furnace i (metric tons). k = Number of continuous glass melting
furnaces.
(vi) Calculate and report under subpart C of this part (General Stationary Fuel Combustion Sources)
the combustion CO 2 emissions in the glass furnace according to the applicable requirements in subpart C.

(c) As an alternative to data provided by the raw material supplier, a value of
1.0 can be used for the mass fraction (MF i ) of carbonate-based mineral i in Equation N–1 of this section.

**§ 98.144 Monitoring and QA/QC requirements.** 

(a) You must measure annual amounts
of carbonate-based raw materials charged to each continuous glass melting furnace from monthly measurements using plant instruments used for accounting purposes, such as calibrated scales or weigh hoppers. Total annual mass charged to glass melting furnaces at the facility shall be compared to records of raw material purchases for the year.

(b) You must measure carbonatebased mineral mass fractions at least annually to verify the mass fraction data provided by the supplier of the raw material; such measurements shall be based on sampling and chemical analysis conducted by a certified laboratory using ASTM D3682–01 (Reapproved 2006) Standard Test Method for Major and Minor Elements
in Combustion Residues from Coal Utilization Processes (incorporated by reference, see § 98.7).

(c) You must determine the annualaverage mass fraction for the carbonatebased mineral in each carbonate-based raw material by calculating an arithmetic average of the monthly data obtained from raw material suppliers or sampling and chemical analysis.

(d) You must determine on an annual
basis the calcination fraction for each carbonate consumed based on sampling and chemical analysis using an industry
consensus standard. This chemicalanalysis must be conducted using an xray fluorescence test or other enhanced testing method published by an industry consensus standards organization (e.g., ASTM, ASME, API, etc.).

**§ 98.145 Procedures for estimating missing data.** 

A complete record of all measured parameters used in the GHG emissions calculations is required (e.g., carbonate raw materials consumed, etc.). If the monitoring and quality assurance procedures in § 98.144 cannot be followed and data is missing, you must use the most appropriate of the missing data procedures in paragraphs (a) and (b) of this section. You must document and keep records of the procedures used for all such missing value estimates.

(a) For missing data on the monthly
amounts of carbonate-based raw materials charged to any continuous glass melting furnace use the best available estimate(s) of the parameter(s), based on all available process data or data used for accounting purposes, such as purchase records.

(b) For missing data on the mass
fractions of carbonate-based minerals in
the carbonate-based raw materials
assume that the mass fraction of each
carbonate based mineral is 1.0.

**§ 98.146 Data reporting requirements.**

In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) and (b) of this section, as applicable.

(a) If a CEMS is used to measure CO 2 emissions, then you must report under this subpart the relevant information required under § 98.37 for the Tier 4 Calculation Methodology and the following information specified in paragraphs (a)(1) and (a)(2) of this

section:

(1) Annual quantity of each carbonatebased raw material charged to each continuous glass melting furnace and for all furnaces combined (tons).

(2) Annual quantity of glass produced (tons).

(b) If a CEMS is not used to determine

CO 2 emissions from continuous glass melting furnaces, and process CO 2 emissions are calculated according to the procedures specified in § 98.143(b), then you must report the following information as specified in paragraphs (b)(1) through (b)(9) of this section:

(1) Annual process emissions of CO 2 (metric tons) for each continuous glass melting furnace and for all furnaces
combined.

(2) Annual quantity of each carbonatebased raw material charged (tons) to each continuous glass melting furnace
and for all furnaces combined.


### 56427 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

(3) Annual quantity of glass produced (tons) from each continuous glass melting furnace and from all furnaces
combined.

(4) Carbonate-based mineral mass fraction (percentage, expressed as a decimal) for each carbonate-based raw material charged to a continuous glass melting furnace.

(5) Results of all tests used to verify
the carbonate-based mineral mass
fraction for each carbonate-based raw material charged to a continuous glass melting furnace, as specified in paragraphs (b)(5)(i) through (b)(5)(iii) of
this section.

(i) Date of test. (ii) Method(s) and any variations used in the analyses.

(iii) Mass fraction of each sample analyzed.

(6) The fraction of calcination
achieved for each carbonate-based raw material, if a value other than 1.0 is used to calculate process mass
emissions of CO 2
.

(7) Method used to determine fraction of calcination (percentage, expressed as a decimal).

(8) Total number of continuous glass melting furnaces.

(9) The number of times in the reporting year that missing data procedures were followed to measure monthly quantities of carbonate-based raw materials any continuous glass melting furnace or mass fraction of the carbonate-based minerals (months).

**§ 98.147 Records that must be retained.**

In addition to the information required by § 98.3(g), you must retain the records listed in paragraphs (a), (b), and (c) of this section.

(a) If a CEMS is used to measure emissions, then you must retain the records required under § 98.37 for the Tier 4 Calculation Methodology and the following information specified in paragraphs (a)(1) and (a)(2) of this

section:

(1) Monthly glass production rate for each continuous glass melting furnace (tons).

(2) Monthly amount of each carbonate-based raw material charged to each continuous glass melting furnace (tons).

(b) If process CO 2 emissions are calculated according to the procedures specified in § 98.143(b), you must retain the records in paragraphs (b)(1) through (b)(5) of this section.

(1) Monthly glass production rate for each continuous glass melting furnace (metric tons).

(2) Monthly amount of each carbonate-based raw material charged to each continuous glass melting furnace (metric tons). (3) Data on carbonate-based mineral mass fractions provided by the raw material supplier for all raw materials consumed annually and included in calculating process emissions in Equation N–1 of this subpart.

(4) Results of all tests used to verify
the carbonate-based mineral mass
fraction for each carbonate-based raw material charged to a continuous glass melting furnace, including the data specified in paragraphs (b)(4)(i) through (b)(4)(v) of this section.

(i) Date of test. (ii) Method(s), and any variations of the methods, used in the analyses.

(iii) Mass fraction of each sample analyzed.

(iv) Relevant calibration data for the instrument(s) used in the analyses.

(v) Name and address of laboratory
that conducted the tests.

(5) The fraction of calcination
achieved for each carbonate-based raw material (percentage, expressed as a decimal), if a value other than 1.0 is used to calculate process mass
emissions of CO 2
.

(c) All other documentation used to support the reported GHG emissions.

**§ 98.148 Definitions.**

All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.



### TABLE 

### N–1 TO 

### S UBPART 

### N OF 

### P ART



### 98—CO 2 

### E MISSION 

### FACTORS FOR 

### C ARBONATE 

### -B ASED 

### R AW 

### M ATERIALS

Carbonate-based raw material—mineral CO 2 emission factor a

Limestone—CaCO 3 .................. 0.440 Dolomite—CaMg(CO 3 ) 2 ............ 0.477
Sodium carbonate/soda ash—

Na 2 CO 3 ................................. 0.415

a Emission factors in units of metric tons of CO 2 emitted per metric ton of carbonatebased raw material charged to the furnace.

**Subpart O—HCFC–22 Production and**
**HFC–23 Destruction**

**§ 98.150 Definition of the source category.**

The HCFC–22 production and HFC– 23 destruction source category consists of HCFC–22 production processes and HFC–23 destruction processes.

(a) An HCFC–22 production process produces HCFC–22 (chlorodifluoromethane, or CHClF 2 ) from chloroform (CHCl 3 ) and hydrogen fluoride (HF).

(b) An HFC–23 destruction process is any process in which HFC–23 undergoes destruction. An HFC–23 destruction process may or may not be co-located with an HCFC–22 production process at the same facility. **§ 98.151 Reporting threshold.** You must report GHG emissions under this subpart if your facility contains an HCFC–22 production or HFC–23 destruction process and the facility meets the requirements of either § 98.2(a)(1) or (a)(2).

**§ 98.152 GHGs to report.**

(a) You must report under subpart C of this part (General Stationary Fuel Combustion Sources) the emissions of

CO 2 , CH 4 , and N 2 O from each stationary combustion unit following the requirements of subpart C.

(b) You must report HFC–23 emissions from HCFC–22 production processes and HFC–23 destruction

processes.

**§ 98.153 Calculating GHG emissions.**

(a) The mass of HFC–23 generated from each HCFC–22 production process shall be estimated by using one of two methods, as applicable:

(1) Where the mass flow of the
combined stream of HFC–23 and another reaction product (e.g., HCl) is measured, multiply the weekly (or more frequent) HFC–23 concentration measurement (which may be the average of more frequent concentration measurements) by the weekly (or more frequent) mass flow of the combined
stream of HFC–23 and the other product. To estimate annual HFC–23 production, sum the weekly (or more frequent) estimates of the quantities of HFC–23 produced over the year. This calculation is summarized in Equation
O–1 of this section:



### G cF p

p

n

23 23 3

1 

### 10 = ∗∗ −

= 

# ∑ (. ) Eq O -1

Where:

G 23 = Mass of HFC–23 generated annually (metric tons).

c 23 = Fraction HFC–23 by weight in HFC–23/ other product stream.

F p = Mass flow of HFC–23/other product stream during the period p (kg). p = Period over which mass flows and
concentrations are measured.
n = Number of concentration and flow measurement periods for the year.

10

¥ 3 = Conversion factor from kilograms to

metric tons. (2) Where the mass of only a reaction product other than HFC–23 (either HCFC–22 or HCl) is measured, multiply the ratio of the weekly (or more frequent) measurement of the HFC–23 concentration and the weekly (or more frequent) measurement of the other product concentration by the weekly (or more frequent) mass produced of the other product. To estimate annual HFC– 23 production, sum the weekly (or more


### 56428 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

frequent) estimates of the quantities of HFC–23 produced over the year. This calculation is summarized in Equation O–2 of this section, assuming that the other product is HCFC–22. If the other product is HCl, HCl may be substituted for HCFC–22 in Equations O–2 and O–
3 of this section.



### G c

c P

p

n

23 23

22 3

1 

### 10 2 = ⎛
⎝ ⎜ ⎞
⎠ ⎟ ∗ ∗ −

= 

# ∑ 22 

### O(. ) Eq

Where:

G 23 = Mass of HFC–23 generated annually (metric tons).

c 23 = Fraction HFC–23 by weight in HCFC–

22/HFC–23 stream. c 22 = Fraction HCFC–22 by weight in HCFC–
22/HFC–23 stream.

P 22 = Mass of HCFC–22 produced over the period p (kg), calculated using Equation
O–3 of this section. p = Period over which masses and
concentrations are measured.
n = Number of concentration and mass measurement periods for the year.

10

¥ 3 = Conversion factor from kilograms to

metric tons. (b) The mass of HCFC–22 produced over the period p shall be estimated by using Equation O–3 of this section:



### P LF O U

22 22 22 

### =∗ − 

## ( ) ( . Eq O-3)

Where:

P 22 = Mass of HCFC–22 produced over the period p (kg). O 22 = mass of HCFC–22 that is measured coming out of the Production process over the period p (kg).

U 22 = Mass of used HCFC–22 that is added to the production process upstream of the output measurement over the period p (kg).

LF = Factor to account for the loss of HCFC– 22 upstream of the measurement. The

value for LF shall be determined pursuant to § 98.154(e).

(c) For HCFC–22 production facilities
that do not use a thermal oxidizer or
that have a thermal oxidizer that is not directly connected to the HCFC–22 production equipment, HFC–23 emissions shall be estimated using Equation O–4 of this section:



### E G S OD D

23 23 23 23 23 23 

### 4 =− + ++ 

## ( ) I ( . Eq O- )

Where:

E 23 = Mass of HFC–23 emitted annually (metric tons).

G 23 = Mass of HFC–23 generated annually (metric tons).

S 23 = Mass of HFC–23 sent off site for sale annually (metric tons).

OD 23 = Mass of HFC–23 sent off site for destruction (metric tons).

D 23 = Mass of HFC–23 destroyed on site (metric tons).

I 23 = Increase in HFC–23 inventory = HFC– 23 in storage at end of year—HFC–23 in storage at beginning of year (metric tons). (d) For HCFC–22 production facilities
that use a thermal oxidizer connected to the HCFC–22 production equipment,
HFC–23 emissions shall be estimated using Equation O–5 of this section:



### E =E +E +E L PV D 23 

### O-5) ( . Eq

Where:

E 23 = Mass of HFC–23 emitted annually (metric tons).

E L = Mass of HFC–23 emitted annually from equipment leaks, calculated using Equation O–6 of this section (metric tons).

E PV = Mass of HFC–23 emitted annually from process vents, calculated using Equation O–7 of this section (metric tons).

E D = Mass of HFC–23 emitted annually from thermal oxidizer (metric tons), calculated using Equation O–8 of this section.

(1) The mass of HFC–23 emitted annually from equipment leaks (for use in Equation O–5 of this section) shall be estimated by using Equation O–6 of this

section:



### E FN FN

t Gt Gt

p

n

L Lt Lt 

### c = ∗ ∗+∗ 

## ( ) ∗ 

# ∑ ∑

−

= 23 3

1 

### 10 ( . Eq O-6)

Where:

E L = Mass of HFC–23 emitted annually from equipment leaks (metric tons).

c 23 = Fraction HFC–23 by weight in the stream(s) in the equipment.

F Gt = The applicable leak rate specified in Table O–1 of this subpart for each source of equipment type and service t with a screening value greater than or equal to 10,000 ppmv (kg/hr/source).

N Gt = The number of sources of equipment type and service t with screening values greater than or equal to 10,000 ppmv as determined according to § 98.154(i).

F Lt = The applicable leak rate specified in Table O–1 of this subpart for each source of equipment type and service t with a screening value of less than 10,000 ppmv (kg/hr/source).

NLt = The number of sources of equipment type and service t with screening values less than 10,000 ppmv as determined according to § 98.154(j). p = One hour. n = Number of hours during the year during which equipment contained HFC–23. t = Equipment type and service as specified in Table O–1 of this subpart .

10

¥ 3 = Factor converting kg to metric tons.

(2) The mass of HFC–23 emitted annually from process vents (for use in Equation O–5 of this section) shall be estimated by using Equation O–7 of this

section:



### E = ER * PR

PR * l T p

T p PV

p n

= − 

# ∑ ⎛
⎝ ⎜ ⎞
⎠ ⎟ ∗

1 3 

### 10 ( . Eq O-7)

Where:

E PV = Mass of HFC–23 emitted annually from process vents (metric tons).

ERT = The HFC–23 emission rate from the process vents during the period of the most recent test (kg/hr). PRp = The HCFC–22 production rate during the period p (kg/hr).

PRT = The HCFC–22 production rate during the most recent test period (kg/hr).

l p = The length of the period p (hours).

10

¥ 3 = Factor converting kg to metric tons. n = The number of periods in a year. (3) The total mass of HFC–23 emitted
from destruction devices shall be estimated by using Equation O–8 of this

section:



### E FD

D D



### = − 23 

### 8 ( . Eq O- )


### 56429 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

Where:

E D = Mass of HFC–23 emitted annually from the destruction device (metric tons).

F D = Mass of HFC–23 fed into the destruction device annually (metric tons).

D 23 = Mass of HFC–23 destroyed annually (metric tons). (4) For facilities that destroy HFC–23, the total mass of HFC–23 destroyed shall be estimated by using Equation O–
9 of this section:



### D F DE O- )

23 D 

### = ∗ ( . Eq 9

Where:

D 23 = Mass of HFC–23 destroyed annually (metric tons).

F D = Mass of HFC–23 fed into the destruction device annually (metric tons). DE = Destruction Efficiency of the destruction device (fraction).

**§ 98.154 Monitoring and QA/QC requirements.** 

These requirements apply to measurements that are reported under this subpart or that are used to estimate reported quantities pursuant to § 98.153.

(a) The concentrations (fractions by weight) of HFC–23 and HCFC–22 in the product stream shall be measured at least weekly using equipment and methods (e.g., gas chromatography) with an accuracy and precision of 5 percent
or better at the concentrations of the process samples.

(b) The mass flow of the product stream containing the HFC–23 shall be measured at least weekly using weigh scales, flowmeters, or a combination of volumetric and density measurements with an accuracy and precision of 1.0 percent of full scale or better.

(c) The mass of HCFC–22 or HCl coming out of the production process shall be measured at least weekly using weigh scales, flowmeters, or a combination of volumetric and density measurements with an accuracy and precision of 1.0 percent of full scale or
better.

(d) The mass of any used HCFC–22 added back into the production process upstream of the output measurement in paragraph (c) of this section shall be measured (when being added) using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of 1.0 percent of full scale or better. If the mass in paragraph (c) of this section is measured by weighing
containers that include returned heels as well as newly produced fluorinated GHGs, the returned heels shall be
considered used fluorinated HCFC–22 for purposes of this paragraph (d) of this section and § 98.153(b).

(e) The loss factor LF in Equation O– 3 of this subpart for the mass of HCFC– 22 produced shall have the value 1.015
or another value that can be demonstrated, to the satisfaction of the Administrator, to account for losses of
HCFC–22 between the reactor and the point of measurement at the facility where production is being estimated.

(f) The mass of HFC–23 sent off site
for sale shall be measured at least weekly (when being packaged) using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of 1.0 percent of full scale or
better.

(g) The mass of HFC–23 sent off site
for destruction shall be measured at least weekly (when being packaged) using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of 1.0 percent of full scale or
better. If the measured mass includes
more than trace concentrations of materials other than HFC–23, the
concentration of the fluorinated GHG shall be measured at least weekly using equipment and methods (e.g., gas chromatography) with an accuracy and precision of 5 percent or better at the concentrations of the process samples. This concentration (mass fraction) shall be multiplied by the mass measurement
to obtain the mass of the HFC–23 sent to another facility for destruction.

(h) The masses of HFC–23 in storage at the beginning and end of the year shall be measured using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of 1.0 percent of full scale or better.

(i) The number of sources of equipment type t with screening values greater than or equal to 10,000 ppmv shall be determined using EPA Method 21 at 40 CFR part 60, appendix A–7, and defining a leak as follows:

(1) A leak source that could emit HFC–23, and

(2) A leak source at whose surface a concentration of fluorocarbons equal to or greater than 10,000 ppm is measured.

(j) The number of sources of equipment type t with screening values less than 10,000 ppmv shall be the
difference between the number of leak sources of equipment type t that could
emit HFC–23 and the number of sources of equipment type t with screening values greater than or equal to 10,000 ppmv as determined under paragraph (h) of this section.

(k) The mass of HFC–23 emitted from process vents shall be estimated at least monthly by incorporating the results of
the most recent emissions test into Equation O–6 of this subpart. HCFC–22 production facilities that use a thermal oxidizer connected to the HCFC–22 production equipment shall conduct emissions tests at process vents at least once every five years or after significant changes to the process. Emissions tests
shall be conducted in accordance with EPA Method 18 at 40 CFR part 60, appendix A–6, under conditions that are typical for the production process at the facility. The sensitivity of the tests shall
be sufficient to detect an emission rate
that would result in annual emissions of 200 kg of HFC–23 if sustained over one

year.

(l) For purposes of Equation O–9 of this subpart, the destruction efficiency must be equated to the destruction efficiency determined during a new or previous performance test of the
destruction device. HFC–23 destruction
facilities shall conduct annual
measurements of HFC–23
concentrations at the outlet of the
thermal oxidizer in accordance with EPA Method 18 at 40 CFR part 60, appendix A–6. Three samples shall be taken under conditions that are typical for the production process and destruction device at the facility, and the average concentration of HFC–23 shall be determined. The sensitivity of
the concentration measurement shall be
sufficient to detect an outlet concentration equal to or less than the
outlet concentration determined in the destruction efficiency performance test.
If the concentration measurement
indicates that the HFC–23 concentration is less than or equal to that measured during the performance test that is the basis for the destruction efficiency, continue to use the previously determined destruction efficiency. If the
concentration measurement indicates that the HFC–23 concentration is greater than that measured during the performance test that is the basis for the destruction efficiency, facilities shall
either:

(1) Substitute the higher HFC–23 concentration for that measured during the destruction efficiency performance
test and calculate a new destruction efficiency, or

(2) Estimate the mass emissions of
HFC–23 from the destruction device
based on the measured HFC–23
concentration and volumetric flow rate determined by measurement of volumetric flow rate using EPA Method 2, 2A, 2C,2D, or 2F at 40 CFR part 60, appendix A–1, or Method 26 at 40 CFR part 60, appendix A–2. Determine the
mass rate of HFC–23 into the destruction device by measuring the
HFC–23 concentration and volumetric flow rate at the inlet or by a metering
device for HFC–23 sent to the device. Determine a new destruction efficiency


### 56430 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

based on the mass flow rate of HFC–23
into and out of the destruction device.

(m) HCFC–22 production facilities shall account for HFC–23 generation
and emissions that occur as a result of startups, shutdowns, and malfunctions, either recording HFC–23 generation and emissions during these events, or documenting that these events do not result in significant HFC–23 generation
and/or emissions.

(n) The mass of HFC–23 fed into the
destruction device shall be measured at least weekly using flow meters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of 1.0 percent of
full scale or better. If the measured mass
includes more than trace concentrations of materials other than HFC–23, the
concentrations of the HFC–23 shall be measured at least weekly using equipment and methods (e.g., gas chromatography) with an accuracy and precision of 5 percent or better at the concentrations of the process samples. This concentration (mass fraction) shall be multiplied by the mass measurement
to obtain the mass of the HFC–23 destroyed.

(o) In their estimates of the mass of HFC–23 destroyed, HFC–23 destruction facilities shall account for any temporary reductions in the destruction efficiency that result from any startups, shutdowns, or malfunctions of the destruction device, including departures from the operating conditions defined in state or local permitting requirements
and/or oxidizer manufacturer specifications.

(p) Calibrate all flow meters, weigh scales, and combinations of volumetricand density measures using NISTtraceable standards and suitable methods published by a consensus standards organization (e.g., ASTM, ASME, ISO, or others). Recalibrate all flow meters, weigh scales, and combinations of volumetric and density measures at the minimum frequency specified by the manufacturer.

(q) All gas chromatographs used to
determine the concentration of HFC–23 in process streams shall be calibrated at least monthly through analysis of certified standards (or of calibrationgases prepared from a highconcentration certified standard using a gas dilution system that meets the requirements specified in Method 205 at 40 CFR part 51, appendix M) with
known HFC–23 concentrations that are in the same range (fractions by mass) as the process samples. **§ 98.155 Procedures for estimating missing data.** 

(a) A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable (e.g., if a meter malfunctions during unit operation or if a required process sample is not taken), a substitute data value for the missing parameter shall be used in the calculations, according to the following requirements:

(1) For each missing value of the HFC–23 or HCFC–22 concentration, the
substitute data value shall be the arithmetic average of the quality-assured values of that parameter immediately preceding and immediately following the missing data incident. If, for a particular parameter, no quality-assured data are available prior to the missing data incident, the substitute data value shall be the first quality-assured value obtained after the missing data period.

(2) For each missing value of the product stream mass flow or product mass, the substitute value of that parameter shall be a secondary product
measurement where such a
measurement is available. If that measurement is taken significantly
downstream of the usual mass flow or mass measurement (e.g., at the shipping dock rather than near the reactor), the measurement shall be multiplied by 1.015 to compensate for losses. Where a secondary mass measurement is not available, the substitute value of the parameter shall be an estimate based on a related parameter. For example, if a flowmeter measuring the mass fed into
a destruction device is rendered inoperable, then the mass fed into the destruction device may be estimated using the production rate and the previously observed relationship between the production rate and the
mass flow rate into the destruction
device.

**§ 98.156 Data reporting requirements.**

(a) In addition to the information required by § 98.3(c), the HCFC–22 production facility shall report the following information at the facility
level:

(1) Annual mass of HCFC–22 produced in metric tons.

(2) Loss Factor used to account for the loss of HCFC– 22 upstream of the

measurement.

(3) Annual mass of reactants fed into the process in metric tons of reactant.

(4) The mass (in metric tons) of
materials other than HCFC–22 and HFC–23 (i.e., unreacted reactants, HCl and other by-products) that occur in
more than trace concentrations and that are permanently removed from the

process.

(5) The method for tracking startups, shutdowns, and malfunctions and HFC– 23 generation/emissions during these

events.

(6) The names and addresses of facilities to which any HFC–23 was sent for destruction, and the quantities of HFC–23 (metric tons) sent to each.

(7) Annual mass of the HFC–23 generated in metric tons.

(8) Annual mass of any HFC–23 sent
off site for sale in metric tons.

(9) Annual mass of any HFC–23 sent
off site for destruction in metric tons.

(10) Mass of HFC–23 in storage at the beginning and end of the year, in metric

tons.

(11) Annual mass of HFC–23 emitted

in metric tons.

(12) Annual mass of HFC–23 emitted from equipment leaks in metric tons.

(13) Annual mass of HFC–23 emitted from process vents in metric tons.

(b) In addition to the information required by § 98.3(c), facilities that destroy HFC–23 shall report the following for each HFC–23 destruction

process:

(1) Annual mass of HFC–23 fed into
the thermal oxidizer.

(2) Annual mass of HFC–23 destroyed.

(3) Annual mass of HFC–23 emitted
from the thermal oxidizer.

(c) Each HFC–23 destruction facility shall report the results of the facility’s
annual HFC–23 concentration
measurements at the outlet of the destruction device, including:

(1) Flow rate of HFC–23 being fed into the destruction device in kg/hr.

(2) Concentration (mass fraction) of
HFC–23 at the outlet of the destruction
device.

(3) Flow rate at the outlet of the destruction device in kg/hr.

(d) Emission rate calculated from paragraphs (c)(2) and (3) of this section in kg/hr.

(e) HFC–23 destruction facilities shall submit a one-time report including the following information for each the destruction process:

(1) Destruction efficiency (DE). (2) The methods used to determine destruction efficiency.

(3) The methods used to record the mass of HFC–23 destroyed.

(4) The name of other relevant federal or state regulations that may apply to the destruction process.

(5) If any changes are made that affect HFC–23 destruction efficiency or the
methods used to record volume destroyed, then these changes must be reflected in a revision to this report. The revised report must be submitted to EPA within 60 days of the change.


### 56431 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

**§ 98.157 Records that must be retained.**

(a) In addition to the data required by § 98.3(g), HCFC–22 production facilities shall retain the following records:

(1) The data used to estimate HFC–23

emissions.

(2) Records documenting the initial and periodic calibration of the gas chromatographs, weigh scales, volumetric and density measurements,
and flowmeters used to measure the quantities reported under this rule, including the industry standards or manufacturer directions used for calibration pursuant to § 98.154(p) and (q).

(b) In addition to the data required by § 98.3(g), the HFC–23 destruction facilities shall retain the following
records:

(1) Records documenting their onetime and annual reports in § 98.156(b) through (d).

(2) Records documenting the initial and periodic calibration of the gas chromatographs, weigh scales, volumetric and density measurements,
and flowmeters used to measure the quantities reported under this subpart, including the industry standard practice
or manufacturer directions used for calibration pursuant to § 98.154(p) and (q).

**§ 98.158 Definitions.**

All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.



### TABLE 

### O–1 TO 

### S UBPART 

### O OF 

### P ART 

### 98—E MISSION 

### FACTORS FOR 

### E QUIPMENT 

### L EAKS

Equipment type Service Emission factor (kg/hr/source)

≥ 10,000

ppmv <10,000

ppmv

Valves ............................................................................... Gas ....................................... ............................................ 0.0782 0.000131 Valves ............................................................................... Light liquid .............................. .......................................... 0.0892 0.000165 Pump seals ....................................................................... Light liquid .................................. ...................................... 0.243 0.00187 Compressor seals ............................................................. Gas ............................................... .................................... 1.608 0.0894
Pressure relief valves ....................................................... Gas ............................................... .................................... 1.691 0.0447
Connectors ........................................................................ All .......................................... ............................................ 0.113 0.0000810 Open-ended lines ............................................................. All ............................................... ....................................... 0.01195 0.00150

**Subpart P—Hydrogen Production**

**§ 98.160 Definition of the source category.**

(a) A hydrogen production source category consists of facilities that produce hydrogen gas sold as a product
to other entities.

(b) This source category comprises process units that produce hydrogen by reforming, gasification, oxidation, reaction, or other transformations of
feedstocks.

(c) 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.

**§ 98.161 Reporting threshold.**

You must report GHG emissions under this subpart if your facility contains a hydrogen production process and the facility meets the requirements of either § 98.2(a)(1) or (a)(2). **§ 98.162 GHGs to report.** You must report: (a) CO 2 process emissions from each hydrogen production process unit.

(b) CO 2 , CH 4 and N 2 O combustion emissions from each hydrogen production process unit. You must calculate and report these combustion emissions under subpart C of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart C.

(c) CO 2 , CH 4 , and N 2 O emissions from each stationary combustion unit other than hydrogen production process units. You must calculate and report these emissions under subpart C of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart C.

(d) For CO 2 collected and transferred off site, you must follow the requirements of subpart PP of this part.

**§ 98.163 Calculating GHG emissions.**

You must calculate and report the annual process CO 2 emissions from each hydrogen production process unit using the procedures specified in either paragraph (a) or (b) of this section.

(a) Continuous Emissions Montoring Systems (CEMS). Calculate and report under this subpart the process CO 2 emissions by operating and maintaining CEMS according to the Tier 4 Calculation Methodology specified in § 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources).

(b) Fuel and feedstock material balance approach. Calculate and report process CO 2 emissions as the sum of the
annual emissions associated with each fuel and feedstock used for hydrogen production by following paragraphs (b)(1) through (b)(3) of this section.

(1) Gaseous fuel and feedstock. You must calculate the annual CO 2 process emissions from gaseous fuel and feedstock according to Equation P–1 of
this section:



### CO Fdstk CC MW

MVC n n

nk

2

1 

### 44

12 0 001 = ∗ ∗∗

⎛

⎝ ⎜ ⎜ ⎞

⎠ ⎟ ⎟ ∗

= 

# ∑ . (. Eq P-1)

Where:

CO 2 = Annual CO 2 process emissions arising from fuel and feedstock consumption (metric tons/yr).
Fdstk

n = Volume of the gaseous fuel and feedstock used in month n (scf (at standard conditions of 68 ° F and atmospheric pressure) of fuel and feedstock).

CC

n = Average carbon content of the gaseous fuel and feedstock, from the results of one or more analyses for month n (kg carbon per kg of fuel and feedstock). MW = Molecular weight of the gaseous fuel and feedstock (kg/kg-mole).


### 56432 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

MVC = Molar volume conversion factor (849.5 scf per kg-mole at standard conditions). k = Months in the year. 44/12 = Ratio of molecular weights, CO 2 to carbon. 0.001 = Conversion factor from kg to metric tons.

(2) Liquid fuel and feedstock. You must calculate the annual CO 2 process emissions from liquid fuel and feedstock according to Equation P–2 of
this section:



### CO

n n 2

1 

### 0 001 2

= 44

12 P- )

nk 

### Fdstk CC

= 

# ∑ ∗ ∗ ⎛

⎝ ⎜ ⎜ ⎞

⎠ ⎟ ⎟ ∗ . (. Eq

Where:

CO 2 = Annual CO 2 emissions arising from fuel and feedstock consumption (metric tons/yr).

Fdstk

n = Volume of the liquid fuel and feedstock used in month n (gallons of fuel and feedstock). CC

n = Average carbon content of the liquid fuel and feedstock, from the results of one or more analyses for month n (kg carbon per gallon of fuel and feedstock). k = Months in the year. 44/12 = Ratio of molecular weights, CO 2 to
carbon. 0.001 = Conversion factor from kg to metric

tons.
(3) Solid fuel and feedstock. You must calculate the annual CO 2 process emissions from solid fuel and feedstock according to Equation P–3 of this

section:



### CO

n n 2

1 

### 0 001 3

= 44

12 P- )

nk 

### Fdstk CC

= 

# ∑ ∗ ∗ ⎛

⎝ ⎜ ⎜ ⎞

⎠ ⎟ ⎟ ∗ . (. Eq

Where:

CO 2 = Annual CO 2 emissions from fuel and feedstock consumption in metric tons per month (metric tons/yr).
Fdstk

n = Mass of solid fuel and feedstock used in month n (kg of fuel and feedstock).

CC

n = Average carbon content of the solid fuel and feedstock, from the results of one or more analyses for month n (kg carbon per kg of fuel and feedstock). k = Months in the year. 44/12 = Ratio of molecular weights, CO 2 to carbon. 0.001 = Conversion factor from kg to metric

tons. (c) If GHG emissions from a hydrogen production process unit are vented through the same stack as any combustion unit or process equipment that reports CO 2 emissions using a CEMS that complies with the Tier 4 Calculation Methodology in subpart C of this part (General Stationary Fuel Combustion Sources), then the calculation methodology in paragraph (b) of this section shall not be used to calculate process emissions. The owner or operator shall report under this subpart the combined stack emissions according to the Tier 4 Calculation Methodology in § 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources).

**§ 98.164 Monitoring and QA/QC requirements.** 

The GHG emissions data for hydrogen production process units must be quality-assured as specified in paragraphs (a) or (b) of this section, as appropriate for each process unit: (a) If a CEMS is used to measure GHG emissions, then the facility must comply with the monitoring and QA/QC procedures specified in § 98.34(c).

(b) If a CEMS is not used to measure GHG emissions, then you must:

(1) Calibrate all oil and gas flow meters (except for gas billing meters), solids weighing equipment, and oil tank drop measurements (if used to determine liquid fuel and feedstock use volume) according to the calibration accuracy requirements in § 98.3(i) of this part.

(2) Determine the carbon content and the molecular weight annually of standard gaseous hydrocarbon fuels and feedstocks having consistent composition (e.g., natural gas). For other gaseous fuels and feedstocks (e.g., biogas, refinery gas, or process gas), weekly sampling and analysis is required to determine the carbon content and molecular weight of the fuel
and feedstock.

(3) Determine the carbon content of fuel oil, naphtha, and other liquid fuels and feedstocks at least monthly, except annually for standard liquid hydrocarbon fuels and feedstocks having consistent composition, or upon delivery for liquid fuels delivered by bulk transport (e.g., by truck or rail).

(4) Determine the carbon content of coal, coke, and other solid fuels and feedstocks at least monthly, except annually for standard solid hydrocarbon fuels and feedstocks having consistent composition, or upon delivery for solid fuels delivered by bulk transport (e.g., by truck or rail). (5) You must use the following applicable methods to determine the
carbon content for all fuels and feedstocks, and molecular weight of gaseous fuels and feedstocks.

(i) ASTM D1945–03 Standard Test Method for Analysis of Natural Gas by Gas Chromatography (incorporated by reference, see § 98.7).

(ii) ASTM D1946–90 (Reapproved 2006), Standard Practice for Analysis of Reformed Gas by Gas Chromatography (incorporated by reference, see § 98.7).

(iii) ASTM D2013–07 Standard Practice of Preparing Coal Samples for Analysis (incorporated by reference, see § 98.7).

(iv) ASTM D2234/D2234M–07
Standard Practice for Collection of a Gross Sample of Coal (incorporated by reference, see § 98.7).

(v) ASTM D2597–94 (Reapproved 2004) Standard Test Method for Analysis of Demethanized Hydrocarbon Liquid Mixtures Containing Nitrogen and Carbon Dioxide by Gas Chromatography (incorporated by reference, see § 98.7).

(vi) ASTM D3176–89 (Reapproved 2002), Standard Practice for Ultimate Analysis of Coal and Coke (incorporated by reference, see § 98.7).

(vii) ASTM D3238–95 (Reapproved 2005), Standard Test Method for
Calculation of Carbon Distribution and Structural Group Analysis of Petroleum Oils by the n-d-M Method (incorporated by reference, see § 98.7).

(viii) ASTM D4057–06 Standard Practice for Manual Sampling of
Petroleum and Petroleum Products (incorporated by reference, see § 98.7).


### 56433 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

(ix) ASTM D4177–95 (Reapproved 2005) Standard Practice for Automatic Sampling of Petroleum and Petroleum Products (incorporated by reference, see § 98.7).

(x) ASTM D5291–02 (Reapproved 2007), Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants (incorporated by reference, see § 98.7).

(xi) ASTM D5373–08 Standard Test
Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal (incorporated by reference, see § 98.7).

(xii) ASTM D6609–08 Standard Guide for Part-Stream Sampling of Coal (incorporated by reference, see § 98.7).

(xiii) ASTM D6883–04 Standard Practice for Manual Sampling of Stationary Coal from Railroad Cars, Barges, Trucks, or Stockpiles (incorporated by reference, see § 98.7).

(xiv) ASTM D7430–08ae1 Standard Practice for Mechanical Sampling of Coal (incorporated by reference, see § 98.7).

(xv) ASTM UOP539–97 Refinery Gas Analysis by Gas Chromatography (incorporated by reference, see § 98.7).

(xvi) GPA 2261–00 Analysis for
Natural Gas and Similar Gaseous Mixtures by Gas Chromatography (incorporated by reference, see § 98.7).

(xvii) ISO 3170: Petroleum Liquids— Manual sampling—Third Edition (incorporated by reference, see § 98.7).

(xviii) ISO 3171: Petroleum Liquids— Automatic pipeline sampling—Second Edition (incorporated by reference, see § 98.7).

(c) For units using the calculation methodologies described in this section, the records required under § 98.3(g) must include both the company records and a detailed explanation of how company records are used to estimate the following:

(1) Fuel and feedstock consumption,
when solid fuel and feedstock is
combusted and a CEMS is not used to

measure GHG emissions.

(2) Fossil fuel consumption, when, pursuant to § 98.33(e), the owner or operator of a unit that uses CEMS to quantify CO 2 emissions and that combusts both fossil and biogenic fuels separately reports the biogenic portion
of the total annual CO 2 emissions.

(3) Sorbent usage, if the methodology in § 98.33(d) is used to calculate CO 2 emissions from sorbent.

(d) The owner or operator must document the procedures used to ensure the accuracy of the estimates of fuel and feedstock usage and sorbent usage (as applicable) in paragraph (b) of this section, including, but not limited to, calibration of weighing equipment, fuel and feedstock flow meters, and other
measurement devices. The estimated accuracy of measurements made with these devices must also be recorded,
and the technical basis for these estimates must be provided.

**§ 98.165 Procedures for estimating missing data.** 

A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable (e.g., if a meter malfunctions during unit operation), a substitute data value for the missing parameter must be used in the calculations as specified in paragraphs (a), (b), and (c) of this

section:

(a) For each missing value of the monthly fuel and feedstock consumption, the substitute data value
must be the best available estimate of the fuel and feedstock consumption, based on all available process data (e.g., hydrogen production, electrical load, and operating hours). You must document and keep records of the procedures used for all such estimates.

(b) For each missing value of the carbon content or molecular weight of the fuel and feedstock, the substitute
data value must be the arithmetic average of the quality-assured values of carbon contents or molecular weight of the fuel and feedstock immediately preceding and immediately followingthe missing data incident. If no qualityassured data on carbon contents or molecular weight of the fuel and feedstock are available prior to the missing data incident, the substitutedata value must be the first qualityassured value for carbon contents or molecular weight of the fuel and feedstock obtained after the missing data period. You must document and keep records of the procedures used for
all such estimates.

(c) For missing CEMS data, you must use the missing data procedures in § 98.35.

**§ 98.166 Data reporting requirements.**

In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) or (b) of this section, as appropriate:

(a) If a CEMS is used to measure CO 2 emissions, then you must report the relevant information required under § 98.36 for the Tier 4 Calculation Methodology and the following information in this paragraph (a):

(1) Unit identification number and
annual CO 2 process emissions. (2) Annual quantity of hydrogen produced (metric tons) for each process
unit and for all units combined.

(3) Annual quantity of ammonia produced (metric tons), if applicable, for each process unit and for all units
combined.

(b) If a CEMS is not used to measure

CO 2 emissions, then you must report the following information for each hydrogen production process unit:

(1) Unit identification number and
annual CO 2 process emissions.

(2) Monthly consumption of each fuel and feedstock used for hydrogen production and its type (scf of gaseous fuels and feedstocks, gallons of liquid fuels and feedstocks, kg of solid fuels and feedstocks).

(3) Annual quantity of hydrogen produced (metric tons).

(4) Annual quantity of ammonia produced, if applicable (metric tons).

(5) Monthly analyses of carbon
content for each fuel and feedstock used in hydrogen production (kg carbon/kg of gaseous and solid fuels and feedstocks, (kg carbon per gallon of liquid fuels and feedstocks).

(6) Monthly analyses of the molecular weight of gaseous fuels and feedstocks (kg/kg-mole) used, if any.

(c) Quarterly quantity of CO 2 collected and transferred off site in either gas, liquid, or solid forms (kg), following the requirements of subpart PP of this part.

(d) Annual quantity of carbon other
than CO 2 collected and transferred off site in either gas, liquid, or solid forms (kg carbon).

**§ 98.167 Records that must be retained.**

In addition to the information required by § 98.3(g), you must retain the records specified in paragraphs (a) through (b) of this section for each hydrogen production facility.

(a) If a CEMS is used to measure CO 2 emissions, then you must retain under this subpart the records required for the Tier 4 Calculation Methodology in § 98.37.

(b) If a CEMS is not used to measure

CO 2 emissions, then you must retain records of all analyses and calculations conducted as listed in §§ 98.166(b), (c), and (d).

**§ 98.168 Definitions.**

All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.

**Subpart Q—Iron and Steel Production**

**§ 98.170 Definition of the source category.**

The iron and steel production source category includes facilities with any of the following processes: taconite iron


### 56434 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

ore processing, integrated iron and steel manufacturing, cokemaking not colocated with an integrated iron and steel manufacturing process, and electric arc furnace (EAF) steelmaking not colocated 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.

**§ 98.171 Reporting threshold.**

You must report GHG emissions under this subpart if your facility contains an iron and steel production process and the facility meets the requirements of either § 98.2(a)(1) or (2).

**§ 98.172 GHGs to report.**

(a) You must report under subpart C of this part (General Stationary Fuel Combustion Sources) the emissions of

CO 2, CH 4 , and N 2 O from each stationary combustion unit following the requirements of subpart C except for flares. Stationary combustion unitsinclude, 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 other miscellaneous
combustion sources.

(b) You must report CO 2 emissions from flares according to the procedures in § 98.253(b)(1) of subpart Y (Petroleum Refineries) of this part except you must
use the default CO 2 emission factors for coke oven gas and blast furnace gas from Table C–1 of subpart C in Equation Y– 1 of subpart Y of this part. You must report CH 4 and N 2 O emissions from flares according to the requirements in § 98.33(c)(2) using the emission factors for coke oven gas and blast furnace gas in Table C–2 of subpart C of this part.

(c) You must report process CO 2 emissions from each taconite induratingfurnace; basic oxygen furnace; nonrecovery coke oven battery combustion stack; coke pushing process; sinter process; EAF; argon-oxygen decarburization vessel; and direct reduction furnace by following the procedures in this subpart.

**§ 98.173 Calculating GHG emissions.**

You must calculate and report the annual process CO 2 emissions from each taconite indurating furnace, basic oxygen furnace, non-recovery coke ovenbattery, sinter process, EAF, argonoxygen decarburization vessel, and direct reduction furnace using the procedures in either paragraph (a) or (b) of this section. Calculate and report the annual process CO 2 emissions from the coke pushing process according to paragraph (c) of this section.

(a) Calculate and report under this subpart the process CO 2 emissions by operating and maintaining CEMS according to the Tier 4 Calculation Methodology in § 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources).

(b) Calculate and report under this subpart the process CO 2 emissions using the procedure in paragraph (b)(1) or (b)(2) of this section.

(1) Carbon mass balance method.
Calculate the annual mass emissions of

CO 2 for the process as specified in paragraphs (b)(1)(i) through (b)(1)(vii) of
this section. The calculations are based on the annual mass of inputs and outputs to the process and an annual analysis of the respective weight
fraction of carbon as determined according to the procedures in § 98.174(b). If you have a process input or output other than CO 2 in the exhaust gas that contains carbon that is not included in Equations Q–1 through Q– 7 of this section, you must account for the carbon and mass rate of that process input or output in your calculations according to the procedures in § 98.174(b)(5).

(i) For taconite indurating furnaces,

estimate CO 2 emissions using Equation Q–1 of this section.

CO F F C MW

MVC F C s sf g gf l lf 2 44

12 0 001 0 0 = ∗ 

## ( ) ∗ 

# ( ) + 

# ( ) ∗ 

# ( ) ∗ ∗+ 

## ( ) ∗ 

# ( ) ∗ C . .0 01 + 

## ( ) ∗ 

## ( )

− 

## ( ) ∗ 

# ( ) − ∗ 

## ( ) ⎡
⎣ ⎢ ⎤
⎦ ⎥ OC PC o p ( ) R C R (Eq. Q-1)

Where:

CO 2 = Annual CO 2 mass emissions from the taconite indurating furnace (metric tons). 44/12 = Ratio of molecular weights, CO 2 to
carbon. (F

s ) = Annual mass of the solid fuel combusted (metric tons). (C sf) = Carbon content of the solid fuel, from the fuel analysis (percent by weight, expressed as a decimal fraction, e.g., 95% = 0.95). (F g ) = Annual volume of the gaseous fuel combusted (scf). (C gf) = Average carbon content of the gaseous fuel, from the fuel analysis results (kg C per kg of fuel). MW = Molecular weight of the gaseous fuel (kg/kg-mole).
MVC = Molar volume conversion factor (849.5 scf per kg-mole at standard conditions). 0.001 = Conversion factor from kg to metric

tons. (F l ) = Annual volume of the liquid fuel combusted (gallons). (C lf) = Carbon content of the liquid fuel, from the fuel analysis results (kg C per gallon of fuel). (O) = Annual mass of greenball (taconite) pellets fed to the furnace (metric tons). (C 0 ) = Carbon content of the greenball (taconite) pellets, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (P) = Annual mass of fired pellets produced by the furnace (metric tons). (C p ) = Carbon content of the fired pellets, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (R) = Annual mass of air pollution control residue collected (metric tons). (C R) = Carbon content of the air pollution control residue, from the carbon analysis results (percent by weight, expressed as a decimal fraction).

(ii) For basic oxygen process furnaces,

estimate CO 2 emissions using Equation Q–2 of this section.



### CO Iron Scrap C Flux C Iron Scrap Flux 2 

### 44

12 = ∗ 

## ( ) ∗ 

## ( ) + 

## ( ) ∗ 

# ( ) + 

## ( ) ∗ 

## ( ) C (Eq . Q- ) 2 ⎡ ⎣

+ 

## ( ) ∗ 

## ( )

− 

## ( ) ∗ 

## ( )

− 

## ( ) ∗ Carbon C Steel C Slag C Carbon Steel Slag 

# ( ) − ∗ 

## ( ) ⎤ ⎦ ( ) R C R


### 56435 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

Where:

CO 2 = Annual CO 2 mass emissions from the basic oxygen furnace (metric tons). 44/12 = Ratio of molecular weights, CO 2 to carbon. (Iron) = Annual mass of molten iron charged to the furnace (metric tons). (C Iron ) = Carbon content of the molten iron, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (Scrap) = Annual mass of ferrous scrap charged to the furnace (metric tons). (C Scrap ) = Carbon content of the ferrous scrap, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (Flux) = Annual mass of flux materials (e.g., limestone, dolomite) charged to the furnace (metric tons). (C Flux ) = Carbon content of the flux materials, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (Carbon) = Annual mass of carbonaceous materials (e.g., coal, coke) charged to the furnace (metric tons). (C Carbon ) = Carbon content of the carbonaceous materials, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (Steel) = Annual mass of molten raw steel produced by the furnace (metric tons). (C Steel ) = Carbon content of the steel, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (Slag) = Annual mass of slag produced by the furnace (metric tons). (C Slag ) = Carbon content of the slag, from the carbon analysis (percent by weight, expressed as a decimal fraction). (R) = Annual mass of air pollution control residue collected (metric tons). (C R) = Carbon content of the air pollution control residue, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (iii) For non-recovery coke oven batteries, estimate CO 2 emissions using Equation Q–3 of this section.



### CO Coal Coke C Coal Coke 2 

### 44

12 = ∗ 

## ( ) ∗ 

## ( )

− 

## ( ) ∗ 

## ( ) − ∗ 

## ( ) ⎡ ⎣ ⎤ ⎦ C RC R 

### () ( . Eq Q- 3)

Where:

CO 2 = Annual CO 2 mass emissions from the non-recovery coke oven battery (metric tons). 44/12 = Ratio of molecular weights, CO 2 to
carbon. (Coal) = Annual mass of coal charged to the battery (metric tons). (C Coal ) = Carbon content of the coal, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (Coke) = Annual mass of coke produced by the battery (metric tons). (C Coke ) = Carbon content of the coke, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (R) = Annual mass of air pollution control residue collected (metric tons). (C R) = Carbon content of the air pollution control residue, from the carbon analysis results (percent by weight, expressed as a decimal fraction).

(iv) For sinter processes, estimate CO 2 emissions using Equation Q–4 of this

section.



### CO F MW

MVC Feed C g gf Feed 2 

### 44

12 0 001 = ∗ 

# ( ) ∗ 

# ( ) ∗ ⎡ ⎣ ∗ + 

## ( ) ∗ 

## ( )

− 

## ( ) C . Sinter ∗ 

## ( ) − ∗ 

## ( ) ⎤ ⎦ C

Sinter 

### ( ) ( . R C R 

### Eq Q-4)

Where:

CO 2 = Annual CO 2 mass emissions from the sinter process (metric tons). 44/12 = Ratio of molecular weights, CO 2 to
carbon. (F g ) = Annual volume of the gaseous fuel combusted (scf). (C gf) = Carbon content of the gaseous fuel, from the fuel analysis results (kg C per kg of fuel). MW = Molecular weight of the gaseous fuel (kg/kg-mole). MVC = Molar volume conversion factor (849.5 scf per kg-mole at standard conditions). 0.001 = Conversion factor from kg to metric

tons. (Feed) = Annual mass of sinter feed material (metric tons). (C Feed) = Carbon content of the mixed sinter feed materials that form the bed entering the sintering machine, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (Sinter) = Annual mass of sinter produced (metric tons). (C Sinter) = Carbon content of the sinter pellets, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (R) = Annual mass of air pollution control residue collected (metric tons). (C R) = Carbon content of the air pollution control residue, from the carbon analysis results (percent by weight, expressed as a decimal fraction).

(v) For EAFs, estimate CO 2 emissions using Equation Q–5 of this section.



### CO Iron Scrap C Flux

C El Iron Scrap

f 2 

### 44

12 = ∗ 

## ( ) ∗ 

## ( ) + 

## ( ) ∗ 

# ( ) + 

## ( ) ⎡ ⎣

∗ 

# ( ) + C

e ctrode Carbon C Steel

C Electrode c

St 

## ( ) ∗ 

## ( ) + 

## ( ) ∗ 

## ( )

− 

## ( )

∗ C (Eq. Q- ) 5

e el Slag 

### Slag C 

## ( )

− 

## ( ) ∗ 

# ( ) − ∗ 

## ( ) ( ) R C R

Where:

CO 2 = Annual CO 2 mass emissions from the EAF (metric tons). 44/12 = Ratio of molecular weights, CO 2 to
carbon. (Iron) = Annual mass of direct reduced iron (if any) charged to the furnace (metric tons). (C Iron ) = Carbon content of the direct reduced iron, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (Scrap) = Annual mass of ferrous scrap charged to the furnace (metric tons). (C Scrap ) = Carbon content of the ferrous scrap, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (Flux) = Annual mass of flux materials (e.g., limestone, dolomite) charged to the furnace (metric tons). (C Flux ) = Carbon content of the flux materials, from the carbon analysis results (percent by weight, expressed as a decimal fraction).


### 56436 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

(Electrode) = Annual mass of carbon electrode consumed (metric tons). (C Electrode ) = Carbon content of the carbon electrode, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (Carbon) = Annual mass of carbonaceous materials (e.g., coal, coke) charged to the furnace (metric tons). (C Carbon ) = Carbon content of the carbonaceous materials, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (Steel) = Annual mass of molten raw steel produced by the furnace (metric tons). (C Steel ) = Carbon content of the steel, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (Slag) = Annual mass of slag produced by the furnace (metric tons). (C Slag ) = Carbon content of the slag, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (R) = Annual mass of air pollution control residue collected (metric tons). (C R) = Carbon content of the air pollution control residue, from the carbon analysis results (percent by weight, expressed as a decimal fraction).

(vi) For argon-oxygen decarburization vessels, estimate CO 2 emissions using Equation Q–6 of this section.



### CO Steel C Steelin Steelout 2 

### 44

12 = ∗ 

## ( ) ∗ 

## ( )

− 

## ( ) ⎡ ⎣ ⎤ ⎦ − ∗ 

## ( ) C RC R 

### () ( . Eq Q - ) 6

Where:

CO 2 = Annual CO 2 mass emissions from the argon-oxygen decarburization vessel (metric tons). 44/12 = Ratio of molecular weights, CO 2 to
carbon. (Steel) = Annual mass of molten steel charged to the vessel (metric tons). (C Steelin ) = Carbon content of the molten steel before decarburization, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (C Steelout) = Carbon content of the molten steel after decarburization, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (R) = Annual mass of air pollution control residue collected (metric tons). (C R) = Carbon content of the air pollution control residue, from the carbon analysis results (percent by weight, expressed as a decimal fraction).

(vii) For direct reduction furnaces,

estimate CO 2 emissions using Equation Q–7 of this section.



### CO F C MW

MVC Ore C g gf Ore 2 

### (Eq. Q-7)

= ∗ 

# ( ) ∗ 

# ( ) ∗ ∗+ 

## ( ) ∗ ⎡
⎣ ⎢

+ 44

12 0 001 . ()

( (

( ( Carbon C Other C

Iron C NM Carbon Other

Iron 

### ) )

) ∗ 

## ( ) + ∗ 

## ( )

− 

## ( ) − ∗

) C RC

NM R 

## ( ) − ∗ 

## ( ) ⎤ ⎦ ( )

Where:

CO 2 = Annual CO 2 mass emissions from the direct reduction furnace (metric tons). 44/12 = Ratio of molecular weights, CO 2 to carbon. (F g ) = Annual volume of the gaseous fuel combusted (scf). (C gf) = Carbon content of the gaseous fuel, from the fuel analysis results (kg C per kg of fuel). MW = Molecular weight of the gaseous fuel (kg/kg-mole).
MVC = Molar volume conversion factor (849.5 scf per kg-mole at standard conditions). 0.001 = Conversion factor from kg to metric

tons. (Ore) = Annual mass of iron ore or iron ore pellets fed to the furnace (metric tons). (C Ore ) = Carbon content of the iron ore or iron ore pellets, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (Carbon) = Annual mass of carbonaceous materials (e.g., coal, coke) charged to the furnace (metric tons). (C Carbon ) = Carbon content of the carbonaceous materials, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (Other) = Annual mass of other materials charged to the furnace (metric tons). (C Other) = Average carbon content of the other materials charged to the furnace, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (Iron) = Annual mass of iron produced (metric tons). (C Iron ) = Carbon content of the iron, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (NM) = Annual mass of non-metallic materials produced by the furnace (metric tons). (C NM ) = Carbon content of the non-metallic materials, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (R) = Annual mass of air pollution control residue collected (metric tons). (C R) = Carbon content of the air pollution control residue, from the carbon analysis results (percent by weight, expressed as a decimal fraction).

(2) Site-specific emission factor
method. Conduct a performance test and

measure CO 2 emissions from all exhaust stacks for the process and measure
either the feed rate of materials into the process or the production rate during the test as described in paragraphs (b)(2)(i) through (b)(2)(iv) of this section.

(i) You must measure the process production rate or process feed rate, as applicable, during the performance test according to the procedures in § 98.174(c)(5) and calculate the average rate for the test period in metric tons per
hour.

(ii) You must calculate the hourly CO 2 emission rate using Equation Q–8 of this section and determine the average hourly CO 2 emission rate for the test.



### CO C H O

CO 2 7 2 

### 5 18 10 100

100 = − ⎛ ⎝ ⎜ ⎞ ⎠ ⎟ −



### . % x (Eq. Q-8)2 

### Q

Where: CO 2 = CO 2 mass emission rate, corrected for moisture (metric tons/hr). 5.18 × 10

¥ 7 = Conversion factor (metric tons/
scf

¥ % CO 2 ).


### 56437 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

C CO2 = Hourly CO 2 concentration, dry basis (% CO 2 ). Q = Hourly stack gas volumetric flow rate (scfh). %H 2 O = Hourly moisture percentage in the stack gas.
(iii) You must calculate a site-specific emission factor for the process in metric
tons of CO 2 per metric ton of feed or production, as applicable, by dividing the average hourly CO 2 emission rate during the test by the average hourly feed or production rate during the test.

(iv) You must calculate CO 2 emissions for the process by multiplying the emission factor by the total amount of feed or production, as applicable, for the reporting period.

(c) You must determine emissions of

CO 2 from the coke pushing process in

mtCO 2 e by multiplying the metric tons of coal charged to the coke ovens during the reporting period by 0.008.

(d) If GHG emissions from a taconite indurating furnace, basic oxygen furnace, non-recovery coke oven battery, sinter process, EAF, argon-oxygen decarburization vessel, or direct reduction furnace are vented through the same stack as any combustion unit or process equipment that reports CO 2 emissions using a CEMS that complies
with the Tier 4 Calculation Methodology in subpart C of this part (General Stationary Fuel Combustion Sources), then the calculation methodology in paragraph (b) of this
section shall not be used to calculate process emissions. The owner or operator shall report under this subpart the combined stack emissions according to the Tier 4 Calculation Methodology in § 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources).

**§ 98.174 Monitoring and QA/QC requirements.** 

(a) If you operate and maintain a
CEMS that measures CO 2 emissions consistent with subpart C of this part, you must meet the monitoring and QA/ QC requirements of § 98.34(c).

(b) If you determine CO 2 emissions using the carbon mass balance procedure in § 98.173(b)(1), you must:

(1) Except as provided in paragraph (b)(4) of this section, determine the mass of each process input and output other than fuels using the same plant instruments or procedures that are used for accounting purposes (such as weigh hoppers, belt weigh feeders, weighed purchased quantities in shipments or containers, combination of bulk density and volume measurements, etc.), record the totals for each process input and output for each calendar month, and sum the monthly mass to determine the annual mass for each process input and output. Determine the mass rate of fuels using the procedures for combustion units in § 98.34.

(2) Except as provided in paragraph (b)(4) of this section, determine the carbon content of each process input and output annually for use in the applicable equations in § 98.173(b)(1) based on analyses provided by the supplier or by the average carbon content determined by collecting and analyzing at least three samples each year using the standard methods specified in paragraphs (b)(2)(i) through (b)(2)(vi) of this section as applicable.

(i) ASTM C25–06, Standard Test Methods for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime (incorporated by reference, see § 98.7) for limestone, dolomite, and slag.

(ii) ASTM D5373–08 Standard Test
Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal (incorporated by reference, see § 98.7) for coal, coke, and other carbonaceous
materials.

(iii) ASTM E1915–07a, Standard Test Methods for Analysis of Metal Bearing Ores and Related Materials by Combustion Infrared-Absorption Spectrometry (incorporated by reference, see § 98.7) for iron ore, taconite pellets, and other iron-bearing
materials.

(iv) ASTM E1019–08, Standard Test Methods for Determination of Carbon, Sulfur, Nitrogen, and Oxygen in Steel, Iron, Nickel, and Cobalt Alloys by
Various Combustion and Fusion Techniques (incorporated by reference,

see § 98.7) for iron and ferrous scrap.

(v) ASM CS–104 UNS No. G10460— Alloy Digest April 1985 (Carbon Steel of Medium Carbon Content) (incorporated by reference, see § 98.7); ISO/TR 15349– 1:1998, Unalloyed steel—Determination of low carbon content, Part 1: Infrared absorption method after combustion in an electric resistance furnace (by peak separation) (1998–10–15) First Edition (incorporated by reference, see § 98.7); or ISO/TR 15349–3:1998, Unalloyed
steel-Determination of low carbon content Part 3: Infrared absorption
method after combustion in an electric resistance furnace (with preheating) (1998–10–15) First Edition (incorporated by reference, see § 98.7) as applicable for steel.

(vi) For each process input that is a fuel, determine the carbon content and molecular weight (if applicable) using the applicable methods listed in § 98.34.

(3) For solid ferrous materials charged to basic oxygen process furnaces or EAFs that differ in carbon content, you may determine a weighted average
carbon content based on the carbon content of each type of ferrous material and the average weight percent of each type that is used. Examples of these
different ferrous materials include carbon steel, low carbon steel, stainless steel, high alloy steel, pig iron, iron scrap, and direct reduced iron.

(4) If you document that a specific process input or output contributes less than one percent of the total mass of carbon into or out of the process, you do not have to determine the monthly mass or annual carbon content of that input or output.

(5) Except as provided in paragraph (b)(4) of this section, you must
determine the annual carbon content and monthly mass rate of any input or output that contains carbon that is not listed in the equations in § 98.173(b)(1) using the procedures in paragraphs (b)(1) and (b)(2) of this section.

(c) If you determine CO 2 emissions using the site-specific emission factor procedure in § 98.173(b)(2), you must:

(1) Conduct an annual performance test that is based on representative performance (i.e., performance based on normal operating conditions) of the affected process.

(2) For the furnace exhaust from basic oxygen furnaces, EAFs, argon-oxygen decarburization vessels, and direct reduction furnaces, sample the furnace exhaust for at least three complete production cycles that start when the furnace is being charged and end after steel or iron and slag have been tapped. For EAFs that produce both carbon steel and stainless or specialty (low carbon) steel, develop an emission factor for the production of both types of steel.

(3) For taconite indurating furnaces, non-recovery coke batteries, and sinter processes, sample for at least 3 hours.

(4) Conduct the stack test using EPA Method 3A at 40 CFR part 60, appendix
A–2 to measure the CO 2 concentration, Method 2, 2A, 2C, 2D, or 2F at 40 CFR part 60, appendix A–1 or Method 26 at 40 CFR part 60, appendix A–2 to determine the stack gas volumetric flow rate, and Method 4 at 40 CFR part 60, at appendix A–3 to determine the moisture content of the stack gas.

(5) Determine the mass rate of process feed or process production (as applicable) during the test using the same plant instruments or procedures that are used for accounting purposes (such as weigh hoppers, belt weigh feeders, combination of bulk density and volume measurements, etc.)

(6) If your process operates under different conditions as part of normal operations in such a manner that CO 2 emissions change by more than 20


### 56438 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

percent (e.g., routine changes in the
carbon content of the sinter feed or change in grade of product), you must perform emission testing and develop separate emission factors for these different operating conditions and
determine emissions based on the number of hours the process operates and the production or feed rate (as applicable) at each specific different
condition.

(7) If your EAF and argon-oxygen
decarburization vessel exhaust to a
common emission control device and stack, you must sample each process in
the ducts before the emissions are combined, sample each process when only one process is operating, or sample
the combined emissions when both processes are operating and base the site-specific emission factor on the steel production rate of the EAF.

(8) The results of a performance test must include the analysis of samples, determination of emissions, and raw data. The performance test report must
contain all information and data used to
derive the emission factor.

(d) For a coke pushing process,
determine the metric tons of coal charged to the coke ovens and record the totals for each pushing process for each calendar month. Coal charged to coke ovens can be measured using weigh belts or a combination of measuring volume and bulk density.

**§ 98.175 Procedures for estimating missing data.** 

A complete record of all measured parameters used in the GHG emissions calculations in § 98.173 is required. Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter shall be used in the calculations as specified in the paragraphs (a) and (b) of this section. You must document and keep records of the procedures used for all such

estimates.

(a) For each missing data for the carbon content of inputs and outputs for facilities that estimate emissions using the carbon mass balance procedure in § 98.173(b)(1) or for facilities thatestimate emissions using the sitespecific emission factor procedure in § 98.173(b)(2); 100 percent data availability is required. You must repeat the test for average carbon contents of inputs and outputs according to the procedures in § 98.174(b)(2). Similarly, you must repeat the test to determine the site-specific emission factor if data
on the CO 2 emission rate, process production rate or process feed rate are missing. (b) For missing records of the monthly mass or volume of carbon-containing inputs and outputs using the carbon mass balance procedure in § 98.173(b)(1), the substitute data value
must be based on the best available estimate of the mass of the input or output material from all available process data or data used for accounting

purposes.

**§ 98.176 Data reporting requirements.**

In addition to the information required by § 98.3(c), each annual report must contain the information required in paragraphs (a) through (f) of this section for each coke pushing operation; taconite indurating furnace; basic oxygen furnace; non-recovery coke ovenbattery; sinter process; EAF; argonoxygen decarburization vessel; and
direct reduction furnace:

(a) Unit identification number and
annual CO 2 emissions (in metric tons).

(b) Annual production quantity (in metric tons) for taconite pellets, coke, sinter, iron, and raw steel.

(c) If a CEMS is used to measure CO 2 emissions, then you must report the relevant information required under § 98.37 for the Tier 4 Calculation Methodology.

(d) If a CEMS is not used to measure

CO 2 emissions, then you must report for each process whether the emissions were determined using the carbon mass balance method in § 98.173(b)(1) or the site-specific emission factor method in § 98.173(b)(2).

(e) If you use the carbon mass balance method in § 98.173(b)(1) to determine

CO 2 emissions, you must report the following information for each process:

(1) The carbon content of each process input and output used to determine CO 2 emissions.

(2) Whether the carbon content was
determined from information from the supplier or by laboratory analysis, and if by laboratory analysis, the method
used.

(3) The annual volume of gaseous fuel (in standard cubic feet), the annual volume of liquid fuel (in gallons), and the annual mass (in metric tons) of all other process inputs and outputs used
to determine CO 2 emissions.

(4) The molecular weight of gaseous
fuels.

(5) If you used the missing data procedures in § 98.175(b), you must report how the monthly mass for each process input or output with missing
data was determined and the number of months the missing data procedures
were used.

(f) If you used the site-specific emission factor method in § 98.173(b)(2)
to determine CO 2 emissions, you must report the following information for each process:

(1) The measured average hourly CO 2 emission rate during the test (in metric tons per hour).

(2) The average hourly feed or production rate (as applicable) during the test (in metric tons per hour).

(3) The site-specific emission factor (in metric tons of CO 2 per metric ton of feed or production, as applicable).

(4) The annual feed or production rate (as applicable) used to estimate annual

CO 2 emissions (in metric tons).

**§ 98.177 Records that must be retained.**

In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) through (e) of this section, as applicable. Facilities that

use CEMS to measure emissions must
also retain records of the verification data required for the Tier 4 Calculating Methodology in § 98.36(e).

(a) Records of all analyses and calculations conducted, including all information reported as required under § 98.176.

(b) When the carbon mass balance
method is used to estimate emissions for a process, the monthly mass of each process input and output that are used
to determine the annual mass.

(c) Production capacity (in metric tons per year) for the production of taconite pellets, coke, sinter, iron, and raw steel.

(d) Annual operating hours for taconite furnaces, coke oven batteries, sinter production, blast furnaces, direct reduced iron furnaces, and electric arc
furnaces.

(e) Facilities must keep records that include a detailed explanation of how company records or measurements are
used to determine all sources of carbon input and output and the metric tons of coal charged to the coke ovens (e.g., weigh belts, a combination of measuring volume and bulk density). You also must document the procedures used to ensure the accuracy of the measurements of fuel usage including, but not limited to, calibration of weighing equipment, fuel flow meters, coal usage including, but not limited to, calibration of weighing equipment and
other measurement devices. The estimated accuracy of measurements
made with these devices must also be recorded, and the technical basis for these estimates must be provided.

**§ 98.178 Definitions.**

All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.


### 56439 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

**Subpart R—Lead Production**

**§ 98.180 Definition of the source category.**

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. 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.

**§ 98.181 Reporting threshold.**

You must report GHG emissions under this subpart if your facility contains a lead production process and the facility meets the requirements of either § 98.2(a)(1) or (a)(2).

**§ 98.182 GHGs to report.**

You must report: (a) Process CO 2 emissions from each smelting furnace used for lead production.

(b) CO 2 combustion emissions from each smelting furnace used for lead production.

(c) CH 4 and N 2 O combustion emissions from each smelting furnace used for lead production. You must calculate and report these emissions under subpart C of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart C.

(d) CO 2 , CH 4 , and N 2 O emissions from each stationary combustion unit other than smelting furnaces used for lead production. You must report these emissions under subpart C of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart C.

**§ 98.183 Calculating GHG emissions.**

You must calculate and report the annual process CO 2 emissions from each smelting furnace using the procedure in paragraphs (a) and (b) of this section.

(a) For each smelting furnace that meets the conditions specified in § 98.33(b)(4)(ii) or (b)(4)(iii), you must calculate and report combined process
and combustion CO 2 emissions by operating and maintaining a CEMS to

measure CO 2 emissions according to the Tier 4 Calculation Methodology specified in § 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources).

(b) For each smelting furnace that is not subject to the requirements in paragraph (a) of this section, calculate and report the process and combustion CO 2 emissions from the smelting furnace by using the procedure in either paragraph (b)(1) or (b)(2) of this section.

(1) Calculate and report under this subpart the combined process and
combustion CO 2 emissions by operating and maintaining a CEMS to measure

CO 2 emissions according to the Tier 4 Calculation Methodology specified in § 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources).

(2) Calculate and report process and
combustion CO 2 emissions separately using the procedures specified in paragraphs (b)(2)(i) through (b)(2)(iii) of
this section.

(i) For each smelting furnace,
determine the annual mass of carbon in each carbon-containing material, other than fuel, that is fed, charged, or otherwise introduced into the smelting furnace and estimate annual process

CO 2 emissions using Equation R–1 of this section. Carbon-containing
materials include carbonaceous reducing agents. If you document that a specific material contributes less than 1 percent of the total carbon into the process, you do not have to include the material in your calculation using Equation R–1 of this section.



### E 2000

2205 CO2 

### 44

12 =× × × 

## ( ) + × 

# ( ) + × 

## ( ) + Ore C Scrap C Flux C Ore Scrap Flux 

### C arbon C Other C Carbon Other 

### × 

## ( ) + × 

## ( ) ⎡ ⎣ ⎤ ⎦ (Eq. R-1)

Where:

E CO2 = Annual process CO 2 emissions from an individual smelting furnace (metric tons). 44/12 = Ratio of molecular weights, CO 2 to carbon.
2000/2205 = Conversion factor to convert

tons to metric tons. Ore = Annual mass of lead ore charged to the smelting furnace (tons).

C Ore = Carbon content of the lead ore, from the carbon analysis results (percent by weight, expressed as a decimal fraction). Scrap = Annual mass of lead scrap charged to the smelting furnace (tons).

C Scrap = Carbon content of the lead scrap, from the carbon analysis (percent by weight, expressed as a decimal fraction). Flux = Annual mass of flux materials (e.g., limestone, dolomite) charged to the smelting furnace (tons).

C Flux = Carbon content of the flux materials, from the carbon analysis (percent by weight, expressed as a decimal fraction).
Carbon = Annual mass of carbonaceous materials (e.g., coal, coke) charged to the smelting furnace (tons).

C Carbon = Carbon content of the carbonaceous materials, from the carbon analysis (percent by weight, expressed as a decimal fraction). Other = Annual mass of any other material containing carbon, other than fuel, fed, charged, or otherwise introduced into the smelting furnace (tons).

C Other = Carbon content of the other material from the carbon analysis results (percent by weight, expressed as a decimal fraction).

(ii) Determine the combined annual process CO 2 emissions from the smelting furnaces at your facility using Equation R–2 of this section.



### CO = E (Eq. R-2) 2 CO2

1 k

k 

# ∑

Where:

CO 2 = Annual process CO 2 emissions from smelting furnaces at facility used for lead production (metric tons).

E CO2k = Annual process CO 2 emissions from smelting furnace k calculated using Equation R–1 of this section (metric tons/year). k = Total number of smelting furnaces at facility used for lead production.
(iii) Calculate and report under subpart C of this part (General Stationary Fuel Combustion Sources) the combustion CO 2 emissions from the smelting furnaces according to the applicable requirements in subpart C.

**§ 98.184 Monitoring and QA/QC requirements.** 

If you determine process CO 2 emissions using the carbon mass balance procedure in § 98.183(b)(2)(i) and (b)(2)(ii), you must meet the requirements specified in paragraphs (a) and (b) of this section.

(a) Determine the annual mass for
each material used for the calculations of annual process CO 2 emissions using Equation R–1 of this subpart by summing the monthly mass for the
material determined for each month of the calendar year. The monthly mass may be determined using plant instruments used for accounting purposes, including either direct measurement of the quantity of the material placed in the unit or by calculations using process operating
information.

(b) For each material identified in paragraph (a) of this section, you must determine the average carbon content of


### 56440 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

the material consumed or used in the calendar year using the methods specified in either paragraph (b)(1) or (b)(2) of this section. If you document that a specific process input or output contributes less than one percent of the
total mass of carbon into or out of the process, you do not have to determine the monthly mass or annual carbon content of that input or output.

(1) Information provided by your material supplier.

(2) Collecting and analyzing at least three representative samples of the material each year. The carbon content of the material must be analyzed at least annually using the methods (and their QA/QC procedures) specified in paragraphs (b)(2)(i) through (b)(2)(iii) of this section, as applicable.

(i) ASTM E1941–04, Standard Test
Method for Determination of Carbon in Refractory and Reactive Metals and Their Alloys (incorporated by reference, see § 98.7) for analysis of metal ore and alloy product.

(ii) ASTM D5373–08 Standard Test
Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal (incorporated by reference, see § 98.7), for analysis of carbonaceous reducing agents and carbon electrodes.

(iii) ASTM C25–06, Standard Test Methods for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime (incorporated by reference, see § 98.7) for analysis of flux materials
such as limestone or dolomite.

**§ 98.185 Procedures for estimating missing data.** 

A complete record of all measured parameters used in the GHG emissions calculations in § 98.183 is required. Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter shall be used in the calculations as specified in the paragraphs (a) and (b) of this section. You must document and keep records of the procedures used for all such

estimates.

(a) For each missing data for the carbon content for the smelting furnaces at your facility that estimate annual process CO 2 emissions using the carbon mass balance procedure in § 98.183(b)(2)(i) and (ii), 100 percent data availability is required. You must repeat the test for average carbon contents of inputs according to the procedures in § 98.184(b) if data are missing.

(b) For missing records of the monthly mass of carbon-containing materials, the
substitute data value must be based the
best available estimate of the mass of the material from all available process data or data used for accounting purposes (such as purchase records).

**§ 98.186 Data reporting procedures.**

In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) or (b) of this section, as applicable.

(a) If a CEMS is used to measure CO 2 emissions according to the requirements in § 98.183(a) or (b)(1), then you must report under this subpart the relevant information required by § 98.36 and the information specified in paragraphs (a)(1) through (a)(4) of this section.

(1) Identification number of each smelting furnace.

(2) Annual lead product production capacity (tons).

(3) Annual production for each lead product (tons).

(4) Total number of smelting furnaces at facility used for lead production.

(b) If a CEMS is not used to measure

CO 2 emissions, and you measure CO 2 emissions according to the requirements in § 98.183(b)(2)(i) and (b)(2)(ii), then you must report the information specified in paragraphs (b)(1) through (b)(9) of this section.

(1) Identification number of each smelting furnace. (2) Annual process

CO 2 emissions (in metric tons) from each smelting furnace as determined by Equation R–1 of this subpart.

(3) Annual lead product production capacity for the facility and each smelting furnace(tons).

(4) Annual production for each lead product (tons).

(5) Total number of smelting furnaces at facility used for production of lead products reported in paragraph (b)(4) of
this section.

(6) Annual material quantity for each
material used for the calculation of annual process CO 2 emissions using Equation R–1 of this subpart for each smelting furnace (tons).

(7) Annual average of the carbon
content determinations for each material
used for the calculation of annual process CO 2 emissions using Equation R–1 of this subpart for each smelting
furnace.

(8) List the method used for the
determination of carbon content for each material reported in paragraph (b)(7) of this section (e.g., supplier provided information, analyses of representative samples you collected).

(9) If you use the missing data procedures in § 98.185(b), you mustreport how the monthly mass of carboncontaining materials with missing data
was determined and the number of months the missing data procedures
were used. **§ 98.187 Records that must be retained.** In addition to the records required by § 98.3(g), each annual report must contain the information specified in paragraphs (a) through (c) of this section, as applicable to the smelting furnaces at your facility.

(a) If a CEMS is used to measure combined process and combustion CO 2 emissions according to the requirements in § 98.183(a) or (b)(1), then you must retain the records required for the Tier 4 Calculation Methodology in § 98.37 and the information specified in paragraphs (a)(1) through (a)(3) of this

section.

(1) Monthly smelting furnace production quantity for each lead product (tons).

(2) Number of smelting furnace operating hours each month.

(3) Number of smelting furnace operating hours in calendar year.

(b) If the carbon mass balance procedure is used to determine process

CO 2 emissions according to the requirements in § 98.183(b)(2)(i) and (b)(2)(ii), then you must retain under this subpart the records specified in paragraphs (b)(1) through (b)(5) of this

section.

(1) Monthly smelting furnace production quantity for each lead product (tons).

(2) Number of smelting furnace operating hours each month.

(3) Number of smelting furnace operating hours in calendar year.

(4) Monthly material quantity consumed, used, or produced for each
material included for the calculations of annual process CO 2 emissions using Equation R–1 of this subpart (tons).

(5) Average carbon content determined and records of the supplier provided information or analyses used
for the determination for each material
included for the calculations of annual process CO 2 emissions using Equation R–1 of this subpart.

(c) You must keep records that include a detailed explanation of how company records of measurements are used to estimate the carbon input to each smelting furnace, including documentation of any materials excluded from Equation R–1 of this subpart that contribute less than 1 percent of the total carbon into or out of the process. You also must document the procedures used to ensure the accuracy of the measurements of materials fed, charged, or placed in an smelting furnace including, but not limited to, calibration of weighing equipment and other measurement devices. The estimated accuracy of
measurements made with these devices must also be recorded, and the technical


### 56441 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

basis for these estimates must be provided.

**§ 98.188 Definitions.**

All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.

**Subpart S—Lime Manufacturing**

**§ 98.190 Definition of the source category.**

(a) Lime manufacturing plants (LMPs) engage in the manufacture of a limeproduct (e.g., calcium oxide, highcalcium quicklime, calcium hydroxide, hydrated lime, dolomitic quicklime, dolomitic hydrate, or other products) by calcination of limestone, dolomite,
shells or other cacareous substances as defined in 40 CFR 63.7081(a)(1).

(b) 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. The lime manufacturing source category consists
of marketed and non-marketed lime manufacturing facilities.

(c) Lime kilns at pulp and paper manufacturing facilities must report emissions under subpart AA of this part (Pulp and Paper Manufacturing).

**§ 98.191 Reporting threshold.**

You must report GHG emissions under this subpart if your facility is a lime manufacturing plant as defined in § 98.190 and the facility meets the requirements of either § 98.2(a)(1) or (a)(2).

**§ 98.192 GHGs to report.**

You must report: (a) CO 2 process emissions from lime
kilns.

(b) CO 2 emissions from fuel
combustion at lime kilns.

(c) N 2 O and CH 4 emissions from fuel
combustion at each lime kiln. You must report these emissions under 40 CFR part 98, subpart C (General Stationary Fuel Combustion Sources).

(d) CO 2 , N 2 O, and CH 4 emissions from each stationary fuel combustion unit other than lime kilns. You must report these emissions under 40 CFR part 98, subpart C (General Stationary Fuel Combustion Sources).

(e) CO 2 collected and transferred off site under 40 CFR part 98, following the requirements of subpart PP of this part (Suppliers of Carbon Dioxide (CO 2 )).

**§ 98.193 Calculating GHG emissions.**

You must calculate and report the annual process CO 2 emissions from all lime kilns combined using the procedure in paragraphs (a) and (b) of
this section.

(a) If all lime kilns meet the conditions specified in § 98.33(b)(4)(ii) or (b)(4)(iii), you must calculate and report under this subpart the combined process and combustion CO 2 emissions by operating and maintaining a CEMS to

measure CO 2 emissions according to the Tier 4 Calculation Methodology specified in § 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources).

(b) If CEMS are not required to be
used to determine CO 2 emissions from all lime kilns under paragraph (a) of this section, then you must calculate and report the process and combustion CO 2 emissions from the lime kilns by using the procedures in either paragraph (b)(1) or (b)(2) of this section.

(1) Calculate and report under this subpart the combined process and
combustion CO 2 emissions by operating and maintaining a CEMS to measure

CO 2 emissions from all lime kilns according to the Tier 4 Calculation Methodology specified in § 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources).

(2) Calculate and report process and
combustion CO 2 emissions separately using the procedures specified in paragraphs (b)(2)(i) through (b)(2)(v) of
this section.

(i) You must calculate a monthly emission factor for each type of lime produced using Equation S–1 of this section. Calcium oxide and magnesium oxide content must be analyzed monthly for each lime type:



### EF SR CaO SR MgO LIME,i,n CaO i,n MgO i,n 

### = ∗ 

# ( ) ∗ 

# ( ) ⎡ ⎣ ⎤ ⎦ ∗ + ( 2000

2205 E q. S-1)

Where:

EF LIME,i,n = Emission factor for lime type i, for month n (metric tons CO 2 /ton lime).

SRCaO = Stoichiometric ratio of CO 2 and CaO for calcium carbonate [see Table S–1 of this subpart] (metric tons CO 2 /metric tons CaO).

SRMgO = Stoichiometric ratio of CO 2 and MgO for magnesium carbonate (See Table S– 1 of this subpart) (metric tons CO 2 /metric tons MgO).

CaO i,n = Calcium oxide content for lime type i, for month n, determined according to § 98.194(c) (metric tons CaO/metric ton lime). MgO i,n = Magnesium oxide content for lime type i, for month n, determined according to § 98.194(c) (metric tons MgO/metric ton lime). 2000/2205 = Conversion factor for metric

tons to tons.

(ii) You must calculate a monthly emission factor for each type of byproduct/waste sold (including lime kiln dust) using Equation S–2
of this section:



### EF SR CaO SR MgO LKD,i,n CaO LKD,i,n MgO LKD,i,n 

### = ∗ 

# ( ) ∗ 

# ( ) ⎡ ⎣ ⎤ ⎦ ∗ + 20 0 0

2205 (Eq. S-2)

Where:

EF LKD,i,n = Emission factor for sold lime byproduct/waste type i, for month n (metric tons CO 2 /ton lime byproduct).

SRCaO = Stoichiometric ratio of CO 2 and CaO for calcium carbonate (see Table S–1 of this subpart((metric tons CO 2 /metric tons CaO).

SRMgO = Stoichiometric ratio of CO 2 and MgO for magnesium carbonate (See Table S– 1 of this subpart) (metric tons CO 2 /metric tons MgO).

CaO LKD,i,n = Calcium oxide content for sold lime byproduct/waste type i, for month n (metric tons CaO/metric ton lime). MgO LKD,i,n = Magnesium oxide content for sold lime byproduct/waste type i, for month n (metric tons MgO/metric ton lime). 2000/2205 = Conversion factor for metric

tons to tons.

(iii) You must calculate the annual

CO 2 emissions from each type of byproduct/waste that is not sold (including lime kiln dust and scrubber sludge) using Equation S–3 of this

section:


### 56442 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

E SR CaO SR MgO M

waste,i CaO waste,i MgO waste,i w 

### = ∗ 

# ( ) ∗ 

# ( ) ⎡ ⎣ ⎤ ⎦ ∗ +
a ste,i 

### ∗ 2000

2205 (Eq. S-3)

Where:

E waste,i = Annual CO 2 emissions for unsold lime byproduct/waste type i (metric tons

CO 2 ).

SRCaO = Stoichiometric ratio of CO 2 and CaO for calcium carbonate (see Table S–1 of this subpart) (metric tons CO 2 /metric tons CaO). SRMgO = Stoichiometric ratio of CO 2 and MgO for magnesium carbonate (See Table S– 1 of this subpart) (metric tons CO 2 /metric tons MgO).

CaO waste,i = Calcium oxide content for unsold lime byproduct/waste type i (metric tons CaO/metric ton lime). MgO waste,i = Magnesium oxide content for unsold lime byproduct/waste type i (metric tons MgO/metric ton lime). M waste,i = Annual weight or mass of unsold byproducts/wastes for lime type i (tons).

2000/2205 = Conversion factor for metric

tons to tons.

(iv) You must calculate annual CO 2 process emissions for all kilns using Equation S–4 of this section:



### E EF M EF M

CO LIME,i,n LIME,i,n LKD,i,n LKD,i,n

n i b

2 1 12

1 

### ∗ 

# ( ) + ∗ 

# )

= = 

# ∑ ∑ ∑ ∑ ∑ +

= = = 

### E waste,i

i z

n i t

1 1 12

1 

### (Eq. S-4)

Where:

E CO2 = Annual CO 2 process emissions from lime production from all kilns (metric tons/year).

EF LIME,i,n = Emission factor for lime type i, in calendar month n (metric tons CO 2 /ton lime) from Equation S–1 of this section.

MLIME,i,n = Weight or mass of lime type i in calendar month n (tons).

EF LKD,i,n = Emission factor of byproducts/ wastes sold for lime type i in calendar month n, (metric tons CO 2 /ton byproduct/waste) from Equation S–2 of
this section.

MLKD,i,n = Monthly weight or mass of byproducts/waste sold (such as lime kiln dust, LKD) for lime type i in calendar month n (tons).

E waste,i = Annual CO 2 emissions for unsold lime byproduct/waste type i (metric tons

CO 2 ) from Equation S–3 of this section. t = Number of lime types b = Number of byproducts/wastes sold z = Number of byproducts/wastes not sold

(v) Calculate and report under subpart C of this part (General Stationary Fuel Combustion Sources) the combustion

CO 2 emissions from each lime kiln according to the applicable requirements in subpart C.

**§ 98.194 Monitoring and QA/QC requirements.** 

(a) You must determine the total quantity of each product type of lime and each calcined byproduct/waste (such as lime kiln dust) that is sold. The quantities of each should be directly measured monthly with the same plant instruments used for accounting purposes, including but not limited to, calibrated weigh feeders, rail or truck scales, and barge measurements. The
direct measurements of each lime product shall be reconciled annually with the difference in the beginning of and end of year inventories for these products, when measurements represent
lime sold. (b) You must determine the annual quantity of each calcined byproduct/ waste generated that is not sold by either direct measurement using the
same instruments identified in paragraph (a) of this section or by using a calcined byproduct/waste generation

rate.

(c) You must determine the chemical composition (percent total CaO and percent total MgO) of each type of lime and each type of calcined byproduct/ waste sold according to paragraph (c)(1) or (c)(2) of this section. You must determine the chemical composition of each type of lime on a monthly basis.
You must determine the chemical composition for each type of calcined byproduct/waste that is not sold on an
annual basis.

(1) ASTM C25–06 Standard Test Methods for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime (incorporated by reference—see § 98.7).

(2) The National Lime Association’s

CO 2 Emissions Calculation Protocol for the Lime Industry English UnitsVersion, February 5, 2008 RevisionNational Lime Association (incorporated by reference—see § 98.7).

(d) You must use the analysis of calcium oxide and magnesium oxide content of each lime product collected during the same month as the production data in monthly
calculations.

(e) You must follow the quality assurance/quality control procedures (including documentation) in National

Lime Association’s CO 2 Emissions
Calculation Protocol for the Lime Industry English Units Version, February 5, 2008 Revision—National Lime Association (incorporated by
reference—see § 98.7). **§ 98.195 Procedures for estimating missing data.** 

For the procedure in § 98.193(b)(2), a complete record of all measured parameters used in the GHG emissions calculations is required (e.g., oxide content, quantity of lime products, etc.). Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter shall be used in the calculations as specified in paragraphs (a) or (b) of this section. You must document and keep records of the procedures used for all such estimates.

(a) For each missing value of the quantity of lime produced (by lime type), and quantity of byproduct/waste produced and sold, the substitute data
value shall be the best available estimate based on all available process data or data used for accounting purposes.

(b) For missing values related to the CaO and MgO content, you must conduct a new composition test according to the standard methods in § 98.194 (c)(1) or (c)(2).

**§ 98.196 Data reporting requirements.**

In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) or (b) of this section, as applicable.

(a) If a CEMS is used to measure CO 2 emissions, then you must report under this subpart the relevant information required by § 98.36 and the information listed in paragraphs (a)(1) through (a)(8)
of this section.

(1) Method used to determine the quantity of lime sold.

(2) Method used to determine the quantity of lime byproduct/waste sold.

(3) Beginning and end of year inventories for each lime product.

(4) Beginning and end of year inventories for lime byproducts/wastes.


### 56443 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

(5) Annual amount of lime byproduct/ waste sold, by type (tons).

(6) Annual amount of lime product sold, by type (tons).

(7) Annual amount of lime byproduct/ waste not sold, by type (tons).

(8) Annual amount of lime product not sold, by type (tons).

(b) If a CEMS is not used to measure

CO 2 emissions, then you must report the information listed in paragraphs (b)(1) through (b)(17) of this section.

(1) Annual CO 2 process emissions from all kilns combined (metric tons).

(2) Monthly emission factors for each lime type.

(3) Monthly emission factors for each sold byproduct/waste by lime type.

(4) Standard method used (ASTM or NLA testing method) to determine chemical compositions of each lime type and lime byproduct/waste type.

(5) Monthly results of chemical composition analysis of each lime product and byproduct/waste sold.

(6) Annual results of chemical composition analysis of each type of lime byproduct/waste not sold.

(7) Method used to determine the quantity of lime sold.

(8) Monthly amount of lime product sold, by type (tons).

(9) Method used to determine the quantity of lime byproduct/waste sold.

(10) Monthly amount of lime byproduct/waste sold, by type (tons).

(11) Annual amount of lime byproduct/waste not sold (tons).

(12) Monthly mass of each lime type produced (tons).

(13) Beginning and end of year inventories for each lime product.

(14) Beginning and end of year inventories for lime byproducts/wastes.

(15) Annual lime production capacity (tons) per facility.

(16) Number of times in the reporting year that missing data procedures were followed to measure lime production (months) or the chemical composition of lime products sold (months).

(17) Indicate whether CO 2 was used on-site (i.e. for use in a purification process). If CO 2 was used on-site, provide the information in paragraphs (b)(17)(i) and (b)(17)(ii) of this section.

(i) The annual amount of CO 2 captured for use in the on-site process.

(ii) The method used to determine the
amount of CO 2 captured.

**§ 98.197 Records that must be retained.**

In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) and (b) of
this section.

(a) Annual operating hours in calendar year.

(b) Records of all analyses (e.g. chemical composition of lime products, by type) and calculations conducted.

**§ 98.198 Definitions.**

All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.



### TABLE 

### S–1 TO 

### S UBPART 

### S OF 

### P ART



### 98—B ASIC 

### P ARAMETERS FOR THE 

### C ALCULATION OF 

### E MISSION 

### FAC



### TORS FOR 

### L IME 

### P RODUCTION

Variable Stoichiometric ratio

SR CaO .............................. 0.7848
SR MgO ............................. 1.0918

**Subpart T—[Reserved]**

**Subpart U—Miscellaneous Uses of**
**Carbonate**

**§ 98.210 Definition of the source category.**

(a) This source category includes any equipment that uses carbonates listed in Table U–1 in manufacturing processes
that emit carbon dioxide. Table U–1 includes the following carbonates: limestone, dolomite, ankerite, magnesite, siderite, rhodochrosite, or
sodium carbonate. Facilities are
considered to emit CO 2 if they consume at least 2,000 tons per year of carbonates heated to a temperature sufficient to
allow the calcination reaction to occur.

(b) This source category does not include equipment that uses carbonates or carbonate containing minerals that are consumed in the production of cement, glass, ferroalloys, iron and steel, lead, lime, phosphoric acid, pulp and paper, soda ash, sodium bicarbonate, sodium hydroxide, or zinc.

(c) This source category does not
include carbonates used in sorbent technology used to control emissions from stationary fuel combustion equipment. Emissions from carbonates used in sorbent technology are reported under 40 CFR 98, subpart C (Stationary Fuel Combustion Sources).

**§ 98.211 Reporting threshold.**

You must report GHG emissions from miscellaneous uses of carbonate if your facility uses carbonates as defined in § 98.210 of this subpart and the facility meets the requirements of either § 98.2(a)(1) or (a)(2).

**§ 98.212 GHGs to report.**

You must report CO 2 process emissions from all miscellaneous carbonate use at your facility as specified in this subpart.

**§ 98.213 Calculating GHG emissions.**

You must determine CO 2 process emissions from carbonate use in accordance with the procedures specified in either paragraphs (a) or (b)
of this section.

(a) Calculate the process emissions of

CO 2 using calcination fractions with Equation U–1 of this section.



### E CO

i n

2 

### 2000

2205 1 

### = ∗ ∗∗

= 

# ∑ M EF F (Eq. U-1) i ii

Where:

E CO2 = Annual CO 2 mass emissions from consumption of carbonates (metric tons).

M i = Annual mass of carbonate type i consumed (tons).

EF i = Emission factor for the carbonate type i, as specified in Table U–1 to this subpart, metric tons CO 2 /metric ton
carbonate consumed.

F i = Fraction calcination achieved for each particular carbonate type i (decimal fraction). As an alternative to measuring the calcination fraction, a value of 1.0
can be used. n = Number of carbonate types. 2000/2205 = Conversion factor to convert

tons to metric tons.

(b) Calculate the process emissions of

CO 2 using actual mass of output carbonates with Equation U–2 of
this section.



### E CO j n

k m

2 1 1 

### 2000

2205 = ∗ 

## ( ) − ∗ 

# ( ) ⎡

⎣ ⎢ ⎢ ⎤

⎦ ⎥ ⎥ ∗

= = 

# ∑ ∑ M EF M EF (Eq. U-2 kk jj 

### )


### 56444 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

Where:

E CO2 = Annual CO 2 mass emissions from consumption of carbonates (metric tons).

Mk = Annual mass of input carbonate type k (tons).

EF k = Emission factor for the carbonate type k, as specified in Table U–1 of this subpart (metric tons CO 2 /metric ton carbonate input).

M

j = Annual mass of output carbonate type

j (tons).

EF

j = Emission factor for the output

carbonate type j, as specified in Table U– 1 of this subpart (metric tons CO 2 /metric ton carbonate input). m = Number of input carbonate types. n = Number of output carbonate types.

**§ 98.214 Monitoring and QA/QC requirements.** 

(a) The annual mass of carbonate consumed (for Equation U–1 of this subpart) or carbonate inputs (for Equation U–2 of this subpart) must be determined annually from monthly measurements using the same plant instruments used for accounting purposes including purchase records or direct measurement, such as weigh hoppers or weigh belt feeders.

(b) The annual mass of carbonate outputs (for Equation U–2 of this subpart) must be determined annually from monthly measurements using the same plant instruments used for accounting purposes including purchase records or direct measurement, such as weigh hoppers or belt weigh feeders.

(c) If you follow the procedures of § 98.213(a), as an alternative to assuming a calcination fraction of 1.0, you can determine on an annual basis
the calcination fraction for each carbonate consumed based on sampling and chemical analysis using a suitable method such as using an x-ray
fluorescence standard method or other enhanced industry consensus standard method published by an industry consensus standard organization (e.g., ASTM, ASME, etc.).

**§ 98.215 Procedures for estimating missing data.** 

(a) A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter shall be used in the calculations as specified in paragraph (b) of this section. You must document and keep records of the procedures used
for all such estimates.

(b) For each missing value of monthly carbonate consumed, monthly carbonate output, or monthly carbonate input, the
substitute data value must be the best
available estimate based on the all available process data or data used for accounting purposes.

**§ 98.216 Data reporting requirements.**

In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) through (g) of this section at the facility level, as applicable.

(a) Annual CO 2 emissions from miscellaneous carbonate use (metric tons).

(b) Annual mass of each carbonate type consumed (tons).

(c) Measurement method used to
determine the mass of carbonate.

(d) Method used to calculate

emissions.

(e) If you followed the calculation method of § 98.213(b)(1)(i), you must report the information in paragraphs (e)(1) through (e)(3) of this section.

(1) Annual carbonate consumption by carbonate type (tons).

(2) Annual calcination fractions used
in calculations.

(3) If you determined the calcination fraction, indicate which standard
method was used.

(f) If you followed the calculation method of § 98.213(b)(1)(ii), you must report the information in paragraphs (f)(1) and (f)(2) of this section.

(1) Annual carbonate input by carbonate type (tons).

(2) Annual carbonate output by carbonate type (tons).

(g) Number of times in the reporting year that missing data procedures were
followed to measure carbonate consumption, carbonate input or carbonate output (months).

**§ 98.217 Records that must be retained.**

In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) through (d)
of this section:

(a) Monthly carbonate consumption (by carbonate type in tons).

(b) You must document the procedures used to ensure the accuracy of the monthly measurements of carbonate consumption, carbonate input or carbonate output including, but not limited to, calibration of weighing equipment and other measurement
devices.

(c) Records of all analyses conducted to meet the requirements of this rule.

(d) Records of all calculations
conducted.

**§ 98.218 Definitions.**

All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. 

### TABLE 

### U–1 TO 

### S UBPART 

### U OF 

### P ART 

### 98—CO 2 

### E MISSION 

### FACTORS FOR 

### C OMMON 

### C ARBONATES

Mineral name—carbonate CO 2 emission factor (tons CO 2/

ton carbonate)

Limestone—CaCO 3 .................. 0.43971 Magnesite—MgCO 3 .................. 0.52197 Dolomite—CaMg(CO 3 ) 2 ............ 0.47732
Siderite—FeCO 3 ....................... 0.37987 Ankerite—Ca(Fe, Mg,

Mn)(CO 3 ) 2 ............................. 0.47572
Rhodochrosite—MnCO 3 ........... 0.38286
Sodium Carbonate/Soda Ash—

Na 2 CO 3 ................................. 0.41492

**Subpart V—Nitric Acid Production**

**§ 98.220 Definition of source category.**

A nitric acid production facility uses one or more trains to produce weak nitric acid (30 to 70 percent in strength). A nitric acid train produces weak nitric acid through the catalytic oxidation of

ammonia.

**§ 98.221 Reporting threshold.**

You must report GHG emissions under this subpart if your facility
contains a nitric acid train and the facility meets the requirements of either § 98.2(a)(1) or (a)(2).

**§ 98.222 GHGs to report.**

(a) You must report N 2 O process
emissions from each nitric acid production train as required by this subpart.

(b) You must report under subpart C of this part (General Stationary Fuel Combustion Sources) the emissions of

CO 2 , CH 4 , and N 2 O from each stationary combustion unit by following the requirements of subpart C.

**§ 98.223 Calculating GHG emissions.**

(a) You must determine annual N 2 O process emissions from each nitric acid train according to paragraphs (a)(1) or (a)(2) of this section.

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

section.

(2) Request Administrator approval for an alternative method of determining

N 2 O emissions according to paragraphs (a)(2)(i) and (a)(2)(ii) of this section.

(i) You must submit the request within 45 days following promulgation of this subpart or within the first 30 days of each subsequent reporting year.

(ii) If the Administrator does not approve your requested alternative method within 150 days of the end of the reporting year, you must determine
the N 2 O emissions factor for the current


### 56445 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

reporting period using the procedures specified in paragraph (a)(1) of this

section.

(b) You must conduct an annual performance test according to paragraphs (b)(1) through (b)(3) of this

section.

(1) You must measure N 2 O emissions from the absorber tail gas vent for each nitric acid train using the methods specified in § 98.224(b) through (d).

(2) You must conduct the performance test under normal process operating conditions and without using

N 2 O abatement technology (if applicable).

(3) You must measure the production rate during the performance test and calculate the production rate for the test period in metric tons (100 percent acid basis) per hour.

(c) You must determine an N 2 O emissions factor to use in Equation V– 3 of this section according to paragraphs (c)(1) or (c)(2) of this section. (1) You may request Administrator approval for an alternative method of determining N 2 O concentration according to the procedures in paragraphs (a)(2)(i) and (a)(2)(ii) of this
section. Alternative methods include
the use of N 2 O CEMs.

(2) Using the results of the performance test in paragraph (b) of this section, you must calculate an average site-specific emission factor for each nitric acid train ‘‘t’’ according to Equation V–1 of this section:



### EF C Q

P

n N Ot N O n

2 2 7

1 

### 1 14 10

= ∗× ∗ − 

# ∑

.

(Eq. V-1)

Where:

EF N2Ot = Average site-specific N 2 O emissions factor for nitric acid train ‘‘t’’ (lb N 2 O generated/ton nitric acid produced, 100 percent acid basis).

C N2O = N 2 O concentration for each test run during the performance test (ppm N 2 O).

1.14 × 10

¥ 7 = Conversion factor (lb/dscf-ppm

N 2 O). Q = Volumetric flow rate of effluent gas for each test run during the performance test (dscf/hr). P = Production rate for each test run during the performance test (tons nitric acid produced per hour, 100 percent acid basis).
n = Number of test runs.

(d) If applicable, you must determine the destruction efficiency for each N 2 O abatement technology according to paragraphs (d)(1), (d)(2), or (d)(3) of this

section.

(1) Use the manufacturer’s specified destruction efficiency.

(2) Estimate the destruction efficiency through process knowledge. Examples of information that could constitute process knowledge include calculations based on material balances, process stoichiometry, or previous test results provided the results are still relevant to
the current vent stream conditions. You must document how process knowledge (if applicable) was used to determine the destruction efficiency.

(3) Calculate the destruction efficiency by conducting an additional performance test on the emissions stream following the N 2 O abatement technology.

(e) If applicable, you must determine
the abatement factor for each N 2 O abatement technology. The abatement
factor is calculated for each nitric acid train according to Equation V–2 of this

section.



### AF = P N t at Abate

at 

### P (Eq. V-2)

Where: AF N t = Abatement factor of N 2 O abatement technology at nitric acid train ‘‘t’’ (fraction of annual production that abatement technology is operating).

P a t = Total annual nitric acid production from nitric acid train ‘‘t’’ (ton acid produced, 100 percent acid basis).

P a t Abate = Annual nitric acid production from nitric acid train ‘‘t’’ during which N 2 O abatement was used (ton acid produced, 100 percent acid basis).

(f) You must determine the annual amount of nitric acid produced and the annual amount of nitric acid produced
while each N 2 O abatement technology is operating from each nitric acid train (100 percent basis).

(g) You must calculate N 2 O emissions for each nitric acid train by multiplying the emissions factor (determined in Equation V–1 of this section) by the annual nitric acid production and accounting for N 2 O abatement, according to Equation V–3 of this

section:



### EF EF P DF AF

N Ot N Ot at N t N t

N

z

2 2

1 

### 1

2204 63 = ∗ ∗− ∗ 

# ( ) 

# ( )

= 

# ∑

. (Eq. V-3)

Where:

E N2Ot = N 2 O mass emissions per year for nitric acid train ‘‘t’’ (metric tons).

EF N2Ot = Average site-specific N 2 O emissions factor for nitric acid train ‘‘t’’ (lb N 2 O generated/ton acid produced, 100 percent acid basis).

P a t = Annual nitric acid production from the train ‘‘t’’ (ton acid produced, 100 percent acid basis). DF N t = Destruction efficiency of N 2 O abatement technology N that is used on nitric acid train ‘‘t’’ (percent of N 2 O removed from air stream).

AF N t = Abatement factor of N 2 O abatement technology for nitric acid train ‘‘t’’ (fraction of annual production that abatement technology is operating). 2204.63 = Conversion factor (lb/metric ton). z = Number of different N 2 O abatement technologies.

(h) You must determine the annual nitric acid production emissions
combined from all nitric acid trains at your facility using Equation V–4 of this

section:



### N E N Ot

tm

2 2

1 

### O =

= 

# ∑ (Eq. V-4)


### 56446 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

Where:

N 2 O = Annual process N 2 O emissions from nitric acid production facility (metric tons).

E N2Ot = N 2 O mass emissions per year for nitric acid train ‘‘t’’ (metric tons).
m = Number of nitric acid trains.

**§ 98.224 Monitoring and QA/QC requirements.** 

(a) You must conduct a new performance test and calculate a new site-specific emissions factor according to a test plan as specified in paragraphs (a)(1) through (a)(3) of this section.

(1) Conduct the performance test annually.

(2) Conduct the performance test when your nitric acid production process is changed, specifically when abatement equipment is installed.

(3) If you requested Administrator approval for an alternative method of determining N 2 O concentration under § 98.223(a)(2), you must conduct the performance test if your request has not been approved by the Administrator within 150 days of the end of the reporting year in which it was
submitted.

(b) You must measure the N 2 O concentration during the performance test using one of the methods in paragraphs (b)(1) through (b)(3) of this

section.

(1) EPA Method 320 at 40 CFR part 63, appendix A, Measurement of Vapor Phase Organic and Inorganic Emissions by Extractive Fourier Transform Infrared (FTIR) Spectroscopy.

(2) ASTM D6348–03 Standard Test
Method for Determination of Gaseous Compounds by Extractive Direct
Interface Fourier Transform Infrared (FTIR) Spectroscopy (incorporated by reference in § 98.7).

(3) An equivalent method, with Administrator approval.

(c) You must determine the production rate(s) (100 percent basis) from each nitric acid train during the performance test according to paragraphs (c)(1) or (c)(2) of this section.

(1) Direct measurement of production and concentration (such as using flow meters, weigh scales, for production and concentration measurements).

(2) Existing plant procedures used for accounting purposes (i.e. dedicated
tank-level and acid concentration measurements).

(d) You must conduct all performance tests in conjunction with the applicable EPA methods in 40 CFR part 60, appendices A–1 through A–4. Conduct
three emissions test runs of 1 hour each. All QA/QC procedures specified in the reference test methods and any associated performance specifications apply. For each test, the facility must prepare an emission factor determination report that must include the items in paragraphs (d)(1) through (d)(3) of this section.

(1) Analysis of samples, determination of emissions, and raw
data.

(2) All information and data used to derive the emissions factor(s).

(3) The production rate during each
test and how it was determined.

(e) You must determine the monthly nitric acid production and the monthly nitric acid production during which

N 2 O abatement technology is operating from each nitric acid train according to the methods in paragraphs (c)(1) or (c)(2) of this section.

(f) You must determine the annual nitric acid production and the annual nitric acid production during which

N 2 O abatement technology is operating for each train by summing the respective monthly nitric acid production quantities.

**§ 98.225 Procedures for estimating missing data.** 

A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter shall be used in the calculations as specified in paragraphs (a) and (b) of this section.

(a) For each missing value of nitric acid production, the substitute data
shall be the best available estimate based on all available process data or data used for accounting purposes (such as sales records).

(b) For missing values related to the performance test, including emission factors, production rate, and N 2 O concentration, you must conduct a new performance test according to the procedures in § 98.224 (a) through (d).

**§ 98.226 Data reporting requirements.**

In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) through (o) of this section for each nitric acid production

train.

(a) Train identification number. (b) Annual process N 2 O emissions from each nitric acid train (metric tons).

(c) Annual nitric acid production from each nitric acid train (tons, 100 percent acid basis).

(d) Annual nitric acid production from each nitric acid train during which

N 2 O abatement technology is operating (ton acid produced, 100 percent acid basis). (e) Annual nitric acid production from the nitric acid facility (tons, 100 percent acid basis).

(f) Number of nitric acid trains. (g) Number of abatement technologies (if applicable).

(h) Abatement technologies used (if applicable).

(i) Abatement technology destruction efficiency for each abatement technology (percent destruction).

(j) Abatement utilization factor for each abatement technology (fraction of annual production that abatement technology is operating).

(k) Type of nitric acid process used for each nitric acid train (low, medium, high, or dual pressure).

(l) Number of times in the reporting year that missing data procedures were
followed to measure nitric acid production (months).

(m) If you conducted a performance test and calculated a site-specific emissions factor according to § 98.223(a)(1), each annual report must also contain the information specified in paragraphs (m)(1) through (m)(7) of this section for each nitric acid production facility.

(1) Emission factor calculated for each nitric acid train (lb N 2 O/ton nitric acid, 100 percent acid basis).

(2) Test method used for performance

test.

(3) Production rate per test run during performance test (tons nitric acid produced/hr, 100 percent acid basis).

(4) N 2 O concentration per test run during performance test (ppm N 2 O).

(5) Volumetric flow rate per test run during performance test (dscf/hr).

(6) Number of test runs during performance test.

(7) Number of times in the reporting year that a performance test had to be repeated (number).

(n) If you requested Administrator approval for an alternative method of determining N 2 O concentration under § 98.223(a)(2), each annual report must also contain the information specified in paragraphs (n)(1) through (n)(4) of this section for each nitric acid production facility.

(1) Name of alternative method. (2) Description of alternative method. (3) Request date. (4) Approval date. (o) Total pounds of synthetic fertilizer produced through and total nitrogen
contained in that fertilizer.

**§ 98.227 Records that must be retained.**

In addition to the information required by § 98.3(g), you must retain the records specified in paragraphs (a) through (g) of this section for each nitric acid production facility:


### 56447 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

(a) Records of significant changes to

process.

(b) Documentation of how process knowledge was used to estimate abatement technology destruction efficiency (if applicable).

(c) Performance test reports. (d) Number of operating hours in the calendar year for each nitric acid train (hours).

(e) Annual nitric acid permitted production capacity (tons).

(f) Measurements, records, and calculations used to determine reported parameters.

(g) Documentation of the procedures used to ensure the accuracy of the measurements of all reported parameters, including but not limited to, calibration of weighing equipment, flow meters, and other measurement devices. The estimated accuracy of
measurements made with these devices must also be recorded, and the technical
basis for these estimates must be provided.

**§ 98.228 Definitions.**

All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.

**Subpart W—[Reserved]**

**Subpart X—Petrochemical Production**

**§ 98.240 Definition of the source category.**

(a) The petrochemical production source category consists of all processes that produce acrylonitrile, carbon black, ethylene, ethylene dichloride, ethylene oxide, or methanol, except as specified in paragraphs (b) through (f) of this section. The source category includes processes that produce the petrochemical as an intermediate in the onsite production of other chemicals as well as processes that produce the petrochemical as an end product for sale or shipment offsite.

(b) A process that produces a petrochemical as a byproduct is not part of the petrochemical production source category.

(c) A facility that makes methanol, hydrogen, and/or ammonia from synthesis gas is part of the petrochemical source category if the annual mass of methanol produced
exceeds the individual annual mass production levels of both hydrogen recovered as product and ammonia. The facility is part of subpart P of this part (Hydrogen Production) if the annual mass of hydrogen recovered as product
exceeds the individual annual mass production levels of both methanol and ammonia. The facility is part of subpart G of this part (Ammonia Manufacturing) if the annual mass of ammonia produced exceeds the individual annual mass production levels of both hydrogen recovered as product and
methanol.

(d) A direct chlorination process that is operated independently of an oxychlorination process to produce ethylene dichloride is not part of the petrochemical production source category.

(e) A process that produces bone black is not part of the petrochemical source category.

(f) A process that produces a petrochemical from bio-based feedstock is not part of the petrochemical production source category.

**§ 98.241 Reporting threshold.**

You must report GHG emissions under this subpart if your facility contains a petrochemical process as specified in § 98.240, and the facility meets the requirements of either § 98.2(a)(1) or (2).

**§ 98.242 GHGs to report.**

You must report the information in paragraphs (a) through (c) of this

section:

(a) CO 2 CH 4 , and N 2 O process emissions from each petrochemical process unit. Process emissions include

CO 2 generated by reaction in the process and by combustion of process off-gas in stationary combustion units and flares.

(1) If you comply with § 98.243(b) or (d), report under this subpart the
calculated CO 2 , CH 4 , and N 2 O emissions for each stationary combustion source and flare that burns any amount of petrochemical process off-gas.

(2) If you comply with § 98.243(c), report under this subpart the calculated

CO 2 emissions for each petrochemical process unit.

(b) CO 2 , CH 4 , and N 2 O combustion emissions from stationary combustion
units and flares.

(1) If you comply with § 98.243(b) or (d), report these emissions from stationary combustion units that are associated with petrochemical process units and burn only supplemental fuel under subpart C of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart C.

(2) If you comply with § 98.243(c), report CO 2 , CH 4 , and N 2 O combustion emissions under subpart C of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart C only for the combustion of supplemental fuel. Determine the applicable Tier in subpart C of this part (General Stationary Fuel Combustion Sources) based on the maximum rated heat input capacity of the stationary
combustion source. (c) CO 2 captured. You must report the
mass of CO 2 captured under, subpart PP of this part (Suppliers of Carbon Dioxide (CO 2 ) by following the requirements of subpart PP.

**§ 98.243 Calculating GHG emissions.**

(a) If you route all process vent
emissions and emissions from combustion of process off-gas to one or
more stacks and use CEMS on each
stack to measure CO 2 emissions (except flare stacks), then you must determine process-based GHG emissions in accordance with paragraph (b) of thissection. Otherwise, determine processbased GHG emissions in accordance with the procedures specified in paragraph (c) or (d) of this section.

(b) Continuous emission monitoring system (CEMS). Route all process vent
emissions and emissions from combustion of process off-gas to one or
more stacks and determine CO 2 emissions from each stack (except flare stacks) according to the Tier 4 Calculation Methodology requirements in subpart C of this part. For each stack (except flare stacks) that includes
emissions from combustion of petrochemical process off-gas, calculate

CH 4 and N 2 O emissions in accordance with subpart C of this part (use the Tier 3 methodology and emission factors for ‘‘Petroleum’’ in Table C–2 of subpart C of this part). For each flare, calculate

CO 2 , CH 4 , and N 2 O emissions using the methodology specified in § 98.253(b)(1) through (b)(3).

(c) Mass balance for each petrochemical process unit. Calculate
the emissions of CO 2 from each process unit, for each calendar month as described in paragraphs (c)(1) through (c)(5) of this section.

(1) For each gaseous and liquid feedstock and product, measure the volume or mass used or produced each calendar month with a flow meter by following the procedures specified in § 98.244(b)(2). Alternatively, for liquids, you may calculate the volume used or
collected in each month based on measurements of the liquid level in a storage tank at least once per month (and just prior to each change in direction of the level of the liquid) following the procedures specified in § 98.244(b)(3). Fuels used for combustion purposes are not considered
to be feedstocks.

(2) For each solid feedstock and product, measure the mass used or produced each calendar month by following the procedures specified in § 98.244(b)(1).

(3) Collect a sample of each feedstock and product at least once per month and
determine the carbon content of each


### 56448 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

sample according to the procedures in § 98.244(b)(4). Alternatively, you may use the results of analyses conducted by a fuel or feedstock supplier, provided the sampling and analysis are conducted at least once per month using any of the procedures specified in § 98.244(b)(4). If multiple valid carbon content measurements are made during the monthly measurement period, average them arithmetically.

(4) If you determine that the monthly average concentration of a specific compound in a feedstock or product is greater than 99.5 percent by volume (or mass for liquids and solids), then as an alternative to the sampling and analysis specified in paragraph (c)(3) of this section, you may calculate the carbon content assuming 100 percent of that feedstock or product is the specific compound during periods of normal operation. You must maintain records of any determination made in accordance with this paragraph (c)(4) along with all supporting data, calculations, and other information. This alternative may not be used for products during periods of operation when off-specification product is produced. You must
reevaluate determinations made under this paragraph (c)(4) after any process change that affects the feedstock or product composition. You must keep records of the process change and the corresponding composition determinations. If the feedstock or product composition changes so that the average monthly concentration falls below 99.5 percent, you are no longer permitted to use this alternative
method.

(5) Calculate the CO 2 mass emissions for each petrochemical process unit using Equations X–1 through X–4 of this

section.

(i) Gaseous feedstocks and products. Use Equation X–1 of this section to calculate the net annual carbon input or output from gaseous feedstocks and products. Note that the result will be a negative value if there are no gaseous feedstocks in the process but there are gaseous products.



### C F CC MW

MVC P CC MW

M g gf i,n gf i,n f i

gp i,n gp i,n p i



### = 

# ( ) ∗ 

# ( ) ∗ 

# ( )

− 

# ( ) ∗ 

# ( ) ∗ 

# ( )

V C i= j or k

n 

### ⎡

⎣ ⎢ ⎢ ⎤

⎦ ⎥ ⎥ ⎡

⎣ ⎢ ⎢ ⎤

⎦ ⎥ ⎥ 

# ∑ ∑

= 1

1 12 

### (Eq. X-1)

Where:

C g = Annual net contribution to calculated emissions from carbon (C) in gaseous materials (kilograms/year, kg/yr). (F gf) i,n = Volume of gaseous feedstock i introduced in month ‘‘n’’ (standard cubic feet, scf). (CC gf) i,n = Average carbon content of the gaseous feedstock i for month ‘‘n’’ (kg C per kg of feedstock). (MW f) i = Molecular weight of gaseous feedstock i (kg/kg-mole). MVC = Molar volume conversion factor (849.5 scf per kg-mole at standard conditions). (P gp ) i,n = Volume of gaseous product i produced in month ‘‘n’’ (scf). (CC gp ) i,n = Average carbon content of gaseous product i, including streams containing

CO 2 recovered for sale or use in another process, for month ‘‘n’’ (kg C per kg of product). (MWp ) i = Molecular weight of gaseous product i (kg/kg-mole). j = Number of feedstocks. k = Number of products.

(ii) Liquid feedstocks and products. Use Equation X–2 of this section to calculate the net carbon input or output from liquid feedstocks and products. Note that the result will be a negative value if there are no liquid feedstocks in the process but there are liquid products.



### C F CC P CC

l lf i,n lf i,n lp i,n lp i,n i= j or k



### = 

# ( ) ∗ 

# ( )

− 

# ( ) ∗ 

# ( ) ⎡ ⎣ ⎢ ⎤ ⎦ ⎥ ⎡

⎣ 

# ∑

1 

### ⎢ ⎢ ⎤

⎦ ⎥ ⎥

= 

# ∑

n 1 12 

### (Eq. X-2)

Where:

C l = Annual net contribution to calculated emissions from carbon in liquid materials, including liquid organic wastes (kg/yr). (F lf) i,n = Volume or mass of liquid feedstock i introduced in month ‘‘n’’ (gallons or kg). (CC lf) i,n = Average carbon content of liquid feedstock i for month ‘‘n’’ (kg C per gallon or kg of feedstock). (P lp ) i,n = Volume or mass of liquid product i produced in month ‘‘n’’ (gallons or kg). (CC lp ) i,n = Average carbon content of liquid product i, including organic liquid wastes, for month ‘‘n’’ (kg C per gallon or kg of product). j = Number of feedstocks. k = Number of products.

(iii) Solid feedstocks and products. Use Equation X–3 of this section to calculate the net annual carbon input or output from solid feedstocks and products. Note that the result will be a negative value if there are no solid feedstocks in the process but there are solid products.



### C F CC P CC

s sf i,n sf i,n sp i,n sp i,n i= j or k



### = 

# ( ) ∗ 

# ( )

− 

# ( ) ∗ 

# ( ) ⎡ ⎣ ⎢ ⎤ ⎦ ⎥ ⎧ ⎨ 

# ∑

1 

### ⎪

⎩ ⎪ ⎫ ⎬ ⎪

⎭ ⎪

= 

# ∑

n 1 12 

### (Eq. X-3)

Where:

C

s = Annual net contribution to calculated

emissions from carbon in solid materials (kg/yr). (F sf) i,n = Mass of solid feedstock i introduced in month ‘‘n’’ (kg). (CC sf) i,n = Average carbon content of solid feedstock i for month ‘‘n’’ (kg C per kg of feedstock). (P sp ) i,n = Mass of solid product i produced in month ‘‘n’’ (kg). (CC sp ) i,n = Average carbon content of solid product i in month ‘‘n’’ (kg C per kg of product). j = Number of feedstocks. k = Number of products.

(iv) Annual emissions. Use the results from Equations X–1 through X–3 of this section, as applicable, in Equation X–4
of this section to calculate annual CO 2 emissions.


### 56449 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

CO C C C gls 2 

### 0.001 44

12 + + (Eq. X-4) = ∗∗ 

# ( )

Where:

CO 2 = Annual CO 2 mass emissions from process operations and process off-gas combustion (metric tons/year). 0.001 = Conversion factor from kg to metric

tons. 44 = Molecular weight of CO 2 (kg/kg-mole).12 = Atomic weight of carbon (C) (kg/kgmole).
(d) Optional combustion methodology for ethylene production processes. For any ethylene production process,
calculate CO 2 emissions from
combustion of fuel that contains ethylene process off-gas using the Tier 3 or Tier 4 methodology in subpart C of this part, and calculate CH4 and N 2 O emissions using the applicable procedures in § 98.33(c) (use the
emission factors for ‘‘Petroleum’’ in Table C–2 of subpart C of this part (General Stationary Fuel Combustion Sources)). You are not required to use the same Tier for each stationary combustion unit that burns ethylene process off-gas. For each flare, calculate

CO 2 , CH 4 , and N 2 O emissions using the methodology specified in § 98.253(b)(1) through (b)(3).

**§ 98.244 Monitoring and QA/QC requirements.** 

(a) If you use CEMS to determine emissions from process vents, you must comply with the procedures specified in § 98.34(c).

(b) If you use the mass balance methodology in § 98.243(c), use the procedures specified in paragraphs (b)(1) through (b)(4) of this section to determine feedstock and product flows
and carbon contents.

(1) Operate and maintain belt scales or other weighing devices as described in Specifications, Tolerances, and Other Technical Requirements For Weighing and Measuring Devices NIST Handbook 44 (2009) (incorporated by reference, see § 98.7) or follow procedures specified by
the measurement device manufacturer.
Calibrate the measurement device according to the procedures specified by the method, the procedures specified by the manufacturer, or § 98.3(i). Recalibrate either biennially or at the minimum frequency specified by the
manufacturer.

(2) Operate and maintain all flow meters for gas and liquid feedstocks and products by following the procedures in § 98.3(i) and using any of the flow meter methods specified in paragraphs (b)(2)(i) through (b)(2)(xv) of this section, as applicable, use a standard method published by a consensus-based standards organization (e.g., ASTM, API, etc.), or follow procedures specified by the flow meter manufacturer or § 98.3(i). Recalibrate each flow meter either biennially or at the minimum frequency specified by the
manufacturer.

(i) ASME MFC–3M–2004 Measurement of Fluid Flow in Pipes Using Orifice, Nozzle, and Venturi (incorporated by reference, see § 98.7).

(ii) ASME MFC–4M–1986 (Reaffirmed 1997) Measurement of Gas Flow by Turbine Meters (incorporated by reference, see § 98.7).

(iii) ASME MFC–5M–1985 (Reaffirmed 1994) Measurement of Liquid Flow in Closed Conduits Using
Transit-Time Ultrasonic Flowmeters (incorporated by reference, see § 98.7).

(iv) ASME MFC–6M–1998 Measurement of Fluid Flow in Pipes Using Vortex Flowmeters (incorporated by reference, see § 98.7).

(v) ASME MFC–7M–1987 (Reaffirmed 1992) Measurement of Gas Flow by
Means of Critical Flow Venturi Nozzles (incorporated by reference, see § 98.7).

(vi) ASME MFC–9M–1988 (Reaffirmed 2001) Measurement of Liquid Flow in Closed Conduits by Weighing Method (incorporated by reference, see § 98.7).

(vii) ASME MFC–11M–2006 Measurement of Fluid Flow by Means of Coriolis Mass Flowmeters (incorporated by reference, see § 98.7).

(viii) ASME MFC–14M–2003 (Reaffirmed 2008), Measurement of Fluid Flow Using Small Bore Precision Orifice Meters (incorporated by reference, see § 98.7).

(ix) ASME MFC–16–2007 Measurement of Liquid Flow in Closed Conduits with Electromagnetic Flowmeters (incorporated by reference,

see § 98.7).

(x) ASME MFC–18M–2001 (Reaffirmed 2006), Measurement of Fluid Flow Using Variable Area Meters (incorporated by reference, see § 98.7).

(xi) ASME MFC–22–2007 Measurement of Liquid by Turbine Flowmeters (incorporated by reference,

see § 98.7).

(xii) AGA Report No. 3: Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids, Part 1: General Equations and Uncertainty Guidelines (1990), Part 2: Specification and Installation Requirements (2000) (incorporated by reference, see § 98.7).

(xiii) AGA Transmission Measurement Committee Report No. 7: Measurement of Natural Gas by Turbine Meter (2006)/February (incorporated by reference, see § 98.7).

(xiv) AGA Report No. 11: Measurement of Natural Gas by Coriolis Meter (2003) (incorporated by reference,

see § 98.7).

(xv) ISO 8316: Measurement of Liquid Flow in Closed Conduits—Method by Collection of the Liquid in a Volumetric Tank (1987–10–01) First Edition (incorporated by reference, see § 98.7).

(3) Perform tank level measurements (if used to determine feedstock or product flows) according to any standard method published by a consensus-based standards organization (e.g., ASTM, API, etc.) or follow procedures specified by the
measurement device manufacturer or § 98.3(i). Calibrate the measurement devices prior to the effective date of the rule, and recalibrate either biennially or at the minimum frequency specified by the manufacturer or § 98.3(i).

(4) Use any of the standard methods specified in paragraphs (b)(4)(i) through (b)(4)(x) of this section, as applicable, to
determine the carbon content or composition of feedstocks and products and the average molecular weight of gaseous feedstocks and products.
Calibrate instruments in accordance with the method and as specified in paragraphs (b)(4)(i) through (b)(4)(x), as applicable. For coal used as a feedstock, the samples for carbon content
determinations shall be taken at a location that is representative of the coal feedstock used during the corresponding monthly period. For carbon black products, samples shall be taken of each grade or type of product produced during the monthly period. Samples of coal feedstock or carbon black product for carbon content determinations may be either grab samples collected and analyzed monthly or a composite of samples collected more frequently and analyzed monthly. Analyses conducted in accordance with methods specified in paragraphs (b)(4)(i) through (b)(4)(x) of this section may be performed by the owner or operator, by an indpendent laboratory, or by the supplier of a
feedstock.

(i) ASTM D1945–03, Standard Test Method for Analysis of Natural Gas by Gas Chromatography (incorporated by reference, see § 98.7).

(ii) ASTM D6060–96 (Reapproved 2001) Standard Practice for Sampling of
Process Vents With a Portable Gas


### 56450 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

Chromatograph (incorporated by reference, see § 98.7).

(iii) ASTM D2505–88(Reapproved 2004)e1 Standard Test Method for Ethylene, Other Hydrocarbons, and Carbon Dioxide in High-Purity Ethylene by Gas Chromatography (incorporated by reference, see § 98.7).

(iv) ASTM UOP539–97 Refinery Gas Analysis by Gas Chromatography (incorporated by reference, see § 98.7).

(v) ASTM D3176–89 (Reapproved 2002) Standard Practice Method for Ultimate Analysis of Coal and Coke (incorporated by reference, see § 98.7).

(vi) ASTM D5291–02 (Reapproved 2007) Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants (incorporated by reference, see § 98.7).

(vii) ASTM D5373–08 Standard Test
Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal (incorporated by reference, see § 98.7).

(viii) Methods 8031, 8021, or 8015 in ‘‘Test Methods for Evaluating Solid Waste, Physical/Chemical Methods,’’ EPA Publication No. SW–846, Third Edition, September 1986, as amended by Update I, November 15, 1992.

(ix) Method 18 at 40 CFR part 60, appendix A–6.

(x) Performance Specification 9 in 40 CFR part 60, appendix B for continuous online gas analyzers. The 7-day calibration error test period must be completed prior to the effective date of
the rule.

**§ 98.245 Procedures for estimating missing data.** 

For missing feedstock flow rates, product flow rates, and carbon contents, use the same procedures as for missing
flow rates and carbon contents for fuels as specified in § 98.35.

**§ 98.246 Data reporting requirements.**

In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a), (b), or (c) of this section, as appropriate for each process

unit.

(a) If you use the mass balance methodology in § 98.243(c), you must report the information specified in paragraphs (a)(1) through (a)(10) of this section for each type of petrochemical produced, reported by process unit.

(1) The petrochemical process unit ID number or other appropriate descriptor.

(2) The type of petrochemical produced, names of other products, and names of carbon-containing feedstocks.

(3) Annual CO 2 emissions calculated using Equation X–4 of this subpart. (4) Each of the monthly volume, mass,
and carbon content values used in Equations X–1 through X–3 of this subpart (i.e., the directly measured values, substitute values, or the
calculated values based on other measured data such as tank levels or gas composition) and the molecular weights for gaseous feedstocks and products used in Equation X–1 of this subpart. Indicate whether you used the alternative to sampling and analysis specified in § 98.243(c)(4).

(5) Annual quantity of each type of petrochemical produced from each process unit (metric tons).

(6) Name of each method listed in § 98.244 used to determine a measured parameter (or description of manufacturer’s recommended method).

(7) The dates and summarized results (e.g., percent calibration error) of the
calibrations of each measurement
device.

(8) Identification of each combustion unit that burned both process off-gas and supplemental fuel.

(9) If you comply with the alternative to sampling and analysis specified in § 98.243(c)(4), the amount of time during which off-specification product was produced, the volume or mass of off-specification product produced, and if applicable, the date of any process change that reduced the composition to less than 99.5 percent.

(10) You may elect to report the flow and carbon content of wastewater, and you may elect to report the carbon content of hydrocarbons in fugitive emissions and in process vents that are
not controlled with a combustion device. These values may be estimated based on engineering analyses. These
values are not to be used in the mass
balance calculation.

(b) If you use CEMS to measure CO 2 emissions in accordance with § 98.243(b), then you must report the relevant information required under § 98.36 for the Tier 4 Calculation Methodology and the information listed in paragraphs (b)(1) through (b)(6) of
this section.

(1) For CEMS used on stacks for stationary combustion units, report the relevant information required under § 98.36 for the Tier 4 calculation methodology.

(2) For CEMS used on stacks that are not used for stationary combustion units, report the information required under § 98.36(e)(2)(vi) and (vii).

(3) The petrochemical process unit ID or other appropriate descriptor, and the type of petrochemical produced.

(4) The CO 2 emissions from each stack
and the combined CO 2 emissions from all stacks (except flare stacks) that handle process vent emissions and emissions from stationary combustion units that burn process off-gas for the petrochemical process unit. If a stationary combustion source serves multiple petrochemical process units or units other than the petrochemical process unit, estimate based on engineering judgment the fraction of fuel energy and emissions attributable to each petrochemical process unit.

(5) The CH4 and N 2 O emissions from
each stack and the combined CH4 and

N 2 O emissions from all stationarycombustion units that burn process offgas from the petrochemical process unit, the cumulative annual heat input used in Equation C–10 in § 98.33(c) of this subpart, and the annual flow of each fuel on which this heat input is based.

(6) ID or other appropriate descriptor of each stationary combustion unit that burns process off-gas.

(7) Information listed in § 98.256(e) of subpart Y of this part for each flare that burns process off-gas.

(8) Annual quantity of each type of petrochemical produced from each process unit (metric tons).

(c) If you comply with the combustion methodology specified in § 98.243(d), you must report under this subpart the information listed in paragraphs (c)(1) through (c)(4) of this section.

(1) For each stationary combustion unit that burns ethylene process off-gas (or group of stationary sources with a common pipe), the relevant information listed in § 98.36 for the selected Tier 3 or Tier 4 methodology. If a stationary combustion source serves multiple ethylene process units or units other than the ethylene process unit, estimate based on engineering judgment the fraction of fuel energy and emissions attributable to each ethylene process

unit.

(2) Information listed in § 98.256(e) for each flare that burns ethylene process off-gas.

(3) Name and annual quantity of each
feedstock.

(4) Annual quantity of each type of petrochemical produced from each process unit (metric tons).

**§ 98.247 Records that must be retained.**

In addition to the recordkeeping requirements in § 98.3(g), you must retain the records specified in paragraphs (a) through (c) of this section, as applicable.

(a) If you comply with the CEMS measurement methodology in § 98.243(b), then you must retain under this subpart the records required for the Tier 4 Calculation Methodology in § 98.37.


### 56451 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

(b) If you comply with the mass balance methodology in § 98.243(c), then you must retain records of the information listed in paragraphs (b)(1) through (b)(3) of this section.

(1) Results of feedstock or product composition determinations conducted in accordance with § 98.243(c)(4).

(2) Start and end times and calculated carbon contents for time periods when off-specification product is produced, if you comply with the alternative methodology in § 98.243(c)(4) for determining carbon content of feedstock or product.

(3) A part of the monitoring plan required under § 98.3(g)(5), record the estimated accuracy of measurement
devices and the technical basis for these

estimates.

(c) If you comply with the combustion methodology in § 98.243(d), then you must retain under this subpart the records required for the Tier 3 and/or Tier 4 Calculation Methodologies in § 98.37.

**§ 98.248 Definitions.**

Except as specified in this section, all terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.

Product, as used in § 98.243, means each of the following carbon-containing outputs from a process: the petrochemical, recovered byproducts, and liquid organic wastes that are not
incinerated onsite. Product does not include process vent emissions, fugitive emissions, or wastewater.

**Subpart Y—Petroleum Refineries**

**§ 98.250 Definition of source category.**

(a) A petroleum refinery is any facility engaged in producing gasoline, gasoline blending stocks, naphtha, kerosene, distillate fuel oils, residual fuel oils, lubricants, or asphalt (bitumen) through distillation of petroleum or through redistillation, cracking, or reforming of unfinished petroleum derivatives, except as provided in paragraph (b) of
this section.

(b) For the purposes of this subpart, facilities that distill only pipeline transmix (off-spec material created when different specification products mix during pipeline transportation) are not petroleum refineries, regardless of the products produced.

(c) This source category consists of the following sources at petroleum refineries: Catalytic cracking units; fluid coking units; delayed coking units; catalytic reforming units; coke calcining units; asphalt blowing operations; blowdown systems; storage tanks; process equipment components (compressors, pumps, valves, pressure relief devices, flanges, and connectors) in gas service; marine vessel, barge, tanker truck, and similar loading operations; flares; sulfur recovery plants; and non-merchant hydrogen plants (i.e., hydrogen plants that are
owned or under the direct control of the refinery owner and operator).

**§ 98.251 Reporting threshold.**

You must report GHG emissions under this subpart if your facility contains a petroleum refineries process and the facility meets the requirements of either § 98.2(a)(1) or (a)(2).

**§ 98.252 GHGs to report.**

You must report: (a) CO 2 , CH 4 , and N 2 O combustion emissions from stationary combustion
units and from each flare. Calculate and report these emissions under subpart C of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart C, except for

CO 2 emissions from combustion of refinery fuel gas. For CO 2 emissions from combustion of fuel gas, use either equation C–5 in subpart C of this part or the Tier 4 methodology in subpart C of this part. You may aggregate units, monitor common stacks, or monitor common (fuel) pipes as provided in § 98.36(c) when calculating and reporting emissions from stationary
combustion units.

(b) CO 2 , CH 4 , and N 2 O coke burn-off emissions from each catalytic cracking unit, fluid coking unit, and catalytic reforming unit under this subpart.

(c) CO 2 emissions from sour gas sent off site for sulfur recovery operations under this subpart. You must follow the calculation methodologies from § 98.253(f) and the monitoring and QA/ QC methods, missing data procedures, reporting requirements, and recordkeeping requirements of this subpart.

(d) CO 2 process emissions from each on-site sulfur recovery plant under this subpart.

(e) CO 2 , CH 4 , and N 2 O emissions from each coke calcining unit under this subpart.

(f) CO 2 and CH 4 emissions from asphalt blowing operations under this subpart. (g) CH4 emissions from equipment leaks, storage tanks, loading operations, delayed coking units, and uncontrolled blowdown systems under this subpart.

(h) CO 2 , CH 4 , and N 2 O emissions from each process vent not specifically included in paragraphs (a) through (g) of this section under this subpart.

(i) CO 2 and CH 4 emissions from nonmerchant hydrogen production under this subpart. You must follow the calculation methodologies, monitoring and QA/QC methods, missing data procedures, reporting requirements, and recordkeeping requirements of subpart P of this part.

**§ 98.253 Calculating GHG emissions.**

(a) Calculate GHG emissions required to be reported in § 98.252(b) through (i) using the applicable methods in paragraphs (b) through (n) of this

section.

(b) For flares, calculate GHG emissions according to the requirements in paragraphs (b)(1) through (b)(3) of
this section.

(1) Calculate the CO 2 emissions according to the applicable requirements in paragraphs (b)(1)(i) through (b)(1)(iii) of this section.

(i) Flow measurement. If you have a continuous flow monitor on the flare, you must use the measured flow rates when the monitor is operational and the flow rate is within the calibrated range
of the measurement device to calculate the flare gas flow. If you do not have a
continuous flow monitor on the flare and for periods when the monitor is not operational or the flow rate is outside the calibrated range of the measurement device, you must use engineering calculations, company records, or similar estimates of volumetric flare gas
flow.

(ii) Heat value or carbon content

measurement. If you have a continuous higher heating value monitor or gas composition monitor on the flare or if you monitor these parameters at least weekly, you must use the measured heat
value or carbon content value in calculating the CO 2 emissions from the flare using the applicable methods in paragraphs (b)(1)(ii)(A) and (b)(1)(ii)(B).

(A) If you monitor gas composition,
calculate the CO 2 emissions from the flare using Equation Y–1 of this section. If daily or more frequent measurement data are available, you must use daily values when using Equation Y–1 of this section; otherwise, use weekly values.


### 56452 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

CO Flare MW

MVC CC

p p

p

p

n

2 

### =× × × 

## ( ) × × ⎡

⎣ ⎢ ⎤

⎦ ⎥ ⎛

⎝ ⎜ ⎜

=



# ∑ 0 98 0 001 44

12 1 

### . . ( ) ( ) ⎞

⎠ ⎟ ⎟ (Eq. Y-1)

Where:

CO 2 = Annual CO 2 emissions for a specific fuel type (metric tons/year). 0.98 = Assumed combustion efficiency of a

flare. 0.001 = Unit conversion factor (metric tons per kilogram, mt/kg). n = Number of measurement periods. The minimum value for n is 52 (for weekly measurements); the maximum value for n is 366 (for daily measurements during a leap year). p = Measurement period index. 44 = Molecular weight of CO 2 (kg/kg-mole). 12 = Atomic weight of C (kg/kg-mole). (Flare) p = Volume of flare gas combusted during measurement period (standard cubic feet per period, scf/period). If a mass flow meter is used, measure flare gas flow rate in kg/period and replace the term ‘‘(MW) p /MVC’’ with ‘‘1’’. (MW) p = Average molecular weight of the flare gas combusted during measurement period (kg/kg-mole). If measurements are taken more frequently than daily, use the arithmetic average of measurement values within the day to calculate a daily

average. MVC = Molar volume conversion factor (849.5 scf/kg-mole). (CC) p = Average carbon content of the flare gas combusted during measurement period (kg C per kg flare gas). If measurements are taken more frequently than daily, use the arithmetic average of measurement values within the day to calculate a daily average.
(B) If you monitor heat content but do not monitor gas composition, calculate
the CO 2 emissions from the flare using Equation Y–2 of this section. If daily or more frequent measurement data are available, you must use daily values when using Equation Y–2 of this section; otherwise, use weekly values.



### CO Flare HHV EmF p p

p

n

2 

### (Eq. Y-2)

=× × × × ⎡ ⎣ ⎤ ⎦

= 

# ∑ 0 98 0 001

1



### . . ( )( )

Where:

CO 2 = Annual CO 2 emissions for a specific fuel type (metric tons/year). 0.98 = Assumed combustion efficiency of a
flare. 0.001 = Unit conversion factor (metric tons per kilogram, mt/kg). n = Number of measurement periods. The minimum value for n is 52 (for weekly measurements); the maximum value for n is 366 (for daily measurements during a leap year). p = Measurement period index. (Flare) p = Volume of flare gas combusted during measurement period (million (MM) scf/period). If a mass flow meter is used, you must also measure molecular weight and convert the mass flow to a volumetric flow as follows: Flare[MMscf]

= 0.000001 × Flare[kg] × MVC/(MW) p , where MVC is the molar volume conversion factor (849.5 scf/kg-mole) and (MW) p is the average molecular weight of the flare gas combusted during measurement period (kg/kg-mole). (HHV) p = Higher heating value for the flare gas combusted during measurement period (British thermal units per scf, Btu/scf = MMBtu/MMscf). If measurements are taken more frequently than daily, use the arithmetic average of measurement values within the day to calculate a daily average.
EmF = Default CO 2 emission factor of 60 kilograms CO 2 /MMBtu (HHV basis).
(iii) Alternative to heat value or
carbon content measurements. If you do not measure the higher heating value or carbon content of the flare gas at least weekly, determine the quantity of gas discharged to the flare separately for periods of routine flare operation and for periods of start-up, shutdown, or malfunction, and calculate the CO 2 emissions as specified in paragraphs (b)(1)(iii)(A) through (b)(1)(iii)(C) of this

section.

(A) For periods of start-up, shutdown, or malfunction, use engineering calculations and process knowledge to
estimate the carbon content of the flared gas for each start-up, shutdown, or malfunction event exceeding 500,000 scf/day.

(B) For periods of normal operation, use the average heating value measured for the fuel gas for the heating value of the flare gas. If heating value is not measured, the heating value may be
estimated from historic data or engineering calculations.

(C) Calculate the CO 2 emissions using Equation Y–3 of this section.



### CO Flare HHV EmF Flare MW

MVC Norm SSM p p 2 

### =× × × × + × 

## ( ) × 0 98 0 001 44

12 . . ( )

× ⎡

⎣ ⎢ ⎤

⎦ ⎥ ⎛

⎝ ⎜ ⎜ ⎞

⎠ ⎟ ⎟

= 

# ∑ ( ) CC p

p

n

1 

### (Eq. Y-3)

Where:

CO 2 = Annual CO 2 emissions for a specific fuel type (metric tons/year). 0.98 = Assumed combustion efficiency of a
flare. 0.001 = Unit conversion factor (metric tons per kilogram, mt/kg).
Flare Norm = Annual volume of flare gas combusted during normal operations from company records, (million (MM) standard cubic feet per year, MMscf/ year). HHV = Higher heating value for fuel gas or flare gas from company records (British thermal units per scf, Btu/scf = MMBtu/ MMscf).

EmF = Default CO 2 emission factor for flare gas of 60 kilograms CO 2 /MMBtu (HHV basis). n = Number of start-up, shutdown, and malfunction events during the reporting year exceeding 500,000 scf/day. p = Start-up, shutdown, and malfunction
event index. 44 = Molecular weight of CO 2 (kg/kg-mole). 12 = Atomic weight of C (kg/kg-mole). (Flare SSM ) p = Volume of flare gas combusted during indexed start-up, shutdown, or malfunction event from engineering calculations, (scf/event). (MW) p = Average molecular weight of the flare gas, from the analysis results or engineering calculations for the event (kg/kg-mole).
MVC = Molar volume conversion factor (849.5 scf/kg-mole). (CC) p = Average carbon content of the flare gas, from analysis results or engineering calculations for the event (kg C per kg flare gas).

(2) Calculate CH4 using Equation Y–
4 of this section.


### 56453 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

CH EmF

EmF (Eq. Y-4) 4 CH4



### = ×

⎛ ⎝ ⎜ ⎞ ⎠ ⎟ + × ×× CO 224 

### 0 02

0 98 16

44 CO f CH 

### .

.

Where:

CH 4 = Annual methane emissions from flared gas (metric tons CH 4 /year).

CO 2 = Emission rate of CO 2 from flared gas calculated in paragraph (b)(1) of this section (metric tons/year).

EmF CH4 = Default CH 4 emission factor for
‘‘PetroleumProducts’’ from Table C–2 of subpart C of this part (General Stationary Fuel Combustion Sources) (kg CH4 / MMBtu).
EmF = Default CO 2 emission factor for flare gas of 60 kg CO 2 /MMBtu (HHV basis).
0.02/0.98 = Correction factor for flare combustion efficiency.
16/44 = Correction factor ratio of the molecular weight of CH4 to CO 2
. f CH4 = Weight fraction of carbon in the flare gas prior to combustion that is contributed by methane from measurement values or engineering calculations (kg C in methane in flare gas/kg C in flare gas); default is 0.4.
(3) Calculate N 2 O emissions using Equation Y–5 of this section.



### N O CO EmF

EmF (Eq. Y-5) 2 2 N2O 

### = ×

⎛ ⎝ ⎜ ⎞ ⎠ ⎟

Where:

N 2 O = Annual nitrous oxide emissions from flared gas (metric tons N 2 O/year).

CO 2 = Emission rate of CO 2 from flared gas calculated in paragraph (b)(1) of this section (metric tons/year). EmF N2O = Default N 2 O emission factor for
‘‘PetroleumProducts’’ from Table C–2 of subpart C of this part (General Stationary Fuel Combustion Sources) (kg N 2 O/ MMBtu).
EmF = Default CO 2 emission factor for flare gas of 60 kg CO 2 /MMBtu (HHV basis). (c) For catalytic cracking units and traditional fluid coking units, calculate the GHG emissions using the applicable methods described in paragraphs (c)(1) through (c)(5) of this section.

(1) If you operate and maintain a
CEMS that measures CO 2 emissions according to subpart C of this part (General Stationary Fuel Combustion Sources), you must calculate and report

CO 2 emissions as provided in paragraphs (c)(1)(i) and (c)(1)(ii) of this section. Other catalytic cracking units and traditional fluid coking units must either install a CEMS that complies with the Tier 4 Calculation Methodology in subpart C of this part (General Stationary Combustion Sources), or follow the requirements of paragraphs (c)(2) or (3) of this section.

(i) Calculate CO 2 emissions by following the Tier 4 Calculation Methodology specified in § 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources). (ii) If a CO boiler or other postcombustion device is used, you must
also calculate the CO 2 emissions fromthe fuel fired to the CO boiler or postcombustion device using the applicable methods for stationary combustion units in subpart C of this part. Calculate the process emissions from the catalytic cracking unit or fluid coking unit as the
difference in the CO 2 CEMS emissions
and the calculated combustion
emissions associated with the CO boiler.

(2) For catalytic cracking units and fluid coking units with rated capacities greater than 10,000 barrels per stream day (bbls/sd) that do not use a

continuous CO 2 CEMS for the final exhaust stack, you must continuously or no less frequently than hourly monitor
the O 2 , CO 2 , and (if necessary) CO
concentrations in the exhaust stack from the catalytic cracking unit regenerator or fluid coking unit burner prior to the
combustion of other fossil fuels and
calculate the CO 2 emissions according to the requirements of paragraphs (c)(2)(i) through (c)(2)(iii) of this section:

(i) Calculate the CO 2 emissions from each catalytic cracking unit and fluid coking unit using Equation Y–6 of this

section.



### CO Q CO CO

MVC r p p

p

n

2 2 

### % (Eq. Y-6) = 

## ( ) × + 

## ( )

× × ⎡

⎣ ⎢ ⎢ ⎤

⎦ ⎥ ⎥

= 

### %

100 44 0 001

1 

### % . 

# ∑

Where:

CO 2 = Annual CO 2 mass emissions (metric tons/year). Q

r = Volumetric flow rate of exhaust gas from

the fluid catalytic cracking unit regenerator or fluid coking unit burner prior to the combustion of other fossil fuels (dry standard cubic feet per hour, dscfh). %CO 2 = Hourly average percent CO 2 concentration in the exhaust gas stream from the fluid catalytic cracking unit regenerator or fluid coking unit burner (percent by volume—dry basis). %CO = Hourly average percent CO concentration in the exhaust gas stream from the fluid catalytic cracking unit regenerator or fluid coking unit burner (percent by volume—dry basis). When there is no post-combustion device, assume %CO to be zero. 44 = Molecular weight of CO 2 (kg/kg-mole).
MVC = Molar volume conversion factor (849.5 scf/kg-mole). 0.001 = Conversion factor (metric ton/kg). n = Number of hours in calendar year.

(ii) Either continuously monitor the volumetric flow rate of exhaust gas from the fluid catalytic cracking unit regenerator or fluid coking unit burner prior to the combustion of other fossil
fuels or calculate the volumetric flow rate of this exhaust gas stream using Equation Y–7 of this section.



### Q Q OQ

CO CO O r a oxy oxy



### = ∗+ − 

# ( ) ∗ 

# ( )

− −− 79 100

100 %

% %% 2 2 

### (Eq. Y-7)

Where:

Q

r = Volumetric flow rate of exhaust gas from

the fluid catalytic cracking unit regenerator or fluid coking unit burner prior to the combustion of other fossil fuels (dscfh). Q

a = Volumetric flow rate of air to the fluid

catalytic cracking unit regenerator or fluid coking unit burner, as determined

from control room instrumentation (dscfh). Q oxy = Volumetric flow rate of oxygen

enriched air to the fluid catalytic cracking unit regenerator or fluid coking

unit burner as determined from control room instrumentation (dscfh).


### 56454 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

%O 2 = Hourly average percent oxygen concentration in exhaust gas stream from the fluid catalytic cracking unit regenerator or fluid coking unit burner (percent by volume—dry basis). %O oxy = O 2 concentration in oxygen enriched gas stream inlet to the fluid catalytic cracking unit regenerator or fluid coking unit burner based on oxygen purity specifications of the oxygen supply used for enrichment (percent by volume—dry basis). %CO 2 = Hourly average percent CO 2 concentration in the exhaust gas stream from the fluid catalytic cracking unit regenerator or fluid coking unit burner (percent by volume—dry basis). %CO = Hourly average percent CO concentration in the exhaust gas stream from the fluid catalytic cracking unit regenerator or fluid coking unit burner (percent by volume—dry basis). When no auxiliary fuel is burned and a continuous CO monitor is not required under 40 CFR part 63 subpart UUU,
assume %CO to be zero.

(iii) If you have a CO boiler that uses auxiliary fuels or combusts materials other than catalytic cracking unit or fluid coking unit exhaust gas, you must
determine the CO 2 emissions resulting
from the combustion of these fuels or other materials following the requirements in subpart C and report those emissions by following the requirements of subpart C of this part.

(3) For catalytic cracking units and fluid coking units with rated capacities of 10,000 barrels per stream day (bbls/ sd) or less that do not use a continuous

CO 2 CEMS for the final exhaust stack, comply with the requirements in paragraph (c)(3)(i) of this section or paragraphs (c)(3)(ii) and (c)(3)(iii) of this section, as applicable. (i) If you continuously or no less frequently than daily monitor the O 2 , CO 2 , and (if necessary) CO
concentrations in the exhaust stack from the catalytic cracking unit regenerator or fluid coking unit burner prior to the combustion of other fossil fuels, you
must calculate the CO 2 emissions according to the requirements of paragraphs (c)(2)(i) through (c)(2)(iii) of this section, except that daily averages
are allowed and the summation can be performed on a daily basis.

(ii) If you do not monitor at least daily
the O 2 , CO 2 , and (if necessary) CO
concentrations in the exhaust stack from the catalytic cracking unit regenerator or fluid coking unit burner prior to the combustion of other fossil fuels,
calculate the CO 2 emissions from each catalytic cracking unit and fluid coking unit using Equation Y–8 of this section.



### CO Q CBF CC unit 2 

### 0 001 44

12 = × × ×× ( . ) (Eq. Y-8)

Where:

CO 2 = Annual CO 2 mass emissions (metric tons/year). Q

unit = Annual throughput of unit from company records (barrels (bbls) per year, bbl/yr). CBF = Coke burn-off factor from engineering calculations (kg coke per barrel of feed); default for catalytic cracking units = 7.3; default for fluid coking units = 11. 0.001 = Conversion factor (metric ton/kg).
CC = Carbon content of coke based on measurement or engineering estimate (kg C per kg coke); default = 0.94. 44/12 = Ratio of molecular weight of CO 2 to C (kg CO 2 per kg C).

(iii) If you have a CO boiler that uses auxiliary fuels or combusts materials other than catalytic cracking unit or fluid coking unit exhaust gas, you must
determine the CO 2 emissions resulting
from the combustion of these fuels or other materials following the requirements in subpart C of this part (General Stationary Fuel Combustion Sources) and report those emissions by following the requirements of subpart C of this part.

(4) Calculate CH4 emissions using either unit specific measurement data, a unit-specific emission factor based on a source test of the unit, or Equation Y–
9 of this section.



### CH EmF

EmF (Eq. Y-9) 4 2

1 

### = ∗

⎛
⎝ ⎜ ⎞
⎠ ⎟ CO 2

Where:

CH 4 = Annual methane emissions from coke burn-off (metric tons CH4 /year). CO 2 = Emission rate of CO 2 from coke burnoff calculated in paragraphs (c)(1), (c)(2), (e)(1), (e)(2), (g)(1), or (g)(2) of this section, as applicable (metric tons/year).

EmF 1 = Default CO 2 emission factor for petroleum coke from Table C–1 of subpart C of this part (General Stationary Fuel Combustion Sources) (kg CO 2 / MMBtu).

EmF 2 = Default CH 4 emission factor for
‘‘PetroleumProducts’’ from Table C–2 of subpart C of this part (General Stationary Fuel Combustion Sources) (kg CH4 / MMBtu).
(5) Calculate N 2 O emissions using either unit specific measurement data, a unit-specific emission factor based on a source test of the unit, or Equation Y–
10 of this section.



### N O EmF

EmF (Eq. Y-10) 2 3

1 

### = ∗

⎛
⎝ ⎜ ⎞
⎠ ⎟ CO 2

Where:

N 2 O = Annual nitrous oxide emissions from coke burn-off (mt N 2 O/year).

CO 2 = Emission rate of CO 2 from coke burnoff calculated in paragraphs (c)(1), (c)(2), (e)(1), (e)(2), (g)(1), or (g)(2) of this section, as applicable (metric tons/year).

EmF 1 = Default CO 2 emission factor for petroleum coke from Table C–1 of subpart C of this part (General Stationary Fuel Combustion Sources) (kg CO 2 / MMBtu).

EmF 3 = Default N 2 O emission factor for
‘‘PetroleumProducts’’ from Table C–2 of subpart C of this part (kg N 2 O/MMBtu). (d) For fluid coking units that use the flexicoking design, the GHG emissions from the resulting use of the low value fuel gas must be accounted for only once. Typically, these emissions will be accounted for using the methods described in subpart C of this part (General Stationary Fuel Combustion Sources). Alternatively, you may use the methods in paragraph (c) of this section provided that you do not otherwise account for the subsequent combustion of this low value fuel gas.

(e) For catalytic reforming units,
calculate the CO 2 emissions using the applicable methods described in paragraphs (e)(1) through (e)(3) of this
section and calculate the CH4 and N 2 O emissions using the methods described in paragraphs (c)(4) and (c)(5) of this section, respectively.

(1) If you operate and maintain a
CEMS that measures CO 2 emissions according to subpart C of this part (General Stationary Fuel Combustion Sources), you must calculate CO 2 emissions as provided in paragraphs (c)(1)(i) and (c)(1)(ii) of this section. Other catalytic reforming units must either install a CEMS that complies with the Tier 4 Calculation Methodology in subpart C of this part, or follow the requirements of paragraph (e)(2) or (e)(3)
of this section.

(2) If you continuously or no less frequently than daily monitor the O 2 , CO 2 , and (if necessary) CO
concentrations in the exhaust stack from the catalytic reforming unit catalyst regenerator prior to the combustion of other fossil fuels, you must calculate the

CO 2 emissions according to the requirements of paragraphs (c)(2)(i) through (c)(2)(iii) of this section.


### 56455 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

(3) Calculate CO 2 emissions from the catalytic reforming unit catalyst regenerator using Equation Y–11 of this

section.



### CO CB CC Q
n n

2

1 

### 44

12 0 001 = 

# ( ) × ×× ⎡
⎣ ⎢ ⎤
⎦ ⎥ 

# ∑ . (Eq. Y-11)

Where:

CO 2 = Annual CO 2 emissions (metric tons/ year).

CB Q = Coke burn-off quantity per regeneration cycle from engineering estimates (kg coke/cycle). n = Number of regeneration cycles in the calendar year.
CC = Carbon content of coke based on measurement or engineering estimate (kg C per kg coke); default = 0.94. 44/12 = Ratio of molecular weight of CO 2 to C (kg CO 2 per kg C). 0.001 = Conversion factor (metric ton/kg).

(f) For on-site sulfur recovery plants, calculate and report CO 2 process emissions from sulfur recovery plants according to the requirements in paragraphs (f)(1) through (f)(5) of this
section. Combustion emissions from the sulfur recovery plant (e.g., from fuel
combustion in the Claus burner or the tail gas treatment incinerator) must be reported under subpart C of this part (General Stationary Fuel Combustion Sources). For the purposes of this subpart, the sour gas stream for which monitoring is required according to paragraphs (f)(2) through (f)(5) of this
section is not considered a fuel.

(1) If you operate and maintain a
CEMS that measures CO 2 emissions according to subpart C of this part, you
must calculate CO 2 emissions under this subpart by following the Tier 4 Calculation Methodology specified in § 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources). You must monitor fuel use in the Claus burner, tail gas incinerator, or other combustion sources that discharge via the final exhaust stack from the sulfur recovery plant and calculate the combustion emissions from the fuel use according to subpart C of this part. Calculate the process emissions from the sulfur recovery plant as the difference in the

CO 2 CEMS emissions and the calculated
combustion emissions associated with the sulfur recovery plant final exhaust stack. Other sulfur recovery plants must either install a CEMS that complies with the Tier 4 Calculation Methodology in subpart C, or follow the requirements of paragraphs (f)(2) through (f)(5) of this

section.

(2) Flow measurement. If you have a continuous flow monitor on the sour gas feed to the sulfur recovery plant, you
must use the measured flow rates when the monitor is operational to calculate the sour gas flow rate. If you do not have
a continuous flow monitor on the sour gas feed to the sulfur recovery plant, you must use engineering calculations, company records, or similar estimates of volumetric sour gas flow.

(3) Carbon content. If you have a continuous gas composition monitor capable of measuring carbon content on the sour gas feed to the sulfur recovery plant or if you monitor gas composition for carbon content on a routine basis, you must use the measured carbon content value. Alternatively, you may develop a site-specific carbon content factor using limited measurement data or engineering estimates or use the
default factor of 0.20.

(4) Calculate the CO 2 emissions from each sulfur recovery plant using Equation Y–12 of this section.



### CO F MVC MF SG C 2 

### =∗ ∗ ∗ 44 0.001 (Eq. Y-12)

Where:

CO 2 = Annual CO 2 emissions (metric tons/ year).

F SG = Volumetric flow rate of sour gas feed (including sour water stripper gas) to the sulfur recovery plant (scf/year). 44 = Molecular weight of CO 2 (kg/kg-mole).
MVC = Molar volume conversion factor (849.5 scf/kg-mole).

MF C = Mole fraction of carbon in the sour gas to the sulfur recovery plant (kg-mole C/ kg-mole gas); default = 0.20. 0.001 = Conversion factor, kg to metric tons.

(5) If tail gas is recycled to the front of the sulfur recovery plant and the recycled flow rate and carbon content is
included in the measured data under paragraphs (f)(2) and (f)(3) of this section, respectively, then the annual

CO 2 emissions calculated in paragraph (f)(4) of this section must be corrected to avoid double counting these emissions. You may use engineering estimates to perform this correction or
assume that the corrected CO 2 emissions are 95 percent of the uncorrected value calculated using Equation Y–12 of this

section.

(g) For coke calcining units, calculate GHG emissions according to the applicable provisions in paragraphs (g)(1) through (g)(3) of this section.

(1) If you operate and maintain a
CEMS that measures CO 2 emissions according to subpart C of this part, you must calculate and report CO 2 emissions under this subpart by following the Tier 4 Calculation Methodology specified in § 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources). You must monitor fuel use in the coke calcining unit that discharges via the final exhaust stack from the coke calcining unit and
calculate the combustion emissions from the fuel use according to subpart C of this part. Calculate the process emissions from the coke calcining unit
as the difference in the CO 2 CEMS
emissions and the calculated
combustion emissions associated with the coke calcining unit final exhaust stack. Other coke calcining units must either install a CEMS that complies with the Tier 4 Calculation Methodology in subpart C of this part, or follow the requirements of paragraph (g)(2) of this

section.

(2) Calculate the CO 2 emissions from the coke calcining unit using Equation
Y–13 of this section.


### 56456 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

CO M CC M M CC in GC out dust MPC 2 

### = 44

12 (Eq. Y-13) ∗∗ − + 

## ( ) ∗ 

# ( )

Where:

CO 2 = Annual CO 2 emissions (metric tons/ year).

M in = Annual mass of green coke fed to the coke calcining unit from facility records (metric tons/year).

CC GC = Average mass fraction carbon content of green coke from facility measurement data (metric ton carbon/metric ton green coke).

M out = Annual mass of marketable petroleum coke produced by the coke calcining unit from facility records (metric tons petroleum coke/year).

M dust = Annual mass of petroleum coke dust collected in the dust collection system of the coke calcining unit from facility records (metric ton petroleum coke dust/ year).

CC MPC = Average mass fraction carbon content of marketable petroleum coke produced by the coke calcining unit from facility measurement data (metric ton carbon/metric ton petroleum coke). 44 = Molecular weight of CO 2 (kg/kg-mole). 12 = Atomic weight of C (kg/kg-mole).

(3) For all coke calcining units, use
the CO 2 emissions from the coke calcining unit calculated in paragraphs (g)(1) or (g)(2), as applicable, and calculate CH4 using the methods described in paragraph (c)(4) of this
section and N 2 O emissions using the methods described in paragraph (c)(5) of
this section.

(h) For asphalt blowing operations, calculate GHG emissions according to the requirements in paragraph (j) of this section or according to the applicable provisions in paragraphs (h)(1) and (h)(2) of this section.

(1) For uncontrolled asphalt blowing operations or asphalt blowing operations controlled by vapor scrubbing, calculate CO 2 and CH 4 emissions using Equations Y–14 and Y– 15 of this section, respectively.



### CO Q EF AB AB.CO 2 

### (Eq. Y-14)

= ×



## ( ) 2

Where:

CO 2 = Annual CO 2 emissions from uncontrolled asphalt blowing (metric

tons CO 2 /year). Q

AB = Quantity of asphalt blown (million

barrels per year, MMbbl/year).

EF AB,CO2 = Emission factor for CO 2 from uncontrolled asphalt blowing from facility-specific test data (metric tons CO 2 /MMbbl asphalt blown); default =

1,100.

CH Q EF AB AB,CH 4 4

= ×



## ( ) (Eq. Y-15)

Where:

CH 4 = Annual methane emissions from uncontrolled asphalt blowing (metric

tons CH 4 /year). Q

AB = Quantity of asphalt blown (million

barrels per year, MMbbl/year).

EF AB,CH4 = Emission factor for CH4 from uncontrolled asphalt blowing from facility-specific test data (metric tons

CH 4 /MMbbl asphalt blown); default =

580.

(2) For asphalt blowing operations controlled by thermal oxidizer or flare,
calculate CO 2 and CH 4 emissions using Equations Y–16 and Y–17 of this section, respectively, provided these emissions are not already included in
the flare emissions calculated in paragraph (b) of this section or in the stationary combustion unit emissions required under subpart C of this part (General Stationary Fuel Combustion Sources).



### CO Q CEF AB AB 2 

### (Eq. Y-16)

=× × × ⎛ ⎝ ⎜ ⎞ ⎠ ⎟ 0 98 44

12 .

Where:

CO 2 = Annual CO 2 emissions from controlled asphalt blowing (metric tons CO 2 /year). 0.98 = Assumed combustion efficiency of
thermal oxidizer or flare. Q AB = Quantity of asphalt blown (MMbbl/

year).

CEF AB = Carbon emission factor from asphalt blowing from facility-specific test data (metric tons C/MMbbl asphalt blown); default = 2,750. 44 = Molecular weight of CO 2 (kg/kg-mole). 12 = Atomic weight of C (kg/kg-mole).



### CH Q EF AB AB,CH 4 4 

### 0 02 =× × 

# ( ) . (Eq. Y-17)

Where:

CH 4 = Annual methane emissions from controlled asphalt blowing (metric tons

CH 4 /year).
0.02 = Fraction of methane uncombusted in
thermal oxidizer or flare based on assumed 98% combustion efficiency. Q

AB = Quantity of asphalt blown (million

barrels per year, MMbbl/year).

EF AB,CH4 = Emission factor for CH4 from uncontrolled asphalt blowing from facility-specific test data (metric tons

CH 4 /MMbbl asphalt blown); default =

580. (i) For delayed coking units, calculate
the CH 4 emissions from the depressurization of the coking unit vessel (i.e., the ‘‘coke drum’’) to atmosphere using either of the methods provided in paragraphs (i)(1) or (i)(2), provided no water or steam is added to
the vessel once it is vented to the atmosphere. You must use the method in paragraph (i)(1) of this section if you
add water or steam to the vessel after it is vented to the atmosphere. (1) Use the process vent method in paragraph (j) of this section and also
calculate the CH4 emissions from the subsequent opening of the vessel for coke cutting operations using Equation Y–18 of this section. If you have coke
drums or vessels of different dimensions, use Equation Y–18 for each
set of coke drums or vessels of the same
size and sum the resultant emissions
across each set of coke drums or vessels
to calculate the CH4 emissions for all delayed coking units.



### CH N H P f D

MVC MF CV void CH 4 

### = 14.7 4 × × + 

## ( )

× × × ×× × ⎛

⎝ ⎜ ⎜ ⎞

⎠ 14 7 16 0 001 2



### .

. π

4 

### ⎟ ⎟ (Eq. Y-18)


### 56457 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

Where:

CH 4 = Annual methane emissions from the delayed coking unit vessel opening (metric ton/year). N = Cumulative number of vessel openings for all delayed coking unit vessels of the same dimensions during the year. H = Height of coking unit vessel (feet).

P CV = Gauge pressure of the coking vessel when opened to the atmosphere prior to coke cutting or, if the alternative method provided in paragraph (i)(2) of this section is used, gauge pressure of the coking vessel when depressurization gases are first routed to the atmosphere (pounds per square inch gauge, psig). 14.7 = Assumed atmospheric pressure (pounds per square inch, psi).
f void = Volumetric void fraction of coking vessel prior to steaming (cf gas/cf of vessel); default = 0.6. D = Diameter of coking unit vessel (feet). 16 = Molecular weight of CH4 (kg/kg-mole).
MVC = Molar volume conversion factor (849.5 scf/kg-mole).

MF CH4 = Mole fraction of methane in coking vessel gas (kg-mole CH4 /kg-mole gas, wet basis); default value is 0.01. 0.001 = Conversion factor (metric ton/kg).

(2) Calculate the CH4 emissions from the depressurization vent and subsequent opening of the vessel for coke cutting operations using Equation Y–18 of this section and the pressure of the coking vessel when the depressurization gases are first routed to the atmosphere. If you have coke drums or vessels of different dimensions, use Equation Y–18 for each set of coke
drums or vessels of the same size and
sum the resultant emissions across each set of coke drums or vessels to calculate
the CH4 emissions for all delayed coking

units.

(j) For each process vent not covered in paragraphs (a) through (i) of this section that can be reasonably expected to contain greater than 2 percent by
volume CO 2 or greater than 0.5 percent by volume of CH4 or greater than 0.01 percent by volume (100 parts per million) of N 2 O, calculate GHG emissions using the Equation Y–19 of this section. You must use Equation Y– 19 of this section for catalytic reforming unit depressurization and purge vents when methane is used as the purge gas or if you elected this method as an alternative to the methods in paragraphs (h)(1) or (h)(2) of this section.



### E VR MF MW

MVC VT x px p x p

p N 

### = (Eq. Y-19)

=1 

### () () . × 

## ( ) ×× × ⎛ ⎝ ⎜ ⎞ ⎠ ⎟ 

# ∑ 0 001

Where:

E

x = Annual emissions of each GHG from process vent (metric ton/yr). N = Number of venting events per year. P = Index of venting events. (VR) p = Average volumetric flow rate of process gas during the event (scf per hour). (MF

x ) p = Mole fraction of GHG x in process vent during the event (kg-mol of GHG x/ kg-mol vent gas). MW

x = Molecular weight of GHG x (kg/kgmole); use 44 for CO 2 or N 2 O and 16 for

CH 4
. MVC = Molar volume conversion factor (849.5 scf/kg-mole). (VT) p = Venting time for the event, (hours). 0.001 = Conversion factor (metric ton/kg).

(k) For uncontrolled blowdown systems, you must either use the methods for process vents in paragraph (j) of this section or calculate CH4 emissions using Equation Y–20 of this section. Blowdown systems where the uncondensed gas stream is routed to a
flare or similar control device is
considered to be controlled and is not required to estimate emissions under this paragraph (k).



### CH Q EF MVC f BD 4 

### = (Eq. Y-20) Re 

### ××× ⎛ ⎝ ⎜ ⎞ ⎠ ⎟ 16 0 001

.

Where:

CH 4 = Methane emission rate from blowdown systems (mt CH 4 /year). Q

Ref = Quantity of crude oil plus the quantity of intermediate products received from off site that are processed at the facility (MMbbl/year).

EF BD = Methane emission factor for uncontrolled blown systems (scf CH4 / MMbbl); default is 137,000. 16 = Molecular weight of CH4 (kg/kg-mole).

MVC = Molar volume conversion factor (849.5 scf/kg-mole). 0.001 = Conversion factor (metric ton/kg).

(l) For equipment leaks, calculate CH4 emissions using the method specified in either paragraph (l)(1) or (l)(2) of this

section. (1) Use process-specific methane composition data (from measurement data or process knowledge) and any of the emission estimation procedures provided in the Protocol for Equipment Leak Emissions Estimates (EPA–453/R– 95–017, NTIS PB96–175401).

(2) Use Equation Y–21 of this section.



### CH N N N N N CD PU PU H FGS 4 12



### = 0.4 + 0.2 + 0.1 + 4.3 (Eq. × × × × +× 

## ( ) 2 

### 6 Y-21)

Where:

CH 4 = Annual methane emissions from equipment leaks (metric tons/year).

N CD = Number of atmospheric crude oil distillation columns at the facility.

N PU1 = Cumulative number of catalytic cracking units, coking units (delayed or fluid), hydrocracking, and full-range distillation columns (including depropanizer and debutanizer distillation columns) at the facility. N PU2 = Cumulative number of hydrotreating/ hydrorefining units, catalytic reforming units, and visbreaking units at the facility.

N H2 = Total number of hydrogen plants at the facility.

NFGS = Total number of fuel gas systems at the facility.

(m) For storage tanks, except as provided in paragraph (m)(3) of this section, calculate CH4 emissions using the applicable methods in paragraphs (m)(1) and (m)(2) of this section.

(1) For storage tanks other than those processing unstabilized crude oil, you
must either calculate CH4 emissionsfrom storage tanks that have a vaporphase methane concentration of 0.5volume percent or more using tankspecific methane composition data (from measurement data or product knowledge) and the AP–42 emission


### 56458 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

estimation methods provided in Section 7.1 of the AP–42: ‘‘Compilation of Air Pollutant Emission Factors, Volume 1: Stationary Point and Area Sources’’, including TANKS Model (Version 4.09D) or similar programs, or estimate

CH 4 emissions from storage tanks using Equation Y–22 of this section. 

### CH Q f 4 

### = 0.1 (Eq. Y-22) × 

# ( )
Re

Where:

CH 4 = Annual methane emissions from storage tanks (metric tons/year). 0.1 = Default emission factor for storage tanks (metric ton CH 4 /MMbbl). Q

Ref = Quantity of crude oil plus the quantity of intermediate products received from off site that are processed at the facility (MMbbl/year). (2) For storage tanks that process unstabilized crude oil, calculate CH4 emissions from the storage ofunstabilized crude oil using either tankspecific methane composition data (from measurement data or product knowledge) and direct measurement of the gas generation rate or by using Equation Y–23 of this section.



### CH Q P MF MVC un CH 4 

### = 995,000 16 (Eq. Y-23) × × 

## ( ) × ×× Δ 4 

### 0 001

.

Where:

CH 4 = Annual methane emissions from storage tanks (metric tons/year). Q

un = Quantity of unstabilized crude oil

received at the facility (MMbbl/year).

DP = Pressure differential from the previous storage pressure to atmospheric pressure (pounds per square inch, psi).

MF CH4 = Mole fraction of CH4 in vent gas from the unstabilized crude oil storagetank from facility measurements (kgmole CH 4 /kg-mole gas); use 0.27 as a
default if measurement data are not
available. 995,000 = Correlation Equation factor (scf gas per MMbbl per psi). 16 = Molecular weight of CH4 (kg/kg-mole).
MVC = Molar volume conversion factor (849.5 scf/kg-mole). 0.001 = Conversion factor (metric ton/kg).

(3) You do not need to calculate CH4 emissions from storage tanks that meet any of the following descriptions:

(i) Units permanently attached to conveyances such as trucks, trailers, rail cars, barges, or ships;

(ii) Pressure vessels designed to operate in excess of 204.9 kilopascals
and without emissions to the atmosphere;

(iii) Bottoms receivers or sumps; (iv) Vessels storing wastewater; or (v) Reactor vessels associated with a manufacturing process unit.

(n) For crude oil, intermediate, or product loading operations for which the equilibrium vapor-phase
concentration of methane is 0.5 volume percent or more, calculate CH4 emissions from loading operations using product-specific, vapor-phase methane composition data (from measurement data or process knowledge) and the emission estimation procedures provided in Section 5.2 of the AP–42: ‘‘Compilation of Air Pollutant Emission Factors, Volume 1: Stationary Point and Area Sources.’’ For loading operations in which the equilibrium vapor-phase
concentration of methane is less than 0.5 volume percent, you may assume
zero methane emissions. **§ 98.254 Monitoring and QA/QC requirements.** 

(a) Fuel flow meters, gas composition monitors, and heating value monitors associated with stationary combustion sources must follow the monitoring and QA/QC requirements in § 98.34.

(b) All flow meters, gas composition monitors, and heating value monitors that are used to provide data for the
GHG emissions calculations in this subpart for sources other than stationary
combustion sources shall be calibrated according to the procedures in the applicable methods specified in paragraphs (c) through (e) of this section, the procedures specified by the manufacturer, or §§ 98.3(i). Recalibrate each flow meter either biennially (every two years) or at the minimum frequency specified by the manufacturer. Recalibrate each gas composition monitor and heating value monitor either annually or at the minimum frequency specified by the
manufacturer.

(c) For flare or sour gas flow meters, operate and maintain the flow meter using any of the following methods, a method published by a consensus-based standards organization (e.g., ASTM, API, etc.) or follow the procedures specified by the flow meter
manufacturer. Flow meters must have a rated accuracy of ± 5 percent or lower.

(1) ASME MFC–3M–2004 Measurement of Fluid Flow in Pipes Using Orifice, Nozzle, and Venturi (incorporated by reference, see § 98.7).

(2) ASME MFC–4M–1986 (Reaffirmed 1997) Measurement of Gas Flow by Turbine Meters (incorporated by reference, see § 98.7).

(3) ASME MFC–6M–1998 Measurement of Fluid Flow in Pipes Using Vortex Flowmeters (incorporated by reference, see § 98.7).

(4) ASME MFC–7M–1987 (Reaffirmed 1992) Measurement of Gas Flow by
Means of Critical Flow Venturi Nozzles (incorporated by reference, see § 98.7). (5) ASME MFC–11M–2006 Measurement of Fluid Flow by Means of Coriolis Mass Flowmeters (incorporated by reference, see § 98.7).

(6) ASME MFC–14M–2003 Measurement of Fluid Flow Using Small
Bore Precision Orifice Meters (incorporated by reference, see § 98.7).

(7) ASME MFC–18M–2001 Measurement of Fluid Flow Using Variable Area Meters (incorporated by reference, see § 98.7).

(8) AGA Report No. 11 Measurement of Natural Gas by Coriolis Meter (2003) (incorporated by reference, see § 98.7).

(d) Determine flare gas composition using any of the following methods.

(1) Method 18 at 40 CFR part 60, appendix A–6.

(2) ASTM D1945–03 Standard Test Method for Analysis of Natural Gas by Gas Chromatography (incorporated by reference, see § 98.7).

(3) ASTM D1946–90 (Reapproved 2006) Standard Practice for Analysis of Reformed Gas by Gas Chromatography (incorporated by reference, see § 98.7).

(4) GPA 2261–00 Analysis for Natural Gas and Similar Gaseous Mixtures by Gas Chromatography (incorporated by reference, see § 98.7).

(5) UOP539–97 Refinery Gas Analysis by Gas Chromatography (incorporated by reference, see § 98.7).

(e) Determine flare gas higher heating value using any of the following
methods.

(1) ASTM D4809–06 Standard Test
Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method) (incorporated by reference, see § 98.7).

(2) ASTM D240–02 (Reapproved 2007) Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter (incorporated by reference, see § 98.7).

(3) ASTM D1826–94 (Reapproved 2003) Standard Test Method for Calorific (Heating) Value of Gases in Natural Gas Range by Continuous Recording Calorimeter (incorporated by reference, see § 98.7).


### 56459 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

(4) ASTM D3588–98 (Reapproved 2003) Standard Practice for Calculating Heat Value, Compressibility Factor, and Relative Density of Gaseous Fuels (incorporated by reference, see § 98.7).

(5) ASTM D4891–89 (Reapproved 2006) Standard Test Method for Heating Value of Gases in Natural Gas Range by
Stoichiometric Combustion (incorporated by reference, see § 98.7).

(f) For exhaust gas flow meters used to comply with the requirements in § 98.253(c)(2)(ii), install, operate, calibrate, and maintain exhaust gas flow meter according to the requirements in 40 CFR 63.1572(c) or according to the following requirements.

(1) Locate the flow meter(s) and other necessary equipment such as straightening vanes in a position that provides representative flow; reduce swirling flow or abnormal velocity distributions due to upstream and
downstream disturbances.

(2) Use a flow rate meter with an accuracy within ± 5 percent.

(3) Use a continuous monitoring system capable of correcting for the temperature, pressure, and moisture content to output flow in dry standard cubic feet (standard conditions as defined in § 98.6).

(4) Install, operate, and maintain each continuous monitoring system according to the manufacturer’s specifications and requirements.

(g) For exhaust gas CO 2 /CO/O 2 composition monitors used to comply with the requirements in § 98.253(c)(2), install, operate, calibrate, and maintain exhaust gas composition monitors according to the requirements in 40 CFR 60.105a(b)(2) or 40 CFR 63.1572(a) or according to the manufacturer’s specifications and requirements.

(h) Determine the mass of petroleum coke as required by Equation Y–13 of this subpart using mass measurement equipment meeting the requirements for commercial weighing equipment as described in Specifications, Tolerances, and Other Technical Requirements For Weighing and Measuring Devices, NIST Handbook 44 (2009) (incorporated by reference, see § 98.7). Calibrate the measurement device according to the procedures specified by the method, the procedures specified by the manufacturer, or § 98.3(i). Recalibrate either biennially or at the minimum frequency specified by the
manufacturer.

(i) Determine the carbon content of petroleum coke as required by Equation Y–13 of this subpart using any one of the following methods. Calibrate the measurement device according to procedures specified by the method or procedures specified by the
measurement device manufacturer.

(1) ASTM D3176–89 (Reapproved 2002) Standard Practice for Ultimate Analysis of Coal and Coke (incorporated by reference, see § 98.7).

(2) ASTM D5291–02 (Reapproved 2007) Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants (incorporated by reference, see § 98.7).

(3) ASTM D5373–08 Standard Test
Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal (incorporated by reference, see § 98.7).

(j) Determine the quantity of petroleum process streams using company records. These quantities include the quantity of asphalt blown, quantity of crude oil plus the quantity of intermediate products received from off site, and the quantity of unstabilized crude oil received at the facility.

(k) The owner or operator shall document the procedures used to ensure the accuracy of the estimates of fuel usage, gas composition, and heating value including but not limited to calibration of weighing equipment, fuel flow meters, and other measurement devices. The estimated accuracy of
measurements made with these devices shall also be recorded, and the technical
basis for these estimates shall be provided.

(l) All CO 2 CEMS and flow rate
monitors used for direct measurement of GHG emissions must comply with the QA procedures in § 98.34(c).

**§ 98.255 Procedures for estimating missing data.** 

A complete record of all measured parameters used in the GHG emissions calculations is required (e.g., concentrations, flow rates, fuel heating values, carbon content values). Therefore, whenever a quality-assured value of a required parameter is unavailable (e.g., if a CEMS malfunctions during unit operation or if a required fuel sample is not taken), a substitute data value for the missing parameter shall be used in the
calculations.

(a) For stationary combustion sources, use the missing data procedures in subpart C of this part.

(b) For each missing value of the heat content, carbon content, or molecular weight of the fuel, substitute the arithmetic average of the quality-assured values of that parameter immediately preceding and immediately following the missing data incident. If the ‘‘after’’ value is not obtained by the end of the reporting year, you may use the ‘‘before’’ value for the missing data substitution. If, for a particular parameter, no quality-assured data are available prior to the missing data incident, the substitute data value shall be the first quality-assured value obtained after the missing data period.

(c) For missing CO 2 , CO, O 2 , CH 4 , or N 2 O concentrations, gas flow rate, and percent moisture, the substitute data
values shall be the best available estimate(s) of the parameter(s), based on all available process data (e.g., processing rates, operating hours, etc.). The owner or operator shall document and keep records of the procedures used
for all such estimates.

(d) For hydrogen plants, use the missing data procedures in subpart P of this part.

**§ 98.256 Data reporting requirements.**

In addition to the reporting requirements of § 98.3(c), you must report the information specified in paragraphs (a) through (q) of this

section.

(a) For combustion sources, follow the data reporting requirements under subpart C of this part (General Stationary Fuel Combustion Sources).

(b) For hydrogen plants, follow the data reporting requirements under subpart P of this part (Hydrogen Production).

(c) [Reserved] (d) [Reserved] (e) For flares, owners and operators shall report:

(1) The flare ID number (if applicable).

(2) A description of the type of flare (steam assisted, air-assisted).

(3) A description of the flare service (general facility flare, unit flare, emergency only or back-up flare).

(4) The calculated CO 2 , CH 4 , and N 2 O annual emissions for each flare, expressed in metric tons of each pollutant emitted.

(5) A description of the method used
to calculate the CO 2 emissions for each flare (e.g., reference section and equation number).

(6) If you use Equation Y–1 of this subpart, the annual volume of flare gas combusted (in scf/year) and the annualaverage molecular weight (in kg/kgmole) and carbon content of the flare gas (in kg carbon per kg flare gas).

(7) If you use Equation Y–2 of this subpart, the annual volume of flare gas combusted (in million (MM) scf/year) and the annual average higher heating value of the flare gas (in MMBtu per MMscf).

(8) If you use Equation Y–3 of this subpart, the annual volume of flare gas combusted (in MMscf/year) during


### 56460 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

normal operations, the annual average higher heating value of the flare gas (in MMBtu/MMscf), the number of SSM events exceeding 500,000 scf/day, and the volume of gas flared (in scf/event) and the average molecular weight (in kg/kg-mole) and carbon content of the flare gas (in kg carbon per kg flare) for each SSM event over 500,000 scf/day.

(9) The fraction of carbon in the flare gas contributed by methane used in Equation Y–4 of this subpart and the
basis for its value.

(f) For catalytic cracking units, traditional fluid coking units, and catalytic reforming units, owners and operators shall report:

(1) The unit ID number (if applicable). (2) A description of the type of unit (fluid catalytic cracking unit, thermal catalytic cracking unit, traditional fluid coking unit, or catalytic reforming unit).

(3) Maximum rated throughput of the unit, in bbl/stream day.

(4) The calculated CO 2 , CH 4 , and N 2 O annual emissions for each unit, expressed in metric tons of each pollutant emitted.

(5) A description of the method used
to calculate the CO 2 emissions for each unit (e.g., reference section and equation number).

(6) If you use a CEMS, the relevant information required under § 98.36(e)(2)(vi) for the Tier 4 Calculation Methodology, the CO 2 annual emissions as measured by the CEMS (unadjusted to remove CO 2 combustion emissions associated with a CO boiler, if present) and the process

CO 2 emissions as calculated according to § 98.253(c)(1)(ii). Report the CO 2 annual emissions associated with fuel combustion under subpart C of this part (General Stationary Fuel Combustion Sources).

(7) If you use Equation Y–6 of this subpart, the annual average exhaust gas flow rate, %CO 2 , and %CO.

(8) If you use Equation Y–7 of this subpart, the annual average flow rate of inlet air and oxygen-enriched air, %O 2 , %O oxy , %CO 2 , and %CO.

(9) If you use Equation Y–8 of this subpart, the coke burn-off factor, annual throughput of unit, and the average
carbon content of coke and the basis for
the value.

(10) Indicate whether you use a measured value, a unit-specific emission factor, or a default emission
factor for CH 4 emissions. If you use a unit-specific emission factor for CH4 ,report the units of measure for the unitspecific factor, the activity data for calculating emissions (e.g., if the
emission factor is based on coke burnoff rate, the annual quantity of coke burned), and the basis for the factor. (11) Indicate whether you use a measured value, a unit-specific emission factor, or a default emission
factor for N 2 O emissions. If you use a unit-specific emission factor for N 2 O,report the units of measure for the unitspecific factor, the activity data for calculating emissions (e.g., if the
emission factor is based on coke burnoff rate, the annual quantity of coke burned), and the basis for the factor.

(12) If you use Equation Y–11 of this subpart, the number of regeneration cycles during the reporting year, the average coke burn-off quantity per cycle, and the average carbon content of the
coke.

(g) For fluid coking unit of the flexicoking type, the owner or operator shall report:

(1) The unit ID number (if applicable). (2) A description of the type of unit. (3) Maximum rated throughput of the unit, in bbl/stream day.

(4) Indicate whether the GHG emissions from the low heat value gas are accounted for in subpart C of this part or § 98.253(c).

(5) If the GHG emissions for the low heat value gas are calculated at the flexicoking unit, also report the
calculated annual CO 2 , CH 4 , and N 2 O emissions for each unit, expressed in metric tons of each pollutant emitted, and the applicable equation input parameters specified in paragraphs (f)(7) through (f)(11) of this section.

(h) For sulfur recovery plants and for emissions from sour gas sent off-site for sulfur recovery, the owner and operator shall report:

(1) The plant ID number (if applicable).

(2) Maximum rated throughput of each independent sulfur recovery plant, in metric tons sulfur produced/stream day.

(3) The calculated CO 2 annual emissions for each sulfur recovery plant, expressed in metric tons. The calculated
annual CO 2 emissions from sour gas sent off-site for sulfur recovery, expressed in metric tons.

(4) If you use Equation Y–12 of this subpart, the annual volumetric flow to the sulfur recovery plant (in scf/year) and the annual average mole fraction ofcarbon in the sour gas (in kg-mole C/kgmole gas).

(5) If you recycle tail gas to the front of the sulfur recovery plant, indicate whether the recycled flow rate and
carbon content are included in the measured data under § 98.253(f)(2) and (3). Indicate whether a correction for

CO 2 emissions in the tail gas was used in Equation Y–12. If so, then report the value of the correction, the annual volume of recycled tail gas (in scf/year) and the annual average mole fraction ofcarbon in the tail gas (in kg-mole C/kgmole gas). Indicate whether you used the default (95%) or a unit specific correction, and if used, report the approach used.

(6) If you use a CEMS, the relevant information required under § 98.36(e)(2)(vi) for the Tier 4 Calculation Methodology, the CO 2 annual emissions as measured by the CEMS and the annual process CO 2 emissions calculated according to § 98.253(f)(1). Report the CO 2 annual
emissions associated with fuel combustion subpart C of this part (General Stationary Fuel Combustion Sources).

(i) For coke calcining units, the owner and operator shall report:

(1) The unit ID number (if applicable). (2) Maximum rated throughput of the unit, in metric tons coke calcined/ stream day.

(3) The calculated CO 2 , CH 4 , and N 2 O annual emissions for each unit, expressed in metric tons of each pollutant emitted.

(4) A description of the method used
to calculate the CO 2 emissions for each unit (e.g., reference section and equation number).

(5) If you use Equation Y–13 of this subpart, annual mass and carbon content of green coke fed to the unit, the
annual mass and carbon content of marketable coke produced, and the
annual mass of coke dust collected in dust collection systems.

(6) If you use a CEMS, the relevant information required under § 98.36(e)(2)(vi) for the Tier 4 Calculation Methodology, the CO 2 annual emissions as measured by the CEMS and the annual process CO 2 emissions calculated according to § 98.253(g)(1). Report the CO 2 annual
emissions associated with fuel combustion under subpart C of this part (General Stationary Fuel Combustion Sources).

(7) Indicate whether you use a measured value, a unit-specific
emission factor or a default for CH4 emissions. If you use a unit-specific
emission factor for CH4 , the unitspecific emission factor for CH4 , the units of measure for the unit-specific factor, the activity data for calculating emissions (e.g., if the emission factor is based on coke burn-off rate, the annual quantity of coke burned), and the basis
for the factor.

(8) If you use a site-specific emission factor in Equation Y–10 of this subpart, the site-specific emission factor and the
basis of the factor.

(j) For asphalt blowing operations, the owner or operator shall report:


### 56461 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

(1) The unit ID number (if applicable). (2) The quantity of asphalt blown (in Million bbl) at the facility in the reporting year.

(3) The type of control device used to reduce methane (and other organic)
emissions from the unit.

(4) The calculated annual CO 2 and

CH 4 emissions for each unit, expressed in metric tons of each pollutant emitted.

(5) If you use Equation Y–14 of this subpart, the CO 2 emission factor used
and the basis for the value.

(6) If you use Equation Y–15 of this subpart, the CH4 emission factor used
and the basis for the value.

(7) If you use Equation Y–16 of this subpart, the carbon emission factor used
and the basis for the value.

(8) If you use Equation Y–17 of this subpart, the CH4 emission factor used
and the basis for the value.

(k) For delayed coking units, the owner or operator shall report:

(1) The cumulative annual CH4 emissions (in metric tons of each pollutant emitted) for all delayed coking units at the facility.

(2) A description of the method used
to calculate the CH4 emissions for each unit (e.g., reference section and equation number).

(3) The total number of delayed coking units at the facility, the total number of delayed coking drums at the facility, and for each coke drum or vessel: the dimensions, the typical gauge pressure of the coking drum when first vented to the atmosphere, typical void fraction, the typical drum outage (i.e. the unfilled distance from the top of the drum, in feet), and annual number of coke-cutting cycles.

(4) For each set of coking drums that
are the same dimensions: The number of coking drums in the set, the height and diameter of the coke drums (in feet), the cumulative number of vessel openings for all delayed coking drums in the set, the typical venting pressure (in psig), void fraction (in cf gas/cf of vessel), and the mole fraction of methane in coking gas (in kg-mole CF 4 /kg-mole gas, wet basis).

(5) The basis for the volumetric void fraction of the coke vessel prior to steaming and the basis for the mole fraction of methane in the coking gas.

(l) For process vents subject to § 98.253(j), the owner or operator shall report:

(1) The vent ID number (if applicable). (2) The unit or operation associated
with the emissions.

(3) The type of control device used to reduce methane (and other organic) emissions from the unit, if applicable.

(4) The calculated annual CO 2 , CH 4 , and N 2 O emissions for each vent, expressed in metric tons of each pollutant emitted.

(5) The annual volumetric flow discharged to the atmosphere (in scf),
mole fraction of each GHG above the concentration threshold, and for intermittent vents, the number of venting events and the cumulative venting time.

(m) For uncontrolled blowdown systems, the owner or operator shall report:

(1) The cumulative annual CH4 emissions (in metric tons of each pollutant emitted) for uncontrolled blowdown systems.

(2) The total quantity (in Million bbl) of crude oil plus the quantity ofintermediate products received from offsite that are processed at the facility in the reporting year.

(3) The methane emission factor used for uncontrolled blowdown systems and
the basis for the value.

(n) For equipment leaks, the owner or operator shall report:

(1) The cumulative CH4 emissions (in metric tons of each pollutant emitted) for all equipment leak sources.

(2) The method used to calculate the reported equipment leak emissions.

(3) The number of each type of emission source listed in Equation Y–21 of this subpart at the facility.

(o) For storage tanks, the owner or operator shall report:

(1) The cumulative annual CH4 emissions (in metric tons of each pollutant emitted) for all storage tanks, except for those used to process
unstabilized crude oil.

(2) The method used to calculate the reported storage tank emissions for storage tanks other than those processing unstabilized crude (AP–42, TANKS 4.09D, Equation Y–22 of this subpart, other).

(3) The total quantity (in MMbbl) of crude oil plus the quantity ofintermediate products received from offsite that are processed at the facility in the reporting year.

(4) The cumulative CH4 emissions (in metric tons of each pollutant emitted) for storage tanks used to process
unstabilized crude oil.

(5) The method used to calculate the reported storage tank emissions for storage tanks processing unstabilized
crude oil.

(6) The quantity of unstabilized crude oil received during the calendar year (in MMbbl), the average pressure differential (in psi), and the mole
fraction of CH4 in vent gas from the unstabilized crude oil storage tank, and
the basis for the mole fraction.

(7) The tank-specific methane composition data and the gas generation rate data, if you did not use Equation Y–

23.

(p) For loading operations, the owner or operator shall report:

(1) The cumulative annual CH4 emissions (in metric tons of each pollutant emitted) for loading operations.

(2) The quantity and types of materials loaded by vessel type (barge, tanker, marine vessel, etc.) that have an equilibrium vapor-phase concentration of methane of 0.5 volume percent or greater, and the type of vessels in which
the material is loaded.

(3) The type of control system used to reduce emissions from the loading ofmaterial with an equilibrium vaporphase concentration of methane of 0.5 volume percent or greater, if any (submerged loading, vapor balancing, etc.).

(q) Name of each method listed in § 98.254 or a description of
manufacturer’s recommended method
used to determine a measured parameter.

**§ 98.257 Records that must be retained.**

In addition to the records required by § 98.3(g), you must retain the records of all parameters monitored under § 98.255.

**§ 98.258 Definitions.**

All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.

**Subpart Z—Phosphoric Acid**
**Production**

**§ 98.260 Definition of the source category.**

The phosphoric acid production source category consists of facilities with a wet-process phosphoric acid process line used to produce phosphoric acid. A wet-process phosphoric acid process line is the production unit or units identified by an individual identification number in an operating permit and/or any process unit or group of process units at a facility reacting phosphate rock from a common supply
source with acid.

**§ 98.261 Reporting threshold.**

You must report GHG emissions under this subpart if your facility contains a phosphoric acid production process and the facility meets the requirements of either § 98.2(a)(1) or (a)(2).

**§ 98.262 GHGs to report.**

(a) You must report CO 2 process emissions from each wet-process phosphoric acid process line.

(b) You must report under subpart C of this part (General Stationary Fuel


### 56462 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

Combustion Sources) the emissions of

CO 2 , CH 4 , and N 2 O from each stationary combustion unit following the requirements of subpart C of this part.

**§ 98.263 Calculating GHG emissions.**

You must calculate and report the annual process CO 2 emissions from each wet-process phosphoric acid process line using the procedures in either paragraph (a) or (b) of this section.

(a) Calculate and report under this subpart the process CO 2 emissions by operating and maintaining a CEMS according to the Tier 4 Calculation Methodology specified in § 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources). (b) Calculate and report under this subpart the process CO 2 emissions using the procedures in paragraphs (b)(1) and (b)(2) of this section.

(1) Calculate and report the process

CO 2 emissions from each wet-process phosphoric acid process line using Equation Z–1 of this section:



### E IC P

m n,i n,i

nz

i b



### = ∗ 

# ( ) ∗ ∗

= = 

# ∑ ∑ 2000

2205 (Eq. Z-1) 44

12 1 1

Where:

E

m = Annual CO 2 mass emissions from a wetprocess phosphoric acid process line m (metric tons).

IC n,i = Inorganic carbon content of a grab sample batch of phosphate rock by origin i obtained during month n, from the carbon analysis results (percent by weight, expressed as a decimal fraction).

P n,i = Mass of phosphate rock by origin i consumed in month n by wet-process phosphoric acid process line m (tons). z = Number of months during which the process line m operates. b = Number of different types of phosphate rock in month, by origin. If the grab sample is a composite sample of rock from more than one origin, b=1.
2000/2205 = Conversion factor to convert

tons to metric tons. 44/12 = Ratio of molecular weights, CO 2 to carbon. (2) You must determine the total emissions from the facility using Equation Z–2 of this section:



### CO E

m

m

p

2

=1



### = (Eq. Z-2)



# ∑

Where:

CO 2 = Annual process CO 2 emissions from phosphoric acid production facility (metric tons/year).

E

m = Annual process CO 2 emissions from wet-process phosphoric acid process line m (metric tons/year). p = Number of wet-process phosphoric acid process lines.
(c) If GHG emissions from a wetprocess phosphoric acid process line are vented through the same stack as any combustion unit or process equipment that reports CO 2 emissions using a CEMS that complies with the Tier 4 Calculation Methodology in subpart C of this part (General Stationary Fuel Combustion Sources), then the calculation methodology in paragraph (b) of this section shall not be used to calculate process emissions. The owner or operator shall report under this subpart the combined stack emissions according to the Tier 4 Calculation Methodology in § 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part.

**§ 98.264 Monitoring and QA/QC requirements.** 

(a) You must obtain a monthly grab sample of phosphate rock directly from the rock being fed to the process line. Conduct the representative bulk sampling using the applicable standard method in the Phosphate Mining States Methods Used and Adopted by the Association of Fertilizer and Phosphate
Chemists AFPC Manual 10th Edition 2009—Version 1.9 (incorporated by reference, see § 98.7). If phosphate rock is obtained from more than one origin in a month, you must obtain a sample from each origin of rock or obtain a composite representative sample.

(b) You must determine the inorganic carbon content of each monthly grab sample of phosphate rock (consumed in the production of phosphoric acid) using the applicable standard method in the Phosphate Mining States Methods Used and Adopted by the Association of Fertilizer and Phosphate Chemists
AFPC Manual 10th Edition 2009— Version 1.9 (incorporated by reference,

see § 98.7).

(c) You must determine the mass of phosphate rock consumed each month (by origin) in each wet-process phosphoric acid process line. You can use existing plant procedures that are used for accounting purposes (such as sales records) or you can use data from existing monitoring equipment that is
used to measure total mass flow of phosphorous-bearing feed under 40 CFR part 60 or part 63.

**§ 98.265 Procedures for estimating missing data.** 

A complete record of all measured parameters used in the GHG emissions calculations in § 98.263(b) is required. Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter shall be used in the calculations as specified in paragraphs (a) and (b) of this section. You must document and keep records of the procedures used for all such

estimates.

(a) For each missing value of the inorganic carbon content of phosphate rock (by origin), you must use the appropriate default factor provided in Table Z–1 of this subpart. Alternatively, the you must determine substitute data value by calculating the arithmetic average of the quality-assured values of inorganic carbon contents of phosphate rock of origin i ( see Equation Z–1 of this subpart) from samples immediately preceding and immediately followingthe missing data incident. If no qualityassured data on inorganic carbon contents of phosphate rock of origin i are available prior to the missing data incident, the substitute data value shall be the first quality-assured value for inorganic carbon contents for phosphate rock of origin i obtained after the missing data period.

(b) For each missing value of monthly mass consumption of phosphate rock (by origin), you must use the best
available estimate based on all available process data or data used for accounting

purposes.

**§ 98.266 Data reporting requirements.**

In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) through (b) of this

section.

(a) Annual phosphoric acid production by origin (as listed in Table Z–1 to this subpart) of the phosphate rock (tons).

(b) Annual phosphoric acid permitted production capacity (tons).

(c) Annual arithmetic average percent inorganic carbon in phosphate rock from monthly records.

(d) Annual phosphate rock consumption from monthly measurement records by origin, (as


### 56463 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

listed in Table Z–1 to this subpart) (tons).

(e) If you use a CEMS to measure CO 2 emissions, then you must report the information in paragraphs (e)(1) and (e)(2) of this section.

(1) The identification number of each wet-process phosphoric acid process
line.

(2) The annual CO 2 emissions from each wet-process phosphoric acid process line (metric tons) and the relevant information required under 40 CFR 98.36 (e)(2)(vi) for the Tier 4 Calculation Methodology.

(f) If you do not use a CEMS to measure emissions, then you must report the information in paragraphs (f)(1) through (f)(8) of this section.

(1) Identification number of each wetprocess phosphoric acid process line.

(2) Annual CO 2 emissions from each wet-process phosphoric acid process line (metric tons) as calculated by Equation Z–1 of this subpart.

(3) Annual phosphoric acid permittedproduction capacity (tons) for each wetprocess phosphoric acid process line (metric tons).

(4) Method used to estimate any missing values of inorganic carboncontent of phosphate rock for each wetprocess phosphoric acid process line.

(5) Monthly inorganic carbon content of phosphate rock for each wet-process phosphoric acid process line (percent by weight, expressed as a decimal fraction).

(6) Monthly mass of phosphate rock consumed by origin, (as listed in Table Z–1 of this subpart) in production for each wet-process phosphoric acid process line (tons).

(7) Number of wet-process phosphoric acid process lines.

(8) Number of times missing data procedures were used to estimate phosphate rock consumption (months) and inorganic carbon contents of the phosphate rock (months).

**§ 98.267 Records that must be retained.**

In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) through (c) of this section for each wet-process phosphoric acid production facility.

(a) Monthly mass of phosphate rock consumed by origin (as listed in Table Z–1 of this subpart) (tons).

(b) Records of all phosphate rock purchases and/or deliveries (if vertically integrated with a mine).

(c) Documentation of the procedures used to ensure the accuracy of monthly phosphate rock consumption by origin, (as listed in Table Z–1 of this subpart).

**§ 98.268 Definitions.**

All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.



### TABLE 

### Z–1 TO 

### S UBPART 

### Z OF 

### P ART



### 98—D EFAULT 

### C HEMICAL 

### C OMPOSI



### TION OF 

### P HOSPHATE 

### R OCK BY 

### O RI



### GIN

Origin Total carbon (percent by

weight)

Central Florida .......................... 1.6
North Florida ............................. 1.76 North Carolina (Calcined) ......... 0.76 Idaho (Calcined) ....................... 0.60
Morocco .................................... 1.56

**Subpart AA—Pulp and Paper Manufacturing** 

**§ 98.270 Definition of source category.**

(a) The pulp and paper manufacturing source category consists of facilities that produce market pulp (i.e., stand-alone pulp facilities), manufacture pulp and paper (i.e., integrated facilities), 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.

(b) The emission units for which GHG emissions must be reported are listed in paragraphs (b)(1) through (b)(5) of this

section:

(1) Chemical recovery furnaces at kraft and soda mills (including recovery furnaces that burn spent pulping liquor produced by both the kraft and semichemical process).

(2) Chemical recovery combustion
units at sulfite facilities.

(3) Chemical recovery combustion
units at stand-alone semichemical
facilities.

(4) Pulp mill lime kilns at kraft and
soda facilities.

(5) Systems for adding makeup chemicals (CaCO 3 , Na 2 CO 3 ) in the chemical recovery areas of chemical pulp mills.

**§ 98.271 Reporting threshold.**

You must report GHG emissions under this subpart if your facility contains a pulp and paper manufacturing process and the facility meets the requirements of either § 98.2(a)(1) or (a)(2). **§ 98.272 GHGs to report.** You must report the emissions listed in paragraphs (a) through (f) of this

section:

(a) CO 2 , biogenic CO 2 , CH 4 , and N 2 O
emissions from each kraft or soda chemical recovery furnace.

(b) CO 2 , biogenic CO 2 , CH 4 , and N 2 O
emissions from each sulfite chemical recovery combustion unit.

(c) CO 2 , biogenic CO 2 , CH 4 , and N 2 O
emissions from each stand-alone semichemical chemical recovery
combustion unit.

(d) CO 2 , biogenic CO 2 , CH 4 , and N 2 O emissions from each kraft or soda pulp
mill lime kiln.

(e) CO 2 emissions from addition of makeup chemicals (CaCO 3 , Na 2 CO 3 ) in the chemical recovery areas of chemical pulp mills.

(f) CO 2 , CH 4, and N 2 O combustion emissions from each stationary
combustion unit. You must calculate and report these emissions under subpart C of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart C.

**§ 98.273 Calculating GHG emissions.**

(a) For each chemical recovery
furnace located at a kraft or soda facility, you must determine CO 2 , biogenic CO 2 , CH 4 , and N 2 O emissions using the procedures in paragraphs (a)(1) through (a)(3) of this section. CH4 and N 2 O emissions must be calculated
as the sum of emissions from
combustion of fossil fuels and combustion of biomass in spent liquor
solids.

(1) Calculate fossil fuel-based CO 2 emissions from direct measurement of
fossil fuels consumed and default emissions factors according to the Tier 1 methodology for stationary combustion sources in § 98.33(a)(1).

(2) Calculate fossil fuel-based CH4 and

N 2 O emissions from direct measurement of fossil fuels consumed, default HHV,
and default emissions factors and
convert to metric tons of CO 2 equivalent according to the methodology for stationary combustion sources in § 98.33(c).

(3) Calculate biogenic CO 2 emissions
and emissions of CH4 and N 2 O from biomass using measured quantities of spent liquor solids fired, site-specific HHV, and default or site-specific emissions factors, according to Equation
AA–1 of this section:



### CO CH or N O from biomass Solids HHV EF 24 2



### , , (Eq. = ∗ ∗∗

(. . ) 0 907 18 AA-1)


### 56464 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

Where:

CO 2 , CH 4 , or N 2 O, from Biomass = Biogenic

CO 2 emissions or emissions of CH4 or N 2 O from spent liquor solids combustion (metric tons per year). Solids = Mass of spent liquor solids combusted (short tons per year) determined according to § 98.274(b). HHV = Annual high heat value of the spent liquor solids (mmBtu per kilogram) determined according to § 98.274(b).
EF = Default emission factor for CO 2 , CH 4 , or N 2 O, from Table AA–1 of this subpart (kg

CO 2 , CH 4 , or N 2 O per mmBtu).
0.90718 = Conversion factor from short tons

to metric tons. (b) For each chemical recovery
combustion unit located at a sulfite or stand-alone semichemical facility, you
must determine CO 2 , CH 4 , and N 2 O emissions using the procedures in paragraphs (b)(1) through (b)(4) of this

section:

(1) Calculate fossil CO 2 emissions
from fossil fuels from direct
measurement of fossil fuels consumed and default emissions factors according to the Tier 1 Calculation Methodology for stationary combustion sources in § 98.33(a)(1). (2) Calculate CH4 and N 2 O emissions
from fossil fuels from direct measurement of fossil fuels consumed, default HHV, and default emissions
factors and convert to metric tons of CO 2 equivalent according to the methodology for stationary combustion sources in § 98.33(c).

(3) Calculate biogenic CO 2 emissions using measured quantities of spent liquor solids fired and the carbon content of the spent liquor solids, according to Equation AA–2 of this

section:



### Biogenic CO (Eq. AA-2) 2 

### =∗ ∗ ∗ 44

12 0 90718 Solids CC ( . )

Where:
Biogenic CO 2 = Annual CO 2 mass emissions for spent liquor solids combustion (metric tons per year). Solids = Mass of the spent liquor solids combusted (short tons per year) determined according to § 98.274(b). CC = Annual carbon content of the spent liquor solids, determined according to § 98.274(b) (percent by weight, expressed as a decimal fraction, e.g., 95% = 0.95). 44/12 = Ratio of molecular weights, CO 2 to carbon.
0.90718 = Conversion from short tons to

metric tons.
(4) Calculate CH4 and N 2 O emissions from biomass using Equation AA–1 of
this section and the default CH4 and

N 2 O emissions factors for kraft facilities in Table AA–1 of this subpart and
convert the CH4 or N 2 O emissions to
metric tons of CO 2 equivalent by multiplying each annual CH4 and N 2 O emissions total by the appropriate global warming potential (GWP) factor from Table A–1 of subpart A of this part.

(c) For each pulp mill lime kiln located at a kraft or soda facility, you
must determine CO 2, CH 4 , and N 2 O emissions using the procedures in paragraphs (c)(1) through (c)(3) of this

section:

(1) Calculate CO 2 emissions from
fossil fuel from direct measurement of
fossil fuels consumed and default HHV and default emissions factors, according to the Tier 1 Calculation Methodology for stationary combustion sources in § 98.33(a)(1); use the default HHV listed in Table C–1 of subpart C and the
default CO 2 emissions factors listed in Table AA–2 of this subpart.

(2) Calculate CH4 and N 2 O emissions
from fossil fuel from direct measurement of fossil fuels consumed, default HHV, and default emissions
factors and convert to metric tons of CO 2 equivalent according to the methodology for stationary combustion sources in § 98.33(c); use the default HHV listed in Table C–1 of subpart C
and the default CH4 and N 2 O emissions
factors listed in Table AA–2 of this subpart.

(3) Biogenic CO 2 emissions from
conversion of CaCO 3 to CaO are included in the biogenic CO 2 estimates calculated for the chemical recovery furnace in paragraph (a)(3) of this

section.

(d) For makeup chemical use, you
must calculate CO 2 emissions by using
direct or indirect measurement of the quantity of chemicals added and ratios of the molecular weights of CO 2 and the makeup chemicals, according to Equation AA–3 of this section:



### CO M M kg/metric CaCO Na CO 2 3 23



### = ∗+

⎡
⎣ ⎢ ⎤
⎦ ⎥ ∗ 

## () ( ) 44

100 44

105 99 1000

. t on (Eq. AA-3)

Where:

CO 2 = CO 2 mass emissions from makeup chemicals (kilograms/yr). M (CaCO 3 ) = Make-up quantity of CaCO 3 used for the reporting year (metric tons per year). M (NaCO 3 ) = Make-up quantity of Na 2 CO 3 used for the reporting year (metric tons per year). 44 = Molecular weight of CO 2
. 100 = Molecular weight of CaCO 3
. 105.99 = Molecular weight of Na 2 CO 3
.

**§ 98.274 Monitoring and QA/QC requirements.** 

(a) Each facility subject to this subpart must quality assure the GHG emissions data according to the applicable requirements in § 98.34. All QA/QC data must be available for inspection upon request.

(b) Fuel properties needed to perform the calculations in Equations AA–1 and AA–2 of this subpart must be determined according to paragraphs (b)(1) through (b)(3) of this section.

(1) High heat values of black liquor
must be determined no less than annually using T684 om–06 Gross Heating Value of Black Liquor, TAPPI (incorporated by reference, see § 98.7). If measurements are performed more frequently than annually, then the high heat value used in Equation AA–1 of this subpart must be based on the average of the representative measurements made during the year. (2) The annual mass of spent liquor solids must be determined using either of the methods specified in paragraph (b)(2)(i) or (b)(2)(ii) of this section.

(i) Measure the mass of spent liquor solids annually (or more frequently) using T–650 om–05 Solids Content of Black Liquor, TAPPI (incorporated by reference in § 98.7). If measurements are performed more frequently than annually, then the mass of spent liquor solids used in Equation AA–1 of this subpart must be based on the average of the representative measurements made during the year.

(ii) Determine the annual mass of spent liquor solids based on records of
measurements made with an online measurement system that determines


### 56465 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

the mass of spent liquor solids fired in a chemical recovery furnace or chemical recovery combustion unit.

(3) Carbon analyses for spent pulping liquor must be determined no less than annually using ASTM D5373–08
Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal (incorporated by reference, see § 98.7). If measurements using ASTM D5373–08 are performed more frequently than annually, then the spent pulping liquor carbon content used in Equation AA–2 of this subpart must be based on the average of the representative measurements made during the year.

(c) Each facility must keep records that include a detailed explanation of how company records of measurements
are used to estimate GHG emissions. The owner or operator must also document the procedures used to ensure the accuracy of the measurements of fuel, spent liquor solids, and makeup chemical usage, including, but not limited to calibration of weighing equipment, fuel flow meters, and other
measurement devices. The estimated accuracy of measurements made with
these devices must be recorded and the
technical basis for these estimates must be provided. The procedures used to convert spent pulping liquor flow rates to units of mass (i.e., spent liquor solids firing rates) also must be documented.

(d) Records must be made available upon request for verification of the
calculations and measurements.

**§ 98.275 Procedures for estimating missing data.** 

A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable (e.g., if a meter malfunctions during unit operation or if a required sample is not taken), a substitute data value for the missing parameter shall be used in the calculations, according to the requirements of paragraphs (a) through (c) of this section:

(a) There are no missing data procedures for measurements of heat content and carbon content of spent pulping liquor. A re-test must be performed if the data from any annual
measurements are determined to be
invalid.

(b) For missing measurements of the mass of spent liquor solids or spent pulping liquor flow rates, use the lesser
value of either the maximum mass or fuel flow rate for the combustion unit,
or the maximum mass or flow rate that
the fuel meter can measure.

(c) For the use of makeup chemicals (carbonates), the substitute data value
shall be the best available estimate of makeup chemical consumption, based on available data (e.g., past accounting records, production rates). The owner or operator shall document and keep records of the procedures used for all
such estimates.

**§ 98.276 Data reporting requirements.**

In addition to the information required by § 98.3(c), each annual report
must contain the information in paragraphs (a) through (k) of this section as applicable:

(a) Annual emissions of CO 2 , biogenic

CO 2 , CH 4 , biogenic CH4 N 2 O, and biogenic N 2 O (metric tons per year).

(b) Annual quantities fossil fuels by type used in chemical recovery furnaces and chemical recovery combustion units in short tons for solid fuels, gallons for liquid fuels and scf for gaseous fuels.

(c) Annual mass of the spent liquor solids combusted (short tons per year), and basis for determining the annual mass of the spent liquor solidscombusted (whether based on T650 om05 Solids Content of Black Liquor, TAPPI (incorporated by reference, see § 98.7) or an online measurement system).

(d) The high heat value (HHV) of the spent liquor solids used in Equation AA–1 of this subpart (mmBtu per kilogram).

(e) The default emission factor for

CO 2 , CH 4 , or N 2 O, used in Equation AA– 1 of this subpart (kg CO 2 , CH 4 , or N 2 O per mmBtu).

(f) The carbon content (CC) of the spent liquor solids, used in Equation AA–2 of this subpart (percent by weight, expressed as a decimal fraction, e.g., 95% = 0.95). (g) Annual quantities of fossil fuels by type used in pulp mill lime kilns in short tons for solid fuels, gallons for liquid fuels and scf for gaseous fuels.

(h) Make-up quantity of CaCO 3 used for the reporting year (metric tons per year) used in Equation AA–3 of this subpart.

(i) Make-up quantity of Na 2 CO 3 used for the reporting year (metric tons per year) used in Equation AA–3 of this subpart.

(j) Annual steam purchases (pounds of steam per year).

(k) Annual production of pulp and/or paper products produced (metric tons).

**§ 98.277 Records that must be retained.**

In addition to the information required by § 98.3(g), you must retain the records in paragraphs (a) through (f)
of this section.

(a) GHG emission estimates (including separate estimates of biogenic CO 2 ) for
each emissions source listed under § 98.270(b).

(b) Annual analyses of spent pulping liquor HHV for each chemical recovery
furnace at kraft and soda facilities.

(c) Annual analyses of spent pulping liquor carbon content for each chemical recovery combustion unit at a sulfite or semichemical pulp facility.

(d) Annual quantity of spent liquor
solids combusted in each chemical recovery furnace and chemical recovery combustion unit, and the basis for detemining the annual quantity of the spent liquor solids combusted (whether
based on T650 om–05 Solids Content of Black Liquor, TAPPI (incorporated by reference, see § 98.7) or an online measurement system). If an online measurement system is used, you must
retain records of the calculations used to determine the annual quantity of spent liquor solids combusted from the

continuous measurements.

(e) Annual steam purchases. (f) Annual quantities of makeup
chemicals used.

**§ 98.278 Definitions.**

All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.



### TABLE 

### AA–1 TO 

### S UBPART 

### AA OF 

### P ART 

### 98—K RAFT 

### P ULPING 

### L IQUOR 

### E MISSIONS 

### FACTORS FOR 

### B IOMASS 

### -B ASED 

### CO 2 

### , CH 4 

### , AND 

### N 2 

### O

Wood furnish Biomass-based emissions factors (kg/mmBtu HHV)

CO 2 aCH 4 N 2 O

North American Softwood ........................................................................................................ ............................ 94.4 0.030 0.005

North American Hardwood ........................................................................................................ .......................... 93.7 Bagasse ........................................................................................................................ ....................................... 95.5

Bamboo ......................................................................................................................... ....................................... 93.7


### 56466 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

TABLE 

### AA–1 TO 

### S UBPART 

### AA OF 

### P ART 

### 98—K RAFT 

### P ULPING 

### L IQUOR 

### E MISSIONS 

### FACTORS FOR 

### B IOMASS 

### -B ASED 

### CO 2 

### , CH 4 

### , AND 

### N 2 

### O—Continued

Wood furnish Biomass-based emissions factors (kg/mmBtu HHV)

CO 2 aCH 4 N 2 O

Straw .......................................................................................................................... .......................................... 95.1

a Includes emissions from both the recovery furnace and pulp mill lime kiln.



### TABLE 

### AA–2 TO 

### S UBPART 

### AA OF 

### P ART 

### 98—K RAFT 

### L IME 

### K ILN AND 

### C ALCINER 

### E MISSIONS 

### FACTORS FOR 

### F OSSIL 

### F UEL 

### B ASED 

### CO 2 

### , CH 4 

### , AND 

### N 2 

### O

Fuel Fossil fuel-based emissions factors (kg/mmBtu HHV)

Kraft lime kilns Kraft calciners

CO 2 CH 4 N 2 O CO 2 CH 4 N 2 O

Residual Oil ...................................................................... 76.7 0.0027 0 76.7 0.0027 0.0003
Distillate Oil ...................................................................... 73.5 73.5 0.0004
Natural Gas ...................................................................... 56.0 56.0 0.0001 Biogas .............................................................................. 0 0.0001

**Subpart BB—Silicon Carbide**

**Production**

**§ 98.280 Definition of the source category.**

Silicon carbide production includes any process that produces silicon carbide for abrasive purposes.

**§ 98.281 Reporting threshold.**

You must report GHG emissions under this subpart if your facility contains a silicon carbide production process and the facility meets the requirements of either § 98.2(a)(1) or (a)(2).

**§ 98.282 GHGs to report.**

You must report: (a) CO 2 and CH 4 process emissions from all silicon carbide process units or
furnaces combined

.

(b) CO 2, CH 4 , and N 2 O emissions from each stationary combustion unit. You must report these emissions under subpart C of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart C.

**§ 98.283 Calculating GHG emissions.**

You must calculate and report the annual process CO 2 emissions from each silicon carbide process unit or production furnace using the procedures in either paragraph (a) or (b)
of this section. You must determine CH4 process emissions in accordance with the procedures specified in paragraph (d) of this section. (a) Calculate and report under this subpart the process CO 2 emissions by operating and maintaining CEMS according to the Tier 4 Calculation Methodology specified in § 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources).

(b) Calculate and report under this subpart the process CO 2 emissions using the procedures in paragraphs (b)(1) and (b)(2) of this section.

(1) Use Equation BB–1 of this section to calculate the facility-specific emissions factor for determining CO 2 emissions. The carbon content must be measured monthly and used to calculate a monthly CO 2 emisssions factor:



### EF CCF CO n n 2, 

### =∗ ∗ ⎛ ⎝ ⎜ ⎞ ⎠ ⎟ 0 65

. 44

12 (Eq. BB-1)

Where:

EF CO2,n = CO 2 emissions factor in month n (metric tons CO 2 /metric ton of petroleum coke consumed). 0.65 = Adjustment factor for the amount of carbon in silicon carbide product (assuming 35 percent of carbon input is in the carbide product). CCF

n = Carbon content factor for petroleum

coke consumed in month n from the supplier or as measured by the applicable method incorporated by reference in § 98.7 according to § 98.284(c) (percent by weight expressed as a decimal fraction). 44/12 = Ratio of molecular weights, CO 2 to
carbon.

(2) Use Equation BB–2 of this section
to calculate annual CO 2 process emissions from all silicone carbide production:



### CO T EF n CO n

n 2

=1



### = (Eq. BB-2) ∗ ⎡ ⎣ ⎤ ⎦ ∗ 

# ∑ 2, 

### 2000

2205 12

Where: CO 2 = Annual CO 2 emissions from silicon carbide production facility (metric tons

CO 2 ). T

n = Petroleum coke consumption in month n (tons).


### 56467 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

EF CO2,n = CO 2 emissions factor from month n (calculated in Equation BB–1 of this section).
2000/2205 = Conversion factor to convert

tons to metric tons.
n = Number of month.

(c) If GHG emissions from a silicon carbide production furnace or process unit are vented through the same stack as any combustion unit or process equipment that reports CO 2 emissions using a CEMS that complies with the Tier 4 Calculation Methodology in subpart C of this part (General Stationary Fuel Combustion Sources), then the calculation methodology in paragraph (b) of this section shall not be used to calculate process emissions. The owner or operator shall report under this subpart the combined stack emissions according to the Tier 4 Calculation Methodology in § 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part.

(d) You must calculate annual process

CH 4 emissions from all silicon carbide production combined using Equation
BB–3 of this section:



### CH T

n

n 4

=1 

### (Eq. BB-3)

= ∗ 

# [ ] ∗ ∗ 

# ∑ 10 2 2000

2205 0 001 12



### . .

Where:

CH 4 = Annual CH 4 emissions from silicon carbide production facility (metric tons

CH 4 ).

T

n = Petroleum coke consumption in month n (tons).

10.2 = CH 4 emissions factor (kg CH4 /metric ton coke).
2000/2205 = Conversion factor to convert

tons to metric tons. 0.001 = Conversion factor from kilograms to

metric tons. n = Number of month.

**§ 98.284 Monitoring and QA/QC requirements.** 

(a) You must measure your consumption of petroleum coke using plant instruments used for accounting purposes including direct measurement weighing the petroleum coke fed into your process (by belt scales or a similar device) or through the use of purchase
records.

(b) You must document the procedures used to ensure the accuracy of monthly petroleum coke consumption measurements.

(c) For CO 2 process emissions, you must determine the monthly carbon content of the petroleum coke using reports from the supplier. Alternatively, facilities can measure monthly carbon contents of the petroleum coke using ASTM D3176–89 (Reapproved 2002) Standard Practice for Ultimate Analysis of Coal and Coke (incorporated by reference, see § 98.7) and ASTM D5373–
08 Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal (incorporated by reference, see § 98.7).

(d) For quality assurance and quality control of the supplier data, you must
conduct an annual measurement of the carbon content of the petroleum coke using ASTM D3176–89 and ASTM
D5373–08 Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal (incorporated by reference, see § 98.7). **§ 98.285 Procedures for estimating missing data.** 

For the petroleum coke input procedure in § 98.283(b), a complete record of all measured parameters used
in the GHG emissions calculations is required (e.g., carbon content values,etc.). Therefore, whenever a qualityassured value of a required parameter is unavailable, a substitute data value for the missing parameter shall be used in the calculations as specified in the paragraphs (a) and (b) of this section. You must document and keep records of the procedures used for all such

estimates.

(a) For each missing value of the monthly carbon content of petroleum coke, the substitute data value shall bethe arithmetic average of the qualityassured values of carbon contents immediately preceding and immediately following the missing data incident. If no quality-assured data on carbon contents are available prior to the missing data incident, the substitutedata value shall be the first qualityassured value for carbon contents obtained after the missing data period.

(b) For each missing value of the monthly petroleum coke consumption,
the substitute data value shall be the best available estimate of the petroleum coke consumption based on all available process data or information used for accounting purposes (such as purchase records).

**§ 98.286 Data reporting requirements.**

In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) or (b) of this section, as applicable for each silicon carbide production facility.

(a) If a CEMS is used to measure process CO 2 emissions, you must report under this subpart the relevant information required for the Tier 4 Calculation Methodology in § 98.36 and the information listed in this paragraph (a): (1) Annual consumption of petroleum coke (tons).

(2) Annual production of silicon carbide (tons).

(3) Annual production capacity of silicon carbide (tons).

(b) If a CEMS is not used to measure process CO 2 emissions, you must report the information listed in this paragraph (b) for all furnaces combined:

(1) Monthly consumption of petroleum coke (tons).

(2) Annual production of silicon carbide (tons).

(3) Annual production capacity of silicon carbide (tons).

(4) Carbon content factor of petroleum coke from the supplier or as measured by the applicable method in § 98.284(c) for each month (percent by weight expressed as a decimal fraction).

(5) Whether carbon content of the petroleum coke is based on reports from the supplier or through self measurement using applicable ASTM
standard method.

(6) CO 2 emissions factor calculated for each month (metric tons CO 2 /metric ton of petroleum coke consumed)

.

(7) Sampling analysis results for carbon content of consumed petroleum coke as determined for QA/QC of supplier data under § 98.284(d) (percent by weight expressed as a decimal fraction).

(8) Number of times in the reporting year that missing data procedures were
followed to measure the carbon contents of petroleum coke (number of months) and petroleum coke consumption (number of months).

**§ 98.287 Records that must be retained.**

In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) and (b) of
this section for each silicon carbide production facility.

(a) If a CEMS is used to measure CO 2 emissions, you must retain under this subpart the records required for the Tier 4 Calculation Methodology in § 98.37


### 56468 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

and the information listed in this paragraph (a):

(1) Records of all petroleum coke purchases.

(2) Annual operating hours. (b) If a CEMS is not used to measure emissions, you must retain records for the information listed in this paragraph (b):

(1) Records of all analyses and calculations conducted for reported data listed in § 98.286(b).

(2) Records of all petroleum coke purchases.

(3) Annual operating hours.

**§ 98.288 Definitions.**

All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.

**Subpart CC—Soda Ash Manufacturing**

**§ 98.290 Definition of the source category.**

(a) A soda ash manufacturing facility is any facility with a manufacturing line that produces soda ash by one of the methods in paragraphs (a)(1) through (3)
of this section:

(1) Calcining trona. (2) Calcining sodium sesquicarbonate. (3) Using a liquid alkaline feedstock process that directly produces CO 2
.

(b) 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. **§ 98.291 Reporting threshold.** You must report GHG emissions under this subpart if your facility contains a soda ash manufacturing process and the facility meets the requirements of either § 98.2(a)(1) or (a)(2).

**§ 98.292 GHGs to report.**

You must report: (a) CO 2 process emissions from each soda ash manufacturing line combined.

(b) CO 2 combustion emissions from each soda ash manufacturing line.

(c) CH 4 and N 2 O combustion
emissions from each soda ash manufacturing line. You must calculate and report these emissions under subpart C of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart C.

(d) CO 2, CH 4 , and N 2 O emissions from each stationary combustion unit other than soda ash manufacturing lines. You must calculate and report these emissions under subpart C of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart C.

**§ 98.293 Calculating GHG emissions.**

You must calculate and report the annual process CO 2 emissions from each soda ash manufacturing line using the procedures specified in paragraph (a) or (b) of this section.

(a) For each soda ash manufacturing line that meets the conditions specified in § 98.33(b)(4)(ii) or (b)(4)(iii), you must calculate and report under this subpart the combined process and combustion

CO 2 emissions by operating and maintaining a CEMS to measure CO 2 emissions according to the Tier 4 Calculation Methodology specified in § 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources).

(b) For each soda ash manufacturing line that is not subject to the requirements in paragraph (a) of this section, calculate and report the process

CO 2 emissions from the soda ash manufacturing line by using the procedure in either paragraphs (b)(1), (b)(2), or (b)(3) of this section; and the
combustion CO 2 emissions using the procedure in paragraph (b)(4) of this

section.

(1) Calculate and report under this subpart the combined process and
combustion CO 2 emissions by operating and maintaining a CEMS to measure

CO 2 emissions according to the Tier 4 Calculation Methodology specified in § 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources).

(2) Use either Equation CC–1 or Equation CC–2 of this section to
calculate annual CO 2 process emissions from each manufacturing line that calcines trona to produce soda ash:



### E (Eq. CC-1)

k 

### = 

## ( ) ∗ 

## ( ) ⎡ ⎣ ⎤ ⎦ ∗ ∗

= 

# ∑ IC T T n t n

n 

### 2000

2205 0 097

1 1 12



### .

E (Eq. CC-2)

k 

### = 

## ( ) ∗ 

## ( ) ⎡ ⎣ ⎤ ⎦ ∗ ∗

= 

# ∑ IC T

sa n sa n

n 

### 2000

2205 0 138

1 1 12



### .

Where:

E k = Annual CO 2 process emissions from each manufacturing line, k (metric tons). (IC T )

n = Inorganic carbon content (percent by weight, expressed as a decimal fraction) in trona input, from the carbon analysis results for month n. This represents the

ratio of trona to trona ore. (IC

sa)

n = Inorganic carbon content (percent by weight, expressed as a decimal fraction) in soda ash output, from the carbon analysis results for month n. This represents the purity of the soda ash produced. (T t)

n = Mass of trona input in month n (tons). (T

sa)

n = Mass of soda ash output in month n (tons).
2000/2205 = Conversion factor to convert

tons to metric tons.
0.097/1 = Ratio of ton of CO 2 emitted for each
ton of trona.
0.138/1 = Ratio of ton of CO 2 emitted for each ton of soda ash produced.

(3) Site-specific emission factor
method. Use Equations CC–3, CC–4, and
CC–5 of this section to determine
annual CO 2 process emissions from manufacturing lines that use the liquid alkaline feedstock process to produce
soda ash. You must conduct an annual performance test and measure CO 2 emissions and flow rates at all process vents from the mine water stripper/ evaporator for each manufacturing line
and calculate CO 2 emissions as described in paragraphs (b)(3)(i) through (b)(3)(iv) of this section.

(i) During the performance test, you must measure the process vent flow from each process vent during the test and calculate the average rate for the test period in metric tons per hour.

(ii) Using the test data, you must calculate the hourly CO 2 emission rate using Equation CC–3 of this section:


### 56469 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

ER C x Q x CO co 2 2 9 4 

### 10000 2 59 10 44 60 4 53 10 = ∗ 

## ( ) ∗ ∗ ⎡ ⎣ ⎤ ⎦ ∗∗ ∗ − − 

### . ( ) . (Eq. CC -3)

Where:

ERCO2 = CO 2 mass emission rate (metric tons/ hour).

C CO2 = Hourly CO 2 concentration (percent

CO 2 ) as determined by § 98.294(c). 10000 = Parts per million per percent

2.59 x 10

¥ 9 = Conversion factor (poundsmole/dscf/ppm). 44 = Pounds per pound-mole of carbon

dioxide. Q = Stack gas volumetric flow rate per minute (dscfm). 60 = Minutes per hour 4.53 × 10

¥ 4 = Conversion factor (metric tons/ pound)

(iii) Using the test data, you must
calculate a CO 2 emission factor for the process using Equation CC–4 of this

section:



### EF ER

V CO CO

t 2 2

4 

### 4 53 10 =

∗



# ( )

−



### . x (Eq. CC-4)

Where: EF CO2 = CO 2 emission factor (metric tons

CO 2 /metric ton of process vent flow from mine water stripper/evaporator).

ERCO2 = CO 2 mass emission rate (metric tons/ hour).

Vt = Process vent flow rate from mine water stripper/evaporator during annual performance test (pounds/hour).

4.53 × 10

¥ 4 = Conversion factor (metric tons/ pound) (iv) You must calculate annual CO 2 process emissions from each manufacturing line using Equation CC–
5 of this section:



### E EF V

k CO a



### = ∗∗ 

## ( ) ∗ 2 

### 0.453 (Eq. CC-5) H

Where:

E k = Annual CO 2 process emissions for each manufacturing line, k (metric tons).

EF CO2 = CO 2 emission factor (metric tons

CO 2 /metric ton of process vent flow from mine water stripper/evaporator).

V

a = Annual process vent flow rate from mine water stripper/evaporator (thousand pounds/hour). H = Annual operating hours for the each manufacturing line. 0.453 = Conversion factor (metric tons/ thousand pounds).
(4) Calculate and report under subpart C of this part (General Stationary Fuel Combustion Sources) the combustion

CO 2 , CH 4 , and N 2 O emissions in the soda ash manufacturing line according to the applicable requirements in subpart C.

**§ 98.294 Monitoring and QA/QC requirements.** 

Section 98.293 provides three different procedures for emission calculations. The appropriate paragraphs (a) through (c) of this section should be used for the procedure
chosen.

(a) If you determine your emissions using § 98.293(b)(2) (Equation CC–1 of this subpart) you must:

(1) Determine the monthly inorganic
carbon content of the trona from a weekly composite analysis for each soda ash manufacturing line, using a
modified version of ASTM E359–00 (Reapproved 2005)e1, Standard Test Methods for Analysis of Soda Ash (Sodium Carbonate) (incorporated by reference, see § 98.7). ASTM E359– 00(Reapproved 2005) e1 is designed to measure the total alkalinity in soda ash
not in trona. The modified method of ASTM E359–00 adjusts the regular ASTM method to expresse the results in terms of trona. Although ASTM E359– 00 (Reapproved 2005) e1 uses manual titration, suitable autotitrators may also
be used for this determination.

(2) Measure the mass of trona input produced by each soda ash manufacturing line on a monthly basis using belt scales or methods used for accounting purposes.

(3) Document the procedures used to ensure the accuracy of the monthly
measurements of trona consumed.

(b) If you calculate CO 2 process emissions based on soda ash production (§ 98.293(b)(2) Equation CC–2 of this subpart), you must:

(1) Determine the inorganic carbon content of the soda ash (i.e., soda ash purity) using ASTM E359–00 (Reapproved 2005) e1 Standard Test Methods for Analysis of Soda Ash (Sodium Carbonate) (incorporated by reference, see § 98.7). Although ASTM E359–00 (Reapproved 2005) e1 uses manual titration, suitable autotitrators may also be used for this determination.

(2) Measure the mass of soda ash produced by each soda ash manufacturing line on a monthly basis using belt scales, by weighing the soda ash at the truck or rail loadout points of your facility, or methods used for accounting purposes.

(3) Document the procedures used to ensure the accuracy of the monthly measurements of soda ash produced.

(c) If you calculate CO 2 emissions using the site-specific emission factor method in § 98.293(b)(3), you must:

(1) Conduct an annual performance test that is based on representative performance (i.e., performance based on normal operating conditions) of the affected process.

(2) Sample the stack gas and conduct
three emissions test runs of 1 hour each. (3) Conduct the stack test using EPA Method 3A at 40 CFR part 60, appendix
A–2 to measure the CO 2 concentration, Method 2, 2A, 2C, 2D, or 2F at 40 CFR part 60, appendix A–1 or Method 26 at 40 CFR part 60, appendix A–2 to determine the stack gas volumetric flow rate. All QA/QC procedures specified in the reference test methods and any associated performance specifications apply. For each test, the facility must prepare an emission factor determination report that must include the items in paragraphs (c)(3)(i) through (c)(3)(iii) of this section.

(i) Analysis of samples, determination of emissions, and raw data.

(ii) All information and data used to derive the emissions factor(s).

(iii) You must determine the average process vent flow rate from the mine water stripper/evaporater during each
test and document how it was
determined.

(4) You must also determine the
annual vent flow rate from the mine water stripper/evaporater from monthly information using the same plant instruments or procedures used for accounting purposes (i.e., volumetric flow meter).

**§ 98.295 Procedures for estimating missing data.** 

For the emission calculation methodologies in § 98.293(b)(2) and (b)(3), a complete record of all measured parameters used in the GHG emissions calculations is required (e.g., inorganic carbon content values, etc.). Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter shall be used in the calculations as specified in the paragraphs (a) through (d) of this


### 56470 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

section. You must document and keep records of the procedures used for all such missing value estimates.

(a) For each missing value of the weekly composite of inorganic carbon content of either soda ash or trona, the
substitute data value shall be the arithmetic average of the quality-assured values of inorganic carbon contents from the week immediately preceding and the week immediately following themissing data incident. If no qualityassured data on inorganic carbon contents are available prior to the missing data incident, the substitutedata value shall be the first qualityassured value for carbon contents obtained after the missing data period.

(b) For each missing value of either the monthly soda ash production or the trona consumption, the substitute data
value shall be the best available estimate(s) of the parameter(s), based on all available process data or data used for accounting purposes.

(c) For each missing value collected during the performance test (hourly CO 2 concentration, stack gas volumetric flow rate, or average process vent flow from mine water stripper/evaporator during performance test), you must repeat the annual performance test following the calculation and monitoring and QA/QC requirements under §§ 98.293(b)(3) and 98.294(c).

(d) For each missing value of the monthly process vent flow rate from mine water stripper/evaporator, the
subsititute data value shall be the best available estimate(s) of the parameter(s), based on all available process data or the lesser of the maximum capacity of the system or the maximum rate the

meter can measure.

**§ 98.296 Data reporting requirements.**

In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) or (b) of this section, as appropriate for each soda ash manufacturing facility.

(a) If a CEMS is used to measure CO 2 emissions, then you must report under this subpart the relevant information required under § 98.36 and the following information in this paragraph (a):

(1) Annual consumption of trona or liquid alkaline feedstock for each manufacturing line (metric tons).

(2) Annual production of soda ash for each manufacturing line (tons).

(3) Annual production capacity of soda ash for each manufacturing line (tons).

(4) Identification number of each manufacturing line. (b) If a CEMS is not used to measure

CO 2 emissions, then you must report the information listed in this paragraph (b):

(1) Identification number of each manufacturing line.

(2) Annual process CO 2 emissions from each soda ash manufacturing line (metric tons).

(3) Annual production of soda ash (tons).

(4) Annual production capacity of soda ash for each manufacturing line (tons).

(5) Monthly consumption of trona or liquid alkaline feedstock for each manufacturing line (tons).

(6) Monthly production of soda ash for each manufacturing line (metric tons).

(7) Inorganic carbon content factor of trona or soda ash (depending on use of Equations CC–1 or CC–2 of this subpart) as measured by the applicable method in § 98.294(b) or (c) for each month (percent by weight expressed as a decimal fraction).

(8) Whether CO 2 emissions for each manufacturing line were calculated using a trona input method as described in Equation CC–1 of this subpart, a soda ash output method as described inEquation CC–2 of this subpart, or a sitespecific emission factor method as described in Equations CC–3 through CC–5 of this subpart.

(9) Number of manufacturing lines located used to produce soda ash.

(10) If you produce soda ash using the liquid alkaline feedstock process and use the site-specific emission factor method (§ 98.293(b)(3)) to estimate emissions then you must report the following relevant information:

(i) Stack gas volumetric flow rate per minute (dscfm)

(ii) Hourly CO 2 concentration (percent

CO 2 )

(iii) CO 2 emission factor (metric tons

CO 2 /metric tons of process vent flow from mine water stripper/evaporator).

(iv) CO 2 mass emission rate (metric tons/hour).

(v) Average process vent flow from mine water stripper/evaporater during performance test (pounds/hour).

(vi) Annual process vent flow rate from mine stripper/evaporator (thousand pounds/hour).

(vii) Annual operating hours for each manufacturing line used to produce soda ash using liquid alkaline feedstock (hours).

(11) Number of times missing data procedures were used and for which parameter as specified in this paragraph (b)(11):

(i) Trona or soda ash (number of months).

(ii) Inorganic carbon contents of trona or soda ash (weeks). (iii) Process vent flow rate from mine water stripper/evaporator (number of months).

(iv) Stack gas volumetric flow rate during performance test (number of times).

(v) Hourly CO 2 concentration (number of times).

(vi) Average vent process vent flow rate from mine stripper/evaporator during performance test (number of times).

**§ 98.297 Records that must be retained.**

In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) and (b) of
this section for each soda ash manufacturing line.

(a) If a CEMS is used to measure CO 2 emissions, then you must retain under this subpart the records required for the Tier 4 Calculation Methodology specified in subpart C of this part and the information listed in this paragraph (a):

(1) Monthly production of soda ash (tons)

(2) Monthly consumption of trona or liquid alkaline feedstock (tons)

(3) Annual operating hours (hours). (b) If a CEMS is not used to measure emissions, then you must retain records
for the information listed in this paragraph (b):

(1) Records of all analyses and calculations conducted for determining all reported data as listed in § 98.296(b).

(2) If using Equation CC–1 or CC–2 of this subpart, weekly inorganic carbon content factor of trona or soda ash, depending on method chosen, as measured by the applicable method in § 98.294(b) (percent by weight expressed as a decimal fraction).

(3) Annual operating hours for each manufacturing line used to produce soda ash (hours).

(4) You must document the procedures used to ensure the accuracy of the monthly trona consumption or soda ash production measurements including, but not limited to, calibration of weighing equipment and other
measurement devices. The estimated accuracy of measurements made with these devices must also be recorded,
and the technical basis for these estimates must be provided.

(5) If you produce soda ash using the liquid alkaline feedstock process and use the site-specific emission factor
method to estimate emissions (§ 98.293(b)(3)) then you must also retain the following relevant
information:

(i) Records of performance test results. (ii) You must document the procedures used to ensure the accuracy


### 56471 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

of the annual average vent flow measurements including, but not limited to, calibration of flow rate
meters and other measurement devices. The estimated accuracy of
measurements made with these devices must also be recorded, and the technical
basis for these estimates must be provided.

**§ 98.298 Definitions.**

All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.

**Subpart DD—[Reserved]**

**Subpart EE—Titanium Dioxide**
**Production**

**§ 98.310 Definition of the source category.**

The titanium dioxide production source category consists of facilities that use the chloride process to produce
titanium dioxide.

**§ 98.311 Reporting threshold.**

You must report GHG emissions under this subpart if your facility contains a titanium dioxide production process and the facility meets the requirements of either § 98.2(a)(1) or (a)(2). **§ 98.312 GHGs to report.** (a) You must report CO 2 process emissions from each chloride process line as required in this subpart.

(b) You must report CO 2 , CH 4 , and

N 2 O emissions from each stationary combustion unit under subpart C of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart C.

**§ 98.313 Calculating GHG emissions.**

You must calculate and report the annual process CO 2 emissions for each chloride process line using the procedures in either paragraph (a) or (b)
of this section.

(a) Calculate and report under this subpart the process CO 2 emissions by operating and maintaining a CEMS according to the Tier 4 Calculation Methodology specified in § 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources).

(b) Calculate and report under this subpart the annual process CO 2 emissions for each chloride process line by determining the mass of calcined petroleum coke consumed in each line as specified in paragraphs (b)(1) through (b)(3) of this section. Use Equation EE–
1 of this section to calulate annual combined process CO 2 emissions from all process lines and use Equation EE–
2 of this section to calculate annual process CO 2 emissions for each processline. If your facility generates carboncontaining waste, use Equation EE–3 of
this section to estimate the annual quantity of carbon-containing waste generated and its carbon contents according to § 98.314(e) and (f):

(1) You must calculate the annual CO 2 process emissions from all process lines at the facility using Equation EE–1 of
this section:



### CO E p

p m

2

1



### =

=



# ∑ (Eq. EE-1)

Where:

CO 2 = Annual CO 2 emissions from titanium dioxide production facility (metric tons/ year).

E p = Annual CO 2 emissions from chloride process line p (metric tons), determined using Equation EE–2 of this section. p = Process line. m = Number of separate chloride process lines located at the facility.

(2) You must calculate the annual CO 2 process emissions from each process lines at the facility using Equation EE–
2 of this section:



### E C CCF

p p,n n

n 

### = ∗∗ ∗

= 

# ∑ 44

12 2000

2205 (Eq. EE-2)

1 12

Where:

E p = Annual CO 2 mass emissions from chloride process line p (metric tons).

C p,n = Calcined petroleum coke consumption for process line p in month n (tons). 44/12 = Ratio of molecular weights, CO 2 to carbon.
2000/2205 = Conversion of tons to metric

tons.
CCF

n = Carbon content factor for petroleum
coke consumed in month n from the supplier or as measured by the applicable method incorporated by reference in § 98.7 according to § 98.314(c) (percent by weight expressed as a decimal fraction).
n = Number of month.

(3) If facility generates carboncontaining waste, you must calculatethe total annual quantity of carboncontaining waste produced from all process lines using Equation EE–3 of
this section and its carbon contents according to § 98.314(e) and (f):



### TWC WC p n

n p m



### =

= = 

# ∑ ∑

, 

### (Eq. EE-3)

1 12

1

Where: TWC = Annual production of carboncontaining waste from titanium dioxide production facility (tons).

WC p,n = Production of carbon-containing waste in month n from chloride process line p (tons). p = Process line. m = Total number of process lines.

n = Number of month.

(c) If GHG emissions from a chloride process line are vented through the same stack as any combustion unit or process equipment that reports CO 2 emissions using a CEMS that complies
with the Tier 4 Calculation Methodology in subpart C of this part (General Stationary Fuel Combustion Sources), then the calculation methodology in paragraph (b) of this
section shall not be used to calculate process CO 2 emissions. The owner or operator shall report under this subpart the combined stack emissions according to the Tier 4 Calculation Methodology in § 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part. **§ 98.314 Monitoring and QA/QC requirements.** 

(a) You must measure your consumption of calcined petroleum coke using plant instruments used for accounting purposes including direct measurement weighing the petroleum coke fed into your process (by belt scales or a similar device) or through the use of purchase records.

(b) You must document the procedures used to ensure the accuracy of monthly calcined petroleum coke consumption measurements.

(c) You must determine the carbon content of the calcined petroleum coke each month based on reports from the supplier. Alternatively, facilities can measure monthly carbon contents of the petroleum coke using ASTM D3176–89 (Reapproved 2002) Standard Practice for Ultimate Analysis of Coal and Coke (incorporated by reference, see § 98.7)
and ASTM D5373–08 Standard Test
Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal (incorporated by reference, see § 98.7).


### 56472 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

(d) For quality assurance and quality control of the supplier data, you must
conduct an annual measurement of the carbon content from a representative sample of the petroleum coke consumed using ASTM D3176–89 and ASTM

D5373–08.

(e) You must determine the quantity of carbon-containing waste generated from the each titanium production line dioxide using plant instruments used for accounting purposes including direct measurement weighing the carbon-containing waste not used during the process (by belt scales or a similar device) or through the use of
sales records.

(f) You must determine the carbon contents of the carbon-containing waste from each titanium production line on an annual basis by collecting and analyzing a representative sample of the material using ASTM D3176–89 and

ASTM D5373–08.

**§ 98.315 Procedures for estimating missing data.** 

For the petroleum coke input procedure in § 98.313(b), a complete record of all measured parameters used
in the GHG emissions calculations is required (e.g., carbon content values, etc.). Therefore, whenever the monitoring and quality assurance procedures in § 98.315 cannot be followed, a substitute data value for the missing parameter shall be used in the calculations as specified in the paragraphs (a) through (c) of this section. You must document and keep records of the procedures used for all
such estimates.

(a) For each missing value of the monthly carbon content of calcined petroleum coke the substitute data value shall be the arithmetic average of the quality-assured values of carbon contents for the month immediately preceding and the month immediately following the missing data incident. If no quality-assured data on carbon contents are available prior to the missing data incident, the substitutedata value shall be the first qualityassured value for carbon contents obtained after the missing data period.

(b) For each missing value of the monthly calcined petroleum coke consumption and/or carbon-containing waste, the substitute data value shall be
the best available estimate of the monthly petroleum coke consumption based on all available process data or information used for accounting purposes (such as purchase records).

(c) For each missing value of the carbon content of carbon-containing waste, you must conduct a new analysis following the procedures in § 98.314(f). **§ 98.316 Data reporting requirements.**

In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) or (b) of this section, as applicable for each titanium dioxide production line.

(a) If a CEMS is used to measure CO 2 emissions, then you must report the relevant information required under § 98.36(e)(2)(vi) for the Tier 4 Calculation Methodology and the following information in this paragraph (a).

(1) Identification number of each process line.

(2) Annual consumption of calcined petroleum coke (tons).

(3) Annual production of titanium dioxide (tons).

(4) Annual production capacity of titanium dioxide (tons).

(5) Annual production of carboncontaining waste (tons), if applicable.

(b) If a CEMS is not used to measure

CO 2 emissions, then you must report the information listed in this paragraph (b):

(1) Identification number of each process line.

(2) Annual CO 2 emissions from each chloride process line (metric tons/year).

(3) Annual consumption of calcined petroleum coke for each process line (tons).

(4) Annual production of titanium dioxide for each process line (tons).

(5) Annual production capacity of titanium dioxide for each process line (tons).

(6) Calcined petroleum coke consumption for each process line for each month (tons).

(7) Annual production of carboncontaining waste for each process line (tons), if applicable.

(8) Monthly production of titanium dioxide for each process line (tons).

(9) Monthly carbon content factor of petroleum coke from the supplier (percent by weight expressed as a decimal fraction).

(10) Whether monthly carbon content of the petroleum coke is based on reports from the supplier or through self measurement using applicable ASTM
standard methods.

(11) Carbon content for carboncontaining waste (percent by weight expressed as a decimal fraction).

(12) If carbon content of petroleum coke is based on self measurement, the
ASTM standard methods used.

(13) Sampling analysis results of carbon content of petroleum coke as determined for QA/QC of supplier data under § 98.314(d) (percent by weight expressed as a decimal fraction).

(14) Number of separate chloride process lines located at the facility. (15) The number of times in the reporting year that missing data procedures were followed to measure the carbon contents of petroleum coke (number of months); petroleum coke consumption (number of months); carbon-containing waste generated (number of months); and carbon contents of the carbon-containing waste (number of times during year).

**§ 98.317 Records that must be retained.**

In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) and (b) of
this section for each titanium dioxide production facility.

(a) If a CEMS is used to measure CO 2 emissions, then you must retain under this subpart required for the Tier 4 Calculation Methodology in § 98.37 and the information listed in this paragraph (a):

(1) Records of all calcined petroleum coke purchases.

(2) Annual operating hours for each titanium dioxide process line.

(b) If a CEMS is not used to measure

CO 2 emissions, then you must retain
records for the information listed in this paraghraph:

(1) Records of all calcined petroleum coke purchases (tons).

(2) Records of all analyses and calculations conducted for all reported data as listed in § 98.316(b).

(3) Sampling analysis results for
carbon content of consumed calcined petroleum coke (percent by weight expressed as a decimal fraction).

(4) Sampling analysis results for the carbon content of carbon containing waste (percent by weight expressed as a decimal fraction), if applicable.

(5) Monthly production of carboncontaining waste (tons).

(6) You must document the procedures used to ensure the accuracy of the monthly petroleum cokeconsumption and quantity of carboncontaining waste measurement including, but not limited to, calibration of weighing equipment and other
measurement devices. The estimated accuracy of measurements made with these devices must also be recorded,
and the technical basis for these estimates must be provided.

(7) Annual operating hours for each titanium dioxide process line (hours).

**§ 98.318 Definitions.**

All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.


### 56473 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

**Subpart FF—[Reserved]**

**Subpart GG—Zinc Production**

**§ 98.330 Definition of the source category.**

The zinc production source category consists of zinc smelters and secondary zinc recycling facilities.

**§ 98.331 Reporting threshold.**

You must report GHG emissions under this subpart if your facility contains a zinc production process and the facility meets the requirements of either § 98.2(a)(1) or (2).

**§ 98.332 GHGs to report.**

You must report: (a) CO 2 process emissions from each
Waelz kiln and electrothermic furnace used for zinc production.

(b) CO 2 , CH 4 , and N 2 O combustion
emissions from each Waelz kiln. You must calculate and report these emissions under subpart C of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart C.

(c) CO 2 , CH 4 , and N 2 O emissions from each stationary combustion unit other than Waelz kilns. You must report these emissions under subpart C of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart C.

**§ 98.333 Calculating GHG emissions.**

You must calculate and report the annual process CO 2 emissions using the procedures specified in either paragraph (a) or (b) of this section.

(a) Calculate and report under this subpart the process or combined process
and combustion CO 2 emissions by operating and maintaining a CEMS according to the Tier 4 Calculation Methodology in § 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources).

(b) Calculate and report under this subpart the process CO 2 emissions by following paragraphs (b)(1) and (b)(2) of
this section.

(1) For each Waelz kiln or electrothermic furnace at your facility used for zinc production, you must
determine the mass of carbon in each carbon-containing material, other than fuel, that is fed, charged, or otherwise
introduced into each Waelz kiln and electrothermic furnace at your facility for each year and calculate annual CO 2 process emissions from each affected unit at your facility using Equation GG–
1 of this section. For electrothermic furnaces, carbon containing input
materials include carbon eletrodes and carbonaceous reducing agents. For Waelz kilns, carbon containing input
materials include carbonaceous reducing agents. If you document that a specific material contributes less than 1 percent of the total carbon into the process, you do not have to include the material in your calculation using Equation R–1 of § 98.183.

E 44

12 CO2k =∗ ∗ 

## ( ) ∗ 

## ( ) +∗+ 2000

2205 Zinc C Flux C Ele k Zinc k k Flux k ( )( ) ( c trode C Carbon C k Electrode k k carbon k ) ()

∗ 

## ( ) + ∗ 

## ( ) ⎡ ⎣ ⎤ ⎦ (Eq. GG-1)

Where:

E CO2k = Annual CO 2 process emissions from
individual Waelz kiln or electrothermic furnace ‘‘k’’ (metric tons). 44/12 = Ratio of molecular weights, CO 2 to carbon.
2000/2205 = Conversion factor to convert

tons to metric tons. (Zinc) k = Annual mass of zinc bearing material charged to kiln or furnace ’’k’’ (tons). (C Zinc ) k = Carbon content of the zinc bearing material, from the annual carbon analysis for kiln or furnace ‘‘k’’ (percent by weight, expressed as a decimal fraction). (Flux) k = Annual mass of flux materials (e.g., limestone, dolomite) charged to kiln or furnace ‘‘k’’ (tons). (C Flux ) k = Carbon content of the flux materials charged to kiln or furnace ‘‘k’’, from the annual carbon analysis (percent by weight, expressed as a decimal fraction). (Electrode) k = Annual mass of carbon
electrode consumed in kiln or furnace ‘‘k’’ (tons). (C Electrode ) k = Carbon content of the carbon
electrode consumed in kiln or furnace ‘‘k’’, from the annual carbon analysis (percent by weight, expressed as a decimal fraction). (Carbon) k = Annual mass of carbonaceous materials (e.g., coal, coke) charged to the kiln or furnace ‘‘k’’(tons). (C Carbon ) k Carbon content of the carbonaceous materials charged to kiln or furnace, ‘‘k’’, from the annual carbon analysis (percent by weight, expressed as a decimal fraction). (2) You must determine the CO 2 emissions from all of the Waelz kilns or electrothermic furnaces at your facility using Equation GG–2 of this section.



### CO E CO

k n

2 2

1 

### =

=



# ∑

k 

### (Eq. GG-2)

Where:

CO 2 = Annual combined CO 2 emissions from
all Waelz kilns or electrothermic furnaces (tons).

E CO2k = Annual CO 2 emissions from each
Waelz kiln or electrothermic furnace k calculated using Equation GG–1 of this section (tons).
n = Total number of Waelz kilns or electrothermic furnaces at facility used for the zinc production.
(c) If GHG emissions from a Waelz
kiln or electrothermic furnace are vented through the same stack as any combustion unit or process equipment that reports CO 2 emissions using a CEMS that complies with the Tier 4 Calculation Methodology in subpart C of this part (General Stationary Fuel Combustion Sources), then the calculation methodology in paragraph (b) of this section shall not be used to calculate process emissions. The owner or operator shall report under this subpart the combined stack emissions according to the Tier 4 Calculation Methodology in § 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part. **§ 98.334 Monitoring and QA/QC requirements.** 

If you determine CO 2 emissions using the carbon input procedure in § 98.333(b)(1) and (b)(2), you must meet the requirements specified in paragraphs (a) and (b) of this section.

(a) Determine the mass of each solid carbon-containing input material consumed using facility instruments, procedures, or records used for accounting purposes including direct measurement weighing or through the use of purchase records same plant instruments or procedures that are used for accounting purposes (such as weigh hoppers, belt weigh feeders, weighed purchased quantities in shipments or containers, combination of bulk density and volume measurements, etc.). Record
the total mass for the materials
consumed each calendar month and sum the monthly mass to determine the annual mass for each input material.

(b) For each input material identified in paragraph (a) of this section, you must determine the average carbon
content of the material consumed or used in the calendar year using the methods specified in either paragraph (b)(1) or (b)(2) of this section.

(1) Information provided by your material supplier.

(2) Collecting and analyzing at least three representative samples of the material using the appropriate testing method. For each carbon-containing


### 56474 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

input material identified for which the carbon content is not provided by your material supplier, the carbon content of the material must be analyzed at least annually using the appropriate standard methods (and their QA/QC procedures), which are identified in paragraphs (b)(2)(i) through (b)(2)(iii) of this section, as applicable. If you document that a specific process input or output contributes less than one percent of the
total mass of carbon into or out of the process, you do not have to determine the monthly mass or annual carbon content of that input or output.

(i) Using ASTM E1941–04 Standard
Test Method for Determination of Carbon in Refractory and Reactive Metals and Their Alloys (incorporated by reference, see § 98.7), analyze zinc bearing materials.

(ii) Using ASTM D5373–08 Standard
Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal (incorporated by reference, see § 98.7), analyze carbonaceous reducing agents
and carbon electrodes.

(iii) Using ASTM C25–06 Standard Test Methods for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime (incorporated by reference, see § 98.7), analyze flux materials such as
limestone or dolomite.

**§ 98.335 Procedures for estimating missing data.** 

For the carbon input procedure in § 98.333(b), a complete record of all measured parameters used in the GHG emissions calculations is required (e.g., raw materials carbon content values,etc.). Therefore, whenever a qualityassured value of a required parameter is unavailable, a substitute data value for the missing parameter shall be used in the calculations as specified in paragraphs (a) and (b) of this section. You must document and keep records of the procedures used for all such

estimates.

(a) For missing records of the carbon content of inputs for facilities that estimate emissions using the carbon input procedure in § 98.333(b); 100 percent data availability is required. You must repeat the test for average carbon contents of inputs according to the procedures in § 98.335(b) if data are missing.

(b) For missing records of the annual mass of carbon-containing inputs using the carbon input procedure in § 98.333(b), the substitute data value
must be based on the best available estimate of the mass of the input material from all available process data or information used for accounting purposes, such as purchase records. **§ 98.336 Data reporting requirements.**
In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) or (b) of this section, as applicable, for each Waelz kiln or
electrothermic furnace.

(a) If a CEMS is used to measure CO 2 emissions, then you must report under this subpart the relevant information required for the Tier 4 Calculation Methodology in § 98.37 and the information listed in this paragraph (a):

(1) Annual zinc product production capacity (tons).

(2) Annual production quantity for each zinc product (tons).

(3) Annual facility production quantity for each zinc product (tons).

(4) Number of Waelz kilns at each facility used for zinc production.

(5) Number of electrothermic furnaces at each facility used for zinc production.

(b) If a CEMS is not used to measure

CO 2 emissions, then you must report the information listed in this paragraph (b):

(1) Kiln identification number and annual process CO 2 emissions from each
individual Waelz kiln or electrothermic furnace (metric tons).

(2) Annual zinc product production capacity (tons).

(3) Annual production quantity for each zinc product (tons).

(4) Number of Waelz kilns at each facility used for zinc production.

(5) Number of electrothermic furnaces at each facility used for zinc production.

(6) Annual mass of each carboncontaining input material charged to each kiln or furnace (including zinc bearing material, flux materials (e.g., limestone, dolomite), carbon electrode, and other carbonaceous materials (e.g., coal, coke)) (tons).

(7) Carbon content of each carboncontaining input material charged to each kiln or furnace (including zinc bearing material, flux materials, and other carbonaceous materials) from the annual carbon analysis for each kiln or furnace (percent by weight, expressed as a decimal fraction).

(8) Whether carbon content of each carbon-containing input material charged to each kiln or furnace is based on reports from the supplier or through self measurement using applicable
ASTM standard method.

(9) If carbon content of each carboncontaining input material charged to
each kiln or furnace is based on self measurement, the ASTM Standard Test
Method used.

(10) Carbon content of the carbon
electrode used in each furnace from the annual carbon analysis (percent by weight, expressed as a decimal fraction).

(11) Whether carbon content of the
carbon electrode used in each furnace is based on reports from the supplier or through self measurement using applicable ASTM standard method.

(12) If carbon content of carbon
electrode used in each furnace is based on self measurement, the ASTM
standard method used.

(13) If you use the missing data procedures in § 98.335(b), you mustreport how the monthly mass of carboncontaining materials with missing data
was determined and the number of months the missing data procedures
were used.

**§ 98.337 Records that must be retained.**

In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) through (b) of this section for each zinc production facility.

(a) If a CEMS is used to measure emissions, then you must retain under this subpart the records required for the Tier 4 Calculation Methodology in § 98.37 and the information listed in this paragraph (a):

(1) Monthly facility production quantity for each zinc product (tons).

(2) Annual operating hours for all
Waelz kilns and electrothermic furnaces used in zinc production.

(b) If a CEMS is not used to measure emissions, you must also retain the records specified in paragraphs (b)(1) through (b)(7) of this section.

(1) Records of all analyses and calculations conducted for data reported as listed in § 98.336(b).

(2) Annual operating hours for Waelz
kilns and electrothermic furnaces used in zinc production.

(3) Monthly production quantity for each zinc product (tons).

(4) Monthly mass of zinc bearing materials, flux materials (e.g., limestone, dolomite), and carbonaceous materials (e.g., coal, coke) charged to the kiln or furnace (tons).

(5) Sampling and analysis records for carbon content of zinc bearing materials, flux materials (e.g., limestone, dolomite), carbonaceous materials (e.g., coal, coke), charged to the kiln or furnace (percent by weight, expressed as a decimal fraction).

(6) Monthly mass of carbon electrode
consumed in for each electrothermic furnace (tons).

(7) Sampling and analysis records for
carbon content of electrode materials.

(8) You must keep records that include a detailed explanation of how company records of measurements are used to estimate the carbon input to
each Waelz kiln or electrothermic furnace, as applicable to your facility, including documentation of any materials excluded from Equation GG–


### 56475 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

1 of this subpart that contribute less than 1 percent of the total carbon inputs to the process. You also must document the procedures used to ensure the accuracy of the measurements of materials fed, charged, or placed in an affected unit including, but not limited to, calibration of weighing equipment
and other measurement devices. The estimated accuracy of measurements
made with these devices must also be recorded, and the technical basis for these estimates must be provided.

**§ 98.338 Definitions.**

All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. **Subpart HH—Municipal Solid Waste**
**Landfills**

**§ 98.340 Definition of the source category.**

(a) This source category applies to municipal solid waste (MSW) landfills that accepted waste on or after January

1, 1980.

(b) This source category does not include hazardous waste landfills, construction and demolition landfills,
or industrial landfills.

(c) This source category consists of the following sources at municipal solid waste (MSW) landfills: Landfills, landfill gas collection systems, and landfill gas destruction devices (including flares).

**§ 98.341 Reporting threshold.**

You must report GHG emissions under this subpart if your facility contains a MSW landfill and the facility meets the requirements of § 98.2(a)(1). **§ 98.342 GHGs to report.** (a) You must report CH4 generation
and CH 4 emissions from landfills.

(b) You must report CH4 destruction resulting from landfill gas collection and combustion systems.

(c) You must report under subpart C of this part (General Stationary Fuel Combustion Sources) the emissions of

CO 2 , CH 4 , and N 2 O from each stationary combustion unit following the requirements of subpart C.

**§ 98.343 Calculating GHG emissions.**

(a) For all landfills subject to the reporting requirements of this subpart,
calculate annual modeled CH4 generation according to the applicable requirements in paragraphs (a)(1) through (a)(3) of this section.

(1) Calculate annual modeled CH4 generation using Equation HH–1 of this

section.



### G WL e e

CH x x kT x kT x

x S T

4 

### = − 

# ( ) 

# { } ⎡

⎣ ⎢ ⎢ ⎤

⎦ ⎥ ⎥ − −− − −

= − 

# ∑ 0 1

1

, ( ) () 

### ( . Eq HH-1)

Where:

GCH4 = Modeled methane generation rate in reporting year T (metric tons CH4 ). X = Year in which waste was disposed. S = Start year of calculation. Use the year 50 years prior to the year of the emissions estimate, or the opening year of the landfill, whichever is more recent. T = Reporting year for which emissions are
calculated.

W

x = Quantity of waste disposed in the landfill in year X from tipping fee receipts or other company records (metric tons, as received (wet weight)).

L 0 = CH 4 generation potential (metric tons

CH 4 /metric ton waste) = MCF × DOC × DOC F × F × 16/12. MCF = Methane correction factor (fraction);
default is 1. DOC = Degradable organic carbon from Table HH–1 of this subpart or measurement data, if available [fraction (metric tons C/ metric ton waste)].

DOC F = Fraction of DOC dissimilated (fraction); default is 0.5. F = Fraction by volume of CH4 in landfill gas from measurement data, if available (fraction); default is 0.5. k = Rate constant from Table HH–1 of this subpart or measurement data, if available (yr

¥ 1 ).

(2) For years when material-specific waste quantity data are available, apply Equation HH–1 of this section for each waste quantity type and sum the CH4 generation rates for all waste types to
calculate the total modeled CH4 generation rate for the landfill. Use the appropriate parameter values for k, DOC, MCF, DOC F , and F shown in Table HH–1 of this subpart. The annual quantity of each type of waste disposed
must be calculated as the sum of the daily quantities of waste (of that type) disposed. You may use the bulk waste parameters for a portion of your wastematerials when using the materialspecific modeling approach for mixed waste streams that cannot be designated to a specific material type. For years when waste composition data are not available, use the bulk waste parameter
values for k and L 0 in Table HH–1 of this subpart for the total quantity of waste disposed in those years.

(3) For years prior to reporting for which waste disposal quantities are not readily available, W

x shall be estimated using one of the applicable methods in paragraphs (a)(3)(i) through (a)(3)(iii) of
this section. You must determine which method is most applicable to the conditions and disposal history of your facility and use that method to estimate waste disposal quantities.

(i) Assume all prior year waste disposal quantities are the same as the waste quantity in the first reporting

year.

(ii) Use the estimated population served by the landfill in each year, the values for national average per capita waste generation, and fraction of generated waste disposed of in solid waste disposal sites found in Table HH– 2 of this subpart, and calculate the waste quantity landfilled using Equation
HH–2 of this section.



### W POP WGR SWDS

xxx x



### =× × %

% 100 (Eq. HH-2)

Where:

W

x = Quantity of waste placed in the landfill in year × (metric tons, wet basis).

POP

x = Population of served by the landfill in year × from city population, census data, or other estimates (capita). WGR = Average per capita waste generation rate for year x from Table HH–2 of this subpart (metric tons per capita per year, wet basis; tons/cap/yr). %SWDS = Percent of waste generated subsequently managed in solid waste disposal sites (i.e., landfills) for year × from Table HH–2 of this subpart.

(iii) Use a constant average waste disposal quantity calculated using Equation HH–3 of this section for each year the landfill was in operation (i.e.,


### 56476 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

from first accepting waste until the last year for which waste disposal data is unavailable, inclusive).



### WAR LFC

YrData YrOpen = − +

( ) 1 (Eq. HH-3)

Where: WAR = Annual average waste acceptance rate (metric tons per year). LFC = Landfill capacity or, for operating landfills, capacity of the landfill currently used from design drawings or engineering estimates (metric tons).
YrData = Year in which the landfill last received waste or, for operating landfills, the year prior to the first reporting year when waste disposal data is first available from company records, or best
available data. YrOpen = Year in which the landfill first received waste from company records or best available data. If no data are available for estimating YrOpen for a closed landfill, use 30 years as the default operating life of the landfill.

(b) For landfills with gas collection systems, calculate the quantity of CH4 destroyed according to the requirements in paragraphs (b)(1) and (b)(2) of this

section.

(1) If you continuously monitor the flow rate, CH4 concentration, temperature, pressure, and moisture content of the landfill gas that is collected and routed to a destruction device (before any treatment equipment) using a monitoring meter specifically for

CH 4 gas, as specified in § 98.344, you must use this monitoring system and calculate the quantity of CH4 recovered for destruction using Equation HH–4 of this section. A fully integrated system that directly reports CH4 content requires no other calculation than summing the results of all monitoring periods for a given year.



### RV f C R

T P

n H n o

n n 

### = ×− 

## ( ) ⎡ ⎣ ⎤ ⎦ × × × ×× ( ) ( )

% . ( ) ( ) 1 100 0 0423 520

1 1 20 n 

### atm , .

, ( . 440 0 454

1 000 1 

### × ⎛
⎝ ⎜ ⎞
⎠ ⎟

= 

# ∑ Eq

n N 

### HH-4)

Where: R = Annual quantity of recovered CH4 (metric

tons CH 4 ). N = Total number of measurement periods in a year. Use daily averaging periods for continuous monitoring system (N = 365). For weekly sampling, use N = 52. n = Index for measurement period. (V)

n = Daily average volumetric flow rate for day n (acfm). If the flow rate meter automatically corrects for temperature and pressure, replace ‘‘520 ° R/(T)

n × (P)

n/
1 atm’’ with ‘‘1’’. If the CH4 concentration is determined on a dry
basis and the flow rate meter automatically corrects for moisture/ content, replace the term [1 ¥ (f H 20 )

n ]
with 1. (f

H 2 O )

n = Daily average moisture content of landfill gas, volumetric basis (cubic feet water per cubic feet landfill gas). (C)

n = Daily average CH4 concentration of landfill gas for day n (volume %, dry basis). If the CH4 concentration is determined on a wet basis, replace the term [1 ¥ (f H 20 )

n ] with 1. 0.0423 = Density of CH4 lb/cf at 520 ° R or 60

° F and 1 atm. (T)

n = Temperature at which flow is measured for day n ( ° R). (P)

n = Pressure at which flow is measured for day n (atm). 1,440 = Conversion factor (min/day). 0.454/1,000 = Conversion factor (metric ton/ lb). (2) If you do not continuously monitor according to paragraph (b)(1) of this section, you must determine the flow rate, CH 4 concentration, temperature, pressure, and moisture content of the landfill gas that is collected and routed to a destruction device (before any treatment equipment) at least weekly according to the requirements in paragraphs (b)(2)(i) through (b)(2)(iii) of this section and calculate the quantity of

CH4 recovered for destruction using Equation HH–4 of this section.

(i) Continuously monitor gas flow rate
and determine the cumulative volume of landfill gas each week and the cumulative volume of landfill gas each year that is collected and routed to a destruction device (before any treatment equipment). Under this option, the gas flow meter is not required to automatically correct for temperature, pressure, or, if necessary, moisture content. If the gas flow meter is not equipped with automatic correction for temperature, pressure, or, if necessary, moisture content, you must determine these parameters as specified in paragraph (b)(2)(iii) of this section.

(ii) Determine the CH4 concentration in the landfill gas that is collected and routed to a destruction device (before any treatment equipment) in a location near or representative of the location of the gas flow meter no less than weekly.

(iii) If the gas flow meter is not equipped with automatic correction for temperature, pressure, or, if necessary,

moisture content:

(A) Determine the temperature, pressure in the landfill gas that is
collected and routed to a destruction device (before any treatment equipment) in a location near or representative of the location of the gas flow meter no less than weekly.

(B) If the CH 4 concentration is determined on a dry basis, determine the moisture content in the landfill gas
that is collected and routed to a destruction device (before any treatment equipment) in a location near or representative of the location of the gas flow meter no less than weekly

(c) Calculate CH4 generation (adjusted for oxidation in cover materials) and
actual CH4 emissions (taking into account any CH4 recovery, and oxidation in cover materials) according to the applicable methods in paragraphs (c)(1) through (c)(3) of this section.

(1) Calculate CH4 generation, adjusted for oxidation, from the modeled CH4 (GCH4 from Equation HH–1 of this section) using Equation HH–5 of this

section.



### MG G OX Eq CH 

### = ×− 4 

### 1 ( ) ( . HH-5)

Where: MG = Methane generation, adjusted for oxidation, from the landfill in the reporting year (metric tons CH

4 ).

GCH4 = Modeled methane generation rate in reporting year from Equation HH–1 of this section (metric tons CH4 ).
OX = Oxidation fraction. Use the default value of 0.1 (10%).

(2) For landfills that do not have landfill gas collection systems, the CH4 emissions are equal to the CH4 generation (MG) calculated in Equation
HH–5 of this section.

(3) For landfills with landfill gas collection systems, calculate CH4 emissions using the methodologies specified in paragraphs (c)(3)(i) and (c)(3)(ii) of this section.


### 56477 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

(i) Calculate CH4 emissions from the
modeled CH4 generation and measured CH 4 recovery using Equation HH–6 of
this section.



### Emissions G R OX R DE f Eq CH Dest 

### = − 

## ( ) × − 

## ( ) +×− × 

## ( ) 

# ( ) ⎡ ⎣ ⎤ ⎦ 4 

### 1 1 ( . HH-6)

Where:

Emissions = Methane emissions from the landfill in the reporting year (metric tons

CH 4 ).

GCH4 = Modeled methane generation rate in reporting year from Equation HH–1 of this section or the quantity of recovered

CH 4 from Equation HH–4 of this section, whichever is greater (metric tons CH4 ). R = Quantity of recovered CH4 from Equation HH–4 of this section (metric tons).
OX = Oxidation fraction. Use the oxidation fraction default value of 0.1 (10%). DE = Destruction efficiency (lesser of manufacturer’s specified destruction efficiency and 0.99). If the gas is transported off-site for destruction, use

DE = 1.
f Dest = Fraction of hours the destruction device was operating (annual operating hours/8760 hours per year). If the gas is destroyed in a back-up flare (or simlar device) or if the gas is transported off-site for destruction, use f Dest = 1.

(ii) Calculate CH4 generation and CH4 emissions using measured CH4 recovery and estimated gas collection efficiency and Equations HH–7 and HH–8 of this

section.



### MG R

CE f OX Eq

c 

### = × × −

Re 

### ( ) (. 1 HH-7)

Emissions R

CE f R OX R DE f

c Dest 

### = × − ⎛
⎝ ⎜ ⎞
⎠ ⎟ × −



## ( ) +×− × 

## ( ) 

# ( ) ⎡

⎣ ⎢ ⎢ ⎤

⎦ ⎥ ⎥ Re 

### 11 ( . Eq HH- ) 8

Where: MG = Methane generation, adjusted for oxidation, from the landfill in the reporting year (metric tons CH4 ).
Emissions = Methane emissions from the landfill in the reporting year (metric tons

CH 4 ). R = Quantity of recovered CH4 from Equation HH–4 of this section (metric tons CH4 ). CE = Collection efficiency estimated at landfill, taking into account system coverage, operation, and cover system
materials from Table HH–3 of this subpart. If area by soil cover type information is not available, use default value of 0.75 (CE4 in table HH–3 of this subpart) for all areas under active influence of the collection system.
f Rec = Fraction of hours the recovery system was operating (annual operating hours/ 8760 hours per year).
OX = Oxidation fraction. Use the oxidation fractions default value of 0.1 (10%). DE = Destruction efficiency, (lesser of manufacturer’s specified destruction efficiency and 0.99). If the gas is transported off-site for destruction, use

DE = 1.
f Dest = Fraction of hours the destruction device was operating (device operating hours/8760 hours per year). If the gas is destroyed in a back-up flare (or similar device) or if the gas is transported off-site for destruction, use f Dest = 1.

**§ 98.344 Monitoring and QA/QC requirements.** 

(a) The quantity of waste landfilled must be determined using mass measurement equipment meeting the requirements for commercial weighing equipment as described in ‘‘Specifications, Tolerances, and Other Technical Requirements For Weighing and Measuring Devices’’ NIST Handbook 44 (2009)(incorporated by reference, see § 98.7).

(b) For landfills with gas collection systems, install, operate, maintain, and calibrate a gas composition monitor capable of measuring the concentration of CH4 in the recovered landfill gas using one of the methods specified in paragraphs (b)(1) through (b)(6) of this section or as specified by the manufacturer. Gas composition monitors shall be calibrated prior to the first reporting year and recalibrated either annually or at the minimum frequency specified by the manufacturer, whichever is more frequent, or whenever the error in the midrange calibration check exceeds ± 10 percent.

(1) Method 18 at 40 CFR part 60, appendix A–6.

(2) ASTM D1945–03, Standard Test Method for Analysis of Natural Gas by Gas Chromatography (incorporated by reference, see § 98.7).

(3) ASTM D1946–90 (Reapproved 2006), Standard Practice for Analysis of Reformed Gas by Gas Chromatography (incorporated by reference, see § 98.7).

(4) GPA Standard 2261–00, Analysis
for Natural Gas and Similar Gaseous Mixtures by Gas Chromatography.

(5) UOP539–97 Refinery Gas Analysis by Gas Chromatography (incorporated by reference, see § 98.7). (6) As an alternative to the gas chromatography methods provided in paragraphs (b)(1) through (b)(5) of this section, you may use total gaseous organic concentration analyzers and
calculate the methane concentration following the requirements in paragraphs (b)(6)(i) through (b)(6)(iii) of
this section.

(i) Use Method 25A or 25B at 40 CFR part 60, appendix A–7 to determine total gaseous organic concentration. You
must calibrate the instrument with
methane and determine the total gaseous organic concentration as carbon (or as methane; K=1 in Equation 25A– 1 of Method 25A at 40 CFR part 60, appendix A–7).

(ii) Determine a non-methane organic
carbon correction factor no less frequently than once a reporting year following the requirements in paragraphs (b)(6)(ii)(A) through (b)(6)(ii)(C) of this section.

(A) Take a minimum of three grab samples of the landfill gas that is
collected and routed to a destruction device (before any treatment equipment)
with a minimum of 20 minutes between samples and determine the methane composition of the landfill gas using one of the methods specificed in paragraphs (b)(1) through (b)(5) of this

section.

(B) As soon as practical after each grab sample is collected and prior to the collection of a subsequent grab sample, determine the total gaseous organic concentration of the landfilll gas that is


### 56478 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

collected and routed to a destruction device (before any treatment equipment) using either Method 25A or 25B at 40 CFR part 60, appendix A–7 as specified in paragaph (b)(6)(i) of this section.

(C) Determine the arithmetic average
methane concentration and the arithmetic average total gaseous organic concentration of the samples analyzed according to paragraphs (b)(6)(ii)(A) and (b)(6)(ii)(B) of this section, respectively, and calculate the non-methane organic
carbon correction factor as the ratio of the average methane concentration to the average total gaseous organic concentration. If the ratio exceeds 1, use 1 for the non-methane organic carbon
correction factor.

(iii) Calculate the methane concentration as specified in Equation
HH–9 of this section.



### C (Eq. HH-9)

CH4 

### = × f C

NMOC TGOC

Where:

C CH4 = Methane concentration in the landfill gas (volume %).
f NMOC = Non-methane organic carbon
correction factor from the most recent
determination of the non-methane organic carbon correction factor as specified in paragraph (b)(6)(ii) of this section (unitless).

C TGOC = Total gaseous organic carbon concentration measured using Method 25A or 25B at 40 CFR part 60, appendix A–7 during routine monitoring of the landfill gas (volume %).
(c) For landfills with gas collection systems, install, operate, maintain, and calibrate a gas flow meter capable of measuring the volumetric flow rate of the recovered landfill gas using one of the methods specified in paragraphs (c)(1) through (c)(8) of this section or as specified by the manufacturer. Each gas flow meter shall be calibrated prior to the first year of reporting and recalibrated either biennially (every 2 years) or at the minimum frequency specified by the manufacturer. Except as provided in § 98.343(b)(2)(i), each gas flow meter must be capable of correcting for the temperature and pressure and, if the gas composition monitor determines

CH 4 concentration on a dry basis,

moisture content.

(1) ASME MFC–3M–2004, Measurement of Fluid Flow in Pipes Using Orifice, Nozzle, and Venturi (incorporated by reference, see § 98.7).

(2) ASME MFC–4M–1986 (Reaffirmed 1997), Measurement of Gas Flow by Turbine Meters (incorporated by reference, see § 98.7).

(3) ASME MFC–6M–1998, Measurement of Fluid Flow in Pipes Using Vortex Flowmeters (incorporated by reference, see § 98.7). (4) ASME MFC–7M–1987 (Reaffirmed 1992), Measurement of Gas Flow by
Means of Critical Flow Venturi Nozzles (incorporated by reference, see § 98.7).

(5) ASME MFC–11M–2006 Measurement of Fluid Flow by Means of Coriolis Mass Flowmeters (incorporated by reference, see § 98.7). The mass flow
must be corrected to volumetric flow based on the measured temperature, pressure, and gas composition.

(6) ASME MFC–14M–2003 Measurement of Fluid Flow Using Small
Bore Precision Orifice Meters (incorporated by reference, see § 98.7).

(7) ASME MFC–18M–2001 Measurement of Fluid Flow using Variable Area Meters (incorporated by reference, see § 98.7).

(8) Method 2A or 2D at 40 CFR part 60, appendix A–1.

(d) All temperature and pressure monitors must be calibrated using the procedures and frequencies specified by
the manufacturer.

(e) The owner or operator shall document the procedures used to ensure the accuracy of the estimates of disposal quantities and, if applicable, gas flow rate, gas composition, temperature, and pressure measurements. These procedures include, but are not limited to, calibration of weighing equipment, fuel flow meters, and other
measurement devices. The estimated accuracy of measurements made with these devices shall also be recorded, and
the technical basis for these estimates shall be provided.

**§ 98.345 Procedures for estimating missing data.** 

A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable (e.g., if a meter malfunctions during unit operation or if a required fuel sample is not taken), a substitute data value for the missing parameter shall be used in the calculations, according to the requirements in paragraphs (a) through (c) of this section.

(a) For each missing value of the CH4 content, the substitute data value shallbe the arithmetic average of the qualityassured values of that parameter immediately preceding and immediately following the missing data incident. If the ‘‘after’’ value is not obtained by the end of the reporting year, you may use the ‘‘before’’ value for the missing data substitution. If, for a particular parameter, no quality-assured data are available prior to the missing data incident, the substitute data value shall be the first quality-assured value obtained after the missing data period. (b) For missing gas flow rates, the
substitute data value shall be the arithmetic average of the quality-assured values of that parameter immediately preceding and immediately following the missing data incident. If the ‘‘after’’ value is not obtained by the end of the reporting year, you may use the ‘‘before’’ value for the missing data substitution. If, for a particular parameter, no quality-assured data are available prior to the missing data incident, the substitute data value shall be the first quality-assured value obtained after the missing data period.

(c) For missing daily waste disposal quantity data for disposal in reporting years, the substitute value shall be the average daily waste disposal quantity for that day of the week as measured on
the week before and week after the missing daily data.

**§ 98.346 Data reporting requirements.**

In addition to the information required by § 98.3(c), each annual report must contain the following information
for each landfill.

(a) A classification of the landfill as ‘‘open’’ (actively received waste in the reporting year) or ‘‘closed’’ (no longer receiving waste), the year in which the landfill first started accepting waste for disposal, the last year the landfill accepted waste (for open landfills, enter the estimated year of landfill closure), the capacity (in metric tons) of the landfill, an indication of whether leachate recirculation is used, and the waste disposal quantity for each year of landfilling.

(b) Method for estimating waste disposal quantity, and reason for its
selection.

(c) Waste composition for each year of landfilling, if available, in percentage categorized as:

(1) Municipal. (2) Biosolids or biological sludges. (3) Other, or more refined categories,
such as those for which k rates are available in Table HH–1 of this subpart, and the method or basis for estimating waste composition.

(d) For each waste type used to
calculate CH4 generation using Equation HH–1 of this subpart, you must report:

(1) Degradable organic carbon (DOC)
value used in the calculations.

(2) Decay rate (k) value used in the
calculations.

(e) Fraction of CH4 in landfill gas (F)
and an indication of whether the
fraction of CH4 was determined based
on measured values or the default value.

(f) The surface area of the landfill containing waste (in square meters), the cover types applicable to the landfill,
the surface area and oxidation fraction


### 56479 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

for each cover type used to calculate the average oxidation fraction, and the average oxidation fraction used in the
calculations.

(g) The modeled annual methane generation rate for the reporting year (metric tons CH4 ) calculated using Equation HH–1 of this subpart.

(h) For landfills without gas collection systems, the annual methane emissions (i.e., the methane generation, adjusted for oxidation, calculated using Equation HH–5 of this subpart), reported in

metric tons CH4
.

(i) For landfills with gas collection systems, you must report:

(1) Total volumetric flow of landfill gas collected for destruction (cubic feet

at 520 ° R or 60 ° F and 1 atm).

(2) CH 4 concentration of landfill gas collected for destruction (percent by volume).

(3) Monthly average temperature for
each month at which flow is measured for landfill gas collected for destruction, or statement that temperature is incorporated into internal calculations run by the monitoring equipment.

(4) Monthly average pressure for each
month at which flow is measured for landfill gas collected for destruction, or statement that temperature is incorporated into internal calculations run by the monitoring equipment.

(5) An indication of whether destruction occurs at the landfill facility
or off-site. If destruction occurs at the landfill facility, also report an indication of whether a back-up destruction device is present at the landfill, the annual operating hours for the primary destruction device, the annual operating hours for the back-up destruction device (if present), and the destruction efficiency used (percent).

(6) Annual quantity of recovered CH4 (metric tons CH4 ) calculated using Equation HH–4 of this subpart.

(7) A description of the gas collection system (manufacture, capacity, number of wells, etc.), the surface area (square meters) and estimated waste depth (meters) for each area specified in Table HH–3 of this subpart, the estimated gas collection system efficiency for landfills with this gas collection system, and the annual operating hours of the gas collection system.

(8) Methane generation corrected for oxidation calculated using Equation HH–5 of this subpart, reported in metric

tons CH4
. (9) Methane generation (GCH4 ) value used as an input to Equation HH–6 of this subpart. Specify whether the value is modeled (GCH4 from HH–1 of this subpart) or measured (R from Equation HH–4 of this subpart).

(10) Methane generation corrected for oxidation calculated using Equation HH–7 of this subpart, reported in metric

tons CH4
.

(11) Methane emissions calculated using Equation HH–6 of this subpart, reported in metric tons CH4
.

(12) Methane emissions calculated using Equation HH–8 of this subpart, reported in metric tons CH4
.

**§ 98.347 Records that must be retained.**

In addition to the information required by § 98.3(g), you must retain
the calibration records for all monitoring equipment, including the method or manufacturer’s specification
used for calibration.

**§ 98.348 Definitions.**

All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.



### TABLE 

### HH–1 TO 

### S UBPART 

### HH OF 

### P ART 

### 98—E MISSIONS 

### FACTORS 

### , O XIDATION 

### FACTORS AND 

### M ETHODS

Factor Default value Units

**Waste model—bulk waste option**

k (precipitation <20 inches/year and no leachate recirculation) 0.02 ......................................... yr

¥ 1k (precipitation 20–40 inches/year and no leachate recirculation). 0.038 ....................................... yr

¥ 1

k (precipitation >40 inches/year or for landfill areas with leachate recirculation). 0.057 ....................................... yr

¥ 1

L 0 (Equivalent to DOC = 0.2028 when MCF = 1, DOC F = 0.5,

and F = 0.5). 0.067 ....................................... metric tons CH 4/metric ton waste

**Waste model—All MSW landfills**

MCF ............................................................................................ 1 ...............................

............... DOC F ........................................................................................... 0.5 .................................

.......... F .................................................................................................. 0.5 .........................

..................

**Waste model—MSW using waste composition option**

DOC (food waste) ....................................................................... 0.15 .................................... ..... Weight fraction, wet basis DOC (garden) ............................................................................. 0.2 ................................... ........ Weight fraction, wet basis DOC (paper) ............................................................................... 0.4 .................................. ......... Weight fraction, wet basis DOC (wood and straw) ............................................................... 0.43 ........................................ . Weight fraction, wet basis DOC (textiles) ............................................................................. 0.24 ................................ ......... Weight fraction, wet basis DOC (diapers) ............................................................................. 0.24 ................................. ........ Weight fraction, wet basis DOC (sewage sludge) ................................................................ 0.05 ........................................ . Weight fraction, wet basis DOC (bulk waste) ....................................................................... 0.20 .................................... ..... Weight fraction, wet basis k (food waste) ............................................................................. 0.06 to 0.185 a ......................... yr ¥ 1 k (garden) .................................................................................... 0.05 to 0.10 a ........................... yr ¥ 1 k (paper) ...................................................................................... 0.04 to 0.06 a ........................... yr ¥ 1 k (wood and straw) ..................................................................... 0.02 to 0.03 a ........................... yr ¥ 1 k (textiles) .................................................................................... 0.04 to 0.06 a ........................... yr ¥ 1 k (diapers) ................................................................................... 0.05 to 0.10 a ........................... yr ¥ 1 k (sewage sludge) ....................................................................... 0.06 to 0.185 a ......................... yr ¥ 1

**Calculating methane generation and emissions**

OX ............................................................................................... 0.1 ...........................

................


### 56480 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

TABLE 

### HH–1 TO 

### S UBPART 

### HH OF 

### P ART 

### 98—E MISSIONS 

### FACTORS 

### , O XIDATION 

### FACTORS AND 

### M ETHODS

### —Continued

Factor Default value Units

DE ............................................................................................... 0.99 ..........................

...............

a Use the lesser value when the potential evapotranspiration rate exceeds the mean annual precipitation rate and leachate recircu lation is not used. Use the greater value when the potential evapotranspiration rate does not exceed the mean annual precipitation rate or wh en leachate recirculation is used.



### TABLE 

### HH–2 TO 

### S UBPART 

### HH OF 

### P ART 

### 98—U.S. P ER 

### C APITA 

### WASTE 

### D ISPOSAL 

### R ATES

Year Waste per capita ton/cap/yr % to SWDS

1950 ........................................................................................................................... .............................................. 0.63 100

1951 ........................................................................................................................... .............................................. 0.63 100

1952 ........................................................................................................................... .............................................. 0.63 100

1953 ........................................................................................................................... .............................................. 0.63 100

1954 ........................................................................................................................... .............................................. 0.63 100

1955 ........................................................................................................................... .............................................. 0.63 100

1956 ........................................................................................................................... .............................................. 0.63 100

1957 ........................................................................................................................... .............................................. 0.63 100

1958 ........................................................................................................................... .............................................. 0.63 100

1959 ........................................................................................................................... .............................................. 0.63 100

1960 ........................................................................................................................... .............................................. 0.63 100

1961 ........................................................................................................................... .............................................. 0.64 100

1962 ........................................................................................................................... .............................................. 0.64 100

1963 ........................................................................................................................... .............................................. 0.65 100

1964 ........................................................................................................................... .............................................. 0.65 100

1965 ........................................................................................................................... .............................................. 0.66 100

1966 ........................................................................................................................... .............................................. 0.66 100

1967 ........................................................................................................................... .............................................. 0.67 100

1968 ........................................................................................................................... .............................................. 0.68 100

1969 ........................................................................................................................... .............................................. 0.68 100

1970 ........................................................................................................................... .............................................. 0.69 100

1971 ........................................................................................................................... .............................................. 0.69 100

1972 ........................................................................................................................... .............................................. 0.70 100

1973 ........................................................................................................................... .............................................. 0.71 100

1974 ........................................................................................................................... .............................................. 0.71 100

1975 ........................................................................................................................... .............................................. 0.72 100

1976 ........................................................................................................................... .............................................. 0.73 100

1977 ........................................................................................................................... .............................................. 0.73 100

1978 ........................................................................................................................... .............................................. 0.74 100

1979 ........................................................................................................................... .............................................. 0.75 100

1980 ........................................................................................................................... .............................................. 0.75 100

1981 ........................................................................................................................... .............................................. 0.76 100

1982 ........................................................................................................................... .............................................. 0.77 100

1983 ........................................................................................................................... .............................................. 0.77 100

1984 ........................................................................................................................... .............................................. 0.78 100

1985 ........................................................................................................................... .............................................. 0.79 100

1986 ........................................................................................................................... .............................................. 0.79 100

1987 ........................................................................................................................... .............................................. 0.80 100

1988 ........................................................................................................................... .............................................. 0.80 100

1989 ........................................................................................................................... .............................................. 0.85 84

1990 ........................................................................................................................... .............................................. 0.84 77

1991 ........................................................................................................................... .............................................. 0.78 76

1992 ........................................................................................................................... .............................................. 0.76 72

1993 ........................................................................................................................... .............................................. 0.78 71

1994 ........................................................................................................................... .............................................. 0.77 67

1995 ........................................................................................................................... .............................................. 0.72 63

1996 ........................................................................................................................... .............................................. 0.71 62

1997 ........................................................................................................................... .............................................. 0.72 61

1998 ........................................................................................................................... .............................................. 0.78 61

1999 ........................................................................................................................... .............................................. 0.78 60

2000 ........................................................................................................................... .............................................. 0.84 61

2001 ........................................................................................................................... .............................................. 0.95 63

2002 ........................................................................................................................... .............................................. 1.06 66

2003 ........................................................................................................................... .............................................. 1.06 65

2004 ........................................................................................................................... .............................................. 1.06 64

2005 ........................................................................................................................... .............................................. 1.06 64

2006 ........................................................................................................................... .............................................. 1.06 64


### 56481 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

TABLE 

### HH–3 TO 

### S UBPART 

### HH OF 

### P ART 

### 98—LANDFILL 

### G AS 

### C OLLECTION 

### E FFICIENCIES

Description Landfill Gas Collection Efficiency

A1: Area with no waste in-place .............................................................. Not applicable; do not use this area in the calculation. A2: Area without active gas collection, regardless of cover type ............ H2: Average depth of waste in area A2 ................................................... CE2: 0%.

A3: Area with daily soil cover and active gas collection .......................... H3: Average depth of waste in area A3 ................................................... CE3: 60%.

A4: Area with an intermediate soil cover and active gas collection ........ H4: Average depth of waste in area A4 ................................................... CE4: 75%.

A5: Area with a final soil and geomembrane cover system and active

gas collection. H5: Average depth of waste in area A5 ................................................... CE5: 95%.

Area weighted average collection efficiency for landfills ......................... CEave1 = (A2*CE2 + A3*CE3 + A4*CE4 + A5*CE5)/(A2+A3+A4+A5).

**Subpart II—[Reserved]**

**Subpart JJ—Manure Management**

**§ 98.360 Definition of the source category.**

(a) This source category consists of
livestock facilities with manure management systems that emit 25,000

metric tons CO 2 e or more per year. (1) Table JJ–1 presents the minimum average annual animal population by animal group that is estimated to emit 25,000 metric tons CO 2 e or more per year. Facilities with an average annual animal population, as described in § 98.363(a)(1) and (2), below those listed in Table JJ–1 do not need to report under this rule. A facility with an annual animal population that exceeds those listed in Table JJ–1 should conduct a more thorough analysis to determine applicability.

(2) (i) If a facility has more than one animal group present (e.g., swine and poultry), the facility must determine if they are required to report by calculating the combined animal group factor (CAGF) using equation JJ–1:



### CAGF AAAP

APTL (Eq. JJ-1) Animal Groups AG, Facility

AG 

### = ⎛
⎝ ⎜ ⎞
⎠ ⎟ 

# ∑

Where: CAGF = Combined Animal Group Factor

AAAP AG,Facility = Average annual animal population at the facility, by animal

group APTL AG = Animal population threshold level, as specified in Table JJ–1 of this

section
(ii) If the calculated CAGF for a facility is less than 1, the facility is not required to report under this rule. If the CAGF is equal to or greater than 1, the facility must use more detailed applicability tables and tools to determine if they are required to report
under this rule.

(b) A manure management system (MMS) is a system that stabilizes and/ or stores livestock manure, litter, or
manure wastewater 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, solid manure storage, dry lots (including feedlots), high-rise houses for poultry production (poultry without litter), poultry production with litter, deep bedding systems for cattle and swine, manure composting, and aerobic

treatment.

(c) This source category does not include system components at a livestock facility that are unrelated to the stabilization and/or storage of manure such as daily spread or pasture/ range/paddock systems or land application activities or any method of
manure utilization that is not listed in § 98.360(b).

(d) This source category does not include manure management activities located off site from a livestock facility or off-site manure composting operations.

**§ 98.361 Reporting threshold.**

Livestock facilities must report GHG emissions under this subpart if the facility meets the reporting threshold as defined in 98.360(a) above, contains a manure management system as defined in 98.360(b) above, and meets the requirements of § 98.2(a)(1).

**§ 98.362 GHGs to report.**

(a) Livestock facilities must report annual aggregate CH4 and N 2 O emissions for the following MMS components at the facility:

(1) Uncovered anaerobic lagoons. (2) Liquid/slurry systems (with and without crust covers, and including but not limited to ponds and tanks).

(3) Storage pits. (4) Digesters, including covered anaerobic lagoons. (5) Solid manure storage. (6) Dry lots, including feedlots. (7) High-rise houses for poultry production (poultry without litter)

(8) Poultry production with litter. (9) Deep bedding systems for cattle
and swine.

(10) Manure composting. (11) Aerobic treatment. (b) A livestock facility that is subject to this rule only because of emissions from manure management system components is not required to report emissions from subparts C through PP (other than subpart JJ) of this part.

(c) A livestock facility that is subject to this part because of emissions from source categories described in subparts C through PP of this part is not required to report emissions under subpart JJ of this part unless emissions from manure management systems are 25,000 metric
tons CO 2 e per year or more.

**§ 98.363 Calculating GHG emissions.**

(a) For all manure management system components listed in 98.360(b) except digesters, estimate the annual

CH 4 emissions and sum for all the components to obtain total emissions from the manure management system for all animal types using Equation JJ–

1.


### 56482 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

CH Emissions (metric tons/yr) TVS MMS animal types MMSC A 4 

### = ⎡ ⎣ 

# ∑ ∑ T MMSC

ss 0 AT MMSC 

### x VS

x VS x days/yr x B x MCF x kg 

## ( ⎡ ⎣

− 

## ( ) () 

# ) 1 365 0 662 . CH /m x metric ton/1000 kg (Eq. JJ-2)

4 3 

### 1 ⎤ ⎦

Where:

MMSC = Manure management systems
component.

TVS AT = Total volatile solids excreted by animal type, calculated using Equation JJ–3 of this section (kg/day).

VS MMSC = Fraction of the total manure for each animal type that is managed in MMS component MMSC, assumed to be equivalent to the fraction of VS in each MMS component.
VS

ss = Volatile solids removal through solid separation; if solid separation occurs prior to the MMS component, use a default value from Table JJ–4 of this section; if no solid separation occurs,
this value is set to 0. (B 0 ) AT = Maximum CH4 -producing capacity for each animal type, as specified in Table JJ–2 of this section (m 3 CH 4 /kg VS).

MCF MMSC = CH 4 conversion factor for the MMS component, as specified in Table JJ–5 of this section (decimal).



### TVS Population TAM VS Eq AT AT AT AT 

### = ×× /1000 3 ( . JJ- )

Where:

TVS AT = Daily total volatile solids excreted per animal type (kg/day). Population AT = Average annual animal population contributing manure to the manure management system by animal type (head) (see description in § 98.363(a)(i) and (ii) below).

TAM AT = Typical animal mass for each animal type, using either default valuesin Table JJ–2 of this section or farmspecific data (kg/head). VS AT = Volatile solids excretion rate for each animal type, using default values in Table JJ–2 or JJ–3 of this section (kg VS/ day/1000 kg animal mass). (1) Average annual animal populations for static populations (e.g., dairy cows, breeding swine, layers) must be estimated by performing an animal inventory or review of facility records once each reporting year.

(2) Average annual animal populations for growing populations (meat animals such as beef and veal cattle, market swine, broilers, and turkeys) must be estimated each year using the average number of days each animal is kept at the facility and the number of animals produced annually, and an equation similar or equal to Equation JJ–4 below, adapted from Equation 10.1 in 2006 IPCC Guidelines for National Greenhouse Gas
Inventories, Volume 4, Chapter 10.



### Population AT 

### = × ⎛ ⎝ ⎜ ⎞ ⎠ ⎟ Days onsite NAPA

365 (Eq. JJ-4) AT AT

Where:
Population AT = Average annual animal population (by animal type). Days onsite AT = Average number of days the animal is kept at the facility, by animal type.
NAPA AT = Number of animals produced annually, by animal type. (b) For each digester, calculate the
total amount of CH4 emissions, and then sum the emissions from all digesters, as shown in Equation JJ–5 of this section.



### H Emissions CH C CH D CH L (Eq. JJ-5)

4 AD 4 4 4

1 AD



### = −+ 

## ( ) 

# ∑

Where:

CH 4 Emissions AD = CH 4 emissions from anaerobic digestion (metric tons/yr). AD = Number of anaerobic digesters at the manure management facility.

CH 4 C = CH 4 flow to digester combustion device, calculated using Equation JJ–6 of this section (metric tons CH4 /yr). CH 4D = CH 4 destruction at digesters, calculated using Equation JJ–11 of this section (metric tons CH4 /yr) .

CH 4 L = Leakage at digesters calculated using Equation JJ–12 of this section (metric

tons CH 4 /yr). (1) For each digester, calculate the
annual CH4 flow to the combustion device (CH4 C) using Equation JJ–6 of this section. A fully integrated system that directly reports the quantity of CH4 flow to the digester combustion device requires only summing the results of all monitoring periods for a given year to
obtain CH4 C.



### CH C V C

100% R

T P

1 atm metric ton

1,000 po 4 o



### =× × × × × 0 0423 520 0 454

. .

u nds (Eq. JJ-6) ⎛ ⎝ ⎜ ⎞ ⎠ ⎟

Where:

CH 4 C = CH 4 flow to digester combustion device (metric tons CH4 /yr). V = Average annual volumetric flow rate, calculated in Equation JJ–7 of this subsection (cubic feet CH4 /yr). C = Average annual CH4 concentration of digester gas, calculated in Equation JJ–8 of this section (%, wet basis). 0.0423 = Density of CH4 lb/scf (at 520 ° R or

60 ° F and 1 atm).


### 56483 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

T = Average annual temperature at which flow is measured, calculated in Equation JJ–9 of this section ( ° R). P = Average annual pressure at which flow is measured, calculated in Equation JJ–10 of this section (atm). (2) For each digester, calculate the average annual volumetric flow rate, CH 4 concentration of digester gas, temperature, and pressure at which flow are measured using Equations JJ–7 through JJ–10 of this section.



### V V minutes
day

OD (Eq. JJ-7) n n 1 OD



### = × ⎛ ⎝ ⎜ ⎞ ⎠ ⎟

= 

# ∑ 1 440

,

Where:
V = Average annual volumetric flow rate (cubic feet CH 4 /yr). OD = Operating days, number of days per year that that the digester was operating (days/yr).

V

n = Daily average volumetric flow rate for day n, as determined from daily monitoring as specified in § 98.364 (acfm).



### C C

OD (Eq. JJ-8) n n 1 OD



### = =



# ∑

Where:
C = Average annual CH4 concentration of digester gas (%, wet basis). OD = Operating days, number of days per year that the digester was operating (days/yr).

C

n = Average daily CH4 concentration of digester gas for day n, as determined from daily monitoring as specified in § 98.364 (%, wet basis).



### T T

OD (Eq. JJ-9) n n 1 OD



### = =



# ∑

Where: T = Average annual temperature at which flow is measured ( ° R). OD = Operating days, number of days per year that the digester was operating (days/yr).

T

n = Temperature at which flow is measured for day n( ° R). 

### P P

OD (Eq. JJ-10) n n 1 OD



### = =



# ∑

Where:
P = Average annual pressure at which flow is measured (atm). OD = Operating days, number of days per year that the digester was operating (days/yr).

P

n = Pressure at which flow is measured for day n (atm).

(3) For each digester, calculate the

CH 4 destruction at the digester combustion device using Equation JJ–11
of this section.



### CH D CH C DE OH/Hours (Eq. JJ-11) 4 4 

### = ××

Where:

CH 4D = CH 4 destruction at digester combustion device (metric tons/yr).

CH 4 C = Annual quantity of CH4 flow to digester combustion device, as calculated in Equation JJ–6 of this section (metric tons CH4 ). DE = CH 4 destruction efficiency from flaring or burning in engine (lesser of manufacturer’s specified destruction efficiency and 0.99). If the gas is transported off-site for destruction, use

DE = 1. OH = Number of hours combustion device is functioning in reporting year. Hours = Hours in reporting year.

(4) For each digester, calculate the

CH 4 leakage using Equation JJ–12 of this

section.



### CH L CH C CE (Eq. JJ-12) 4 4 

### = ×− ⎛ ⎝ ⎜ ⎞ ⎠ ⎟ 1 1

Where:

CH 4 L = Leakage at digesters (metric tons/yr).

CH 4 C = Annual quantity of CH4 flow to digester combustion device, as calculated in Equation JJ–6 of this section (metric tons CH4 ). CE = CH 4 collection efficiency of anaerobic digester, as specified in Table JJ–6 of this section (decimal).

(c) For each MMS component,
estimate the annual N 2 O emissions and sum for all MMS components to obtain
total emissions from the manure management system for all animal types using Equation JJ–13 of this section.



### Direct N O Emissions (metric tons/year) 2 animal types 

### = 

# ∑ MMSC 

# ∑ ⎡ ⎣ ×

× −



## ( ) × × N ex AT 

### N (Eq. JJ-13)

1 N EF 365 da ex,MMSC

ss MMSC 

### y s/yr 44 N O/28 N O N 1 metric ton/1000 kg 2 2 

### ⎤ ⎦ × −× ⎤ ⎦

Where:

N ex AT = Daily total nitrogen excreted per animal type, calculated using Equation JJ–14 of this section (kg N/day). N ex,MMSC = Fraction of the total manure for each animal type that is managed in MMS component MMSC, assumed to be equivalent to the fraction of N

ex in each MMS component. N

ss = Nitrogen removal through solid separation; if solid separation occurs prior to the MMS component, use a default value from Table JJ–4 of this


### 56484 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

section; if no solid separation occurs,

this value is set to 0. EF MMSC = Emission factor for MMS component, as specified in Table JJ–7 of this section (kg N 2 O-N/kg N).



### N Population TAM N /1000 (Eq. JJ-14)

ex AT AT AT AT 

### = ××

Where:

N ex AT = Total nitrogen excreted per animal type (kg/day). Population AT = Average annual animal population contributing manure to the manure management system by animal type (head) (see description in § 98.363(a)(i) and (ii)).

TAM AT = Typical animal mass by animal type, using either default values in Table JJ–2 of this section or farm-specific data (kg/head).

NAT = Nitrogen excretion rate by animal type, using default values in Tables JJ–2 or JJ– 3 of this section (kg N/day/1000 kg animal mass).

(d) Estimate the annual total facility emissions using Equation JJ–15 of this

section.

Total Emissions (metric tons CO CH emissions + 2 4 MMS e yr

/ ) = 

## ( ⎡ ⎣ CH emissions x [Direct N O emissions 310] (Eq. JJ- 4 AD 2 

## ) 

## ] + 21 x 1 5)

Where:

CH 4 emissions MMS = From Equation JJ–2 of
this section.

CH 4 emissions AD = From Equation JJ–5 of this

section. 21 = Global Warming Potential of CH4
. Direct N 2 O emissions = From Equation JJ–13
of this section. 310 = Global Warming Potential of N 2 O.

**§ 98.364 Monitoring and QA/QC requirements.** 

(a) Perform an annual animal inventory or review of facility records (for static populations) or population calculation (for growing populations) to determine the average annual animal population for each animal type (see description in § 98.363(a)(1) and (2)).

(b) Perform an analysis on your operation to determine the fraction of total manure by weight for each animal type that is managed in each on-site manure management system component. If your system changes from previous reporting periods, you must
reevaluate the fraction of total manure managed in each system component.

(c) The CH 4 concentration of gas from digesters must be determined using ASTM D1946–90 (Reapproved 2006) Standard Practice for Analysis of Reformed Gas by Gas Chromatography (incorporated by reference see § 98.7). All gas composition monitors shall be calibrated prior to the first reporting year for biogas methane and carbon dioxide content using ASTM D1946–90 (Reapproved 2006) Standard Practice for Analysis of Reformed Gas by Gas Chromatography (incorporated by
reference see § 98.7)and recalibrated either annually or at the minimum frequency specified by the manufacturer, whichever is more frequent, or whenever the error in the midrange calibration check exceeds ± 10 percent. All monitors shall be maintained as specified by the
manufacturer.

(d) All temperature and pressure monitors must be calibrated using the procedures and frequencies specified by the manufacturer. All equipment (temperature and pressure monitors) shall be maintained as specified by the
manufacturer.

(e) For digesters with gas collection systems, install, operate, maintain, and calibrate a gas flow meter capable of measuring the volumetric flow rate to provide data for the GHG emissions calculations, using the applicable methods specified in paragraphs (e)(1) through (e)(6) of this section or as specified by the manufacturer.

(1) ASME MFC–3M–2004 Measurement of Fluid Flow in Pipes Using Orifice, Nozzle, and Venturi (incorporated by reference, see § 98.7).

(2) ASME MFC–4M–1986 (Reaffirmed 1997) Measurement of Gas Flow by Turbine Meters (incorporated by reference, see § 98.7).

(3) ASME MFC–6M–1998 Measurement of Fluid Flow in Pipes Using Vortex Flowmeters (incorporated by reference, see § 98.7).

(4) ASME MFC–7M–1987 (Reaffirmed 1992) Measurement of Gas Flow by
Means of Critical Flow Venturi Nozzles (incorporated by reference, see § 98.7).

(5) ASME MFC–14M–2003 Measurement of Fluid Flow Using Small
Bore Precision Orifice Meters (incorporated by reference, see § 98.7).

(6) ASME MFC–18M–2001 Measurement of Fluid Flow using Variable Area Meters (incorporated by reference, see § 98.7).

(f) If applicable, the owner or operator shall document the procedures used to ensure the accuracy of gas flow rate, gas composition, temperature, and pressure measurements. These procedures include, but are not limited to,
calibration of fuel flow meters and other measurement devices. The estimated accuracy of measurements made with these devices shall also be recorded, and
the technical basis for these estimates shall be provided.

(g) Each gas flow meter shall be calibrated prior to the first reporting year and recalibrated either annually or at the minimum frequency specified by the manufacturer, whichever is more frequent. Each gas flow meter must have a rated accuracy of ± 5 percent or lower and be capable of correcting for the temperature and pressure and, if the gas composition monitor determines CH4 concentration on a dry basis, moisture

content.

**§ 98.365 Procedures for estimating missing data.** 

(a) A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable (e.g., if a meter malfunctions during unit operation or if a required fuel sample is not taken), a substitute data value for the missing parameter shall be used in the calculations, according to the requirements in paragraph (b) of this

section.

(b) For missing gas flow rates or CH4 content data, the substitute data value shall be the arithmetic average of the quality-assured values of that parameter immediately preceding and immediately following the missing data incident. If,for a particular parameter, no qualityassured data are available prior to the missing data incident, the substitutedata value shall be the first qualityassured value obtained after the missing data period.

**§ 98.366 Data reporting requirements.**

(a) In addition to the information required by § 98.3(c), each annual report must contain the following information:


### 56485 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

(1) List of manure management system components at the facility.

(2) Fraction of manure from each animal type that is handled in each manure management system component.

(3) Average annual animal population (for each animal type) for static populations or the results of Equation JJ–4 for growing populations.

(4) Average number of days that growing animals are kept at the facility (for each animal type).

(5) The number of animals produced annually for growing populations (for each animal type).

(6) Typical animal mass (for each animal type).

(7) Total facility emissions (results of Equation JJ–15).

(8) CH 4 emissions from manure management system components listed in § 98.360(b), except digesters (results of Equation JJ–2).

(9) VS value used (for each animal type).

(10) B 0 value used (for each animal type). (11) Methane conversion factor used for each MMS component.

(12) Average ambient temperature
used to select each methane conversion
factor.

(13) N 2 O emissions (results of Equation JJ–13).

(14) N value used for each animal type.

(15) N 2 O emission factor selected for each MMS component.

(b) Facilities with anaerobic digesters must also report:

(1) CH4 emissions from anaerobic digesters (results of Equation JJ–5).

(2) CH 4 flow to the digester combustion device for each digester (results of Equation JJ–6, or value from fully integrated monitoring system as described in 98.363(b)).

(3) CH 4 destruction for each digester (results of Equation JJ–11).

(4) CH 4 leakage for each digester (results of Equation JJ–12).

(5) Total annual volumetric biogas flow for each digester (results of Equation JJ–7). (6) Average annual CH4 concentration for each digester (results of Equation JJ– 8).

(7) Average annual temperature at which gas flow is measured for each digester (results of Equation JJ–9).

(8) Average annual gas flow pressure at which gas flow is measured for each digester (results of Equation JJ–10).

(9) Destruction efficiency used for each digester.

(10) Number of days per year that each digester was operating.

(11) Collection efficiency used for each digester.

**§ 98.367 Records that must be retained.**

In addition to the information required by § 98.3(g), you must retain
the calibration records for all monitoring equipment, including the method or manufacturer’s specification
used for calibration.

**§ 98.368 Definitions.**

All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.



### TABLE 

### JJ–1 TO 

### S UBPART 

### JJ OF 

### P ART 

### 98—A NIMAL 

### P OPULATION 

### T HRESHOLD 

### L EVEL 

### B ELOW 

### W HICH 

### FACILITIES 

### A RE 

### N OT 

### R EQUIRED 

### T O 

### R EPORT 

### E MISSIONS 

### U NDER 

### S UBPART 

### JJ 1,2

Animal group Average annual animal population (Head) 3

Beef ........................................................................................................................... ........................................................................... 29,300 Dairy .......................................................................................................................... ........................................................................... 3,200
Swine .......................................................................................................................... ......................................................................... 34,100 Poultry: Layers ......................................................................................................................... .................................................................. 723,600
Broilers ....................................................................................................................... ................................................................... 38,160,000 Turkeys ........................................................................................................................ ................................................................. 7,710,000

1 The threshold head populations in this table were calculated using the most conservative assumptions (high VS and N values, max imum ambient temperatures, and the application of an uncertainty factor) to ensure that facilities at or near the 25,000 metric ton CO 2 e threshold level were not excluded from reporting.

2 For facilities with more than one animal group present refer to § 98.360 (2) to estimate the combined animal group factor (CAGF) , which is used to determine if a facility may be required to report.

3 For all animal groups except dairy, the average annual animal population represents the total number of animals present at the facility. For dairy facilities, the average annual animal population represents the number of mature dairy cows present at the facility (notethat heifers and calves were included in the emission estimates for dairy facilities using the assumption that the average annual animal populat ion of heifers and calves at dairy facilities are equal to 30 percent of the mature dairy cow average annual animal population, therefore the average annual population for dairy facilities should not include heifers and calves, only dairy cows).



### TABLE 

### JJ–2 TO 

### S UBPART 

### JJ OF 

### P ART 

### 98—WASTE 

### C HARACTERISTICS 

### D ATA

Animal type Typical animal

mass (kg) Volatile solids excretion rate (kg VS/day/1000 kg animal mass) Nitrogen excretion rate (kg N/day/1000 kg animal mass) Maximummethane generation potential, B

o (m 3 CH 4/kg VS added)

Dairy Cows ..................................... 604 See Table JJ–3 .............................. See Table JJ–3 .................. ............ 0.24 Dairy Heifers ................................... 476 See Table JJ–3 .............................. See Table JJ–3 ................. ............. 0.17 Dairy Calves ................................... 118 6.41 ................................................ 0.30 .................... ............................ 0.17
Feedlot Steers ................................ 420 See Table JJ–3 .............................. See Table JJ–3 ................... ........... 0.33
Feedlot heifers ................................ 420 See Table JJ–3 .............................. See Table JJ–3 .................. ............ 0.33
Market Swine <60 lbs ..................... 16 8.80 ................................................ 0.60 ........................... ..................... 0.48
Market Swine 60–119 lbs ............... 41 5.40 ................................................ 0.42 .............................. .................. 0.48
Market Swine 120–179 lbs ............. 68 5.40 ................................................ 0.42 ............................... ................. 0.48
Market Swine >180 lbs ................... 91 5.40 ................................................ 0.42 ............................ .................... 0.48 Breeding Swine .............................. 198 2.60 ................................................ 0.24 ....................... ......................... 0.48


### 56486 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

TABLE 

### JJ–2 TO 

### S UBPART 

### JJ OF 

### P ART 

### 98—WASTE 

### C HARACTERISTICS 

### D ATA

### —Continued

Animal type Typical animal

mass (kg) Volatile solids excretion rate (kg VS/day/1000 kg animal mass) Nitrogen excretion rate (kg N/day/1000 kg animal mass) Maximummethane generation potential, B

o (m 3 CH 4/kg VS added)

Feedlot Sheep ................................ 25 9.20 ................................................ 0.42 ....................... ......................... 0.36
Goats .............................................. 64 9.50 ................................................ 0.45 ................. ............................... 0.17
Horses ............................................ 450 10.00 .............................................. 0.30 .................. .............................. 0.33 Hens >/= 1 yr .................................. 1.8 10.09 .............................................. 0.83 ..................... ........................... 0.39
Pullets ............................................. 1.8 10.09 .............................................. 0.62 ................ ................................ 0.39
Other Chickens ............................... 1.8 10.80 .............................................. 0.83 ....................... ......................... 0.39
Broilers ............................................ 0.9 15.00 .............................................. 1.10 ................ ................................ 0.36 Turkeys ........................................... 6.8 9.70 ................................................ 0.74 ................. ............................... 0.36



### TABLE 

### JJ–3 TO 

### S UBPART 

### JJ OF 

### P ART 

### 98—S TATE 

### -S PECIFIC 

### V OLATILE 

### S OLIDS 

### (VS) AND 

### N ITROGEN 

### (N) E XCRETION 

### R ATES FOR 

### C ATTLE

State Volatile solids excretion rate (kg VS/day/1000 kg animal mass) Nitrogen excretion rate (kg VS/day/1000 kg animal mass)

Dairy

cows Dairy heifers Feedlot
steer Feedlot heifers Dairy

cows Dairy heifers Feedlot
steer Feedlot heifers

Alabama ........................................................... 8.40 8.35 4.27 4.74 0.50 0.46 0.36 0.38
Alaska .............................................................. 7.30 8.35 4.15 4.58 0.45 0.46 0.35 0.37
Arizona ............................................................. 10.37 8.35 3.91 4.27 0.58 0.46 0.33 0.34
Arkansas .......................................................... 7.59 8.35 3.98 4.35 0.46 0.46 0.33 0.35
California .......................................................... 10.02 8.35 3.96 4.33 0.56 0.46 0.33 0.34
Colorado ........................................................... 10.25 8.35 3.97 4.34 0.58 0.46 0.33 0.35
Connecticut ...................................................... 9.22 8.35 4.41 4.93 0.53 0.46 0.37 0.40
Delaware .......................................................... 8.63 8.35 4.19 4.64 0.51 0.46 0.35 0.37
Florida .............................................................. 8.90 8.35 4.15 4.58 0.52 0.46 0.35 0.37 Georgia ............................................................ 9.07 8.35 4.18 4.63 0.53 0.46 0.35 0.37
Hawaii .............................................................. 7.00 8.35 4.15 4.58 0.44 0.46 0.35 0.37
Idaho ................................................................ 10.11 8.35 4.03 4.42 0.57 0.46 0.34 0.35
Illinois ............................................................... 9.07 8.35 4.15 4.59 0.52 0.46 0.35 0.37
Indiana ............................................................. 9.38 8.35 3.98 4.35 0.54 0.46 0.33 0.35
Iowa .................................................................. 9.46 8.35 3.93 4.28 0.54 0.46 0.33 0.34
Kansas ............................................................. 9.63 8.35 3.97 4.35 0.55 0.46 0.33 0.35 Kentucky .......................................................... 7.89 8.35 4.20 4.65 0.48 0.46 0.35 0.37
Louisiana .......................................................... 7.39 8.35 4.07 4.48 0.45 0.46 0.34 0.36
Maine ............................................................... 8.99 8.35 4.07 4.47 0.52 0.46 0.34 0.36 Maryland .......................................................... 9.02 8.35 4.05 4.45 0.52 0.46 0.34 0.35
Massachusetts ................................................. 8.63 8.35 4.15 4.58 0.51 0.46 0.35 0.37 Michigan ........................................................... 10.05 8.35 4.00 4.38 0.57 0.46 0.34 0.35
Minnesota ......................................................... 9.17 8.35 3.89 4.24 0.53 0.46 0.33 0.34 Mississippi ........................................................ 8.19 8.35 4.14 4.57 0.49 0.46 0.35 0.37
Missouri ............................................................ 8.02 8.35 4.08 4.49 0.48 0.46 0.34 0.36
Montana ........................................................... 9.03 8.35 4.23 4.69 0.52 0.46 0.36 0.38
Nebraska .......................................................... 9.09 8.35 3.98 4.35 0.53 0.46 0.33 0.35
Nevada ............................................................. 9.65 8.35 4.07 4.48 0.55 0.46 0.34 0.36 New Hampshire ............................................... 9.44 8.35 3.94 4.30 0.54 0.46 0.33 0.34 New Jersey ...................................................... 8.51 8.35 3.98 4.36 0.50 0.46 0.33 0.35
New Mexico ..................................................... 10.34 8.35 3.88 4.22 0.58 0.46 0.32 0.33
New York ......................................................... 9.42 8.35 3.75 4.05 0.54 0.46 0.31 0.32
North Carolina .................................................. 9.38 8.35 4.20 4.65 0.55 0.46 0.35 0.37
North Dakota .................................................... 8.40 8.35 3.88 4.22 0.50 0.46 0.32 0.34
Ohio .................................................................. 9.01 8.35 3.96 4.33 0.52 0.46 0.33 0.34
Oklahoma ......................................................... 8.58 8.35 3.98 4.35 0.50 0.46 0.33 0.35 Oregon ............................................................. 9.40 8.35 4.06 4.46 0.54 0.46 0.34 0.36 Pennsylvania .................................................... 9.26 8.35 3.98 4.35 0.53 0.46 0.33 0.35
Rhode Island .................................................... 8.94 8.35 4.36 4.87 0.52 0.46 0.37 0.39
South Carolina ................................................. 9.05 8.35 4.15 4.58 0.53 0.46 0.35 0.37
South Dakota ................................................... 9.45 8.35 4.01 4.39 0.54 0.46 0.34 0.35
Tennessee ....................................................... 8.60 8.35 4.48 5.02 0.51 0.46 0.38 0.40
Texas ............................................................... 9.51 8.35 3.95 4.32 0.54 0.46 0.33 0.34
Utah .................................................................. 9.70 8.35 3.88 4.22 0.55 0.46 0.32 0.34
Vermont ............................................................ 9.03 8.35 4.10 4.52 0.52 0.46 0.34 0.36 Virginia ............................................................. 9.02 8.35 3.98 4.35 0.53 0.46 0.33 0.35 Washington ...................................................... 10.36 8.35 4.07 4.47 0.58 0.46 0.34 0.36 West Virginia .................................................... 8.13 8.35 4.65 5.25 0.48 0.46 0.40 0.42
Wisconsin ......................................................... 9.34 8.35 3.95 4.31 0.54 0.46 0.33 0.34


### 56487 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

TABLE 

### JJ–3 TO 

### S UBPART 

### JJ OF 

### P ART 

### 98—S TATE 

### -S PECIFIC 

### V OLATILE 

### S OLIDS 

### (VS) AND 

### N ITROGEN 

### (N) E XCRETION 

### R ATES FOR 

### C ATTLE

### —Continued

State Volatile solids excretion rate (kg VS/day/1000 kg animal mass) Nitrogen excretion rate (kg VS/day/1000 kg animal mass)

Dairy

cows Dairy heifers Feedlot
steer Feedlot heifers Dairy

cows Dairy heifers Feedlot
steer Feedlot heifers

Wyoming .......................................................... 9.29 8.35 4.17 4.61 0.53 0.46 0.35 0.37



### TABLE 

### JJ–4 TO 

### S UBPART 

### JJ OF 

### P ART 

### 98—V OLATILE 

### S OLIDS AND 

### N ITROGEN 

### R EMOVAL THROUGH 

### S OLIDS 

### S EPARATION

Type of solids separation Volatile solids removal (decimal) Nitrogen removal (decimal)

Gravity ........................................................................................................................ .............................. 0.60 0.60
Mechanical: Stationary Screen .............................................................................................................. ............... 0.20 0.10 Vibrating Screen ............................................................................................................... ................ 0.15 0.15
Screw Press .................................................................................................................... ................. 0.25 0.15 Centrifuge ..................................................................................................................... .................... 0.50 0.25
Roller drum .................................................................................................................... ................... 0.25 0.15 Belt press/screen .............................................................................................................. ................ 0.50 0.30

**BILLING CODE 6560–50–P**


### 56488 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

**BILLING CODE 6560–50–C**


### 56489 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

TABLE 

### JJ–6 TO 

### S UBPART 

### JJ OF 

### P ART 

### 98—C OLLECTION 

### E FFICIENCIES OF 

### A NAEROBIC 

### D IGESTERS

Anaerobic digester type Cover type Methane collection efficiency

Covered anaerobic lagoon (biogas capture) .............................. Bank to bank, impermeable ............................... ........................ 0.975 Modular, impermeable ................................................................ 0.70 Complete mix, fixed film, or plug flow digester .......................... Enclosed Vessel ....................................... .................................. 0.99



### TABLE 

### JJ–7 TO 

### S UBPART 

### JJ OF 

### P ART



### 98—N ITROUS 

### O XIDE 

### E MISSION 

### FAC



### TORS 

### ( KG 

### N 2 

### O–N/ KG 

### KJDL 

### N)

Manure management system component N 2 O emission factor

Uncovered anaerobic lagoon ... 0 Liquid/Slurry (with crust cover) 0.005 Liquid/Slurry (without crust

cover) .................................... 0 Storage pits .............................. 0.002 Digesters ................................... 0 Solid manure storage ............... 0.005 Dry lots (including feedlots) ...... 0.02 High-rise house for poultry

(poultry without litter) ............ 0.001 Poultry production with litter ..... 0.001 Deep bedding for cattle and

swine (active mix) ................. 0.07 Deep bedding for cattle and

swine (no mix) ....................... 0.01 Manure Composting (in vessel) 0.006 Manure Composting (intensive) 0.1 Manure Composting (passive) 0.01 Manure Composting (static) ..... 0.006Aerobic Treatment (forced aeration) ..................................... 0.005Aerobic Treatment (natural aeration) ..................................... 0.01

**Subpart KK—[Reserved]**

**Subpart LL—Suppliers of Coal-based Liquid Fuels** 

**§ 98.380 Definition of the source category.**

This source category consists of producers, importers, and exporters of products listed in Table MM–1 ofsubpart MM that are coal-based (coal-toliquid products).

(a) A producer is the owner or operator of a coal-to-liquids facility. A coal-to-liquids facility is any facility engaged in converting coal into liquid products using a process involving conversion of coal into gas and then into liquids (e.g., Fischer-Tropsch) or conversion of coal directly into liquids (i.e., direct liquefaction).

(b) An importer or exporter shall have the same meaning given in § 98.6.

**§ 98.381 Reporting threshold.**

Any supplier of coal-to-liquid products who meets the requirements of § 98.2(a)(4) must report GHG emissions.

**§ 98.382 GHGs to report.**

You must report the CO 2 emissions that would result from the complete combustion or oxidation of fossil-fuel products (besides coal or crude oil) that you produce, use as feedstock, import, or export during the calendar year. Additionally, producers must report

CO 2 emissions that would result from the complete combustion or oxidation of any biomass co-processed with fossil
fuel-based feedstocks.

**§ 98.383 Calculating GHG emissions.**

You must follow the calculation methodologies of § 98.393 as if they applied to the appropriate coal-to-liquid product supplier (i.e., calculation methodologies for refiners apply to producers of coal-to-liquid products and calculation methodologies for importers and exporters of petroleum products apply to importers and exporters of coal-to-liquid products).

(a) In calculation methodologies in § 98.393 for petroleum products or petroleum-based products, suppliers of coal-to-liquid products shall also include coal-to-liquid products.

(b) In calculation methodologies in § 98.393 for non-crude feedstocks or non-crude petroleum feedstocks, producers of coal-to-liquid products shall also include coal-to-liquid products that enter the facility to be further processed or otherwise used on

site.

(c) In calculation methodologies in § 98.393 for petroleum feedstocks, suppliers of coal-to-liquid products
shall also include coal and coal-toliquid products that enter the facility to be further processed or otherwise used

on site.

**§ 98.384 Monitoring and QA/QC requirements.** 

You must follow the monitoring and QA/QC requirements in § 98.394 as ifthey applied to the appropriate coal-toliquid product supplier. Any monitoring and QA/QC requirement for petroleum products in § 98.394 also applies to coal-to-liquid products.

**§ 98.385 Procedures for estimating missing data.** 

You must follow the procedures for estimating missing data in § 98.395 as ifthey applied to the appropriate coal-toliquid product supplier. Any procedure for estimating missing data for petroleum products in § 98.395 also applies to coal-to-liquid products.

**§ 98.386 Data reporting requirements.**

In addition to the information required by § 98.3(c), the following requirements apply:

(a) Producers shall report thefollowing information for each coal-toliquid facility:

(1) For each product listed in Table MM–1 of subpart MM of this part that enters the coal-to-liquid facility to be further processed or otherwise used on site, report the annual quantity in metric tons or barrels by each quantity
measurement standard method or other industry standard practice used. For natural gas liquids, quantity shall reflect the individual components of the product.

(2) For each product listed in Table MM–1 of subpart MM of this part that enters the coal-to-liquid facility to be further processed or otherwise used on site, report the total annual quantity in metric tons or barrels. For natural gas liquids, quantity shall reflect the individual components of the product.

(3) For each feedstock reported in paragraph (a)(2) that was produced by blending a fossil fuel-based product with a biomass-based product, report the percent of the volume reported in paragraph (a)(2) of this section that is
fossil fuel-based.

(4) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (a)(1) of this section.

(5) For each product (leaving the coalto-liquid facility) listed in Table MM–1 of subpart MM of this part, report the annual quantity in metric tons or barrels by each quantity measurement standard method or other industry standard practice used. For natural gas liquids, quantity shall reflect the individual components of the product.

(6) For each product (leaving the coalto-liquid facility) listed in Table MM–1 of subpart MM of this part, report the total annual quantity in metric tons or barrels. For natural gas liquids, quantity shall reflect the individual components of the product.

(7) For each product reported in paragraph (a)(6) of this section that was produced by blending a fossil fuel-based


### 56490 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

product with a biomass-based product, report the percent of the volume reported in paragraph (a)(6) of this
section that is fossil fuel-based.

(8) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (a)(5) of this section.

(9) For every feedstock reported in paragraph (a)(2) of this section for which Calculation Methodology 2 of subpart MM of this part was used to determine an emissions factor, report:

(i) The number of samples collected according to § 98.394(c).

(ii) The sampling standard method
used.

(iii) The carbon share test results in percent mass.

(iv) The standard method used to test
carbon share.

(v) The calculated CO 2 emissions
factor.

(10) For every non-solid feedstock reported in paragraph (a)(2) of this
section for which Calculation Methodology 2 of subpart MM of this part was used to determine an emissions factor, report:

(i) The density test results in metric tons per barrel.

(ii) The standard method used to test density.

(11) For every product reported in paragraph (a)(6) of this section for which Calculation Methodology 2 of this subpart was used to determine an emissions factor, report:

(i) The number of samples collected according to § 98.394(c).

(ii) The sampling standard method
used.

(iii) The carbon share test results in percent mass.

(iv) The standard method used to test
carbon share.

(v) The calculated CO 2 emissions
factor.

(12) For every non-solid product reported in paragraph (a)(6) of this
section for which Calculation Methodology 2 of subpart MM of this part was used to determine an emissions factor, report:

(i) The density test results in metric tons per barrel.

(ii) The standard method used to test density.

(13) For each specific type of biomass that enters the coal-to-liquid facility to be co-processed with fossil fuel-based feedstock to produce a product reported in paragraph (a)(6) of this section, report the annual quantity in metric tons or barrels by each quantity measurement standard method or other industry standard practice used.

(14) For each specific type of biomass that enters the coal-to-liquid facility to be co-processed with fossil fuel-based feedstock to produce a product reported in paragraph (a)(6) of this section, report the total annual quantity in metric tons
or barrels.

(15) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (a)(3) of this section.

(16) The CO 2 emissions in metric tons that would result from the complete
combustion or oxidation of each feedstock reported in paragraph (a)(2) of this section, calculated according to § 98.393(b) or (h).

(17) The CO 2 emissions in metric tons that would result from the complete
combustion or oxidation of each product (leaving the coal-to-liquid facility) reported in paragraph (a)(6) of this section, calculated according to § 98.393(a) or (h).

(18) Annual CO 2 emissions in metric
tons that would result from the complete combustion or oxidation ofeach type of biomass feedstock coprocessed with fossil fuel-based feedstocks reported in paragraph (a)(3) of this section, calculated according to § 98.393(c).

(19) Annual CO 2 emissions that would result from the complete combustion or oxidation of all products, calculated according to § 98.393(d).

(20) Annual quantity of bulk NGLs in
metric tons or barrels received for processing during the reporting year.

(b) In addition to the information required by § 98.3(c), each importer shall report all of the following information at the corporate level:

(1) For each product listed in Table MM–1 of subpart MM of this part, report the annual quantity in metric tons or barrels by each quantity measurement standard method or other industry standard practice used. For natural gas liquids, quantity shall reflect the individual components of the product.

(2) For each product listed in Table MM–1 of subpart MM of this part, report the total annual quantity in metric tons or barrels. For natural gas liquids, quantity shall reflect the individual components of the product as listed in Table MM–1 of subpart MM of this part.

(3) For each product reported in paragraph (b)(2) of this section that was produced by blending a fossil fuel-based product with a biomass-based product, report the percent of the volume reported in paragraph (b)(2) of this
section that is fossil fuel-based.

(4) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (b)(1) of this section.

(5) For each product reported in paragraph (b)(2) of this section for which Calculation Methodology 2 of this subpart used was used to determine an emissions factor, report:

(i) The number of samples collected according to § 98.394(c)

(ii) The sampling standard method
used.

(iii) The carbon share test results in percent mass.

(iv) The standard method used to test
carbon share.

(v) The calculated CO 2 emissions
factor in metric tons.

(6) For each non-solid product reported in paragraph (b)(2) of this
section for which Calculation Methodology 2 of this subpart was used to determine an emissions factor, report:

(i) The density test results in metric
tons ber barrel.

(ii) The standard method used to test density.

(7) The CO 2 emissions in metric tons that would result from the complete
combustion or oxidation of each imported product reported in paragraph (b)(2) of this section, calculated according to § 98.393(a).

(8) The total sum of CO 2 emissions that would result from the complete combustion or oxidation of all imported products, calculated according to § 98.393(e).

(c) In addition to the information required by § 98.3(c), each exporter shall report all of the following information at the corporate level:

(1) For each product listed in Table MM–1 of subpart MM of this part, report the annual quantity in metric tons or barrels by each quantity measurement standard method or other industry standard practice used. For natural gas liquids, quantity shall reflect the individual components of the product.

(2) For each product listed in table MM–1 of subpart MM of this part, report the total annual quantity in metric tons or barrels. For natural gas liquids, quantity shall reflect the individual components of the product.

(3) For each product reported in paragraph (c)(2) of this section that was produced by blending a fossil fuel-based product with a biomass-based product, report the percent of the volume reported in paragraph (c)(2) of this
section that is fossil fuel-based.

(4) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (c)(1) of this section.

(5) For each product reported in paragraph (c)(2) of this section for which Calculation Methodology 2 of this subpart was used to determine an emissions factor, report:

(i) The number of samples collected according to § 98.394(c).


### 56491 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

(ii) The sampling standard method
used.

(iii) The carbon share test results in percent mass.

(iv) The standard method used to test
carbon share.

(v) The calculated CO 2 emissions
factor in metric tons.

(6) For each non-solid product reported in paragraph (c)(2) of this
section for which Calculation Methodology 2 of this subpart used was used to determine an emissions factor, report:

(i) The density test results in metric tons per barrel.

(ii) The standard method used to test density.

(7) The CO 2 emissions in metric tons that would result from the complete
combustion or oxidation of each exported product reported in paragraph (c)(2) of this section, calculated according to § 98.393(a).

(8) Total sum of CO 2 emissions that would result from the complete combustion or oxidation of all exported products, calculated according to § 98.393(e).

**§ 98.387 Records that must be retained.**

You must retain records according to the requirements in § 98.397 as if they applied to the appropriate coal-to-liquid product supplier (e.g., retaining copies of all reports submitted to EPA under § 98.386 and records to support information contained in those reports). Any records for petroleum products that are required to be retained in § 98.397 are also required for coal-to-liquid products.

**§ 98.388 Definitions.**

All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.

**Subpart MM—Suppliers of Petroleum**
**Products**

**§ 98.390 Definition of the source category.**

This source category consists of petroleum refineries and importers and exporters of petroleum products and natural gas liquids as listed in Table MM–1 of this subpart.

(a) A petroleum refinery for the purpose of this subpart is any facility engaged in producing petroleum products through the distillation of
crude oil.

(b) A refiner is the owner or operator of a petroleum refinery.

(c) Importer has the same meaning given in § 98.6 and includes any entity that imports petroleum products or natural gas liquids as listed in Table MM–1 of this subpart. Any blender or refiner of refined or semi-refined petroleum products shall be considered an importer if it otherwise satisfies the
aforementioned definition.

(d) Exporter has the same meaning given in § 98.6 and includes any entity that exports petroleum products or natural gas liquids as listed in Table MM–1 of this subpart. Any blender or
refiner of refined or semi-refined petroleum products shall be considered an exporter if it otherwise satisfies the
aforementioned definition.

**§ 98.391 Reporting threshold.**

Any supplier of petroleum products who meets the requirements of § 98.2(a)(4) must report GHG emissions.

**§ 98.392 GHGs To report.**

Suppliers of petroleum products must report the CO 2 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. Additionally, refiners must report CO 2 emissions that would result from the complete combustion or oxidation of any biomass co-processed with petroleum feedstocks.

**§ 98.393 Calculating GHG emissions.**

(a) Calculation for individual products produced, imported, or exported.

(1) Except as provided in paragraph (h) of this section, any refiner, importer, or exporter shall calculate CO 2 emissions from each individual petroleum product and natural gas liquid using Equation MM–1 of this

section.



### CO Product EF (Eq. MM-1) 2i i i



### = Where:

CO 2i = Annual CO 2 emissions that would result from the complete combustion or oxidation of each petroleum product or natural gas liquid ‘‘i’’ (metric tons).
Producti = Annual volume of product ‘‘i’’ produced, imported, or exported by the reporting party (barrels). For refiners, this volume only includes products ex refinery gate. For natural gas liquids,
volumes shall reflect the individual components of the product as listed in Table MM–1 of this subpart.

EF i = Product-specific CO 2 emission factor (metric tons CO 2 per barrel).

(2) In the event that an individual petroleum product is produced as a solid rather than liquid any refiner, importer, or exporter shall calculate CO 2 emissions using Equation MM–1 of this section.

Where:

CO 2i = Annual CO 2 emissions that would result from the complete combustion or oxidation of each petroleum product ‘‘i’’ (metric tons). Producti = Annual mass of product ‘‘i’’ produced, imported, or exported by the reporting party (metric tons). For refiners, this mass only includes products ex refinery gate.

EF i = Product-specific CO 2 emission factor (metric tons CO 2 per metric ton of product).
(b) Calculation for individualproducts that enter a refinery as a noncrude feedstock.

(1) Except as provided in paragraph (h) of this section, any refiner shall
calculate CO 2 emissions from each noncrude feedstock using Equation MM–2
of this section.



### CO Feedstock EF (Eq. MM-2) 2j j j



### = Where:

CO 2j = Annual CO 2 emissions that would result from the complete combustion or
oxidation of each non-crude feedstock ‘‘j’’ (metric tons).
Feedstock j = Annual volume of a petroleum product or natural gas liquid ‘‘j’’ that enters the refinery to be further refined or otherwise used on site (barrels). For natural gas liquids, volumes shall reflect the individual components of the product as listed in table MM–1 of this subpart.

EF

j = Feedstock-specific CO 2 emission factor

(metric tons CO 2 per barrel).
(2) In the event that a non-crude feedstock enters a refinery as a solid rather than liquid, the refiner shall
calculate CO 2 emissions using Equation
MM–2 of this section.

Where:

CO 2j = Annual CO 2 emissions that would result from the complete combustion or
oxidation of each non-crude feedstock ‘‘j’’ (metric tons).
Feedstock j = Annual mass of a petroleum product ‘‘j’’ that enters the refinery to be
further refined or otherwise used on site (metric tons).

EF

j = Feedstock-specific CO 2 emission factor

(metric tons CO 2 per metric ton of feedstock).
(c) Calculation for biomass coprocessed with petroleum feedstocks.

(1) Refiners shall calculate CO 2 emissions from each type of biomassthat enters a refinery and is coprocessed with petroleum feedstocks using Equation MM–3 of this section.



### CO Biomass EF (Eq. MM-3) 2m m m 

### = Where:

CO 2m = Annual CO 2 emissions that would result from the complete combustion or oxidation of each type of biomass ‘‘m’’ (metric tons).

Biomass

m = Annual volume of a specific type of biomass that enters the refinery and is co-processed with petroleum feedstocks to produce a petroleum product reported under paragraph (a) of this section (barrels).


### 56492 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

EF

m = Biomass-specific CO 2 emission factor (metric tons CO 2 per barrel).
(2) In the event that biomass enters a refinery as a solid rather than liquid and is co-processed with petroleum feedstocks, the refiner shall calculate

CO 2 emissions from each type of biomass using Equation MM–3 of this

section. Where:

CO 2m = Annual CO 2 emissions that would result from the complete combustion or oxidation of each type of biomass ‘‘m’’ (metric tons).

Biomass

m = Total annual mass of a specific type of biomass that enters the refinery to be co-processed with petroleum feedstocks to produce a petroleum product reported under paragraph (a) of this section (metric tons).

EF

m = Biomass-specific CO 2 emission factor (metric tons CO 2 per metric ton of biomass).

(d) Summary calculation for refinery products. Refiners shall calculate
annual CO 2 emissions from all products using Equation MM–4 of this section.



### CO CO CO CO (Eq. MM-4) 2r 2i 2j 2m



### = 

## ( )

− 

# ( )

− 

## ( )



# ∑∑∑

Where:

CO 2r = Annual CO 2 emissions that would result from the complete combustion or oxidation of all petroleum products and natural gas liquids (ex refinery gate) minus non-crude feedstocks and any biomass to be co-processed with petroleum feedstocks.

CO 2i = Annual CO 2 emissions that would result from the complete combustion or oxidation of each petroleum product or natural gas liquid ‘‘i’’ (metric tons).

CO 2j = Annual CO 2 emissions that would result from the complete combustion or

oxidation of each non-crude feedstock ‘‘j’’ (metric tons).

CO 2m = Annual CO 2 emissions that would result from the complete combustion or oxidation of each type of biomass ‘‘m’’ (metric tons).

(e) Summary calculation for importer and exporter products. Importers and exporters shall calculate annual CO 2 emissions from all petroleum products and natural gas liquids imported or exported, respectively, using Equations
MM–1 and MM–5 of this section.



### CO CO Eq x i 2 2 

### = 

## ( )



# ∑ ( . MM-5)

Where:

CO 2i = Annual CO 2 emissions that would result from the complete combustion or oxidation of each petroleum product or natural gas liquid ‘‘i’’ (metric tons).

CO 2x = Annual CO 2 emissions that would result from the complete combustion or oxidation of all petroleum products and natural gas liquids.

(f) Emission factors for petroleum products and natural gas liquids. The emission factor (EF i,j ) for each petroleum product and natural gas liquid shall be determined using either
of the calculation methods described in paragraphs (f)(1) or (f)(2) of this section.
The same calculation method must be used for the entire quantity of the product for the reporting year. For refiners, the quantity of a product that enters a refinery (i.e., a non-crude feedstock) is considered separate from the quantity of a product ex refinery gate.

(1) Calculation Method 1. For solid products, use the default carbon share factor (i.e., percent carbon by mass) in column B of Table MM–1 of this subpart for the appropriate product. For all other products, use the default CO 2 emission factor listed in column C of Table MM–1 of this subpart for the appropriate product.

(2) Calculation Method 2. (i) For solid products, develop emission factors according to Equation MM–6 of this section using a value of 1 for density and direct measurements of carbon share according to methods set forth in § 98.394(c). For all other products, develop emission factors according to Equation MM–6 of this section using direct measurements of density and carbon share according to methods set forth in § 98.394(c).



### EF Density i j

, 

### (

= Carbon Share /12) (Eq. MM-6) 44

Where:

EF i,j = Emission factor of the petroleum product or natural gas liquid (metric tons

CO 2 per barrel or per metric ton of product). Density = Density of the petroleum product or natural gas liquid (metric tons per barrel for non-solid products, 1 for solid products).
Carbon share = Percent of total mass that carbon represents in the petroleum product or natural gas liquid, expressed as a fraction (e.g., 75% would be expressed as 0.75 in the above equation).
44/12 = Conversion factor for carbon to
carbon dioxide. (ii) If you use a standard method that involves gas chromatography to determine the percent mass of each component in a product, calculate the product’s carbon share using Equation
MM–7 of this section.



### Carbon Share %Composition %Mass (Eq. MM-7) i...n i...n 

### = 

## ( )



# ∑ Where:

Carbon Share = Percent of total mass that carbon represents in the petroleum product or natural gas liquid. %Composition i* * *n = Percent of total mass that each molecular component in the petroleum product or natural gas liquid represents as determined by the procedures in the selected standard

method. %Mass i* * *n = Percent of total mass that carbon represents in each molecular component of the petroleum product or natural gas liquid.

(g) Emission factors for biomass coprocessed with petroleum feedstocks. Refiners shall use the most appropriate
default CO 2 emission factor (EF

m) for biomass in Table MM–2 of this subpart to calculate CO 2 emissions in paragraph (c) of this section.

(h) Special procedures for blended biomass-based fuels. In the event that some portion of a petroleum product is biomass-based and was not derived by co-processing biomass and petroleum feedstocks together (i.e., the petroleum product was produced by blending a


### 56493 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

petroleum-based product with a biomass-based fuel), the reporting party
shall calculate emissions for the petroleum product according to one of the methods in paragraphs (h)(1) through (h)(4) of this section, as appropriate.

(1) A reporter using Calculation Methodology 1 to determine the emission factor of a petroleum product shall calculate the CO 2 emissions associated with that product using Equation MM–8 of this section in place of Equation MM–1 of this section.



### CO oduct EF Vol Eq i ii i 2 

### = Pr % ( .MM-8)

Where:

CO 2i = Annual CO 2 emissions that would result from the complete combustion or oxidation of each petroleum product ‘‘i’’ (metric tons).

Producti = Annual volume of each petroleum product ‘‘i’’ produced, imported, or exported by the reporting party (barrels). For refiners, this volume only includes products ex refinery gate. EF i = Petroleum product-specific CO 2 emission factor (metric tons CO 2 per barrel) from Table MM–1 of this subpart. %Vol i = Percent volume of product ‘‘i’’ that is petroleum-based, including 2.5% of the volume of any ethanol product blended into a petroleum-based product to represent the denaturant in that ethanol product, expressed as a fraction (e.g., 75% would be expressed as 0.75 in the above equation). (2) A refinery using Calculation Methodology 1 of this subpart to
determine the emission factor of a noncrude petroleum feedstock shall
calculate the CO 2 emissions associated with that feedstock using Equation MM– 9 of this section in place of Equation
MM–2 of this section.



### CO Feedstock EF Vol Eq j ji j 2 

### = % ( . MM-9)

Where:

CO 2j = Annual CO 2 emissions that would result from the complete combustion or

oxidation of each non-crude feedstock ‘‘j’’ (metric tons).

Feedstock j = Annual volume of each petroleum product ‘‘j’’ that enters the refinery as a feedstock to be further

refined or otherwise used on site (barrels). EF j = Non-crude petroleum feedstock-specific

CO 2 emission factor (metric tons CO 2 per barrel). %Vol j = Percent volume of feedstock ‘‘j’’ that is petroleum-based, including 2.5% of the volume of any ethanol product blended with the petroleum-based product to represent the denaturant in that ethanol product, expressed as a fraction (e.g., 75% would be expressed as 0.75 in the above equation). (3) A reporter using Calculation Methodology 2 of this subpart to
determine the emission factor of a petroleum product must calculate the

CO 2 emissions associated with that product using Equation MM–10 of this section in place of Equation MM–1 of
this section.



### CO oduct EF oduct EF Vol Eq i ii im m 2 

### = 

## ( )

− 

## ( ) Pr Pr % ( .MM-10)

Where:

CO 2i = Annual CO 2 emissions that would result from the complete combustion or oxidation of each product ‘‘i’’ (metric tons).
Producti = Annual volume of each petroleum product ‘‘i’’ produced, imported, or exported by the reporting party (barrels). For refiners, this volume only includes products ex refinery gate.

EF i = Product-specific CO 2 emission factor (metric tons CO 2 per barrel). EF

m = Default CO 2 emission factor from Table MM–2 of this subpart that most closely represents the component of product ‘‘i’’

that is biomass-based.
%Vol

m = Percent volume of petroleum product ‘‘i’’ that is biomass-based, not including 2.5% of the volume of any ethanol product blended with the petroleum-based product, which represents the denaturant in that ethanol product, expressed as a fraction (e.g., 75% would be expressed as 0.75 in the above equation).

(4) A refiner using Calculation Methodology 2 of this subpart to
determine the emission factor of a noncrude petroleum feedstock must
calculate the CO 2 emissions associated with that feedstock using Equation MM– 11 of this section in place of Equation
MM–2 of this section.



### CO Feedstock EF Feedstock EF Vol Eq j jj im m 2 

### = 

# ( )

− 

## ( )% ( . MM-11)

Where:

CO 2j = Annual CO 2 emissions that would result from the complete combustion or

oxidation of each non-crude feedstock ‘‘j’’ (metric tons).

Feedstock j = Annual volume of each petroleum product ‘‘j’’ that enters the refinery to be further refined or otherwise used on site (barrels).

EF

j = Feedstock-specific CO 2 emission factor

(metric tons CO 2 per barrel). EF

m = Default CO 2 emission factor from Table MM–2 of this subpart that most closely represents the component of petroleum product ‘‘j’’ that is biomass-based. %Vol

m = Percent volume of non-crude feedstock ‘‘j’’ that is biomass-based, not including 2.5% of the volume of any ethanol product blended with the petroleum-based product, which represents the denaturant in that ethanol product, expressed as a fraction (e.g., 75% would be expressed as 0.75 in the above equation). **§ 98.394 Monitoring and QA/QC requirements.** 

(a) Determination of quantity. (1) The quantity of petroleum products, natural gas liquids, biomass,
and crude oil shall be determined as
follows:

(i) Where an appropriate standard method published by a consensus-based standards organization exists, such a
method shall be used. Consensus-based


### 56494 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

standards organizations include, but are not limited to, the following: ASTM International, the American National Standards Institute (ANSI), the American Gas Association (AGA), the American Society of Mechanical Engineers (ASME), the American Petroleum Institute (API), and the North American Energy Standards Board (NAESB).

(ii) Where no appropriate standard method developed by a consensus-based standards organization exists, industry standard practices shall be followed.

(iii) For products that are liquid at 60 degrees Fahrenheit and one standard atmosphere, all measurements of quantity shall be temperature-adjusted and pressure-adjusted to these conditions. For all other products, reporters shall use appropriate standard conditions specified in the standard method; if temperature and pressure conditions are not specified in the standard method or if a reporter uses an industry standard practice to determine quantity, the reporter shall use appropriate standard conditions according to established industry practices.

(2) All measurement equipment (including, but not limited to, flow meters and tank gauges) used for compliance with this subpart shall be appropriate for the standard method or industry standard practice followed under paragraph (a)(1)(i) or (a)(1)(ii) of
this section.

(b) Equipment Calibration. (1) All measurement equipment shall be calibrated prior to its first use for reporting under this subpart, using an appropriate standard method published by a consensus based standards organization or according to the equipment manufacturer’s directions.

(2) Measurement equipment shall be recalibrated at the minimum frequency specified by the standard method used or by the equipment manufacturer’s
directions.

(c) Procedures for Calculation Methodology 2 of this subpart.

(1) Reporting parties shall collect one sample of each petroleum product or natural gas liquid on any day of each calendar month of the reporting year in which the quantity of that product was
measured in accordance with the requirements of this subpart. For example, if a given product was measured as entering the refinery continuously throughout the reporting year, twelve samples of that product shall be collected over the reporting year, one on any day of each calendar month of that year. If a given product was only measured from April 15 through June 10 of the reporting year, a refiner would collect three samples during that year, one during each of the calendar months of April, May and June on a day when the product was measured as either entering or exiting the refinery. Each sample shall be collected using an appropriate standard method published by a consensus-based standards organization.

(2) Mixing and handling of samples shall be performed using an appropriate standard method published by a consensus-based standards organization.

(3) Density measurement. (i) For all products that are not solid, reporters shall test for density using an appropriate standard method published by a consensus-based standards organization.

(ii) The density value for a given petroleum product shall be generated by either making a physical composite of all of the samples collected for the reporting year and testing that single sample or by measuring the individual samples throughout the year and defining the representative density value for the sample set by numerical means, i.e., a mathematical composite. If a physical composite is chosen as the option to obtain the density value, the reporter shall submit each of the individual samples collected during the reporting year to the laboratory responsible for generating the composite sample.

(iii) For physical composites, the reporter shall handle the individual samples and the laboratory shall mix them in accordance with an appropriate standard method published by a consensus-based standards organization.

(iv) All measurements of density shallbe temperature-adjusted and pressureadjusted to the conditions assumed for determining the quantities of the product reported under this subpart.

(4) Carbon share measurement. (i) Reporters shall test for carbon share using an appropriate standard method published by a consensus-based standards organization.

(ii) If a standard method that involves gas chromatography is used to determine the percent mass of each component in a product, the molecular formula for each component shall be obtained from the information provided
in the standard method and the atomic mass of each element in a given molecular component shall be obtained from the periodic table of the elements.

(iii) The carbon share value for a given petroleum product shall be generated by either making a physical composite of all of the samples collected for the reporting year and testing that single sample or by measuring the individual samples throughout the year and defining the representative carbon share value for the sample set by numerical means, i.e., a mathematical composite. If a physical composite is chosen as the option to obtain the carbon share value, the reporter shall submit each of the individual samples collected during the reporting year to the laboratory responsible for generating the composite sample.

(iv) For physical composites, the reporter shall handle the individual samples and the laboratory shall mix them in accordance with an appropriate standard method published by a consensus-based standards organization.

(d) Measurement of API gravity and
sulfur content of crude oil.

(1) Samples of each batch of crude oil shall be taken according to an appropriate standard method published by a consensus-based standards organization.

(2) Samples shall be handled according to an appropriate standard method published by a consensus-based standards organization.

(3) API gravity shall be measured using an appropriate standard method published by a consensus-based standards organization.

(4) Sulfur content shall be measured using an appropriate standard method published by a consensus-based standards organization.

(5) All measurements shall betemperature-adjusted and pressureadjusted to the conditions assumed for determining the quantities of crude oil reported under this subpart.

**§ 98.395 Procedures for estimating missing data.** 

(a) Determination of quantity. Whenever the quality assurance procedures in § 98.394(a) cannot be followed to measure the quantity of one or more petroleum products, natural gas liquids, types of biomass, feedstocks, or crude oil batches during any period (e.g., if a meter malfunctions), the following missing data procedures shall
be used:

(1) For quantities of a product that are purchased or sold, a period of missing data shall be substituted using a reporter’s established procedures for billing purposes in that period as agreed to by the party selling or purchasing the product.

(2) For quantities of a product that are not purchased or sold but of which the custody is transferred, a period of missing data shall be substituted using a reporter’s established procedures for tracking purposes in that period as agreed to by the party involved in custody transfer of the product.


### 56495 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

(b) Determination of emission factor. Whenever any of the procedures in § 98.394(c) cannot be followed to develop an emission factor for any reason, Calculation Methodology 1 of this subpart must be used in place of Calculation Methodology 2 of this subpart for the entire reporting year.

(c) Determination of API gravity and sulfur content of crude oil. For missing data on sulfur content or API gravity,
the substitute data value shall be the arithmetic average of the quality-assured values of API gravity or sulfur content in the batch preceding and the batch immediately following the missing data incident. If no quality-assured data are available prior to the missing data incident, the substitute data value shall be the first quality-assured values for API gravity and sulfur content obtained from the batch after the missing data period.

**§ 98.396 Data reporting requirements.**

In addition to the information required by § 98.3(c), the following requirements apply:

(a) Refiners shall report the following information for each facility:

(1) For each petroleum product or natural gas liquid listed in table MM–1 of this subpart that enters the refinery to
be further refined or otherwise used on site, report the annual quantity in metric tons or barrels by each quantity
measurement standard method or other industry standard practice used. For natural gas liquids, quantity shall reflect the individual components of the product.

(2) For each petroleum product or natural gas liquid listed in Table MM– 1 of this subpart that enters the refinery
to be further refined or otherwise used on site, report the annual quantity in metric tons or barrels. For natural gas liquids, quantity shall reflect the individual components of the product.

(3) For each feedstock reported in paragraph (a)(2) of this section that wasproduced by blending a petroleumbased product with a biomass-based product, report the percent of the volume reported in paragraph (a)(2) of this section that is petroleum-based.

(4) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (a)(1) of this section.

(5) For each petroleum product and natural gas liquid (ex refinery gate) listed in Table MM–1 of this subpart, report the annual quantity in metric tons or barrels by each quantity
measurement standard method or other industry standard practice used. For natural gas liquids, quantity shall reflect the individual components of the product.

(6) For each petroleum product and natural gas liquid (ex refinery gate) listed in Table MM–1 of this subpart, report the annual quantity in metric tons or barrels. For natural gas liquids, quantity shall reflect the individual components of the product.

(7) For each product reported in paragraph (a)(6) of this section that wasproduced by blending a petroleumbased product with a biomass-based product, report the percent of the volume reported in paragraph (a)(6) of this section that is petroleum-based.

(8) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (a)(5) of this section.

(9) For every feedstock reported in paragraph (a)(2) of this section for which Calculation Methodology 2 of this subpart was used to determine an emissions factor, report:

(i) The number of samples collected according to § 98.394(c)

(ii) The sampling standard method
used.

(iii) The carbon share test results in percentmass.

(iv) The standard method used to test
carbon share.

(v) The calculated CO 2 emissions
factor in metric tons.

(10) For every non-solid feedstock reported in paragraph (a)(2) of this
section for which Calculation Methodology 2 of this subpart was used to determine an emissions factor, report:

(i) The density test results in metric tons per barrel.

(ii) The standard method used to test density.

(11) For every petroleum product and natural gas liquid reported in paragraph (a)(6) of this section for which Calculation Methodology 2 of this subpart was used to determine an emissions factor, report:

(i) The number of samples collected according to § 98.394(c).

(ii) The sampling standard method
used.

(iii) The carbon share test results in percentmass.

(iv) The standard method used to test
carbon share.

(v) The calculated CO 2 emissions
factor in metric tons CO 2 per barrel or per metric ton of product.

(12) For every non-solid petroleum product and natural gas liquid reported in paragraph (a)(6) for which
Calculation Method 2 was used to determine an emissions factor, report:

(i) The density test results in metric tons per barrel.

(ii) The standard method used to test density. (13) For each specific type of biomassthat enters the refinery to be coprocessed with petroleum feedstocks to produce a petroleum product reported in paragraph (a)(6) of this section, report the annual quantity in metric tons or barrels by each quantity measurement standard method or other industry standard practice used.

(14) For each specific type of biomassthat enters the refinery to be coprocessed with petroleum feedstocks to produce a petroleum product reported in paragraph (a)(6) of this section, report the annual quantity in metric tons or
barrels.

(15) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (a)(13) of this section.

(16) The CO 2 emissions in metric tons that would result from the complete
combustion or oxidation of each petroleum product and natural gas liquid (ex refinery gate) reported in paragraph (a)(6) of this section, calculated according to § 98.393(a) or (h).

(17) The CO 2 emissions in metric tons that would result from the complete
combustion or oxidation of each feedstock reported in paragraph (a)(2) of this section, calculated according to § 98.393(b) or (h).

(18) The CO 2 emissions in metric tons that would result from the complete combustion or oxidation of each type of biomass feedstock co-processed with petroleum feedstocks reported in paragraph (a)(13) of this section, calculated according to § 98.393(c).

(19) The sum of CO 2 emissions that would result from the complete combustion or oxidation of all products, calculated according to § 98.393(d).

(20) All of the following information
for all crude oil feedstocks used at the refinery:

(i) Batch volume in barrels. (ii) API gravity of the batch at the point of entry at the refinery.

(iii) Sulfur content of the batch at the point of entry at the refinery.

(iv) Country of origin of the batch, if
known.

(21) The quantity of bulk NGLs in
metric tons or barrels received for processing during the reporting year.

(b) In addition to the information required by § 98.3(c), each importer shall report all of the following information at the corporate level:

(1) For each petroleum product and natural gas liquid listed in Table MM– 1 of this subpart, report the annual quantity in metric tons or barrels by each quantity measurement standard method or other industry standard practice used. For natural gas liquids,


### 56496 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

quantity shall reflect the individual components of the product.

(2) For each petroleum product and natural gas liquid listed in Table MM– 1 of this subpart, report the annual quantity in metric tons or barrels. For natural gas liquids, quantity shall reflect the individual components of the product as listed in Table MM–1 of this subpart.

(3) For each product reported in paragraph (b)(2) of this section that wasproduced by blending a petroleumbased product with a biomass-based product, report the percent of the volume reported in paragraph (b)(2) of this section that is petroleum-based.

(4) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (b)(1) of this section.

(5) For each product reported in paragraph (b)(2) of this section for which Calculation Methodology 2 of this subpart used was used to determine an emissions factor, report:

(i) The number of samples collected according to § 98.394(c).

(ii) The sampling standard method
used.

(iii) The carbon share test results in percent mass.

(iv) The standard method used to test
carbon share.

(v) The calculated CO 2 emissions
factor in metric tons CO 2 per barrel or per metric ton of product.

(6) For each non-solid product reported in paragraph (b)(2) of this
section for which Calculation Methodology 2 of this subpart was used to determine an emissions factor, report:

(i) The density test results in metric tons per barrel.

(ii) The standard method used to test density.

(7) The CO 2 emissions in metric tons that would result from the complete
combustion or oxidation of each imported petroleum product and natural gas liquid reported in paragraph (b)(2) of this section, calculated according to § 98.393(a).

(8) The sum of CO 2 emissions that would result from the complete combustion oxidation of all imported products, calculated according to § 98.393(e).

(c) In addition to the information required by § 98.3(c), each exporter shall report all of the following information at the corporate level: (1) For each petroleum product and natural gas liquid listed in Table MM– 1 of this subpart, report the annual quantity in metric tons or barrels by each quantity measurement standard method or other industry standard practice used. For natural gas liquids, quantity shall reflect the individual components of the product.

(2) For each petroleum product and natural gas liquid listed in Table MM– 1 of this subpart, report the annual quantity in metric tons or barrels. For natural gas liquids, quantity shall reflect the individual components of the product.

(3) For each product reported in paragraph (c)(2) of this section that wasproduced by blending a petroleumbased product with a biomass-based product, report the percent of the volume reported in paragraph (c)(2) of this section that is petroleum based.

(4) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (c)(1) of this section.

(5) For each product reported in paragraph (c)(2) of this section for which Calculation Methodology 2 of this subpart was used to determine an emissions factor, report:

(i) The number of samples collected according to § 98.394(c).

(ii) The sampling standard method
used.

(iii) The carbon share test results in percentmass.

(iv) The standard method used to test
carbon share.

(v) The calculated CO 2 emissions
factor in metric tons CO 2 per barrel or per metric ton of product.

(6) For each non-solid product reported in paragraph (c)(2) of this
section for which Calculation Methodology 2 of this subpart used was used to determine an emissions factor, report:

(i) The density test results in metric tons per barrel.

(ii) The standard method used to test density.

(7) The CO 2 emissions in metric tons that would result from the complete
combustion or oxidation of for each exported petroleum product and natural gas liquid reported in paragraph (c)(2) of this section, calculated according to § 98.393(a).

(8) The sum of CO 2 emissions that would result from the complete combustion or oxidation of all exported products, calculated according to § 98.393(e).

**§ 98.397 Records that must be retained.**

(a) All reporters shall retain copies of all reports submitted to EPA under § 98.396. In addition, all reporters shall maintain sufficient records to support information contained in those reports, including but not limited to information
on the characteristics of their feedstocks and products.

(b) Reporters shall maintain records to support quantities that are reported under this subpart, including records documenting any estimations of missing data and the number of calendar days in the reporting year for which substitute data procedures were followed. For all quantities of petroleum products, natural gas liquids, biomass, and feedstocks, reporters shall maintain metering, guaging, and other records normally maintained in the course of business to document product and feedstock flows including the date of initial calibration and the frequency of
recalibration for the measurement equipment used

(c) Reporters shall retain laboratory reports, calculations and worksheets
used to estimate the CO 2 emissions of the quantities of petroleum products, natural gas liquids, biomass, and feedstocks reported under this subpart.

(d) Reporters shall maintain laboratory reports, calculations and
worksheets used in the measurement of density and carbon share for any petroleum product or natural gas liquid
for which CO 2 emissions were calculated using Calculation Methodology 2.

(e) Reporters shall maintain laboratory reports, calculations and worksheets used in the measurement of API gravity and sulfur content for every crude oil batch reported under this subpart.

(f) Estimates of missing data shall be
documented and records maintained showing the calculations.

(g) Reporters described in this subpart
shall also retain all records described in § 98.3(g).

**§ 98.398 Definitions.**

All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.


### 56497 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

TABLE 

### MM–1 TO 

### S UBPART 

### MM OF 

### P ART 

### 98—D EFAULT 

### FACTORS FOR 

### P ETROLEUM 

### P RODUCTS AND 

### N ATURAL 

### G AS 

### L IQUIDS 1 2

Products Column A: density (metric tons/ bbl) Column B: carbon share (% of mass) Column C: emission

factor (metric tons

CO 2/bbl)

**Finished Motor Gasoline**

Conventional—Summer Regular ........................................................................................................................ ..................... 0.1181 86.66 0.3753 Midgrade ....................................................................................................................... .................... 0.1183 86.63 0.3758
Premium ........................................................................................................................ ................... 0.1185 86.61 0.3763
Conventional—Winter Regular ........................................................................................................................ ..................... 0.1155 86.50 0.3663 Midgrade ....................................................................................................................... .................... 0.1161 86.55 0.3684
Premium ........................................................................................................................ ................... 0.1167 86.59 0.3705
Reformulated—Summer Regular ........................................................................................................................ ..................... 0.1167 86.13 0.3686 Midgrade ....................................................................................................................... .................... 0.1165 86.07 0.3677
Premium ........................................................................................................................ ................... 0.1164 86.00 0.3670
Reformulated—Winter Regular ........................................................................................................................ ..................... 0.1165 86.05 0.3676 Midgrade ....................................................................................................................... .................... 0.1165 86.06 0.3676
Premium ........................................................................................................................ ................... 0.1166 86.06 0.3679
Gasoline—Other ................................................................................................................. ..................... 0.1185 86.61 0.3763

**Blendstocks**

CBOB—Summer Regular ........................................................................................................................ ..................... 0.1181 86.66 0.3753 Midgrade ....................................................................................................................... .................... 0.1183 86.63 0.3758
Premium ........................................................................................................................ ................... 0.1185 86.61 0.3763
CBOB—Winter Regular ........................................................................................................................ ..................... 0.1155 86.50 0.3663 Midgrade ....................................................................................................................... .................... 0.1161 86.55 0.3684
Premium ........................................................................................................................ ................... 0.1167 86.59 0.3705
RBOB—Summer Regular ........................................................................................................................ ..................... 0.1167 86.13 0.3686 Midgrade ....................................................................................................................... .................... 0.1165 86.07 0.3677
Premium ........................................................................................................................ ................... 0.1164 86.00 0.3670
RBOB—Winter Regular ........................................................................................................................ ..................... 0.1165 86.05 0.3676 Midgrade ....................................................................................................................... .................... 0.1165 86.06 0.3676
Premium ........................................................................................................................ ................... 0.1166 86.06 0.3679
Blendstocks—Other .............................................................................................................. ................... 0.1185 86.61 0.3763

**Oxygenates**

Methanol ....................................................................................................................... ........................... 0.1268 37.48 0.1743
GTBA ........................................................................................................................... ............................ 0.1257 64.82 0.2988
MTBE ........................................................................................................................... ............................ 0.1181 68.13 0.2950
ETBE ........................................................................................................................... ............................. 0.1182 70.53 0.3057
TAME ........................................................................................................................... ............................ 0.1229 70.53 0.3178
DIPE ........................................................................................................................... .............................. 0.1156 70.53 0.2990

**Distillate Fuel Oil**

Distillate No. 1
Ultra Low Sulfur ............................................................................................................... ................. 0.1346 86.40 0.4264
Low Sulfur ..................................................................................................................... .................... 0.1346 86.40 0.4264 High Sulfur .................................................................................................................... .................... 0.1346 86.40 0.4264
Distillate No. 2
Ultra Low Sulfur ............................................................................................................... ................. 0.1342 87.30 0.4296
Low Sulfur ..................................................................................................................... .................... 0.1342 87.30 0.4296 High Sulfur .................................................................................................................... .................... 0.1342 87.30 0.4296
Distillate Fuel Oil No. 4 ...................................................................................................... ...................... 0.1452 86.47 0.4604 Residual Fuel Oil No. 5 (Navy Special) ......................................................................................... ......... 0.1365 85.67 0.4288 Residual Fuel Oil No. 6 (a.k.a. Bunker C) ...................................................................................... ........ 0.1528 84.67 0.4744 Kerosene-Type Jet Fuel ......................................................................................................... ................. 0.1294 86.30 0.4095
Kerosene ....................................................................................................................... ........................... 0.1346 86.40 0.4264
Diesel—Other ................................................................................................................... ....................... 0.1452 86.47 0.4604

**Petrochemical Feedstocks**


### 56498 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

TABLE 

### MM–1 TO 

### S UBPART 

### MM OF 

### P ART 

### 98—D EFAULT 

### FACTORS FOR 

### P ETROLEUM 

### P RODUCTS AND 

### N ATURAL 

### G AS 

### L IQUIDS 1 2

### —Continued

Products Column A: density (metric tons/ bbl) Column B: carbon share (% of mass) Column C: emission

factor (metric tons

CO 2/bbl)

Naphthas (< 401 ° F) ......................................................................................................................... 0.11 58 84.11 0.3571 Other Oils (> 401 ° F) ........................................................................................................................ 0.139 0 87.30 0.4450

**Unfinished Oils**

Heavy Gas Oils ................................................................................................................. ....................... 0.1476 85.80 0.4643
Residuum ....................................................................................................................... .......................... 0.1622 85.70 0.5097

**Other Petroleum Products and Natural Gas Liquids**

Aviation Gasoline .............................................................................................................. ....................... 0.1120 85.00 0.3490 Special Naphthas ............................................................................................................... ...................... 0.1222 84.76 0.3798
Lubricants ..................................................................................................................... ........................... 0.1428 85.80 0.4492
Waxes .......................................................................................................................... ............................ 0.1285 85.30 0.4019
Petroleum Coke ................................................................................................................. ...................... 0.1818 92.28 0.6151 Asphalt and Road Oil ........................................................................................................... ................... 0.1634 83.47 0.5001
Still Gas ...................................................................................................................... ............................. 0.1405 77.70 0.4003
Ethane ......................................................................................................................... ............................. 0.0866 79.89 0.2537 Ethylene ....................................................................................................................... ............................ 0.0903 85.63 0.2835 Propane ........................................................................................................................ ........................... 0.0784 81.71 0.2349 Propylene ...................................................................................................................... ........................... 0.0803 85.63 0.2521
Butane ......................................................................................................................... ............................. 0.0911 82.66 0.2761 Butylene ....................................................................................................................... ............................ 0.0935 85.63 0.2936
Isobutane ...................................................................................................................... ........................... 0.0876 82.66 0.2655 Isobutylene .................................................................................................................... ........................... 0.0936 85.63 0.2939
Pentanes Plus .................................................................................................................. ........................ 0.1055 83.63 0.3235
Miscellaneous Products ......................................................................................................... .................. 0.1380 85.49 0.4326

1 In the case of products blended with some portion of biomass-based fuel, the carbon share in Table MM–1 of this subpart represe nts only the petroleum-based components.

2 Products that are derived entirely from biomass should not be reported, but products that were derived from both biomass and a petroleum product (i.e., co-processed) should be reported as the petroleum product that it most closely represents.



### TABLE 

### MM–2 TO 

### S UBPART 

### MM OF 

### P ART 

### 98—D EFAULT 

### FACTORS FOR 

### B IOMASS 

### -B ASED 

### F UELS AND 

### B IOMASS

Biomass-based fuel and biomass Column A: Density (metric tons/ bbl) Column B: Carbon share (% of mass) Column C: Emission

factor (metric tons

CO 2/bbl)

Ethanol (100%) ................................................................................................................. ....................... 0.1267 52.14 0.2422 Biodiesel (100%, methyl ester) ................................................................................................. ............... 0.1396 77.30 0.3957
Rendered Animal Fat ............................................................................................................ ................... 0.1333 76.19 0.3724 Vegetable Oil .................................................................................................................. ......................... 0.1460 76.77 0.4110

**Subpart NN—Suppliers of Natural Gas and Natural Gas Liquids** 

**§ 98.400 Definition of the source category.**

This supplier category consists of natural gas liquids fractionators and local natural gas distribution companies.

(a) Natural gas liquids fractionators
are installations that fractionate natural gas liquids (NGLs) into their consitutent liquid products (ethane, propane, normal butane, isobutane or pentanes plus) for supply to downstream
facilities.

(b) Local Distribution Companies (LDCs) are companies that own or operate distribution pipelines, not interstate pipelines or intrastate pipelines, that physically deliver natural gas to end users and that are regulated as separate operating companies by State public utility commissions or that operate as independent municipally-owned distribution systems.

(c) This supply category does not consist of the following facilities:

(1) Field gathering and boosting

stations.

(2) Natural gas processing plants that separate NGLs from natural gas and produce bulk or y-grade NGLs but do
not fractionate these NGLs into their constituent products. (3) Facilities that meet the definition of refineries and report under subpart MM of this part.

(4) Facilities that meet the definition of petrochemical plants and report under subpart X of this part.

**§ 98.401 Reporting threshold.**

Any supplier of natural gas and natural gas liquids that meets the requirements of § 98.2(a)(4) must report

GHG emissions.

**§ 98.402 GHGs to report.**

(a) NGL fractionators must report the

CO 2 emissions that would result from the complete combustion or oxidation of the annual quantity of ethane, propane, normal butane, isobutane, and pentanes


### 56499 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

plus that is produced and sold or
delivered to others.

(b) LDCs must report the CO 2 emissions that would result from the complete combustion or oxidation of the annual volumes of natural gas provided
to end-users on their distribution systems.

**§ 98.403 Calculating GHG emissions.**

(a) LDCs and fractionators shall, for each individual product reported under this part, calculate the estimated CO 2 emissions that would result from the complete combustion or oxidation of the products supplied using either of Calculation Methodology 1 or 2 of this subpart:

(1) Calculation Methodology 1. NGL fractionators shall estimate CO 2 emissions that would result from the complete combustion or oxidation of the product(s) supplied using Equation NN–
1 of this section. LDCs shall estimate

CO 2 emissions that would result from the complete combustion or oxidation of the product received at the city gate using Equation NN–1. For each product, use the default value for higher heating
value and CO 2 emission factor in Table NN–1 of this subpart. Alternatively, for each product, a reporter-specific higher heating value and CO 2 emission factor may be used, in place of one or both defaults provided they are developed using methods outlined in § 98.404. For each product, you must use the same volume unit throughout the equation.



### CO x Fuel HHV EF Eq i hh 2 3 

### 1 10 = − 

# ∑h 

### ( . NN-1)

Where:

CO 2i = Annual CO 2 mass emissions that
would result from the combustion or oxidation of each product ‘‘h’’ for redelivery to all recipients (metric tons). Fuel = Total annual volume of product ‘‘h’’ supplied (volume per year, in Mscf for natural gas and bbl for NGLs). HHV = Higher heating value of product ‘‘h’’ supplied (MMBtu/Mscf or MMBtu/bbl).

EF h = CO 2 emission factor of product ‘‘h’’ (kg

CO 2 /MMBtu).

1 x 10

¥ 3 = Conversion factor from kilograms to metric tons (MT/kg).
(2) Calculation Methodology 2. NGL fractionators shall estimate CO 2 emissions that would result from the complete combustion or oxidation of the product(s) supplied using Equation NN–
2 of this section. LDCs shall estimate

CO 2 emissions that would result from the complete combustion or oxidation of the product received at the city gate using Equation NN–2. For each product,
use the default CO 2 emission factor found in Table NN–2 of this subpart. Alternatively, for each product, a reporter-specific CO 2 emission factor may be used in place of the default factor, provided it is developed using methods outlined in § 98.404. For each product, you must use the same volume unit throughout the equation.



### CO Eq i 2 

### 2

= ∗



# ∑ Fuel EF h h

h 

### ( . NN- ) Where:

CO 2i = Annual CO 2 mass emissions that
would result from the combustion or oxidation of each product ‘‘h’’ (metric tons) Fuel = Total annual volume of product ‘‘h’’ supplied (bbl or Mscf per year)

EF h = CO 2 emission factor of product ‘‘h’’ (MT CO 2 /bbl, or MT CO 2 /Mscf)
(b) Each LDC shall follow the procedures below.

(1) For natural gas that is received for redelivery to downstream gas transmission pipelines and other local distribution companies, use eEquation
NN–3 of this section and the default
values for the CO 2 emission factors found in Table NN–2 of this subpart. Alternatively, reporter-specific CO 2 emission factors may be used, provided they are developed using methods outlined in § 98.404.



### CO Fuel EF Eq j 2 

### 3

= (. ) NN-

Where:

CO 2j = Annual CO 2 mass emissions that
would result from the combustion or oxidation of natural gas for redelivery to transmission pipelines or other LDCs (metric tons). Fuel = Total annual volume of natural gas supplied (Mscf per year). EF = Fuel-specific CO 2 emission factor (MT

CO 2 /Mscf). (2)(i) For natural gas delivered to each meter registering a supply equal to or greater than 460,000 Mscf per year, use Equation NN–4 of this section and the
default values for the CO 2 emission
factors found in Table NN–2 of this subpart.

(ii) Alternatively, reporter-specific

CO 2 emission factors may be used, provided they are developed using methods outlined in § 98.404.



### CO Fuel EF Eq k 2 

### 4 = (. ) NN-

Where:

CO 2k = Annual CO 2 mass emissions that

would result from the combustion oroxidation of natural gas received by endusers that receive a supply equal to or greater than 460,000 Mscf per year (metric tons). Fuel = Total annual volume of natural gas supplied (Mscf per year). EF = Fuel-specific CO 2 emission factor (MT

CO 2 /Mscf).

(3) For natural gas received by the LDC at the city gate that is injected into on-system storage, and/or liquefied and stored, use Equation NN–5 of this
section and the default value for the CO 2 emission factors found in Table NN–2 ofthis subpart. Alternatively, a reporterspecific CO 2 emission factor may be used, provided it is developed using methods outlined in § 98.404.



### CO Fuel Fuel EF Eq l 2 12 

### 5

= −



# [ ] (. ) NN-

Where:

CO 2l = Annual CO 2 mass emissions that

would result from the combustion or oxidation of the net natural gas that is liquefied and/or stored and not used for deliveries by the LDC within the reported year (metric tons).

Fuel 1 = Total annual volume of natural gas received by the LDC at the city gate and stored on-system or liquefied and stored in the reportng year (Mscf per year).
Fuel 2 = Total annual volume of natural gas
that is used for deliveries in the reporting year that was not otherwise accounted for in Equation NN–1 or NN– 2 of this section (Mscf per year). This primarily includes natural gas previously stored on-system or liquefied and stored that is removed from storage and used for deliveries to customers or other LDCs by the LDC within the reporting year. This also includes natural gas that bypassed the city gate and was delivered directly to LDC systems from producers or natural gas processing plants from local production. EF = Fuel-specific CO 2 emission factor (MT

CO 2 /Mscf).


### 56500 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

(4) Calculate the total CO 2 emissions that would result from the complete
combustion or oxidation of the annual supply of natural gas to end-users using Equation NN–6 of this section.



### CO CO CO CO (Eq. NN-6) 2 2i 2j 2k



### = −− −



# ∑∑ ∑ ∑ CO l 2

Where:

CO 2 = Annual CO 2 mass emissions that
would result from the combustion or oxidation of natural gas delivered to LDC customers not covered in paragraph (b)(2) of this section (metric tons).

CO 2i = Annual CO 2 mass emissions that
would result from the combustion or oxidation of natural gas received at the city gate as calculated in paragraph (a)(1) or (a)(2) of this section (metric tons).

CO 2j = Annual CO 2 mass emissions that
would result from the combustion or oxidation of natural gas delivered to transmission pipelines or other LDCs as calculated in paragraph (b)(1) of this section (metric tons).

CO 2k = Annual CO 2 mass emissions that
would result from the combustion oroxidation of natural gas received by endusers that receive a supply equal to or greater than 460,000 Mscf per year as calculated in paragraph (b)(2) of this section (metric tons).

CO 2l = Annual CO 2 mass emissions that
would result from the combustion or oxidation of natural gas received by the LDC and liquefied and/or stored but not used for deliveries within the reported year as calculated in paragraph (b)(3) of this section (metric tons).
(c) Each NGL fractionator shall follow the following procedures.

(1)(i) For fractionated NGLs received by the reporter from other NGL fractionators, you shall use Equation
NN–7 of this section and the default
values for the CO 2 emission factors found in Table NN–2 of this subpart.

(ii) Alternatively, reporter-specific

CO 2 emission factors may be used, provided they are developed using methods outlined in § 98.404. 

### CO Eq

m 2 

### 7 = 

# ∑ Fuel EF NN- ) g g



### g 

### ( .

Where:

CO 2m = Annual CO 2 mass emissions that

would result from the combustion or

oxidation of each fractionated NGL product ‘‘g’’ received from other fractionators (metric tons).

Fuel g = Total annual volume of each NGL product ‘‘g’’ received (bbls). EF = Fuel-specific CO 2 emission factor (MT

CO 2 /bbl).

(2) Calculate the total CO 2 equivalent
emissions that would result from the
combustion or oxidation of fractionated NGLs supplied less the quantity received by other fractionators using Equation NN–8 of this section.



### CO CO CO (Eq. NN-8) 2 2i 2j



### = −



# ∑ ∑

Where:

CO 2 = Annual CO 2 mass emissions that
would result from the combustion or
oxidation of fractionated NGLs delivered
to customers or on behalf of customers (metric tons).

CO 2i = Annual CO 2 mass emissions that
would result from the combustion or
oxidation of fractionated NGLs delivered
to all customers as calculated in paragraph (a)(1) or (a)(2) of this section (metric tons).

CO 2m = Annual CO 2 mass emissions that
would result from the combustion or
oxidation of fractionated NGLs received
from other fractionators and calculated in paragraph (c)(1) of this section (metric tons).

**§ 98.404 Monitoring and QA/QC requirements.** 

(a) Determination of quantity. (1) NGL fractionators and LDCs shall determine the quantity of NGLs and natural gas using methods in common use in the industry for billing purposes as audited under existing Sarbanes Oxley regulationn.

(i) Where an appropriate standard method published by a consensus-based standards organization exists, such a
method shall be used. Consensus-based standards organizations include, but are not limited to, the following: ASTM International, the American National Standards Institute (ANSI), the American Gas Association (AGA), the American Society of Mechanical Engineers (ASME), the American Petroleum Institute (API), and the North American Energy Standards Board (NAESB).

(ii) Where no appropriate standard method developed by a consensus-based standards organization exists, industry standard practices shall be followed.

(2) NGL fractionators and LDCs shall base the minimum frequency of the product quantity measurements, to be summed to the annual quantity reported, on the reporter’s standard practices for commercial operations.

(i) For NGL fractionators the minimum frequency of measurements
shall be the measurements taken at custody transfers summed to the annual reportable volume.

(ii) 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.

(3) NGL fractionators shall use measurement for NGLs at custody
tranfer meters or at such meters that are used to determine the NGL product slate delivered from the fractionation facility.

(4) If a NGL fractionator supplies a product not listed in Table NN–1 of this subpart that is a mixture or blend of two or more products listed in Tables NN– 1 and NN–2 of this subpart, the NGL fractionator shall report the quantities of
the constituents of the mixtures or blends separately.

(5) For an LDC using Equation NN–1 or NN–2 of this subpart, the point(s) of measurement for the natural gas volume supplied shall be the LDC city gate meter(s).

(i) If the LDC makes its own quantity measurements according to established business practices, its own
measurements shall be used.

(ii) If the LDC does not make its own quantity measurements according to established business practices, it shall use its delivering pipeline invoiced measurements for natural gas deliveries to the LDC city gate, used in determining daily system sendout.

(6) An LDC using Equation NN–3 of this subpart shall measure natural gas at the custody transfer meters.

(7) An LDC using Equation NN–4 of this subpart shall measure natural gas at the customer meters. The reporter shall consider the volume delivered through a single particluar meter at a single particular location as the volume
delivered to an individual end-user.

(8) An LDC using Equation NN–5 of this subpart shall measure natural gas as
follows:


### 56501 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

(i) Fuel 1 shall be measured at the onsystem storage injection meters and/or at the meters measuring natural gas to be liquefied.

(ii) Fuel 2 shall be measured at the meters used for measuring on-system storage withdrawals and/or LNG vaporization injection. If Fuel 2 is from a source other than storage, the appropriate meter shall be used to measure the quantity.

(9) An LDC shall measure all natural gas under the following standard industry temperature and pressure conditions: Cubic foot of gas at a temperature of 60 degrees Fahrenheit and at an absolute pressure of fourteen and seventy-three hundredths (14.73) pounds per square inch.

(b) Determination of higher heating values (HHV).

(1) When a reporter uses the default HHV provided in this section to calculate Equation NN–1 of this subpart, the appropriate value shall be taken from Table NN–1 of this subpart.

(2) When a reporter uses a reporterspecific HHV to calculate Equation NN– 1 of this subpart, an appropriatestandard test published by a consensusbased standards organization shall be
used. Consensus-based standards organizations include, but are not limited to, the following: AGA and GPA.

(i) If an LDC makes its own HHV measurements according to established business practices, then its own
measurements shall be used.

(ii) If an LDC does not make its own measurements according to established business practices, it shall use its delivering pipeline measurements.

(c) Determination of emission factor (EF).

(1) When a reporter used the default EF provided in this section to calculate Equation NN–1 of this subpart, the appropriate value shall be taken from Table NN–1 of this subpart.

(2) When a reporter used the default EF provided in this section to calculate Equation NN–2, NN–3, NN–4, NN–5, or NN–7 of this subpart, the appropriate
value shall be taken from Table NN–2 of this subpart.

(3) When a reporter uses a reporterspecific EF, the reporter shall use an appropriate standard method published by a consensus-based standards organization to conduct compositional analysis necessary to determine reporter-specific CO 2 emission factors.
Consensus-based standards organizations include, but are not limited to, the following: AGA and GPA.

(d) Equipment Calibration. (1) Equipment used to measure quantities in Equations NN–1, NN–2, and NN–5 of this subpart shall be calibrated prior to its first use for reporting under this subpart, using a suitable standard method published by
a consensus based standards organization or according to the equipment manufacturer’s directions.

(2) Equipment used to measure quantities in Equations NN–1, NN–2, and NN–5 of this subpart shall be recalibrated at the frequency specified by the standard method used or by the
manufacturer’s directions.

**§ 98.405 Procedures for estimating missing data.** 

(a) Whenever a quality-assured value of the quantity of natural gas liquids or natural gas supplied during any period is unavailable (e.g., if a flow meter malfunctions), a substitute data value for the missing quantity measurement
must be used in the calculations according to paragraphs (b) and (c) of
this section.

(b) Determination of quantity. (1) NGL fractionators shall substitute meter records provided by pipeline(s) for all pipeline receipts of NGLs; by
manifests for deliveries made to trucks or rail cars; or metered quantities accepted by the entities purchasing the output from the fractionator whether by pipeline or by truck or rail car. In cases
where the metered data from the receiving pipeline(s) or purchasing entities are not available, fractionators may substitute estimates based on contract quantities required to be delivered under purchase or delivery contracts with other parties.

(2) LDCs shall either substitute their delivering pipeline metered deliveries at the city gate or substitute nominations and scheduled delivery quantities for the period when metered values of
actual deliveries are not available.

(c) Determination of HHV and EF. (1) Whenever an LDC that makes its own HHV measurements according to established business practices cannot follow the quality assurance procedures for developing a reporter-specific HHV, as specified in § 98.404, during any period for any reason, the reporter shall use either its delivering pipeline
measurements or the default HHV provided in Table NN–1 of this part for that period.

(2) Whenever an LDC that does not
make its own HHV measurements according to established business practices or an NGL fractionator cannot follow the quality assurance procedures for developing a reporter-specific HHV, as specified in § 98.404, during any period for any reason, the reporter shall use the default HHV provided in Table NN–1 of this part for that period. (3) Whenever a NGL fractionator cannot follow the quality assuranceprocedures for developing a reporterspecific HHV, as specified in § 98.404, during any period for any reason, the
NGL fractionator shall use the default HHV provided in Table NN–1 of this part for that period.

(4) Whenever a reporter cannot follow the quality assurance procedures for developing a reporter-specific EF, as specified in § 98.404, during any period for any reason, the reporter shall use the default EF provided in § 98.408 for that period.

**§ 98.406 Data reporting requirements.**

(a) In addition to the information required by § 98.3(c), the annual report for each NGL fractionator covered by this rule shall contain the following
information.

(1) Annual quantity (in barrels) of each NGL product supplied to downstream facilities in the following product categories: ethane, propane, normal butane, isobutane, and pentanes plus.

(2) Annual quantity (in barrels) of each NGL product received from other NGL fractionators in the following product categories: ethane, propane, normal butane, isobutane, and pentanes plus.

(3) Annual volumes in Mscf of natural gas received for processing.

(4) Annual quantity (in barrels) of ygrade, bulk NGLs received from others
for fractionation.

(5) Annual quantity (in barrels) of propane that the NGL fractionator odorizes at the facility and delivers to
others.

(6) Annual CO 2 emissions (metric tons) that would result from the complete combustion or oxidation of the quantities in paragraphs (b)(1) and (b)(2) of this section, calculated in accordance with § 98.403(a) and (c)(1).

(7) Annual CO 2 mass emissions (metric tons) that would result from the
combustion or oxidation of fractionated NGLs supplied less the quantity received by other fractionators,
calculated in accordance with § 98.403(c)(2).

(8) The specific industry standard used to measure each quantity reported in paragraph (a)(1) of this section.

(9) If the LNG fractionator developed reporter-specific EFs or HHVs, report the following:

(i) The specific industry standard(s) used to develop reporter-specific higher heating value(s) and/or emission factor(s), pursuant to § 98.404(b)(2) and (c)(3).

(ii) The developed HHV(s). (iii) The developed EF(s).


### 56502 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

(b) In addition to the information required by § 98.3(c), the annual report for each LDC shall contain the following
information.

(1) Annual volume in Mscf of natural gas received by the LDC at its city gate stations for redelivery on the LDC’s distribution system, including for use by
the LDC.

(2) Annual volume in Mscf of natural gas placed into storage.

(3) Annual volume in Mscf of vaporized liquefied natural gas (LNG) produced at on-system vaporization facilities for delivery on the distribution system that is not accounted for in paragraph (b)(1) of this section.

(4) Annual volume in Mscf of natural gas withdrawn from on-system storage (that is not delivered to the city gate) for delivery on the distribution system.

(5) Annual volume in Mscf of natural gas delivered directly to LDC systems from producers or natural gas processing plants from local production.

(6) Annual volume in Mscf of natural gas delivered to downstream gas transmission pipelines and other local distribution companies.

(7) Annual volume in Mscf of natural gas delivered by LDC to each meter registering supply equal to or greater than 460,000 Mcsf during the calendar

year.

(8) The total annual CO 2 mass emissions (metric tons) associated with the volumes in paragraphs (b)(1) through (b)(7) of this section, calculated in accordance with § 98.403(a) and (b)(1) through (b)(3). (9) Annual CO 2 emissions (metric tons) that would result from the complete combustion or oxidation of theannual supply of natural gas to endusers registering less than 460,000 Mcsf,
calculated in accordance with § 98.403(b)(4).

(10) The specific industry standard used to develop the volume reported in paragraph (b)(1) of this section.

(11) If the LDC developed reporterspecific EFs or HHVs, report the following:

(i) The specific industry standard(s) used to develop reporter-specific higher heating value(s) and/or emission factor(s), pursuant to § 98.404 (b)(2) and (c)(3).

(ii) The developed HHV(s). (iii) The developed EF(s). (12) The customer name, address, and meter number of each meter reading used to report in paragraph (b)(7) of this

section.

(i) If known, report the EIA
identification number of each LDC

customer.

(ii) [Reserved] (13) The annual volume in Mscf of natural gas delivered by the local distribution company to each of the following end-use categories. For definitions of these categories, refer to EIA Form 176 (Annual Report of Natural Gas and Supplemental Gas Supply & Disposition) and Instructions.

(i) Residential consumers. (ii) Commercial consumers. (iii) Industrial consumers. (iv) Electricity generating facilities. (c) Each reporter shall report the number of days in the reporting year for which substitute data procedures were used for the following purpose:

(1) To measure quantity. (2) To develop HHV(s). (3) To develop EF(s).

**§ 98.407 Records that must be retained.**

In addition to the information required by § 98.3(g), each annual report must contain the following information:

(a) Records of all daily meter readings and documentation to support volumes of natural gas and NGLs that are reported under this part.

(b) Records documenting any estimates of missing metered data and showing the calculations of the values used for the missing data.

(c) Calculations and worksheets used

to estimate CO 2 emissions for the volumes reported under this part.

(d) Records related to the large endusers identified in § 98.406(b)(6).

(e) Records relating to measured Btu content or carbon content showing specific industry standards used to develop reporter-specific higher heating
values and emission factors.

(f) Records of such audits as required by Sarbanes Oxley regulations on the accuracy of measurements of volumes of natural gas and NGLs delivered to
customers or on behalf of customers.

**§ 98.408 Definitions.**

All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.



### TABLE 

### NN–1 TO 

### S UBPART 

### NN OF 

### P ART 

### 98—D EFAULT 

### FACTORS FOR 

### C ALCULATION 

### M ETHODOLOGY 

### 1 OF 

### T HIS 

### S UBPART

Fuel Default high heating value factor Default CO 2 emission

factor (kg CO 2/ MMBtu)

Natural Gas .................................................................................. 1.027 MMBtu/Mscf .................. ...................................................... 53.02 Propane ........................................................................................ 3.836 MMBtu/bbl ................. ......................................................... 63.02

Normal butane .............................................................................. 4.326 MMBtu/bbl ..................... ..................................................... 64.93

Ethane .......................................................................................... 3.082 MMBtu/bbl ................ .......................................................... 59.58

Isobutane ...................................................................................... 3.974 MMBtu/bbl ................. ......................................................... 65.08 Pentanes plus ............................................................................... 4.620 MMBtu/bbl .................... ...................................................... 66.90



### TABLE 

### NN–2 TO 

### S UBPART 

### NN OF 

### P ART 

### 98—L OOKUP 

### D EFAULT 

### VALUES FOR 

### C ALCULATION 

### M ETHODOLOGY 

### 2 OF 

### T HIS 

### S UBPART

Fuel Unit Default CO 2 emission

value (MT CO 2/

Unit)

Natural Gas .................................................................................. Mscf .............................. ................................................................ 0.054452 Propane ........................................................................................ Barrel .......................... .................................................................. 0.241745

Normal butane .............................................................................. Barrel .............................. .............................................................. 0.280887

Ethane .......................................................................................... Barrel ......................... ................................................................... 0.183626

Isobutane ...................................................................................... Barrel .......................... .................................................................. 0.258628


### 56503 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

TABLE 

### NN–2 TO 

### S UBPART 

### NN OF 

### P ART 

### 98—L OOKUP 

### D EFAULT 

### VALUES FOR 

### C ALCULATION 

### M ETHODOLOGY 

### 2 OF 

### T HIS 

### S UBPART

### —Continued

Fuel Unit Default CO 2 emission

value (MT CO 2/

Unit)

Pentanes plus ............................................................................... Barrel ............................. ............................................................... 0.309078

**Subpart OO—Suppliers of Industrial**
**Greenhouse Gases**

**§ 98.410 Definition of the source category.**

(a) The industrial gas supplier source category consists of any facility that produces a fluorinated GHG or nitrous oxide, any bulk importer of fluorinated GHGs or nitrous oxide, and any bulk exporter of fluorinated GHGs or nitrous
oxide.

(b) To produce a fluorinated GHG
means to manufacture a fluorinated GHG from any raw material or feedstock chemical. Producing a fluorinated GHG
includes the manufacture of a fluorinated GHG for use in a process
that will result in its transformation either at or outside of the production facility. Producing a fluorinated GHG
also includes the creation of a fluorinated GHG (with the exception of HFC–23) that is captured and shipped off site for any reason, including destruction. Producing a fluorinated
GHG does not include the reuse or recycling of a fluorinated GHG, the creation of HFC–23 during the production of HCFC–22, or the creation of by-products that are released or destroyed at the production facility.

(c) To produce nitrous oxide means to produce nitrous oxide by thermally decomposing ammonium nitrate (NH 4NO 3 ). Producing nitrous oxide does not include the reuse or recycling ofnitrous oxide or the creation of byproducts that are released or destroyed at the production facility.

**§ 98.411 Reporting threshold.**

Any supplier of industrial greenhouse gases who meets the requirements of § 98.2(a)(4) must report GHG emissions.

**§ 98.412 GHGs to report.**

You must report the GHG emissions
that would result from the release of the
nitrous oxide and each fluorinated GHG that you produce, import, export, transform, or destroy during the calendar year.

**§ 98.413 Calculating GHG emissions.**

(a) Calculate the total mass of each
fluorinated GHG or nitrous oxide produced annually, except for amounts that are captured solely to be shipped off site for destruction, by using Equation OO–1 of this section:



### P P p

p

n



### =

=



# ∑

1 

### ( . Eq OO-1)

P = Mass of fluorinated GHG or nitrous oxide produced annually.

P p = Mass of fluorinated GHG or nitrous oxide produced over the period ‘‘p’’.

(b) Calculate the total mass of each
fluorinated GHG or nitrous oxide produced over the period ‘‘p’’ by using Equation OO–2 of this section:



### POU

ppp



### = − ( . Eq OO-2)

Where:

P p = Mass of fluorinated GHG or nitrous oxide produced over the period ‘‘p’’ (metric tons).

O p = Mass of fluorinated GHG or nitrous oxide that is measured coming out of the production process over the period p (metric tons).

Up = Mass of used fluorinated GHG or nitrous oxide that is added to the production process upstream of the output measurement over the period ‘‘p’’ (metric tons).

(c) Calculate the total mass of each
fluorinated GHG or nitrous oxide transformed by using Equation OO–3 of
this section:



### T=F T 

### ∗ E T 

### ( . Eq OO-3)

Where:

T = Mass of fluorinated GHG or nitrous oxide transformed annually (metric tons).

F T = Mass of fluorinated GHG fed into the transformation process annually (metric tons).

E T = The fraction of the fluorinated GHG
or nitrous oxide fed into the transformation process that is transformed in the process (metric tons).

(d) Calculate the total mass of each fluorinated GHG destroyed by using Equation OO–4 of this section:



### D = F DE D 

### ∗ ( . Eq OO- ) 4

Where: D = Mass of fluorinated GHG destroyed annually (metric tons). F D = Mass of fluorinated GHG fed into the destruction device annually (metric tons). DE = Destruction efficiency of the destruction device (fraction).

**§ 98.414 Monitoring and QA/QC requirements.** 

(a) The mass of fluorinated GHGs or nitrous oxide coming out of the production process shall be measured using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of one percent of full scale or
better.

(b) The mass of any used fluorinated
GHGs or used nitrous oxide added back into the production process upstream of the output measurement in paragraph (a) of this section shall be measured using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of one percent of full scale or better. If the mass in paragraph (a) of this section is measured by weighing
containers that include returned heels as well as newly produced fluorinated GHGs, the returned heels shall be
considered used fluorinated GHGs for purposes of this paragraph (b) of this section and § 98.413(b).

(c) The mass of fluorinated GHGs or
nitrous oxide fed into the transformation process shall be measured using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of one percent of
full scale or better.

(d) The fraction of the fluorinated
GHGs or nitrous oxide fed into the transformation process that is actually
transformed shall be estimated considering yield calculations or quantities of unreacted fluorinated GHGs or nitrous oxide permanently removed from the process and recovered, destroyed, or emitted.

(e) The mass of fluorinated GHG or nitrous oxide sent to another facility for transformation shall be measured using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of one percent of full scale or
better.


### 56504 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

(f) The mass of fluorinated GHG sent to another facility for destruction shall be measured using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of one percent of
full scale or better. If the measured mass
includes more than trace concentrations
of materials other than the fluorinated GHG, the concentration of the
fluorinated GHG shall be estimated considering current or previous representative concentration
measurements and other relevant process information. This concentration (mass fraction) shall be multiplied by
the mass measurement to obtain the
mass of the fluorinated GHG sent to another facility for destruction.

(g) You must estimate the share of the mass of fluorinated GHGs in paragraph (f) of this section that is comprised of
fluorinated GHGs that are not included in the mass produced in § 98.413(a) because they are removed from the production process as by-products or
other wastes.

(h) The mass of fluorinated GHGs fed
into the destruction device shall be measured using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of one percent of
full scale or better. If the measured mass
includes more than trace concentrations
of materials other than the fluorinated GHG being destroyed, the concentrations of fluorinated GHG being destroyed shall be estimated considering current or previous representative concentration
measurements and other relevant process information. This concentration (mass fraction) shall be multiplied by
the mass measurement to obtain the mass of the fluorinated GHG destroyed.

(i) Very small quantities of fluorinated
GHGs that are difficult to measure because they are entrained in other media such as destroyed filters and destroyed sample containers are exempt from paragraphs (f) and (h) of this

section.

(j) You must estimate the share of the mass of fluorinated GHGs in paragraph (h) of this section that is comprised of
fluorinated GHGs that are not included in the mass produced in § 98.413(a) because they are removed from the production process as by-products or
other wastes.

(k) For purposes of Equation OO–4 of this subpart, the destruction efficiency can be equated to the destruction efficiency determined during a previous performance test of the destruction device or, if no performance test has been done, the destruction efficiency provided by the manufacturer of the
destruction device.

(l) In their estimates of the mass of fluorinated GHGs destroyed, fluorinated GHG production facilities that destroy fluorinated GHGs shall account for any temporary reductions in the destruction efficiency that result from any startups, shutdowns, or malfunctions of the destruction device, including departures from the operating conditions defined in state or local permitting requirements
and/or oxidizer manufacturer specifications.

(m) Calibrate all flow meters, weigh scales, and combinations of volumetric and density measures that are used to measure or calculate quantities that are to be reported under this subpart prior to the first year for which GHG emissions are reported under this part. Calibrations performed prior to the effective date of this rule satisfy this requirement. Recalibrate all flow meters, weigh scales, and combinations of volumetric and density measures at the minimum frequency specified by the
manufacturer. Use NIST-traceable
standards and suitable methods published by a consensus standards organization (e.g., ASTM, ASME, ISO, or others).

**§ 98.415 Procedures for estimating missing data.** 

(a) A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable (e.g., if a meter malfunctions), a substitute data value for the missing parameter shall be used in the calculations, according to paragraph (b) of this

section.

(b) For each missing value of the mass produced, fed into the production process (for used material being reclaimed), fed into the transformation process, fed into destruction devices, sent to another facility for transformation, or sent to another facility for destruction, the substitute value of that parameter shall be a secondary mass measurement where
such a measurement is available. For example, if the mass produced is usually measured with a flowmeter at the inlet to the day tank and that flowmeter fails to meet an accuracy or precision test, malfunctions, or is rendered inoperable, then the mass produced may be estimated by calculating the change in volume in the day tank and multiplying it by the density of the product. Where a secondary mass measurement is not available, the substitute value of the parameter shall be an estimate based on a related parameter. For example, if a flowmeter measuring the mass fed into
a destruction device is rendered inoperable, then the mass fed into the destruction device may be estimated using the production rate and the previously observed relationship between the production rate and the
mass flow rate into the destruction
device.

**§ 98.416 Data reporting requirements.**

In addition to the information required by § 98.3(c), each annual report must contain the following information:

(a) Each fluorinated GHG or nitrous oxide production facility shall report the following information:

(1) Mass in metric tons of each
fluorinated GHG or nitrous oxide produced at that facility by process, except for amounts that are captured solely to be shipped off site for
destruction.

(2) Mass in metric tons of each
fluorinated GHG or nitrous oxide transformed at that facility, by process.

(3) Mass in metric tons of each fluorinated GHG destroyed at that facility, except fluorinated GHGs not
included in the calculation of mass produced in § 98.413(a) because they are removed from the production process as by-products or other wastes. Quantities to be reported under this paragraph (a)(3) of this section could include, for example, quantities that are returned to the facility for reclamation but are found to be irretrievably contaminated and are therefore destroyed.

(4) Mass in metric tons of each fluorinated GHG that is destroyed at that facility except GHGs not included in the calculation of mass produced in § 98.413(a) because they are removed from the production process as byproducts or other wastes.

(5) Total mass in metric tons of each
fluorinated GHG or nitrous oxide sent to another facility for transformation.

(6) Total mass in metric tons of each fluorinated GHG sent to another facility for destruction, except fluorinated GHGs
that are not included in the mass produced in § 98.413(a) because they are removed from the production process as by-products or other wastes. Quantities to be reported under this paragraph (a)(6) could include, for example,
fluorinated GHGs that are returned to the facility for reclamation but are found to be irretrievably contaminated and are therefore sent to another facility for
destruction.

(7) Total mass in metric tons of each
fluorinated GHG that is sent to another facility for destruction and that is not included in the mass produced in § 98.413(a) because it is removed from


### 56505 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

the production process as a byproduct
or other waste.

(8) Total mass in metric tons of each
reactant fed into the F–GHG or nitrous oxide production process, by process.

(9) Total mass in metric tons of the reactants, by-products, and other wastes permanently removed from the F–GHG or nitrous oxide production process, by

process.

(10) For transformation processes that do not produce an F–GHG or nitrous oxide, mass in metric tons of any
fluorinated GHG or nitrous oxide fed into the transformation process, by

process.

(11) Mass in metric tons of each
fluorinated GHG fed into the destruction
device.

(12) Mass in metric tons of each
fluorinated GHG or nitrous oxide that is measured coming out of the production process, by process.

(13) Mass in metric tons of each used
fluorinated GHGs or nitrous oxide added back into the production process (e.g., for reclamation), including
returned heels in containers that are weighed to measure the mass in § 98.414(a), by process.

(14) Names and addresses of facilities to which any nitrous oxide or
fluorinated GHGs were sent for transformation, and the quantities (metric tons) of nitrous oxide and of
each fluorinated GHG that were sent to
each for transformation.

(15) Names and addresses of facilities to which any fluorinated GHGs were sent for destruction, and the quantities (metric tons) of nitrous oxide and of
each fluorinated GHG that were sent to
each for destruction.

(16) Where missing data have been estimated pursuant to § 98.415, the reason the data were missing, the length of time the data were missing, the method used to estimate the missing data, and the estimates of those data.

(b) A fluorinated GHG production facility or importer that destroys
fluorinated GHGs shall submit a onetime report containing the following
information:

(1) Destruction efficiency (DE) of each
destruction unit.

(2) Methods used to determine the destruction efficiency.

(3) Methods used to record the mass of fluorinated GHG destroyed.

(4) Chemical identity of the fluorinated GHG(s) used in the performance test conducted to
determine DE.

(5) Name of all applicable federal or state regulations that may apply to the destruction process.

(6) If any process changes affect unit destruction efficiency or the methods used to record mass of fluorinated GHG destroyed, then a revised report must be submitted to reflect the changes. The revised report must be submitted to EPA within 60 days of the change.

(c) A bulk importer of fluorinated
GHGs or nitrous oxide shall submit an annual report that summarizes their imports at the corporate level, except for shipments including less than 250
metric tons of CO 2 e, transshipments,
and heels that meet the conditions set forth at § 98.417(e). The report shall contain the following information for each import:

(1) Total mass in metric tons of
nitrous oxide and each fluorinated GHG imported in bulk.

(2) Total mass in metric tons of
nitrous oxide and each fluorinated GHG imported in bulk and sold or transferred to persons other than the importer for use in processes resulting in the
transformation or destruction of the
chemical.

(3) Date on which the fluorinated GHGs or nitrous oxide were imported.

(4) Port of entry through which the
fluorinated GHGs or nitrous oxide passed.

(5) Country from which the imported
fluorinated GHGs or nitrous oxide were imported.

(6) Commodity code of the fluorinated GHGs or nitrous oxide shipped.

(7) Importer number for the shipment. (8) Total mass in metric tons of each fluorinated GHG destroyed by the importer.

(9) If applicable, the names and addresses of the persons and facilities to
which the nitrous oxide or fluorinated
GHGs were sold or transferred for transformation, and the quantities (metric tons) of nitrous oxide and of
each fluorinated GHG that were sold or transferred to each facility for
transformation.

(10) If applicable, the names and addresses of the persons and facilities to
which the nitrous oxide or fluorinated
GHGs were sold or transferred for destruction, and the quantities (metric tons) of nitrous oxide and of each
fluorinated GHG that were sold or transferred to each facility for
destruction.

(d) A bulk exporter of fluorinated
GHGs or nitrous oxide shall submit an annual report that summarizes their exports at the corporate level, except for shipments including less than 250
metric tons of CO 2 e, transshipments, and heels. The report shall contain the following information for each export:

(1) Total mass in metric tons of
nitrous oxide and each fluorinated GHG exported in bulk. (2) Names and addresses of the exporter and the recipient of the exports.

(3) Exporter’s Employee Identification
Number.

(4) Commodity code of the fluorinated GHGs and nitrous oxide shipped.

(5) Date on which, and the port from which, fluorinated GHGs and nitrous oxide were exported from the United

States or its territories.

(6) Country to which the fluorinated GHGs or nitrous oxide were exported.

(e) By April 1, 2011, a fluorinated GHG production facility shall submit a one-time report describing the following
information:

(1) The method(s) by which the producer in practice measures the mass of fluorinated GHGs produced, including the instrumentation used (Coriolis flowmeter, other flowmeter, weigh scale, etc.) and its accuracy and precision.

(2) The method(s) by which the producer in practice estimates the mass
of fluorinated GHGs fed into the transformation process, including the instrumentation used (Coriolis flowmeter, other flowmeter, weigh scale, etc.) and its accuracy and precision.

(3) The method(s) by which the producer in practice estimates the
fraction of fluorinated GHGs fed into the transformation process that is actually transformed, and the estimated precision and accuracy of this estimate.

(4) The method(s) by which the producer in practice estimates the
masses of fluorinated GHGs fed into the destruction device, including the method(s) used to estimate the
concentration of the fluorinated GHGs in the destroyed material, and the estimated precision and accuracy of this

estimate.

(5) The estimated percent efficiency of each production process for the fluorinated GHG produced.

**§ 98.417 Records that must be retained.**

(a) In addition to the data required by § 98.3(g), the fluorinated GHG production facility shall retain the following records:

(1) Dated records of the data used to estimate the data reported under § 98.416.

(2) Records documenting the initial and periodic calibration of the gas chromatographs, weigh scales, flowmeters, and volumetric and density measures used to measure the quantities reported under this subpart, including the industry standards or manufacturer directions used for calibration pursuant to § 98.414(j) and (k).

(b) In addition to the data required by paragraph (a) of this section, the


### 56506 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

fluorinated GHG production facility that destroys fluorinated GHGs shall keep records of test reports and other information documenting the facility’s one-time destruction efficiency report
and annual destruction device outlet reports in § 98.416(b) and (e).

(c) In addition to the data required by § 98.3(g), the bulk importer shall retain the following records substantiating each of the imports that they report:

(1) A copy of the bill of lading for the import.

(2) The invoice for the import. (3) The U.S. Customs entry form. (d) In addition to the data required by § 98.3(g), the bulk exporter shall retain the following records substantiating each of the exports that they report:

(1) A copy of the bill of lading for the export and

(2) The invoice for the import. (e) Every person who imports a
container with a heel that is not reported under § 98.416(c) shall keep records of the amount brought into the
United States that document that the residual amount in each shipment is less than 10 percent of the volume of the
container and will:

(1) Remain in the container and be included in a future shipment.

(2) Be recovered and transformed. (3) Be recovered and destroyed. (4) Be recovered and included in a future shipment.

**§ 98.418 Definitions.**

All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. **Subpart PP—Suppliers of Carbon**
**Dioxide**

**§ 98.420 Definition of the source category.**

(a) The carbon dioxide (CO 2 ) supplier source category consists of the following:

(1) Facilities with production process units that capture a CO 2 stream for purposes of supplying CO 2 for commercial applications or that capture and maintain custody of a CO 2 stream in order to sequester or otherwise inject it underground. Capture refers to the initial separation and removal of CO 2 from a manufacturing process or any other process.

(2) Facilities with CO 2 production wells that extract or produce a CO 2 stream for purposes of supplying CO 2 for commercial applications or that extract and maintain custody of a CO 2 stream in order to sequester or otherwise inject it underground.

(3) Importers or exporters of bulk CO 2
. (b) This source category is focused on upstream supply. It does not cover:

(1) Storage of CO 2 above ground or in geologic formations.

(2) Use of CO 2 in enhanced oil and gas

recovery.

(3) Transportation or distribution of

CO 2
.

(4) Purification, compression, or processing of CO 2
.

(5) On-site use of CO 2 captured on

site.

(c) This source category does not
include CO 2 imported or exported in equipment, such as fire extinguishers. **§ 98.421 Reporting threshold.**

Any supplier of CO 2 who meets the requirements of § 98.2(a)(4) of subpart A of this part must report the mass of CO 2 captured, extracted, imported, or exported.

**§ 98.422 GHGs to report.**

(a) Mass of CO 2 captured from each production process unit.

(b) Mass of CO 2 extracted from each

CO 2 production wells.

(c) Mass of CO 2 imported.

(d) Mass of CO 2 exported.

**§ 98.423 Calculating CO** 2 **supply.**

(a) Calculate the annual mass of CO 2 captured, extracted, imported, or exported through each flow meter in accordance with the procedures specified in either paragraph (a)(1) or (a)(2) of this section. If multiple flow meters are used, you shall calculate the
annual mass of CO 2 for all flow meters according to the procedures specified in paragraph (a)(3) of this section.

(1) For each mass flow meter, you shall calculate quarterly the mass of CO 2 in a CO 2 stream in metric tons, prior to any subsequent purification, processing, or compressing, by multiplying the mass flow by the composition data, according to Equation PP–1 of this section. Mass flow and composition data
measurements shall be made in accordance with § 98.424 of this subpart.



### CO Eq

u 2

1 4

2 , , 

### ( .

= ∗

= 

# ∑ Q C p,u CO

p p,u 

### PP-1)

Where:

CO 2,u = Annual mass of CO 2 (metric tons) through flow meter u.

C CO 2 ,p,u = Quarterly CO 2 concentration measurement in flow for flow meter u in quarter p (wt. %CO 2 ). Q

p,u = Quarterly mass flow rate measurement for flow meter u in quarter p (metric tons). p = Quarter of the year.
u = Flow meter.

(2) For each volumetric flow meter, you shall calculate quarterly the mass of

CO 2 in a CO 2 stream in metric tons, prior to any subsequent purification, processing, or compressing, by multiplying the volumetric flow by the concentration and density data, according to Equation PP–2 of this section. Volumetric flow, concentration and density data measurements shall be made in accordance with § 98.424 of
this section.



### CO Eq

u 2

1 4

2 

### 2

, , 

### ( .

= ∗∗

= 

# ∑ Q C p CO

p p 

### D

p 

### PP- )

Where:

CO 2,u = Annual mass of CO 2 (metric tons) through flow meter u.

C CO 2 ,p = Quarterly CO 2 concentration

measurement in flow for flow meter u in quarter p (wt. % CO 2 ). Q p = Quarterly volumetric flow rate

measurement for flow meter u in quarter p (standard cubic meters).

D p = Quarterly CO 2 stream density measurement for flow meter u in quarter p (metric tons per standard cubic meter). p = Quarter of the year. u = Flow meter.

(3) To aggregate data, sum the mass of

CO 2 for all flow meters in accordance with Equation PP–3 of this section.


### 56507 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

CO CO Eq

u U

2 2

1 

### 3 =

=



# ∑

, 

### ( . PP- )

p

Where:

CO 2 = Annual mass of CO 2 (metric tons) through all flow meters.

CO 2,u = Annual mass of CO 2 (metric tons) through flow meter u.
u = Flow meter.

(b) Importers or exporters that import or export CO 2 in containers shall
calculate the total mass of CO 2 imported or exported in metric tons, prior to any subsequent purification, processing, or compressing, based on summing the
mass in each CO 2 container using weigh bills, scales, or load cells according to Equation PP–4 of this section.



### CO Eq 2

1 

### 4

=

=



# ∑ Q

p

I 

### ( . PP- )

Where:

CO 2 = Annual mass of CO 2 (metric tons). Q = Annual mass in all CO 2 containers imported or exported during the reporting year (metric tons).

**§ 98.424 Monitoring and QA/QC requirements.** 

(a) Determination of quantity. (1) Reporters that have a mass flow
meter or volumetric flow meter installed
to measure the flow of a CO 2 stream shall base calculations in § 98.423 of this subpart on the installed mass flow
or volumetric flow meters.

(2) Reporters that do not have a mass
flow meter or volumetric flow meter
installed to measure the flow of the CO 2 stream shall base calculations in § 98.423 of this subpart on the flow of gas transferred off site using a mass flow
meter or a volumetric flow meter located at the point of off-site transfer.

(3) Importers or exporters that import or export CO 2 in containers shall
measure the mass in each CO 2 container using weigh bills, scales, or load cells
and sum the mass in all containers imported or exported during the reporting year.

(4) All flow meters, scales, and load cells used to measure quantities that are reported in § 98.423 of this subpart shall be operated and calibrated according to the following procedure:

(i) You shall use an appropriate standard method published by a consensus-based standards organization
if such a method exists. Consensusbased standards organizations include, but are not limited to, the following: ASTM International, the American National Standards Institute (ANSI), the American Gas Association (AGA), the American Society of Mechanical Engineers (ASME), the American Petroleum Institute (API), and the North American Energy Standards Board (NAESB).

(ii) Where no appropriate standard method developed by a consensus-based standards organization exists, you shall follow industry standard practices.

(iii) You must ensure that any flow meter calibrations performed are NIST
traceable.

(5) Reporters using Equation PP–2 of this subpart shall measure the density of
the CO 2 stream on a quarterly basis in
order to calculate the mass of the CO 2 stream according to the following procedure:

(i) You shall use an appropriate standard method published by a consensus-based standards organization to measure density if such a method
exists. Consensus-based standards organizations include, but are not limited to, the following: ASTM International, the American National Standards Institute (ANSI), the American Gas Association (AGA), the American Society of Mechanical Engineers (ASME), the American Petroleum Institute (API), and the North American Energy Standards Board (NAESB).

(ii) Where no appropriate standard method developed by a consensus-based standards organization exists, you shall follow industry standard practices.

(b) Determination of concentration. (1) Reporters using Equation PP–1 or PP–2 of this subpart shall sample the

CO 2 stream on a quarterly basis to determine the composition of the CO 2 stream.

(2) Methods to measure the composition of the CO 2 stream must conform to applicable chemical analytical standards. Acceptable methods include U.S. Food and Drug Administration food-grade specifications for CO 2 (see 21 CFR 184.1250) and ASTM standard E1747– 95 (Reapproved 2005) Standard Guide for Purity of Carbon Dioxide Used in Supercritical Fluid Applications (incorporated by reference, see § 98.7 of subpart A of this part).

**§ 98.425 Procedures for estimating missing data.** 

(a) Whenever the quality assurance procedures in § 98.424(a) of this subpart cannot be followed to measure quarterly
mass flow or volumetric flow of CO 2 , the most appropriate of the following missing data procedures shall be
followed:

(1) A quarterly CO 2 mass flow or volumetric flow value that is missing may be substituted with a quarterly value measured during another quarter of the current reporting year. (2) A quarterly CO 2 mass flow or volumetric flow value that is missing may be substituted with a quarterly value measured during the same quarter from the past reporting year.

(3) If a mass or volumetric flow meter
is installed to measure the CO 2 stream, you may substitute data from a mass or volumetric flow meter measuring the

CO 2 stream transferred for any period during which the installed meter is inoperable.

(4) The mass or volumetric flow used for purposes of product tracking and billing according to the reporter’s established procedures may be substituted for any period during which measurement equipment is inoperable.

(b) Whenever the quality assurance procedures in § 98.424(b) of this subpart
cannot be followed to determine
concentration of the CO 2 stream, the most appropriate of the following missing data procudures shall be
followed:

(1) A quarterly concentration value that is missing may be substituted with a quarterly value measured during another quarter of the current reporting

year.

(2) A quarterly concentration value that is missing may be substituted with a quarterly value measured during the same quarter from the previous reporting year.

(3) The concentration used for purposes of product tracking and billing according to the reporter’s established procedures may be substituted for any quarterly value.

(c) Missing data on density of the CO 2 stream shall be substituted with quarterly or annual average values from the previous calendar year.

**§ 98.426 Data reporting requirements.**

In addition to the information required by § 98.3(c) of subpart A of this part, the annual report shall contain the following information, as applicable:

(a) If you use Equation PP–1 of this subpart, report the following
information for each mass flow meter:

(1) Annual mass in metric tons of CO 2. (2) Quarterly mass flow of CO 2. (3) Quarterly concentration of the CO 2 stream.

(4) The standard used to measure CO 2 concentration.

(b) If you use Equation PP–2 of this subpart, report the following
information for each volumetric flow

meter:

(1) Annual mass in metric tons of CO 2. (2) Quarterly volumetric flow of CO 2. (3) Quarterly concentration of the CO 2 stream.

(4) Quarterly density of the CO 2 stream.


### 56508 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

(5) The method used to measure density.

(6) The standard used to measure CO 2 concentration.

(c) If you use Equation PP–3 of this subpart, report the annual CO 2 mass in
metric tons from all flow meters.

(d) If you use Equation PP–4 of this subpart, report at the corporate level the
annual mass of CO 2 in metric tons in all

CO 2 containers that are imported or exported.

(e) Each reporter shall report the following information:

(1) The type of equipment used to
measure the total flow of the CO 2 stream or the total mass in CO 2 containers.

(2) The standard used to operate and calibrate the equipment reported in (e)(1) of this section.

(3) The number of days in the reporting year for which substitute data procedures were used for the following

purpose:

(i) To measure quantity. (ii) To measure concentration. (iii) To measure density. (f) Report the aggregated annual quantity of CO 2 in metric tons that is transferred to each of the following end use applications, if known:

(1) Food and beverage. (2) Industrial and municipal water/

wastewater treatment.

(3) Metal fabrication, including welding and cutting.

(4) Greenhouse uses for plant growth. (5) Fumigants (e.g., grain storage) and
herbicides.

(6) Pulp and paper. (7) Cleaning and solvent use. (8) Fire fighting. (9) Transportation and storage of explosives.

(10) Enhanced oil and natural gas

recovery.

(11) Long-term storage (sequestration). (12) Research and development. (13) Other. (g) Each production process unit that captures a CO 2 stream for purposes of supplying CO 2 for commercial applications or in order to sequester or otherwise inject it underground when custody of the CO 2 is maintained shall report the percentage of that stream, if any, that is biomass-based during the reporting year.

**§ 98.427 Records that must be retained.**

In addition to the records required by § 98.3(g) of subpart A of this part, you must retain the records specified in paragraphs (a) through (c) of this section, as applicable.

(a) The owner or operator of a facility containing production process units must retain quarterly records of captured or transferred CO 2 streams and composition. (b) The owner or operator of a CO 2 production well facility must maintain quarterly records of the mass flow or
volumetric flow of the extracted or
transferred CO 2 stream and concentration and density if volumetric
flow meters are used.

(c) Importers or exporters of CO 2 must retain annual records of the mass flow, volumetric flow, and mass of CO 2 imported or exported.

**§ 98.428 Definitions.**

All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.

**PART 1033—[AMENDED]**

■ 21. The authority citation for part
1033 continues to read as follows:

Authority: 42 U.S.C. 7401–7671q.

**Subpart C—[Amended]**

■ 22. Section 1033.205 is amended by revising paragraph (d)(8) to read as
follows:

**§ 1033.205 Applying for a certificate of conformity.** 

* * * * *

(d) * * * (8)(i) All test data you obtained for each test engine or locomotive. As described in § 1033.235, we may allow you to demonstrate compliance based on results from previous emission tests, development tests, or other testing information. Include data for NOx, PM, HC, CO, and CO 2
.

(ii) Report measured CO 2 , N 2 O, and

CH 4 as described in § 1033.235. Small manufacturers/remanufacturers may omit reporting N 2 O and CH 4
. * * * * *

■ 23. Section 1033.235 is amended by adding paragraph (i) to read as follows:

**§ 1033.235 Emission testing required for**
**certification.**

* * * * *

(i) Measure CO 2 with each test.

Measure CH4 with each low-hour certification test using the procedures specified in 40 CFR part 1065 starting in the 2012 model year. Also measure N 2 O
with each low-hour certification test using the procedures specified in 40 CFR part 1065 for any engine family that depends on NOx aftertreatment to meet
emission standards. Small manufacturers/remanufacturers may
omit measurement of N 2 O and CH 4 . Use the same units and modal calculations as for your other results to report a single weighted value for CO 2 , N 2 O, and

CH 4 . Round the final values as follows:

(1) Round CO 2 to the nearest 1 g/bhp–
hr. (2) Round N 2 O to the nearest 0.001 g/ bhp–hr.

(3) Round CH4 to the nearest 0.001g/ bhp–hr.

**Subpart F—[Amended]**

■ 24. Section 1033.501 is amended by revising paragraph (a) introductory text
to read as follows:

**§ 1033.501 General provisions.**

(a) Except as specified in this subpart, use the equipment and procedures for compression-ignition engines in 40 CFR part 1065 to determine whether your locomotives meet the duty-cycle emission standards in § 1033.101. Use the applicable duty cycles specified in this subpart. Measure emissions of all the pollutants we regulate in § 1033.101 plus CO 2 . Measure N 2 O, and CH 4 as described in § 1033.235. The general test procedure is the procedure specified in 40 CFR part 1065 for steady-state discrete-mode cycles. However, if you use the optional ramped modal cycle in § 1033.520, follow the procedures for ramped modal testing in 40 CFR part 1065. The following exceptions from the 1065 procedures apply:

* * * * *

**Subpart J—[Amended]**

■ 25. Section 1033.905 is amended by adding the abbreviations CH4 and N 2 O in alphanumeric order to read as
follows:

**§ 1033.905 Symbols, acronyms, and**
**abbreviations.**

* * * * *

* * * * *

CH 4 methane.

* * * * *

N 2 O nitrous oxide.

* * * * *

**PART 1039—[AMENDED]**

■ 26. The authority citation for part
1039 continues to read as follows:

Authority: 42 U.S.C. 7401–7671q.

**Subpart C—[Amended]**

■ 27. Section 1039.205 is amended by revising paragraph (r) to read as follows:

**§ 1039.205 What must I include in my application?** 

* * * * *

(r) Report test results as follows: (1) Report all test results involving measurement of pollutants for which emission standards apply. Include test results from invalid tests or from any other tests, whether or not they were conducted according to the test


### 56509 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

procedures of subpart F of this part. We may ask you to send other information to confirm that your tests were valid under the requirements of this part and 40 CFR part 1065.

(2) Report measured CO 2 , N 2 O, and

CH 4 as described in § 1039.235. Smallvolume engine manufacturers may omit reporting N 2 O and CH 4
. * * * * *

■ 28. Section 1039.235 is amended by adding paragraph (g) to read as follows:

**§ 1039.235 What emission testing must I perform for my application for a certificate**  **of conformity?**

* * * * *

(g) Measure CO 2 and CH 4 with each low-hour certification test using the procedures specified in 40 CFR part 1065 in the 2011 and 2012 model years, respectively. Also measure N 2 O with each low-hour certification test using the procedures specified in 40 CFR part 1065 starting in the 2013 model year for any engine family that depends on NOx
aftertreatment to meet emission standards. Small-volume engine manufacturers may omit measurement
of N 2 O and CH 4 . These measurements are not required for NTE testing. Use the
same units and modal calculations as for your other results to report a single weighted value for each constituent.
Round the final values as follows:

(1) Round CO 2 to the nearest 1 g/kWhr.

(2) Round N 2 O to the nearest 0.001 g/
kW-hr.

(3) Round CH4 to the nearest 0.001g/
kW-hr.

**Subpart F—[Amended]**

■ 29. Section 1039.501 is amended by revising paragraph (a) to read as follows:

**§ 1039.501 How do I run a valid emission**
**test?**

(a) Use the equipment and procedures for compression-ignition engines in 40 CFR part 1065 to determine whether engines meet the duty-cycle emission standards in subpart B of this part.
Measure the emissions of all the exhaust constituents subject to emissions standards as specified in 40 CFR part

1065. Measure CO 2 , N 2 O, and CH 4 as described in § 1039.235. Use the applicable duty cycles specified in §§ 1039.505 and 1039.510.

* * * * *

**Subpart I—[Amended]**

■ 30. Section 1039.805 is amended by adding the abbreviations CH4 and N 2 O in alphanumeric order to read as
follows: **§ 1039.805 What symbols, acronyms, and abbreviations does this part use?** 

* * * * *

* * * * *

CH 4 methane.

* * * * *

N 2 O nitrous oxide.

* * * * *

**PART 1042—[AMENDED]**

■ 31. The authority citation for part
1042 continues to read as follows:

Authority: 42 U.S.C. 7401–7671q.

**Subpart C—[Amended]**

■ 32. Section 1042.205 is amended by revising paragraph (r) to read as follows:

**§ 1042.205 Application requirements.**

* * * * *

(r) Report test results as follows: (1) Report all test results involving measurement of pollutants for which emission standards apply. Include test results from invalid tests or from any other tests, whether or not they were conducted according to the test procedures of subpart F of this part. We may ask you to send other information to confirm that your tests were valid under the requirements of this part and 40 CFR part 1065.

(2) Report measured CO 2 , N 2 O, and

CH 4 as described in § 1042.235. Smallvolume engine manufacturers may omit reporting N 2 O and CH 4
. * * * * *

■ 33. Section 1042.235 is amended by adding paragraph (g) to read as follows:

**§ 1042.235 Emission testing required for a certificate of conformity.** 

* * * * *

(g) Measure CO 2 with each low-hour certification test using the procedures specified in 40 CFR part 1065 starting in the 2011 model year. Also measure CH4 from Category 1 and Category 2 engines
with each low-hour certification test using the procedures specified in 40 CFR part 1065 starting in the 2012 model year. Measure N 2 O from Category1 and Category 2 engines with each lowhour certification test using the procedures specified in 40 CFR part 1065 for any engine family that depends
on NOx aftertreatment to meet emission standards. Small-volume engine manufacturers may omit measurement
of N 2 O and CH 4 . These measurements are not required for NTE testing. Use the
same units and modal calculations as for your other results to report a single weighted value for each constituent.
Round the final values as follows: (1) Round CO 2 to the nearest 1 g/kWhr.

(2) Round N 2 O to the nearest 0.001 g/
kW-hr.

(3) Round CH4 to the nearest 0.001 g/
kW-hr.

**Subpart F—[Amended]**

■ 34. Section 1042.501 is amended by revising paragraph (a) to read as follows:

**§ 1042.501 How do I run a valid emission**
**test?**

(a) Use the equipment and procedures for compression-ignition engines in 40 CFR part 1065 to determine whether Category 1 and Category 2 engines meet the duty-cycle emission standards in § 1042.101(a). Measure the emissions of all exhaust constituents subject to emissions standards as specified in 40 CFR part 1065. Measure CO 2 , N 2 O, and

CH 4 as described in § 1042.235. Use the applicable duty cycles specified in § 1042.505.

* * * * *

**Subpart J—[Amended]**

■ 35. Section 1042.905 is amended by adding the abbreviations CH4 and N 2 O in alphanumeric order to read as
follows:

**§ 1042.905 Symbols, acronyms, and**
**abbreviations.**

* * * * *

* * * * *

CH 4 methane.

* * * * *

N 2 O nitrous oxide.

* * * * *

**PART 1045—[AMENDED]**

■ 36. The authority citation for part
1045 continues to read as follows:

Authority: 42 U.S.C. 7401–7671q.

**Subpart C—[Amended]**

■ 37. Section 1045.205 is amended by revising paragraph (q) to read as follows:

**§ 1045.205 What must I include in my application?** 

* * * * *

(q) Report test results as follows: (1) Report all test results involving measurement of pollutants for which emission standards apply. Include test results from invalid tests or from any other tests, whether or not they were conducted according to the test procedures of subpart F of this part. We may ask you to send other information to confirm that your tests were valid under the requirements of this part and 40 CFR parts 1060 and 1065.


### 56510 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

(2) Report measured CO 2 , N 2 O, and

CH 4 as described in § 1045.235. Smallvolume engine manufacturers may omit reporting N 2 O and CH 4
. * * * * *

■ 38. Section 1045.235 is amended by adding paragraph (g) to read as follows:

**§ 1045.235 What emission testing must I perform for my application for a certificate**  **of conformity?**

* * * * *

(g) Measure CO 2 and CH 4 with each low-hour certification test using the procedures specified in 40 CFR part 1065 starting in the 2011 and 2012 model years, respectively. Also measure

N 2 O with each low-hour certification test using the procedures specified in 40 CFR part 1065 starting in the 2013 model year for any engine family that depends on NO X aftertreatment to meet
emission standards. Small-volume engine manufacturers may omit
measurement of N 2 O and CH 4 . These measurements are not required for NTE testing. Use the same units and modal calculations as for your other results to report a single weighted value for each
constituent. Round the final values as
follows:

(1) Round CO 2 to the nearest 1 g/kWhr.

(2) Round N 2 O to the nearest 0.001 g/
kW-hr.

(3) Round CH4 to the nearest 0.001 g/
kW-hr.

**Subpart F—[Amended]**

■ 39. Section 1045.501 is amended by revising paragraph (b) to read as follows:

**§ 1045.501 How do I run a valid emission**
**test?**

* * * * *

(b) General requirements. Use theequipment and procedures for sparkignition engines in 40 CFR part 1065 to determine whether engines meet the duty-cycle emission standards in §§ 1045.103 and 1045.105. Measure the
emissions of all exhaust constituents subject to emissions standards as specified in 40 CFR part 1065. Measure

CO 2 , N 2 O, and CH 4 as described in § 1045.235. Use the applicable duty cycles specified in § 1045.505. Section 1045.515 describes the supplemental procedures for evaluating whether engines meet the not-to-exceed emission standards in § 1045.107.

* * * * *

**PART 1048—[AMENDED]**

■ 40. The authority citation for part
1048 continues to read as follows:

Authority: 42 U.S.C. 7401–7671q. **Subpart C—[Amended]**

■ 41. Section 1048.205 is amended by revising paragraph (s) to read as follows:

**§ 1048.205 What must I include in my application?** 

* * * * *

(s) Report test results as follows: (1) Report all test results involving measurement of pollutants for which emission standards apply. Include test results from invalid tests or from any other tests, whether or not they were conducted according to the test procedures of subpart F of this part. We may ask you to send other information to confirm that your tests were valid under the requirements of this part and 40 CFR part 1065.

(2) Report measured CO 2 , N 2 O, and

CH 4 as described in § 1048.235. Smallvolume engine manufacturers may omit reporting N 2 O and CH 4
. * * * * *

■ 42. Section 1048.235 is amended by adding paragraph (g) to read as follows:

**§ 1048.235 What emission testing must I perform for my application for a certificate**  **of conformity?**

* * * * *

(g) Measure CO 2 and CH 4 with each low-hour certification test using the procedures specified in 40 CFR part 1065 starting in the 2011 and 2012 model years, respectively. Also measure

N 2 O with each low-hour certification test using the procedures specified in 40 CFR part 1065 starting in the 2013 model year for any engine family that depends on NOx aftertreatment to meet
emission standards. Small-volume engine manufacturers may omit
measurement of N 2 O and CH 4 . These measurements are not required for measurements using field-testing procedures. Use the same units and modal calculations as for your other results to report a single weighted value
for each constituent. Round the final
values as follows:

(1) Round CO 2 to the nearest 1 g/kWhr.

(2) Round N 2 O to the nearest 0.001 g/
kW-hr.

(3) Round CH4 to the nearest 0.001g/
kW-hr.

**Subpart F—[Amended]**

■ 43. Section 1048.501 is amended by revising paragraph (a) to read as follows:

**§ 1048.501 How do I run a valid emission**
**test?**

(a) Use the equipment and procedures for spark-ignition engines in 40 CFR part 1065 to determine whether engines meet the duty-cycle emission standards in § 1048.101(a) and (b). Measure the emissions of all the pollutants we regulate in § 1048.101 using the sampling procedures specified in 40 CFR part 1065. Measure CO 2 , N 2 O, and

CH 4 as described in § 1048.235. Use the applicable duty cycles specified in §§ 1048.505 and 1048.510.

* * * * *

**Subpart I—[Amended]**

■ 44. Section 1048.805 is amended by adding the abbreviations CH4 and N 2 O in alphanumeric order to read as
follows:

**§ 1048.805 What symbols, acronyms, and abbreviations does this part use?** 

* * * * *

* * * * *

CH 4 methane.

* * * * *

N 2 O nitrous oxide.

* * * * *

**PART 1051—[AMENDED]**

■ 45. The authority citation for part
1051 continues to read as follows:

Authority: 42 U.S.C. 7401–7671q.

**Subpart C—[Amended]**

■ 46. Section 1051.205 is amended by revising paragraph (p) to read as
follows:

**§ 1051.205 What must I include in my application?** 

* * * * *

(p) Report test results as follows: (1) Report all test results involving measurement of pollutants for which emission standards apply. Include test results from invalid tests or from any other tests, whether or not they were conducted according to the test procedures of subpart F of this part. We may ask you to send other information to confirm that your tests were valid under the requirements of this part and 40 CFR parts 86 and 1065.

(2) Report measured CO 2 , N 2 O, and

CH 4 as described in § 1051.235. Smallvolume manufacturers may omit reporting N 2 O and CH 4
. * * * * *

■ 47. Section 1051.235 is amended by adding paragraph (i) to read as follows:

**§ 1051.235 What emission testing must I perform for my application for a certificate**  **of conformity?**

* * * * *

(i) Measure CO 2 and CH 4 with each low-hour certification test using the procedures specified in 40 CFR part 1065 starting in the 2011 and 2012


### 56511 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

model years, respectively. Also measure

N 2 O with each low-hour certification test using the analytical equipment and procedures specified in 40 CFR part 1065 starting in the 2013 model year for any engine family that depends on NOx
aftertreatment to meet emission
standards. Small-volume manufacturers may omit measurement of N 2 O and CH 4 ; other manufacturers may provide appropriate data and/or information and
omit measurement of N 2 O and CH 4 as described in 40 CFR 1065.5. Use the
same units and modal calculations as for your other results to report a single weighted value for each constituent.
Round the final values as follows:

(1) Round CO 2 to the nearest 1 g/kWhr or 1 g/km, as appropriate.

(2) Round N 2 O to the nearest 0.001 g/ kW-hr or 0.001 g/km, as appropriate.

(3) Round CH4 to the nearest 0.001 g/ kW-hr or 0.001 g/km, as appropriate.

**Subpart F—[Amended]**

■ 48. Section 1051.501 is amended by revising paragraphs (a) and (b) to read
as follows:

**§ 1051.501 What procedures must I use to test my vehicles or engines?** 

* * * * *

(a) Snowmobiles. For snowmobiles, use the equipment and procedures for spark-ignition engines in 40 CFR part 1065 to determine whether your snowmobiles meet the duty-cycle emission standards in § 1051.103.
Measure the emissions of all the pollutants we regulate in § 1051.103.

Measure CO 2 , N 2 O, and CH 4 as described in § 1051.235. Use the duty cycle specified in § 1051.505.

(b) Motorcycles and ATVs. For motorcycles and ATVs, use the equipment, procedures, and duty cycle in 40 CFR part 86, subpart F, to determine whether your vehicles meet
the exhaust emission standards in § 1051.105 or § 1051.107. Measure the emissions of all the pollutants we regulate in § 1051.105 or § 1051.107.

Measure CO 2 , N 2 O, and CH 4 as described in § 1051.235. If we allow you to certify ATVs based on engine testing, use the equipment, procedures, and duty cycle described or referenced in the section that allows engine testing. For motorcycles with engine displacement at or below 169 cc and all ATVs, use the driving schedule in paragraph (c) of appendix I to 40 CFR part 86. For all other motorcycles, use the driving schedule in paragraph (b) of Appendix I to part 86. With respect to vehicle-speed governors, test motorcycles and ATVs in their ungoverned configuration, unless we approve in advance testing in a governed configuration. We will only approve testing in a governed configuration if you can show that the governor is permanently installed on all production vehicles and is unlikely to be removed in use. With respect to engine-speed governors, test motorcycles and ATVs in their governed configuration. Run the test engine, with all emission-control systems operating, long enough to stabilize emission levels; you may consider emission levels stable without measurement if you accumulate 12 hours of operation.

* * * * *

**Subpart I—[Amended]**

■ 49. Section 1051.805 is amended by adding the abbreviations CH4 and N 2 O in alphanumeric order to read as
follows:

**§ 1051.805 What symbols, acronyms, and abbreviations does this part use?** 

* * * * *

* * * * *

CH 4 methane.

* * * * *

N 2 O nitrous oxide.

* * * * *

**PART 1054—[AMENDED]**

■ 50. The authority citation for part
1054 continues to read as follows:

Authority: 42 U.S.C. 7401–7671q.

**Subpart C—[Amended]**

■ 51. Section 1054.205 is amended by revising paragraph (p) to read as
follows:

**§ 1054.205 What must I include in my application?** 

* * * * *

(p) Report test results as follows: (1) Report all test results involving measurement of pollutants for which emission standards apply. Include test results from invalid tests or from any other tests, whether or not they were conducted according to the test procedures of subpart F of this part. We may ask you to send other information to confirm that your tests were valid under the requirements of this part and 40 CFR parts 1060 and 1065.

(2) Report measured CO 2 , N 2 O, and

CH 4 as described in § 1054.235. Smallvolume engine manufacturers may omit reporting N 2 O and CH 4
. * * * * *

■ 52. Section 1054.235 is amended by adding paragraph (g) to read as follows: **§ 1054.235 What exhaust emission testing must I perform for my application for a**  **certificate of conformity?**

* * * * *

(g) Measure CO 2 and CH 4 with each low-hour certification test using the procedures specified in 40 CFR part 1065 starting in the 2011 and 2012 model years, respectively. Also measure

N 2 O with each low-hour certification test using the procedures specified in 40 CFR part 1065 starting in the 2013 model year for any engine family that depends on NOx aftertreatment to meet
emission standards. Small-volume engine manufacturers may omit
measurement of N 2 O and CH 4 . Use the
same units and modal calculations as for your other results to report a single weighted value for each constituent.
Round the final values as follows:

(1) Round CO 2 to the nearest 1 g/kWhr.

(2) Round N 2 O to the nearest 0.001 g/
kW-hr.

(3) Round CH4 to the nearest 0.001 g/
kW-hr.

**Subpart F—[Amended]**

■ 53. Section 1054.501 is amended by revising paragraph (b)(1) to read as
follows:

**§ 1054.501 How do I run a valid emission**
**test?**

* * * * *

(b) * * * (1) Measure the emissions of all exhaust constituents subject to emissions standards as specified in § 1054.505 and 40 CFR part 1065.

Measure CO 2 , N 2 O, and CH 4 as described in § 1054.235. See § 1054.650 for special provisions that apply for variable-speed engines (including engines shipped without governors).

* * * * *

**PART 1065—[AMENDED]**

■ 54. The authority citation for part
1065 continues to read as follows:

Authority: 42 U.S.C. 7401–7671q.

**Subpart A—[Amended]**

■ 55. Section 1065.5 is amended by revising paragraph (a)(3) to read as
follows:

**§ 1065.5 Overview of this part 1065 and its relationship to the standard-setting part.** 

(a) * * * (3) Which exhaust constituents do I
need to measure? Measure all exhaust constituents that are subject to emission standards, any other exhaust constituents needed for calculating emission rates, and any additional


### 56512 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

exhaust constituents as specified in the standard-setting part. Alternatively, you may omit the measurement of N 2 O and

CH 4 for an engine, provided it is not subject to an N 2 O or CH 4 emission standard. If you omit the measurement
of N 2 O and CH 4 , you must provide other information and/or data that will give us a reasonable basis for estimating the engine’s emission rates.

* * * * *

**Subpart C—[Amended]**

■ 56. The center heading ‘‘NO

x Measurements’’ preceding § 1065.270 is
revised to read as follows:

NO X and N2 O Measurements

■ 57. A new § 1065.275 is added under the center heading ‘‘NO

x and N 2 O
Measurements’’ to read as follows:

**§ 1065.275 N** 2 **O measurement devices.**

(a) General component requirements. We recommend that you use an analyzer that meets the specifications in Table 1 of § 1065.205. Note that your system must meet the linearity verification in § 1065.307.

(b) Instrument types. You may use any of the following analyzers to measure

N 2 O:

(1) Nondispersive infra-red (NDIR) analyzer. You may use an NDIR analyzer that has compensation algorithms that are functions of other gaseous measurements and the engine’s known or assumed fuel properties. The target value for any compensation algorithm is 0.0% (that is, no bias high and no bias low), regardless of the uncompensated signal’s bias.

(2) Fourier transform infra-red (FTIR) analyzer. You may use an FTIR analyzer that has compensation algorithms that are functions of other gaseous measurements and the engine’s known or assumed fuel properties. The target value for any compensation algorithm is 0.0% (that is, no bias high and no bias low), regardless of the uncompensated signal’s bias. Use appropriate analytical procedures for interpretation of infrared spectra. For example, EPA Test Method
320 is considered a valid method for spectral interpretation (see http://www. epa.gov/ttn/emc/methods/
method320.html).

(3) Photoacoustic analyzer. You may use a photoacoustic analyzer that has compensation algorithms that are functions of other gaseous measurements. The target value for any compensation algorithm is 0.0% (that is, no bias high and no bias low), regardless of the uncompensated signal’s bias. Use an optical wheel configuration that gives analytical priority to measurement of the least stable components in the sample. Select a sample integration time
of at least 5 seconds. Take into account sample chamber and sample line volumes when determining flush times for your instrument.

(4) Gas chromatograph analyzer. You may use a gas chromatograph with an electron-capture detector (GC–ECD) to

measure N 2 O concentrations of diluted exhaust for batch sampling.

(i) You may use a packed or porous layer open tubular (PLOT) column phase of suitable polarity and length to achieve adequate resolution of the N 2 O peak for analysis. Examples of acceptable columns are a PLOT columnconsisting of bonded polystyrenedivinylbenzene or a Porapack Q packed column. Take the column temperature profile and carrier gas selection into consideration when setting up your method to achieve adequate N 2 O peak
resolution.

(ii) Use good engineering judgment to zero your instrument and correct for
drift. You do not need to follow the specific procedures in § 1065.530 and § 1065.550(b) that would otherwise apply. For example, you may perform a span gas measurement before and after sample analysis without zeroing. Use the average area counts of the pre-span and post-span measurements to generate a response factor (area counts/span gas concentration), which you then multiply by the area counts from your sample to generate the sample

concentration.

(c) Interference validation. Perform interference validation for NDIR, FTIR, and photoacoustic analyzers using the procedures of § 1065.375. Interference validation is not required for GC–ECD. Certain interference gases can positively interfere with NDIR, FTIR, and photoacoustic analyzers by causing a response similar to N 2 O. When running
the interference verification for these analyzers, use interference gases as
follows:

(1) The interference gases for NDIR analyzers are CO, CO 2 , H 2 O, CH 4 and

SO 2 . Note that interference species, with the exception of H 2 O, are dependent on
the N 2 O infrared absorption band chosen by the instrument manufacturer and should be determined dently for each analyzer.

(2) Use good engineering judgment to determine interference gases for FTIR. Note that interference species, with the exception of H 2 O, are dependent on the

N 2 O infrared absorption band chosen by
the instrument manufacturer and should be determined independently for each analyzer.

(3) The interference gases for photoacoustic analyzers are CO, CO 2 , and H 2 O.

**Subpart D—[Amended]**

■ 58. Section 1065.303 is revised to read
as follows:

**§ 1065.303 Summary of required**
**calibration and verifications**

The following table summarizes the required and recommended calibrations
and verifications described in this subpart and indicates when these have to be performed:



### TABLE 

### 1 OF 

### § 1065.303–S UMMARY OF 

### R EQUIRED 

### C ALIBRATION AND 

### V ERIFICATIONS

Type of calibration or verification Minimum frequency a

§ 1065.305: Accuracy, repeatability and noise ............................. Accuracy: Not required, but recommended for initial in stallation. Repeatability: Not required, but recommended for initial installation. Noise: Not required, but recommended for initial installation. § 1065.307: Linearity .................................................................... Speed: Upon initial installation, withi n 370 days before testing and after major
maintenance. Torque: Upon initial installation, within 370 days before testing and after major

maintenance. Electrical power: Upon initial installation, within 370 days before testing and

after major maintenance. Clean gas and diluted exhaust flows: Upon initial installation, within 370 days

before testing and after major maintenance, unless flow is verified by propane check or by carbon or oxygen balance.


### 56513 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

TABLE 

### 1 OF 

### § 1065.303–S UMMARY OF 

### R EQUIRED 

### C ALIBRATION AND 

### V ERIFICATIONS

### —Continued

Type of calibration or verification Minimum frequency a

Raw exhaust flow: Upon initial installation, within 185 days before testing and

after major maintenance, unless flow is verified by propane check or by carbon or oxygen balance. Gas analyzers: Upon initial installation, within 35 days before testing and after

major maintenance. FTIR and photoacoustic analyzers: Upon initial installation, within 370 days

before testing and after major maintenance. GC–ECD: Upon initial installation and after major maintenance. PM balance: Upon initial installation, within 370 days before testing and after

major maintenance. Stand-alone pressure and temperature: Upon initial installation, within 370

days before testing and after major maintenance.§ 1065.308: Continuous gas analyzer system response and updating-recording verification—for gas analyzers not continuously compensated for other gas species. Upon initial installation or after system modification that would effect response.

§ 1065.309: Continuous gas analyzer system-response and updating-recording verification—for gas analyzers continuously compensated for other gas species. Upon initial installation or after system modification that would effect response.

§ 1065.310: Torque ....................................................................... Upon initial installation and after maj or maintenance. § 1065.315: Pressure, temperature, dewpoint .............................. Upon initial installation and after major maintenance. § 1065.320: Fuel flow ................................................................... Upon initial installation and after majo r maintenance. § 1065.325: Intake flow ................................................................. Upon initial installation and after majo r maintenance. § 1065.330: Exhaust flow ............................................................. Upon initial installation and after major m aintenance. § 1065.340: Diluted exhaust flow (CVS) ....................................... Upon initial installation and after major maintenan ce. § 1065.341: CVS and batch sampler verification b ....................... Upon initial installation, within 35 days before testing, and after major maintenance. § 1065.345: Vacuum leak ............................................................. Before each laboratory test according to sub part F of this part and before each field test according to subpart J of this part. § 1065.350: CO 2 NDIR H 2 O interference ..................................... Upon initial installation and after major maintenance. § 1065.355: CO NDIR CO 2 and H 2 O interference ....................... Upon initial installation and after major maintenance. § 1065.360: FID calibration, THC FID optimization, and THC

FID verification.. Calibrate all FID analyzers: upon initial installation and after major maintenance. Optimize and determine CH 4 response for THC FID analyzers:

upon initial installation and after major maintenance. Verify CH 4 response for THC FID analyzers: upon initial installation, within

185 days before testing, and after major maintenance. § 1065.362: Raw exhaust FID O 2 interference ............................. For all FID analyzers: upon initial installation, and after major maintenance. For THC FID analyzers: upon initial installation, after major maintenance, and

after FID optimization according to § 1065.360. § 1065.365: Nonmethane cutter penetration ................................ Upon initial installation, within 185 days before testi ng, and after major maintenance. § 1065.370: CLD CO 2 and H 2 O quench ....................................... Upon initial installation and after major maintenance. § 1065.372: NDUV HC and H 2 O interference .............................. Upon initial installation and after major maintenance. § 1065.375: N 2 O analyzer interference ........................................ Upon initial installation and after major maintenance. § 1065.376: Chiller NO 2 penetration ............................................. Upon initial installation and after major maintenance. § 1065.378: NO 2 -to-NO converter conversion .............................. Upon initial installation, within 35 days before testing, and after major maintenance. § 1065.390: PM balance and weighing ........................................ Independent verification: upon initial installation, within 370 days before testing, and after major maintenance. Zero, span, and reference sample verifications: within 12 hours of weighing,

and after major maintenance. § 1065.395: Inertial PM balance and weighing ............................ Independent verification: upon initial installation, wit hin 370 days before testing, and after major maintenance. Other verifications: upon initial installation and after major maintenance.

a Perform calibrations and verifications more frequently, according to measurement system manufacturer instructions and good engi neering judgment.

b The CVS verification described in § 1065.341 is not required for systems that agree within ± 2% based on a chemical balance of carbon or oxygen of the intake air, fuel, and diluted exhaust.

b The CVS verification described in § 1065.341 is not required for systems that agree within ± 2% based on a chemical balance of carbon or oxygen of the intake air, fuel, and diluted exhaust.

■ 59. Section 1065.307 is amended by revising paragraph (c)(6) to read as
follows:

**§ 1065.307 Linearity verification.**

* * * * *

(c) * * *
(6) For all measured quantities, use
instrument manufacturer recommendations and good engineering judgment to select reference values, yrefi , that cover a range of values that you expect would prevent extrapolation beyond these values during emission testing. We recommend selecting a zero reference signal as one of the reference values of the linearity verification. For stand-alone pressure and temperature linearity verifications and for GC–ECD linearity verifications, we recommend at
least three reference values. For all other linearity verifications select at least ten
reference values.

* * * * *

■ 60. Section 1065.365 is amended by revising paragraphs (d), (e), and (f) to
read as follows:


### 56514 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

**§ 1065.365 Nonmethane cutter penetration**
**fractions.**

* * * * *

(d) Procedure for a FID calibrated
with the NMC. The method described in this paragraph (d) is recommended over the procedures specified in paragraphs (e) and (f) of this section. If your FID arrangement is such that a FID is always
calibrated to measure CH4 with the NMC, then span that FID with the NMC using a CH4 span gas, set the product of
that FID’s CH4 response factor and CH4 penetration fraction, RFPF CH4[NMC–FID] , equal to 1.0 for all emission calculations, and determine its combined ethane (C 2H 6 ) response factor and penetration fraction,

RFPF C2H6[NMC–FID] as follows:

(1) Select CH4 and C 2H 6 analytical gas
mixtures and ensure that both mixtures meet the specifications of § 1065.750.
Select a CH4 concentration that you would use for spanning the FID during emission testing and select a C 2H 6 concentration that is typical of the peak NMHC concentration expected at the hydrocarbon standard or equal to the THC analyzer’s span value.

(2) Start, operate, and optimize the nonmethane cutter according to the manufacturer’s instructions, including any temperature optimization.

(3) Confirm that the FID analyzer meets all the specifications of § 1065.360.

(4) Start and operate the FID analyzer according to the manufacturer’s

instructions.

(5) Zero and span the FID with the nonmethane cutter as you would during emission testing. Span the FID through the cutter by using CH4 span gas.

(6) Introduce the C 2H 6 analytical gas mixture upstream of the nonmethane cutter. Use good engineering judgment to address the effect of hydrocarbon contamination if your point of introduction is vastly different from the point of zero/span gas introduction.

(7) Allow time for the analyzer response to stabilize. Stabilization time may include time to purge the
nonmethane cutter and to account for the analyzer’s response.

(8) While the analyzer measures a stable concentration, record 30 seconds of sampled data. Calculate the arithmetic mean of these data points.

(9) Divide the mean C 2H 6 concentration by the reference
concentration of C 2H 6 , converted to a C 1 basis. The result is the C 2H 6 combined response factor and penetration fraction,

RFPF C2H6[NMC–FID] . Use this combined response factor and penetration fraction and the product of the CH4 response factor and CH4 penetration fraction,

RFPF CH4[NMC–FID] , set to 1.0 in emission calculations according to § 1065.660(b)(2)(i), § 1065.660(c)(1)(i), or § 1065.665, as applicable.

(e) Procedure for a FID calibrated with propane, bypassing the NMC. If you use a single FID for THC and CH4 determination with an NMC that is calibrated with propane, C 3 H 8 , by bypassing the NMC, determine its penetration fractions, PF C2H6[NMC–FID] and PF CH4[NMC–FID] , as follows:

(1) Select CH4 and C 2H 6 analytical gas
mixtures and ensure that both mixtures meet the specifications of § 1065.750.
Select a CH4 concentration that you would use for spanning the FID during emission testing and select a C 2H 6 concentration that is typical of the peak NMHC concentration expected at the hydrocarbon standard or equal to the THC analyzer’s span value.

(2) Start and operate the nonmethane cutter according to the manufacturer’s instructions, including any temperature optimization.

(3) Confirm that the FID analyzer meets all the specifications of § 1065.360.

(4) Start and operate the FID analyzer according to the manufacturer’s

instructions.

(5) Zero and span the FID as you would during emission testing. Span the FID by bypassing the cutter and by using C 3 H 8 span gas.

(6) Introduce the C 2H 6 analytical gas mixture upstream of the nonmethane cutter. Use good engineering judgment to address the effect of hydrocarbon contamination if your point of introduction is vastly different from the point of zero/span gas introduction.

(7) Allow time for the analyzer response to stabilize. Stabilization time may include time to purge the
nonmethane cutter and to account for the analyzer’s response.

(8) While the analyzer measures a stable concentration, record 30 seconds of sampled data. Calculate the arithmetic mean of these data points.

(9) Reroute the flow path to bypass the nonmethane cutter, introduce the

C 2H 6 analytical gas mixture, and repeat the steps in paragraph (e)(7) through (e)(8) of this section.

(10) Divide the mean C 2H 6 concentration measured through the nonmethane cutter by the mean C 2H 6 concentration measured after bypassing
the nonmethane cutter. The result is the

C 2H 6 penetration fraction,

PF C2H6[NMC–FID] . Use this penetration fraction according to § 1065.660(b)(2)(ii), § 1065.660(c)(1)(ii), or § 1065.665, as applicable.

(11) Repeat the steps in paragraphs (e)(6) through (e)(10) of this section, but
with the CH4 analytical gas mixture instead of C 2H 6 . The result will be the

CH 4 penetration fraction, PF CH4[NMC–FID]
. Use this penetration fraction according to § 1065.660(b)(2)(ii), § 1065.660(c)(1)(ii), or § 1065.665, as applicable.

(f) Procedure for a FID calibrated with methane, bypassing the NMC. If you use
a FID with an NMC that is calibrated with methane, CH4 , by bypassing the NMC, determine its combined ethane (C 2H 6 ) response factor and penetration fraction, RFPF C2H6[NMC–FID] , as well as

its CH 4 penetration fraction,

PF CH4[NMC–FID] , as follows:

(1) Select CH4 and C 2H 6 analytical gas
mixtures and ensure that both mixtures meet the specifications of § 1065.750.
Select a CH4 concentration that you would use for spanning the FID during emission testing and select a C 2H 6 concentration that is typical of the peak NMHC concentration expected at the hydrocarbon standard or equal to the THC analyzer’s span value.

(2) Start and operate the nonmethane cutter according to the manufacturer’s instructions, including any temperature optimization.

(3) Confirm that the FID analyzer meets all the specifications of § 1065.360.

(4) Start and operate the FID analyzer according to the manufacturer’s

instructions.

(5) Zero and span the FID as you would during emission testing. Span the FID by bypassing the cutter and by using CH 4 span gas. Note that you must span the FID on a C 1 basis. For example, if your span gas has a methane reference
value of 100 μmol/mol, the correct FID response to that span gas is 100 μmol/
mol because there is one carbon atom per CH4 molecule.

(6) Introduce the C 2H 6 analytical gas mixture upstream of the nonmethane cutter. Use good engineering judgment to address the effect of hydrocarbon contamination if your point of introduction is vastly different from the point of zero/span gas introduction.

(7) Allow time for the analyzer response to stabilize. Stabilization time may include time to purge the
nonmethane cutter and to account for the analyzer’s response.

(8) While the analyzer measures a stable concentration, record 30 seconds of sampled data. Calculate the arithmetic mean of these data points.

(9) Divide the mean C 2H 6 concentration by the reference
concentration of C 2H 6 , converted to a C 1 basis. The result is the C 2H 6 combined response factor and penetration fraction,

RFPF C2H6[NMC–FID] . Use this combined response factor and penetration fraction according to § 1065.660(b)(2)(iii),


### 56515 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

§ 1065.660(c)(1)(iii), or § 1065.665, as applicable.

(10) Introduce the CH4 analytical gas mixture upstream of the nonmethane cutter. Use good engineering judgment to address the effect of hydrocarbon contamination if your point of introduction is vastly different from the point of zero/span gas introduction.

(11) Allow time for the analyzer response to stabilize. Stabilization time may include time to purge the
nonmethane cutter and to account for the analyzer’s response.

(12) While the analyzer measures a stable concentration, record 30 seconds of sampled data. Calculate the arithmetic mean of these data points.

(13) Reroute the flow path to bypass the nonmethane cutter, introduce the

CH 4 analytical gas mixture, and repeat the steps in paragraphs (e)(11) and (12)
of this section.

(14) Divide the mean CH4 concentration measured through the nonmethane cutter by the mean CH4 concentration measured after bypassing
the nonmethane cutter. The result is the

CH 4 penetration fraction, PF CH4[NMC–FID]
. Use this penetration fraction according to § 1065.660(b)(2)(iii), § 1065.660(c)(1)(iii), or § 1065.665, as applicable.

■ 61. The center heading ‘‘NO X MEASUREMENTS’’ preceding § 1065.370 is revised to read as follows:

NO X and N 2 O Measurements

■ 62. A new § 1065.375 is added under
the center header ‘‘NO X and N 2 O
Measurements’’ to read as follows:

**§ 1065.375 Interference verification for N** 2 **O analyzers.** 

(a) Scope and frequency. See § 1065.275 to determine whether you need to verify the amount of interference after initial analyzer installation and after major

maintenance.

(b) Measurement principles. Interference gasses can positively interfere with certain analyzers by causing a response similar to N 2 O. If the analyzer uses compensation algorithms that utilize measurements of other gases to meet this interference verification, simultaneously conduct these other measurements to test the compensation algorithms during the analyzer
interference verification.

(c) System requirements. Analyzers
must have combined interference that is within (0.0 ± 1.0) μmol/mol. We strongly recommend a lower interference that is within (0.0 ± 0.5)

μmol/mol.

(d) Procedure. Perform the
interference verification as follows: (1) Start, operate, zero, and span the

N 2 O analyzer as you would before an emission test. If the sample is passed through a dryer during emission testing, you may run this verification test with the dryer if it meets the requirements of § 1065.342. Operate the dryer at the same conditions as you will for an emission test. You may also run this verification test without the sample dryer.

(2) Create a humidified test gas by bubbling a multi component span gas that incorporates the target interference species and meets the specifications in § 1065.750 through distilled water in a sealed vessel. If the sample is not passed through a dryer during emission testing, control the vessel temperature to generate an H 2 O level at least as high as the maximum expected during emission testing. If the sample is passed through a dryer during emission testing, control the vessel temperature to generate an

H 2 O level at least as high as the level determined in § 1065.145(e)(2) for that dryer. Use interference span gas concentrations that are at least as high as the maximum expected during testing.

(3) Introduce the humidified interference test gas into the sample system. You may introduce it downstream of any sample dryer, if one is used during testing.

(4) If the sample is not passed through a dryer during this verification test, measure the water mole fraction, x H2O , of the humidified interference test gas as close as possible to the inlet of the analyzer. For example, measure dewpoint, T dew , and absolute pressure,

ptotal , to calculate x H2O . Verify that the water content meets the requirement in paragraph (d)(2) of this section. If the sample is passed through a dryer during this verification test, you must verify
that the water content of the humidified test gas downstream of the vessel meets the requirement in paragraph (d)(2) of
this section based on either direct measurement of the water content (e.g., dewpoint and pressure) or an estimate based on the vessel pressure and temperature. Use good engineering judgment to estimate the water content. For example, you may use previous
direct measurements of water content to verify the vessel’s level of saturation.

(5) If a sample dryer is not used in this verification test, use good engineering judgment to prevent condensation in the transfer lines, fittings, or valves from the point where x H2O is measured to the analyzer. We recommend that you design your system so that the wall temperatures in the transfer lines, fittings, and valves from the point where

x

H2O is measured to the analyzer are at least 5 ° C above the local sample gas dewpoint.

(6) Allow time for the analyzer response to stabilize. Stabilization time may include time to purge the transfer line and to account for analyzer

response.

(7) While the analyzer measures the sample’s concentration, record its output for 30 seconds. Calculate the
arithmetic mean of this data.

(8) The analyzer meets the
interference verification if the result of paragraph (d)(7) of this section meets the tolerance in paragraph (c) of this

section.

(9) You may also run interference procedures separately for individual interference gases. If the interference gas levels used are higher than the maximum levels expected during testing, you may scale down each observed interference value by multiplying the observed interference by the ratio of the maximum expected
concentration value to the actual value used during this procedure. You may run separate interference concentrations
of H 2 O (down to 0.025 mol/mol H 2 O content) that are lower than the maximum levels expected during testing, but you must scale up the
observed H 2 O interference by multiplying the observed interference by the ratio of the maximum expected

H 2 O concentration value to the actual value used during this procedure. The
sum of the scaled interference values must meet the tolerance specified in paragraph (c) of this section.

**Subpart F—[Amended]**

■ 63. Section 1065.550 is amended by revising paragraphs (b) introductory text and (b)(1), adding and reserving paragraph (b)(3), and adding paragraph (b)(4) to read as follows:

**§ 1065.550 Gas analyzer range validation, drift validation, and drift correction.** 

* * * * *

(b) Drift validation and drift

correction. Calculate two sets of brakespecific emission results for each test interval. Calculate one set using the data
before drift correction and calculate the other set after correcting all the data for drift according to § 1065.672. Use the two sets of brake-specific emission results to validate the duty cycle for
drift as follows:

(1) The duty cycle is validated for drift if you satisfy one of the following

criteria:

(i) For each test interval of the duty cycle and for each measured exhaust constituent, the difference between the
uncorrected and the corrected brakeVerDate Nov<24>2008 17:39 Oct 29, 2009 Jkt 220001 PO 00000 Frm 00257 Fmt 4701 Sfmt 4700 E:\FR\FM\30OCR2.SGM 30OCR2sroberts on DSKD5P82C1PROD with RULES

### 56516 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

specific emission values over the test
interval is within ±4% of the uncorrected value or applicable emission standard, whichever is greater. This requirement also applies for CO 2 , whether or not an emission standard applies for CO 2 . Where no emission standard applies for CO 2 , the difference
must be within ±4% of the uncorrected value. See paragraph (b)(4) of this
section for exhaust constituents other
than CO 2 for which no emission standard applies.

(ii) For the entire duty cycle and for each regulated pollutant, the difference
between the uncorrected and corrected composite brake-specific emission values over the entire duty cycle is
within ±4% of the uncorrected value or the applicable emission standard, whichever is greater. Note that for purposes of drift validation using composite brake-specific emission values over the entire duty cycle, leave unaltered any negative emission results over a given test interval (i.e., do not set them to zero). A third calculation of composite brake-specific emission values is required for final reporting. This calculation uses drift-corrected mass (or mass rate) values from each test interval and sets any negative mass (or mass rate) values to zero before calculating the composite brake-specific emission values over the entire duty cycle. This requirement also applies for

CO 2 , whether or not an emission standard applies for CO 2 . Where no emission standard applies for CO 2 , the
difference must be within ±4% of the uncorrected value. See paragraph (b)(3)
of this section for exhaust constituents
other than CO 2 for which no emission standard applies.

* * * * *

(3) [Reserved] (4) The provisions of paragraph (b)(3) of this section apply for measurement of pollutants other than CO 2 for which no emission standard applies. You may use
measurements that do not meet the drift validation criteria specified in paragraph (b)(1) of this section. For example, this allowance may be appropriate for measuring and reporting very low concentrations of CH4 and N 2 O as long as no emission standard applies for these compounds. **Subpart G—[Amended]**

■ 64. Section 1065.601 is amended by revising paragraph (a)(1) to read as
follows:

**§ 1065.601 Overview.**

(a) * * * (1) Use the signals recorded before, during, and after an emission test to calculate brake-specific emissions of
each measured exhaust constituent.

* * * * *

■ 65. Section 1065.660 is amended by revising paragraphs (a), (b) introductory text, (b)(1), (b)(2), and (b)(3) introductory text, and adding paragraph (c) to read as follows:

**§ 1065.660 THC, NMHC, and CH** 4 **determination.**

(a) THC determination and THC/CH 4 initial contamination corrections. (1) If we require you to determine THC emissions, calculate x THC[THC–FID]cor using the initial THC contamination

concentration x THC[THC

¥ FID]init from § 1065.520 as follows:



### xx x

THC[THC-FID]cor THC[THC-FID]uncor THC[THC-FID] init 

### Eq. = − 1 065.660-1

Example:

x

THCuncor = 150.3 μmol/mol

x

THCinit = 1.1 μmol/mol

x

THCcor = 150.3

¥ 1.1

x

THCcor = 149.2 μmol/mol

(2) For the NMHC determination described in paragraph (b) of this section, correct xTHC[THC–FID] for initial HC contamination using Eq. 1065.660– 1. You may correct xTHC[NMC–FID] for
initial contamination of the CH4 sample train using Eq. 1065.660–1, substituting

in CH 4 concentrations for THC. (3) For the CH4 determination described in paragraph (c) of this section, you may correct xTHC[NMC–FID] for initial contamination of the CH4 sample train using Eq. 1065.660–1, substituting in CH4 concentrations for

THC.

(b) NMHC determination. Use one of the following to determine NMHC concentration, xNMHC :

(1) If you do not measure CH4 , you may determine NMHC concentrations as described in § 1065.650(c)(1)(vi). (2) For nonmethane cutters, calculate

xNMHC using the nonmethane cutter’s penetration fractions (PF) of CH4 and

C 2H 6 from § 1065.365, and using the HC contamination and dry-to-wet corrected

THC concentration xTHC[THC–FID]cor as determined in paragraph (a) of this

section.

(i) Use the following equation for penetration fractions determined using an NMC configuration as outlined in § 1065.365(d):



### x RF

NMHC THC[THC-FID]cor THC[NMC-FID]cor CH4[THC-FID]



### 1 = − ⋅

− x x RF

P F RF C2H6[NMC-FID] CH4[THC-FID] 

### Eq. 1065.660-2

⋅

Where:

x

NMHC = concentration of NMHC.

x

THC[THC–FID]cor = concentration of THC, HC contamination and dry-to-wet corrected, as measured by the THC FID during sampling while bypassing the NMC.

x

THC[NMC–FID]cor = concentration of THC, HC contamination (optional) and dry-to-wet corrected, as measured by the NMC FID during sampling through the NMC. RF CH4[THC–FID] = response factor of THC FID

to CH 4 , according to § 1065.360(d).

RFPF C2H6[NMC–FID] = nonmethane cutter combined ethane response factor and penetration fraction, according to § 1065.365(d). Example:

x

THC[THC–FID]cor = 150.3 μmol/mol

x

THC[NMC–FID]cor = 20.5 μmol/mol

RFPF C2H6[NMC–FID] = 0.019
RF CH4[THC–FID] = 1.05 

### xNMHC 

### = − ⋅

− ⋅ 150 3 20 5 1 05

1 0 019 1 05

. ..

. .

x

NMHC = 131.4 μmol/mol

(ii) For penetration fractions determined using an NMC configuration as outlined in section § 1065.365(e), use the following equation:


### 56517 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

x PF

NMHC THC[THC-FID]cor CH4[NMC-FID]cor THC[NMC-FID]

CH 

### = ⋅ −

x PF x

4 [NMC-FID] C2H6[NMC-FID] 

### Eq. 1065.660-3

− PF

Where:

x

NMHC = concentration of NMHC.

x

THC[THC–FID]cor = concentration of THC, HC contamination and dry-to-wet corrected, as measured by the THC FID during sampling while bypassing the NMC.

PF

CH4[NMC–FID] = nonmethane cutter CH4

penetration fraction, according to § 1065.365(e).

x

THC[NMC–FID]cor = concentration of THC, HC contamination (optional) and dry-to-wet corrected, as measured by the THC FID during sampling through the NMC.

PF

C2H6[NMC–FID] = nonmethane cutter ethane

penetration fraction, according to § 1065.365(e).
Example:

x

THC[THC–FID]cor = 150.3 μmol/mol

PF

CH4[NMC–FID] = 0.990

x

THC[NMC–FID]cor = 20.5 μmol/mol

PF

C2H6[NMC–FID] = 0.020 

### xNMHC 

### = ⋅ −

− 150 3 0 990 20 5

0 990 0 020 .. .

. .

x

NMHC = 132.3 μmol/mol

(iii) For penetration fractions determined using an NMC configuration as outlined in § 1065.365(f), use the following equation:



### xNMHC THC[THC-FID]cor CH4[NMC-FID] THC[NMC-FID]cor C



### = ⋅− ⋅

x PF x RF H 4[THC-FID]

CH4[NMC-FID] C2H6[NMC-FID] CH4[THC-FID 

### PF RFPF RF

− ⋅ ] 

### Eq. 1065.660-4

Where:

x

NMHC = concentration of NMHC.

x

THC[THC–FID]cor = concentration of THC, HC contamination and dry-to-wet corrected, as measured by the THC FID during sampling while bypassing the NMC.

PF

CH4[NMC–FID] = nonmethane cutter CH4

penetration fraction, according to § 1065.365(f).

x

THC[NMC–FID]cor = concentration of THC, HC contamination (optional) and dry-to-wet corrected, as measured by the THC FID during sampling through the NMC.

RFPF C2H6[NMC–FID] = nonmethane cutter CH4 combined ethane response factor and penetration fraction, according to § 1065.365(f). RF CH4[THC–FID] = response factor of THC FID

to CH 4 , according to § 1065.360(d). Example:

x

THC[THC–FID]cor = 150.3 μmol/mol

PF

CH4[NMC–FID] = 0.990

x

THC[NMC–FID]cor = 20.5 μmol/mol

RFPF C2H6[NMC–FID] = 0.019
RF CH4[THC–FID] = 0.980



### xNMHC 

### = ⋅ −⋅

− ⋅ 150 3 0 990 20 5 0 980

0 990 0 019 0 980 .. ..

. ..

x

NMHC = 132.5 μmol/mol

(3) For a gas chromatograph, calculate

xNMHC using the THC analyzer’s response factor (RF) for CH4 , from § 1065.360, and the HC contamination and dry-to-wet corrected
initial THC concentration xTHC[THC–FID]cor as determined in paragraph (a) of this section as
follows:

* * * * *

(c) CH 4 determination. Use one of the following methods to determine CH4 concentration, x CH4 : (1) For nonmethane cutters, calculate x CH4 using the nonmethane cutter’s penetration fractions (PF ) of CH 4 and C 2H 6 from § 1065.365, using the dry-to-wet corrected

CH 4 concentration x THC[NMC–FID]cor as determined in paragraph (a) of this section and optionally using the CH4 contamination correction under paragraph (a) of this section.

(i) Use the following equation for penetration fractions determined using an NMC configuration as outlined in § 1065.365(d):



### xCH4 THC[NMC-FID]cor THC[THC-FID]cor C2H6[NMC-FID]



### = − ⋅

− x x RFPF

1 R FPF RF C2H6[NMC-FID] CH4[THC-FID] 

### Eq. 1065.660-6

⋅

Where:

x

CH4 = concentration of CH4
.

x

THC[NMC–FID]cor = concentration of THC, HC contamination (optional) and dry-to-wet corrected, as measured by the NMC FID during sampling through the NMC.

x

THC[THC–FID]cor = concentration of THC, HC contamination and dry-to-wet corrected, as measured by the THC FID during sampling while bypassing the NMC. RFPF C2H6[NMC–FID] = the combined ethane response factor and penetration fraction of the nonmethane cutter, according to § 1065.365(d).

RF CH4[THC–FID] = response factor of THC FID

to CH 4 , according to § 1065.360(d). Example:

x

THC[NMC–FID]cor = 10.4 μmol/mol

x

THC[THC–FID]cor = 150.3 μmol/mol

RFPF C2H6[NMC–FID] = 0.019 RF CH4[THC–FID] = 1.05



### xCH4 

### = − ⋅

− ⋅ 10 4 150 3 0 019

1 0 019 1 05 . ..

. .

x

CH4 = 7.69 μmol/mol

(ii) For penetration fractions determined using an NMC configuration as outlined in § 1065.365(e), use the following equation:



### x RF

CH4 THC[NMC-FID]cor THC[THC-FID]cor C2H6[NMC-FID]

CH 

### = − ⋅

x x PF

4 [THC-FID] CH4[NMC-FID] C2H6[NMC-FID] 

### Eq. 1065.660-7

⋅ − 

# ( ) PF PF

Where:

x

CH4 = concentration of CH4
.

x

THC[NMC–FID]cor = concentration of THC, HC contamination (optional) and dry-to-wet corrected, as measured by the NMC FID during sampling through the NMC.

x

THC[THC–FID]cor = concentration of THC, HC contamination and dry-to-wet corrected, as measured by the THC FID during sampling while bypassing the NMC.

PF

C2H6[NMC–FID] = nonmethane cutter ethane

penetration fraction, according to § 1065.365(e).

RF CH4[THC–FID] = response factor of THC FID

to CH 4 , according to § 1065.360(d). PF CH4[NMC–FID] = nonmethane cutter CH4

penetration fraction, according to § 1065.365(e). Example:

x

THC[NMC–FID]cor = 10.4 μmol/mol

x

THC[THC–FID]cor = 150.3 μmol/mol

PF

C2H6[NMC–FID] = 0.020

RF CH4[THC–FID] = 1.05


### 56518 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

PF

CH4[NMC–FID] = 0.990



### xCH4 

### = − ⋅

⋅ − 10 4 150 3 0 020

1 05 0 990 0 020 . .. . (. . ) x CH4 = 7.25 μmol/mol

(iii) For penetration fractions determined using an NMC configuration as outlined in § 1065.365(f), use the following equation:



### x RF

PF CH4 THC[NMC-FID]cor THC[THC-FID]cor C2H6[NMC-FID]



### = − ⋅

x x PF

C H4[NMC-FID] C2H6[NMC-FID] CH4[THC-FID] 

### Eq. 1065.660

− ⋅

RF RF PF - 8

Where:

x

CH4 = concentration of CH4
.

x

THC[NMC–FID]cor = concentration of THC, HC contamination (optional) and dry-to-wet corrected, as measured by the NMC FID during sampling through the NMC.

x

THC[THC–FID]cor = concentration of THC, HC contamination and dry-to-wet corrected, as measured by the THC FID during sampling while bypassing the NMC.

RFPF C2H6[NMC–FID] = the combined ethane response factor and penetration fraction of the nonmethane cutter, according to § 1065.365(f).

PF

CH4[NMC–FID] = nonmethane cutter CH4

penetration fraction, according to § 1065.365(f). RF CH4[THC–FID] = response factor of THC FID

to CH 4 , according to § 1065.360(d). Example:

x

THC[NMC–FID]cor = 10.4 μmol/mol

x

THC[THC–FID]cor = 150.3 μmol/mol

RFPF C2H6[NMC–FID] = 0.019
PF

CH4[NMC–FID] = 0.990
RF CH4[THC–FID] = 1.05



### xCH4 

### = − ⋅

− ⋅ 10 4 150 3 0 019

0 990 0 019 1 05

. ..

. ..

x

CH4 = 7.78 μmol/mol

(2) For a gas chromatograph, x CH4 is the actual dry-to-wet corrected CH4 concentration as measured by the analyzer. **Subpart H—[Amended]**

■ 66. Section 1065.750 is amended by revising paragraph (a)(1)(ii) and adding paragraph (a)(3)(xi) to read as follows:

**§ 1065.750 Analytical Gases.**

* * * * *

(a) * * *

(1) * * *
(ii) Contamination as specified in the following table:



### TABLE 

### 1 OF 

### § 1065.750—G ENERAL SPECIFICATIONS FOR PURIFIED GASES



### .

Constituent Purified synthetic air 1 Purified N 2 1

THC (C 1 equivalent) ........................................... ≤ 0.05 μ mol/mol ............................................... ≤ 0.05 μ mol/mol.
CO ...................................................................... ≤ 1 μ mol/mol .................................................... ≤ 1 μ mol/mol.
CO 2

.................................................................... ≤ 10 μ mol/mol .................................................. ≤ 10 μ mol/mol.
O 2 ....................................................................... 0.205 to 0.215 mol/mol ..................................

.. ≤ 2 μ mol/mol.
NO X

.................................................................... ≤ 0.02 μ mol/mol ............................................... ≤ 0.02 μ mol/mol.

N 2 O 2

................................................................... ≤ 0.05 μ mol/mol ............................................... ≤ 0.05 μ mol/mol.

1 We do not require these levels of purity to be NIST-traceable.

2 The N 2 O limit applies only if the standard-setting part requires you to report N 2 O.

* * * * *

(3) * * * (xi) N 2 O, balance purified synthetic

air.

* * * * *

■ 67. Section 1065.1001 is amended by revising the definition for ‘‘Oxides of nitrogen’’ to read as follows:

**§ 1065.1001 Definitions.**

* * * * *

Oxides of nitrogen means NO and

NO 2 as measured by the procedures specified in § 1065.270. Oxides of nitrogen are expressed quantitatively as
if the NO is in the form of NO 2 , such that you use an effective molar mass for all oxides of nitrogen equivalent to that
of NO 2
. * * * * *

■ 68. Section 1065.1005 is amended by revising paragraphs (b), (f)(2), and (g) to
read as follows: **§ 1065.1005 Symbols, abbreviations, acronyms, and units of measure.** 

* * * * *

(b) Symbols for chemical species. This part uses the following symbols for chemical species and exhaust

constituents:

Symbol Species

Ar ................... argon.
C .................... carbon.
CH 4 ................ methane.
C 2 H 6 ............... ethane.
C 3 H 8 ............... propane. C 4 H 10 .............. butane.
C 5 H 12 .............. pentane. CO .................. carbon monoxide.
CO 2 ................ carbon dioxide. H .................... atomic hydrogen.

H 2 ................... molecular hydrogen.

H 2 O ................ water.

He .................. helium.

85 Kr ................ krypton 85.

N 2 ................... molecular nitrogen. Symbol Species

NMHC ............ nonmethane hydrocarbon. NMHCE .......... nonmethane hydrocarbon equivalent.
NO .................. nitric oxide.
NO 2 ................ nitrogen dioxide.
NO X ................ oxides of nitrogen.

N 2 O ................ nitrous oxide. NOTHC .......... nonoxygenated hydrocarbon.
O 2 ................... molecular oxygen. OHC ............... oxygenated hydrocarbon.

210 Po .............. polonium 210. PM .................. particulate mass.
S ..................... sulfur.
SO 2 ................ sulfur dioxide. THC ................ total hydrocarbon.
ZrO 2 ............... zirconium dioxide.

* * * * *

(f) * * * (2) This part uses the following molar
masses or effective molar masses of chemical species:


### 56519 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations

Symbol Quantity g/mol (10

¥ 3. kg

. mol

¥ 1 )

M

air ........................................................... molar mass of dry air ............................................... .................................................. 28.96559
M

Ar ........................................................... molar mass of argon ................................................. ................................................. 39.948
M

C ............................................................. molar mass of carbon .............................................. .................................................. 12.0107
M

CO ........................................................... molar mass of carbon monoxide ....................................... ......................................... 28.0101
M

CO2 ......................................................... molar mass of carbon dioxide .......................................... .......................................... 44.0095
M

H ............................................................ molar mass of atomic hydrogen ...................................... ........................................... 1.00794
M

H2 ........................................................... molar mass of molecular hydrogen .................................... ........................................ 2.01588
M

H2O ......................................................... molar mass of water ................................................... ................................................ 18.01528
M

He ........................................................... molar mass of helium ................................................ ................................................. 4.002602
M

N ............................................................ molar mass of atomic nitrogen ...................................... ............................................. 14.0067
M

N2 ........................................................... molar mass of molecular nitrogen .................................... .......................................... 28.0134
M

NMHC ...................................................... effective molar mass of nonmethane hydrocarbon 2 ................................................. 13.875389
M

NMHCE .................................................... effective molar mass of nonmethane equivalent hydrocarbon 2 ................................ 13.875389
M

NOx ......................................................... effective molar mass of oxides of nitrogen 3 .............................................................. 46.0055
M

N2O ......................................................... effective molar mass of nitrous oxide ................................. ....................................... 44.0128
M

O ............................................................ molar mass of atomic oxygen ........................................ ............................................ 15.9994
M

O2 ........................................................... molar mass of molecular oxygen ...................................... ......................................... 31.9988
M

C3H8 ........................................................ molar mass of propane .................................................. ............................................ 44.09562
M

S ............................................................. molar mass of sulfur .............................................. ..................................................... 32.065
M

THC ......................................................... effective molar mass of total hydrocarbon 2 ............................................................... 13.875389
M

THCE ....................................................... effective molar mass of total hydrocarbon equivalent 2 ............................................. 13.875389

1 See paragraph (f)(1) of this section for the composition of dry air

2 The effective molar masses of THC, THCE, NMHC, and NMHCE are defined by an atomic hydrogen-to-carbon ratio, a , of 1.85

3 The effective molar mass of NOx is defined by the molar mass of nitrogen dioxide, NO 2

* * * * *

(g) Other acronyms and abbreviations. This part uses the following additional abbreviations and acronyms: ASTM American Society for Testing

and Materials. BMD bag mini-diluter. BSFC brake-specific fuel consumption.
CARB California Air Resources Board. CFR Code of Federal Regulations.
CFV critical-flow venturi. CI compression-ignition. CITT Curb Idle Transmission Torque.
CLD chemiluminescent detector. CVS constant-volume sampler.
DF deterioration factor.
ECM electronic control module.
EFC electronic flow control. EGR exhaust gas recirculation. EPA Environmental Protection

Agency. FEL Family Emission Limit FID flame-ionization detector. GC gas chromatograph. GC–ECD gas chromatograph with an

electron-capture detector. IBP initial boiling point. ISO International Organization for

Standardization. LPG liquefied petroleum gas. NDIR nondispersive infrared. NDUV nondispersive ultraviolet. NIST National Institute for Standards

and Technology. PDP positive-displacement pump. PEMS portable emission measurement

system. PFD partial-flow dilution. PMP Polymethylpentene. pt. a single point at the mean value

expected at the standard. PTFE polytetrafluoroethylene

(commonly known as Teflon TM ). RE rounding error. RMC ramped-modal cycle. RMS root-mean square. RTD resistive temperature detector.
SSV subsonic venturi. SI spark-ignition. UCL upper confidence limit.
UFM ultrasonic flow meter.
U.S.C. United States Code.

[FR Doc. E9–23315 Filed 10–29–09; 8:45 am]

**BILLING CODE 6560–50–P**