Page 1 of 265

DRAFT: Please do not cite, quote, or distribute **6560.50**
**ENVIRONMENTAL PROTECTION AGENCY 40 CFR Part 98**  **[ EPA**  **- HQ**  **- OAR**  **- 2009**  **- 0923**  **; FRL -**  **] RIN 2060**  **- AP99**  **Mandatory Reporting of Greenhouse Gases : Petroleum and**  **Natural Gas Systems**
**AGENCY:** Environmental Protection Agency (EPA).
**ACTION:** Final Rule.
**SUMMARY** : EPA is promulgating a regulation to require monitoring and reporting of greenhouse gas emissions from petroleum and natural gas systems . This action adds th is

source category to the list of source categories already required to report greenhouse gas emission s. This action applies to sources with carbon dioxide equivalent emissions above certain threshold levels as described in this regulation. This action does not require control of greenhouse gases.
**DATES:** The final rule is effective on [ INSERT THE
DATE 60 DAYS AFTER PUBLICATION IN THE FEDERAL REGISTER ]. The incorporation by reference of certain publications listed in the rule is approved by the Director of Federal Register as of [ INSERT THE DATE 60 DAYS AFTER PUBLICATION
IN THE FEDERAL REGISTER ].Page 2 of 265

DRAFT: Please do not cite, quote, or distribute **ADDRES SES:**  EPA established a single docket under Docket ID No. EPA

- HQ

- OAR

- 2009

- 0923 for this action
. All documents in the docket are listed on the www.regulations.gov website. Although listed in the index, some information is not publicly available, e.g.,

con fidential business information (CBI) or other information whose disclosure is restricted by statute. Certain other material, such as copyrighted material, is not placed on the i nternet and will be publicly available only in hard copy form. Publicly avail able 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 op en 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

- 1741.
**FOR FURTHER GENERAL INFORMATION CONTACT:** Carole Cook, Climate Change Division, Office of Atmospheric Programs (MC

- 6207J), Environmental Protection Agency, 1200 Pennsylvania Ave., NW, Washington, DC 20460; telephone number: (202) 343

- 9263; fax number: (202) 343

- 2342; e

- mail address: GHGReporting Rule@epa.gov. For technicalPage 3 of 265

DRAFT: Please do not cite, quote, or distribute information and implementation materials, please go to the website www.epa.gov/climatechange/emissions/ghgrulemaking.html
. To submit a question, select Rule Help Center, followed by
Contact Us.
**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 owners or operators of petroleum and natural gas systems. Regulated categories and entities include those listed in Table 1 o f this preamble: **TABLE 1. EXAMPLES O F AFFECTED ENTITIES**  **BY CATEGORY Source Category**  **NAICS Examples of affected facilities** 

**Petroleum and Natural Gas**  **Systems** 486210 Pipeline transportation of natural gas. 221210 Natural gas distribution facilities. 211 Extractors of crude petroleum and natural gas. 211112 Natural gas liquid extraction 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 act ion. Although Table 1 of this preamble lists the types of facilities of which EPA is aware of that could be potentially affected by this action , other types ofPage 4 of 265

DRAFT: Please do not cite, quote, or distribute facilities not listed in the table could also be subject to reporting requirements. To determi ne whether you are affected by this action, you should carefully examine the applicability criteria found in 40 CFR part 98, subpart A as amended by this action. If you have questions regarding the applicability of this action to a particular facility,

co nsult the person listed in the preceding “ **FOR FURTHER**
**GENERAL INFORMATION CONTACT**  ” section. Many facilities that are affected by the final rule have GHG emissions from multiple source categories listed in 40 CFR part 98 . Table 2 of this preamble has been developed as a guide to help potential reporters in the petroleum and natural gas industry affected by this action identify other source categories (by subpart) that they may need to (1) consider in their facility applicability determination, and (2) incl ude in their reporting. Table 2 of this preamble identifies the subparts that are likely to be relevant to sources with petroleum and natural gas systems. The table should only be seen as a guide. Additional subparts in 40 CFR part 98 may be relevant fo r a given reporter. Similarly, not all listed subparts are relevant for all reporters.Page 5 of 265

DRAFT: Please do not cite, quote, or distribute **TABLE 2.**  **SOURCE CATEGORIES AND R**  **ELEVANT SUBPARTS Source C**  **ategory Other Subparts recommended for review**  **to determine applicability**

Petroleum and Natural Gas Systems 40 CFR part 98, subpart C 40 CFR part 98, subpart Y 40 CFR part 98, subpart MM 40 CFR part 98, subpart NN 40 CFR part 98, subpart PP 40 CFR part 98, subpart RR

Under CAA section 307(b)(1), judicial review of this final rule is availab le only by filing a petition for review in the U.S. Court of Appeals for the District of Columbia Circuit by [ INSERT THE DATE 60 DAYS AFTER
PUBLICATION IN THE FEDERAL REGISTER ]. Under CAA section 307(d)(7)(B), 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 **Judicial Review.**Page 6 of 265

DRAFT: Please do not cite, quote, or distribute Petition for Reconsideration to the Office of the Administrator, Environmental Protection Agency, Room 3000, Ariel Rios Building, 1200 Pe nnsylvania Ave., NW., Washington, DC 20004, with a copy to the person listed in the preceding **FOR FURTHER GENERAL**  **INFORMATION CONTACT** section, and the Associate General Counsel for the Air and Radiation Law Office, Office of General Counsel (Mail Code 2344 A), 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.
**Ac r**  **onyms and Abbreviations** 

cf cubic feet **.** The following acronyms and abbreviations are used in this document.
AAPG American Association of Petroleum Geologists AGA American Gas Association AGR acid gas removal ANSI American National Stan dards Institute API American Petroleum Institute ASME American Society of Mechanical Engineers ASTM American Society for Testing and Materials BLS Bureau of Labor Statistics BOEMRE Bureau of Ocean Energy Management, Regulation and Enforcement CAA Clean Air Act CBI confidential business information CBM coal bed methane CEMS continuous emission monitoring systemsPage 7 of 265

DRAFT: Please do not cite, quote, or distribute CFR Code of Federal Regulations CH 4 methane CO 2 carbon dioxide CO 2 e CO 2 - equivalent DOE Department of Energy E&P exploration and produc tion EIA Economic Impact Analysis EO Executive Order EOR enhanced oil recovery EPA U.S. Environmental Protection Agency ESD emergency shutdown FPSO floating production and storage offloading FR Federal Register GHG greenhouse gas GOR gas to oil ratio GRI G as Research Institute GWP global warming potential IBR incorporation by reference ICR information collection request IPCC Intergovernmental Panel on Climate Change IR infrared ISO International Organization for Standardization kg kilograms LACT lease autom atic custody transfer LDCs local natural gas distribution companies LNG liquefied natural gas LPG liquefied petroleum gas M&R meters and regulators MMBTU million British thermal units MMS Minerals Management Service mmscfd million standard cubic feet per d ay MMTCO 2 e million metric tons carbon dioxide equivalent MRR mandatory GHG reporting rule N 2 O nitrous oxide NAESB North American Energy Standards BoardPage 8 of 265

DRAFT: Please do not cite, quote, or distribute NAICS North American Industry Classification System NGLs natural gas liquids NTTAA National Technology Transfer and Advancement Act OAQPS Office of Air Quality, Planning and Standards OMB Office of Management and Budget OVA organic vapor analyzer ppm parts per million QA quality assurance QA/QC quality assurance/quality control RFA Regulatory Flexibility Ac t RGGI Regional Greenhouse Gas Initiative RIA Regulatory Impact Analysis SBREFA Small Business Regulat ory Enforcement and Fairness Act SSM startup, shutdown, and malfunction STP standard temperature and pressure TCR The Climate Registry TSD technical suppo rt document TVA toxic vapor analyzer U.S. United States UMRA Unfunded Mandates Reform Act of 1995 USC United States Code USGS United States Geologic Society VOC volatile organic compound(s) WCI Western Climate Initiative
**TABLE OF CONTENTS I. Background**  A. Organization of this Preamble B. Background on the Final Rule C. Legal Authority
**II. Reporting Requirements for Petroleum and Natural Gas**  **Systems**Page 9 of 265

DRAFT: Please do not cite, quote, or distribute A. Overview of Greenhouse Gas Reporting Program B. Overview of Confidentiality Determination for D ata Elements in the Greenhouse Gas Reporting Program C. Summary of Changes to the General Provisions of the Greenhouse Gas Reporting Program D. Summary of the Requirements for Petroleum and Natural Gas Systems (Subpart W) E. Summary of Major Changes and Cl arifications Since Proposal F. Summary of Comments and Responses **III. Economic Impacts of the Rule**
A. How W ere C ompliance C osts E stimated? B. What are the C osts of the R ule? C. What are the E conomic I mpacts of the R ule? D. What are the I mpacts of the R ule on S mall B usinesses? E. What are the B enefits of the R ule for S ociety? **IV. 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: FederalismPage 10 of 265

DRAFT: Please do not cite, quote, or distribute 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

In come Populations K. Congressional Review Act **I. Background**

T his preamble consists of four sections. The first section provides a brief history of 40 CFR part 98 and describes the purpose and legal authority for this act ion. A. Organization of t his Preamble

The second section of this preamble summarizes the revisions made to the general provisions in 40 CFR part 98, subpart A and outlines the specific requirements for subpart W being incorporated into 40 CFR part 98 by this action. It also describes the major changes made to this source categor y since proposal and provides a brief summary of significant public comments and EPA’s responses on issues specific to each industry segment
.Page 11 of 265

DRAFT: Please do not cite, quote, or distribute The third section of this preamble provides the summary of the cost impacts, economic impacts, and benefits of the final rule and discusses comments on the economic impact analyses for subpart W
. Finally, the last section discusses the various statutory and executive order requirements applicable to this rulemaking.

On April 12, 2010, EPA proposed this rule, amend ing 40 CFR part 98 (i.e., the regulatory requir ements for the Greenhouse Gas Reporting Program ). The GHG Reporting Program requires reporting of GHG emissions and other relevant information from certain source categories in the United States. The G reenhouse Gas (GHG) Reporting Program, which became ef fective on December 29, 2009, includes reporting requirements for facilities and suppliers in 32 subparts
. EPA established this program in response to the fiscal year 2008 Consolidated Appropriations Act B. Background on the Final Rule This action, finalizes monitoring and reporting requirements for the following source category: petroleum and natural gas systems.

1

1 Consolidated Appropria tions 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 and 2010 Appropriations Acts (Consolidated Appropriations Act, 2009, Pub. L/ 110

- 329, 122 Stat. . This ActPage 12 of 265

DRAFT: Please do not cite, quote, or distribute authorized funding for EPA to develop a nd publish a rule “...to require the mandatory reporting of greenhouse gas emissions above appropriate thresholds in all sectors of the economy of the United States.” An accompanying joint explanatory statement directed EPA to “use its existing authority un der the Clean Air Act” to develop a mandatory GHG reporting rule. For more detailed background information on the GHG Reporting Program, see the preamble to the final rule establishing the GHG Reporting Program (74 FR 56260, October 30, 2009). This final action add s requirements for facilities that contain petroleum and natural gas systems to report equipment leaks and vented GHG emissions (subpart W) to the GHG Reporting Program
. The rule applies to facilities in specific segments of the petroleum and n atural gas industry that emit GHGs greater than or equal to 25,000 metric tons of CO 2

35 74

- 3716 and Consolidated Appropriations Act, 2010, Pub. L. 111

- 117, Stat. 3034

- 3408). equivalent per year. Th ese data will inform EPA’s implementation of CAA section 103 (g) regarding improvements in sector based non

- regulatory strategies and technologies for preventing or reducing air pollutants , and inform policy on possible regulatory actions to address greenhouse gas emissions
. As stated above, this rule was proposed by EPA on April 12, 2010. One public hearing wasPage 13 of 265

DRAFT: Please do not cite, quote, or distribute held in April 2010, and the sixty d ay public comment period ended June 11, 2010.

EPA is finalizing 40 CFR part 98, subpart W under the existing CAA authorities provided in CAA section 114. As discussed in detail in Sections I.C and II.Q of the preamble to the 2009 fina l rule (74 FR 56260, October 30, 2009), CAA s ection 114(a)(1) provides EPA with broad authority to require emissions sources, persons subject to the CAA, manufacturers of process or control equipment, or persons whom the Administrator believes may have nec essary 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. EPA may gather information for a variety of purposes, including for the purpose of assisting in the development of emissions reduction regu la tions in the petroleum and natural gas industry , determining compliance with implementation plans or such standards, or more broadly for “carrying out any provision” of the CAA. Section 103 of the CAA authorizes EPA to establish a national research and development program, including non

- regulatory approaches and technologies, for the prevention and control of air pollution, including GHGs. As discussed in the proposal C. Legal AuthorityPage 14 of 265

DRAFT: Please do not cite, quote, or distribute (7 5 FR 18608 , April 1 2 , 20 10 ), among other things, data from petroleum and natural gas systems will inform decisions about possible emissions reduction regulations in the petroleum and natural gas industry . The data collected will also inform EPA’s implementation of CAA section 103(g) regarding improvements in sector based non

- regulatory strategies and technologies for preventing or reducing air pollutants.
EPA has the authority under the Clean Air Act to collect emissions information from offshore petroleum and natural gas platforms including those located in areas of the Western Gulf
. This final action does not regulate GHG emissions; rather it gathers information to inform EPA’s evaluation of various CAA provisions. Moreover, EPA’s authority under CAA Section 114 is broad, and ex tends to any person “who the Administrator believes may have information necessary for the purposes” of carrying out the CAA, even if that person is not subject to the CAA. Indeed, by specifically authorizing EPA to collect information from both persons s ubject to any requirement of the CAA, as well as any person who the Administrator believes may have necessary information, Congress clearly intended that EPA could gather information from a person not otherwise subject to CAA requirements. EPA isPage 15 of 265

DRAFT: Please do not cite, quote, or distribute comprehe nsively considering how to address climate change under the CAA, including both regulatory and non

- regulatory options
. The information from offshore platforms will inform our analyses, including options applicable to emissions of any offshore platforms th at EPA is authorized to regulate under the CAA.
**II. Reporting Requirements for Petroleum and Natural Gas**  **Systems** A. Overview of Greenhouse Gas Reporting Progra m The GHG Reporting Program requires reporting of GHG emissions and other relevant information from certain source categories in the United States , as discussed in section I.B. of this preamble. The rule requires annual reporting of GHGs including carbon dioxide (CO 2 ), methane (CH 4 ), nitrous oxide (N 2 O), hydroflu o rocarbons (HFCs), perfluorocarbons (PFCs), sulfur hexafluoride (SF 6

Th e GHG R eporting Program requires that source categories subject to 40 CFR part 98, monitor and report GHGs in accordance with the methods specified in t he individual subparts
. For a list of the specific GHGs to be reported and the GHG calculation procedures, monitoring, missing data procedures, recordkeeping, and reporting ), and other fluorinated compounds (e.g., hydroflu o roethers (HFEs)).Page 16 of 265

DRAFT: Please do not cite, quote, or distribute required by facilities subject to subpart W included in this action, see Section I I.C of this preamble.
B. Overview of Confidentiality Determination for Data Elements in the Greenhouse Gas Reporting Program This final rule does not address whether data reported under subpart W will be released to the public or will be treated as conf idential business information. EPA published a proposed rule and confidentiality determination on July 7, 2010 (75 FR 39094) which addressed this issue. In that action, EPA proposed which specific data elements would be released to the public and which w ould be treated as confidential business information. EPA received several comments on the proposal, and is in the process of considering these comments. A final rule and determination will be issued before any data is released, and the final determinati on will include all of the data elements under subpart W. C. Summary of Changes to the General Provisions of the Greenhouse Gas Reporting Program This final action amends certain requirements in 40 CFR part 98, subpart A (General Provisions). These amendm ents are summarized in this section of the preamble. Changes to Applicability
. In this final action, EPA is amending Table A

- 4 referenced in 40 CFR 98.2(a)(2) toPage 17 of 265

DRAFT: Please do not cite, quote, or distribute include the petroleum and natural gas systems source category. In addition, EPA is amending 40 CFR 98.2(a) so that 40 CFR Part 98 applies to facilities located in the United States and on or under the Outer Continental Shelf
. This revision is necessary to ensure that any petroleum or natural gas platforms located on or under the Outer Continenta l Shelf of the United States will be required to report under this rule
. Changes to Definitions
. In this final action, EPA is also amending 40 CFR 98.6 (definitions). EPA is revising the definition of United States as applied under the rule to clarify that it includes the territorial seas. Other facilities located offshore of the United States covered by the GHG Reporting Program at 40 CFR part 98 may also be affected by this change in the definition of United States (for example, subpart s RR and UU I njection and Geologic Sequestration of CO 2 ). In addition to the change to the definition of United States, EPA has amended 40 CFR 98.6 by adding a definition of “Outer Continental Shelf.” This definition is drawn from the definition in the U.S. Code
. Th ese revisions are necessary to ensure that facilities on land, in the territorial seas, or on or under the Outer Continental Shelf, of the United States, and that otherwisePage 18 of 265

DRAFT: Please do not cite, quote, or distribute meet the applicability criteria of the rule are required to report . Incorporation by Reference (IBR)
. In the April 2010 proposal, EPA proposed to amend § 98.7 by including the following standard methods : GRI GlyCalc software, the E&P Tank software, and the American Association of Petroleum Geologist (AAPG) Geologic Provinces Code Map. EPA has revised the listing of proposed methods for incorporation by reference. Hence, in this final action EPA is finalizing those amend ments to 40 CFR 98.7 (incorporation by reference) to inc lude standard methods referenced in 40 CFR part 98, subpart W
. Those include: American Association of Petroleum Geologists Geologic Provinces Code Map including the Alaska Geological Province Boundary Map; Energy Information Administration Oil and Gas Field Code Master List; and Year 2005 Gulfwide Emission Inventor y Study. D. Summary of the Requirements for Petroleum and Natural Gas Systems (subpart W) 1. Summary of the Final Rule Source Category Definition
. This source category consists of the following segments of the petroleum and natural gas systems s ource cat egory :Page 19 of 265

DRAFT: Please do not cite, quote, or distribute  Offshore petroleum and natural gas production

 . Offshore petroleum and natural gas production is any platform structure, affixed temporarily or permanently to offshore submerged lands, that houses equipment to extract hydrocarbons from the ocean or lake floor and that processes and/or transfers such hydrocarbons to storage, transport vessels, or onshore
. In addition, offshore production includes secondary platform structures connected to the platform structure, storage tanks associated with the pla tform structure , and floating production and offloading equipment (FPSO). Onshore petroleum and natural gas production
.

 Onshore petroleum and natural gas production equipment means all structures associated with wells (including compressors, generators, o r storage facilities), and portable non

- self

- propelled equipment (including well drilling and completion equipment, workover equipment, gravity separation equipment, auxiliary non

transportation

- related equipment, and leased, rented or contracted equipment ) used in the production, extraction, recovery, lifting, stabilization, separation or treating of petroleum and/or natural gas (including condensate). This also includes associated storage or measurement and all enhanced oil recovery (EOR) operations usin g CO2, and all petroleum and natural gas production located on islands, artificial islands, or structures connected by a causeway to land, an island, or artificial island. Onshore natural gas processing plants . Natural gas processing plants are designed t o separate and recover natural gas liquids (NGLs) or other non

- methane gases and liquids from a stream of produced natural gas through equipment performing one or more of the following processes: oil and condensate removal, water removal, separation of na tural gas liquids, sulfur and carbon dioxide removal, fractionation of NGLs, or other processes, and also the capture of CO 2

 separated from natural gas streams for delivery outside the facility. This segment also includes all residue gas compression equip ment owned or operated by the natural gas processing plant, whether inside or outside the processing plant fence. Onshore natural gas transmission compression
. Onshore natural gas transmission compression includes any fixed combination of compressors that move natural gasPage 20 of 265

DRAFT: Please do not cite, quote, or distribute at elevated pressure from production fields or natural gas processing facilities, in transmission pipelines, to natural gas distribution pipelines, or into storage. In addition, transmission compressor station s include equipment for liqu ids separation, natural gas dehydration, and tanks for the storage of water and hydrocarbon liquids
. Residue (sales) gas compression operated by Natural Gas Processing Facilities are included in the processing segment and excluded from this segment .
 Under ground natural gas storage

 . Underground natural gas storage includes subsurface storage, including depleted gas or oil reservoirs and salt dome caverns utilized for storing natural gas that has been transferred from its original location for the primary p urpose of load balancing (the process of equalizing the receipt and delivery of natural gas); natural gas underground storage processes and operations (including compression, dehydration and flow measurement, and excluding transmission pipelines); and all the wellheads connected to the compression units located at the facility. Liquefied natural gas (LNG) storage

 . LNG storage includes onshore LNG storage vessels located above ground, equipment for liquefying natural gas, compressors to capture and re

- lique fy boil

- off

- gas, re - condensers, and vaporization units for re

gasification of the liquefied natural gas. LNG import and export facilities

 . LNG import equipment includes all onshore or offshore equipment that receives imported LNG via ocean transport, stor es LNG, re

- gasifies LNG, and delivers re

- gasified natural gas to a natural gas transmission or distribution system. LNG export equipment means all onshore or offshore equipment that receives natural gas, liquefies natural gas, stores LNG, and transfers th e LNG via ocean transportation to any location, including locations in the United States. Natural Gas Distribution
. Natural gas distribution includes the distribution pipelines (not interstate pipelines or intrastate pipelines) and metering and regulating equipment at city gate stations , and excluding customer meters, that physically deliver natural gas to end users and is operated by a Local Distribution Company (LDC) that is regulated as a separate operating company by a public utilityPage 21 of 265

DRAFT: Please do not cite, quote, or distribute commission or that is operated as an independent municipally

- owned distribution system
. This segment excludes customer meters and infrastructure and pipelines (both interstate and intrastate) delivering natural gas directly to major industrial users and "farm taps" upstrea m of the local distribution company inlet. Facilities from the following segments: 1) offshore petroleum and natural gas production, 2) onshore natural gas processing plants, 3) onshore natural gas transmission compression, 4) underground natural gas stor age, 5) LNG storage, 6) LNG import and export equipment, and 7 )

_ natural gas distribution facilities, that meet the applicability criteria in the General Provisions (40 CFR 98.2(a)(2) ) and summarized in section II.C. of this preamble must report GHG emissi ons . For facilities assessing their applicability in the o nshore petroleum and natural gas production segment (as defined in 98.238), they must include only emissions from equipment , as specified in
98. 232(c), to determine if they exceed the 25,000 metric
ton CO2e threshold and thus are required to report their GHG emissions
. For other segments, facilities would assess applicability based on all source categories for which methods are provided in the GHG Reporting Program. GHGs to Report
. Facilities mus t report :Page 22 of 265

DRAFT: Please do not cite, quote, or distribute  Carbon dioxide (CO 2 ) and methane (CH 4

 CO ) emissions from e quipment leak s and vent s . 2 , CH 4 , and nitrous oxide (N 2

 CO O) from combustion
2, CH 4, and nitrous oxide (N 2 O) emissions from combustion at flares
. GHG Emissions Calculation and Monitoring
. The petroleum and natural gas source category consist s of several segments (.e.g, onshore production, natural gas processing, etc). Within those segments, t here are different types of emissions sources , some of which appear in multiple segments (e.g., e.g., pneumatic devices, blowdown vents , etc. ).

_ Subpart W provides methodologies for calculating emissions from each source type . Table W

- 3 below, summarizies those source types and indicates the ir applicable segments . After the table, there are summari es of the different methodologies reporters must use to monitor and calculate their GHG emissions from each emissions source
. It is important to note, as detailed in section II. F. of this preamble, f or specified time periods during the 2011 data collec tion year, reporters may use best available monitoring methods for certain emissions sources
. **Table W -**  **3. Summary of Source Type in Each Industry Segment**Page 23 of 265

DRAFT: Please do not cite, quote, or distribute **Source Type**  **Onshore Product**  **ion Natural**  **Gas Process**  **ing Natural**  **Gas Transmissi**  **on Compressio**  **ns Under**  **grou n**  **d Stora**  **ge LNG**  **Storage LNG**  **Import and**  **Export Equipme**  **nt Distrib**  **ution**

Natural gas pneumatic device venting X X X

Natural gas driven pneumatic pump venting X

Well venting for liquids unloading X

Gas well venting dur ing well completion s without hydraulic fracturing X

Gas well venting during well completion s with hydraulic fracturing X

Gas well venting during well workovers without hydraulic fracturing X

Gas well venting during well workovers with hydraulic fracturing X

Onshore XPage 24 of 265

DRAFT: Please do not cite, quote, or distribute production storage tanks Transmissi on storage tanks X
Reciprocat ing compressor rod packing venting X X X X X X

Well testing venting and flaring X

Associated gas venting and flaring X

Dehydrator vent stacks X X

Enhanced Oil Recovery injection pump blowdown X

Acid gas removal vent stack X X

Enhanced Oil Recovery hydrocarbo n liquids dissolved CO2 X

Centrifuga l compressor wet seal degassing venting X X X X X X

Other emissions from equipment leaks X X X X X X

Blowdown vent stacks X X X XPage 25 of 265

DRAFT: Please do not cite, quote, or distribute  Summary of Methodologies for Each Source Type in Table
W

- 3 Natural gas pneumatic device venting : Calculate CO 2 and CH 4

 emissions from natural gas pneumatic devices using component count for each type ( i.e. continuous high bleed, continuous low bleed, and intermittent bleed) togeth er with a population emission factor for each type from Tables W

- 1A, W

- 1D, W

- 3, and W

- 4. Natural gas driven pneumatic pump venting : Calculate CO 2 and CH 4

 emissions using component count of natural gas pneumatic pump s together with a population emission fac tor from Table W

- 1A. Acid gas removal (AGR) vent stacks : Calculate CO 2 emissions using metered flow and volume weighted CO 2 content of natural gas flowing into the AGR unit
. The approaches available to measure the volume weighted CO 2 Flare stacks

content include using a continuous gas analyzer or sampling the gas quarterly. X X Above ground meters re gulators at city gate station equipment leaks X

Below ground meter and regulator station equipment leaks X

Pipeline main equipment leaks X

Service line equipment leaks XPage 26 of 265

DRAFT: Please do not cite, quote, or distribute  Dehydrator vent stacks
. Calculate CH 4 and CO 2

 For glycol dehydrators with a throughput greater than or equal to 0.4 million standard cubic f eet per day u se a software program to calculate emissions
. The software program must determine the equilibrium coefficient using the Peng

Robinson equation of state, speciate CH emissions using the following calculation methodologies:

4 and CO 2

 For glycol dehydrators with a throughput less than 0.4 million standard cubic feet per day u se daily flow rate of wet natural gas together with an emissi on factor to calculate CO emissions from dehydrators, and have provisions to include regenerat or control devices, a separator flash tank, stripping gas, and gas injection pump or gas assist pump.

2 and CH 4

 For d esiccant dehydrators , calculate the amount of gas vented from the vessel every time it is depressurized for desiccant repla cement . This involves knowing the dimensions of the dehydrator and percent of the vessel that is packed with desiccant. emissions
. There are separate emission factors for dehydrator units with a gas assist pump.

 Well venting for liquids unloading : Calculate CO 2 and CH 4

 Determine the average gas flow using a meter on the vent line. A new average flow rate must be calculated every other year starting in the first calendar year of reporting. Use the total venting time during the year together with the gas flow rate t o determine the gas vented during liquid unloading. emission s using either of the following calculation methodologies (the same m ethodology must be used for the entire duration of the calendar year).

 Determine the casing dimension, the shut

- in pressure, sales flow rate and hours that the well was left open to the atmosphere to calcul ate the volume of gas emitted during liquid unloading.

 Gas well venting during well completions and workovers from hydraulic fracturing : Calculate CO 2 and CH 4 emissions using the cumulative vent time during the year and the flow rate of gas vented , sepa rately for both completions and workovers. Use either of thePage 27 of 265

DRAFT: Please do not cite, quote, or distribute following methodologies to determine the flow rate of the gas
.

 D etermine the flow rate of vented gas from both one well during a well completion , and also one well workover event , using a mete r installed on the vent line
. A flow rate determined from a well during a well completion can be applied to all wells in the same field that undergo a completion. A flow rate determined from a well during a well workover can be applied to all wells in th e same field that undergo a workover. A field

- level emissions factor must be developed every two years starting in the first calendar year of reporting.

- Measure the pressure before and after the well choke for both one well during a well completion , a nd a lso one well workover event. A flow rate determined from a well during a well completion can be applied to all wells in the same field that undergo a completion. A flow rate determined from a well during a well workover can be applied to all wells in the same field that undergo a workover
. The flow rate must be determined in the first year of every two year period.

 Gas well venting during well completions and workovers without hydraulic fracturing : Calculate CO 2 and CH 4

 emissions using the cumulative vent time during the year and average daily gas production. Blowdown vent stacks
. Calculate CH 4 and CO 2 emissions from blowdown vent stacks by calculating the total volume of equipment and vessels blown down between isolation valves. This includes the v olume of all piping, compressor cases or cylinders, manifolds, suction and discharge bottles or any other gas

containing volume contained between the valves. Total volumes between isolation valves of process vessels less than 5,000 cubic feet do not have to be reported
. The total volume contained between isolation valves for each process vessel and the number of times it was blowndown in the calendar year equals the actual volume of emissions, which are then converted to volumes at standard conditions and greenhouse gas emissions using the concentration of CH 4 and CO 2 in the applicable stream. For process vessels blowndown to a flare, calculate the volume of emissions the same asPage 28 of 265

DRAFT: Please do not cite, quote, or distribute if they were not flared, then use that volume as an input parameter in the f lare stacks section to estimate combustion emissions.

 Onshore production storage tanks: Calculate CH 4 and CO 2

 For tanks with separator and well production throughput greater than or equal to 10 barrels per day, use a software program that use s the Peng

- Robinson equation of state, models flashing emissions, and speciates CH emissions using one of the following calculation methodologies:

4 and CO 2

 For tanks with separator and well production throughput greater than or equal to 10 barrels per day you may a ssume all of the CH emissions from tanks
. The low pressure separator oil composition and Reid vapor pressure can be determined using the default values within the software program , or using a representative sample analysis.

4 and CO 2

 For throughput less than 10 barrels per day use a population emission factor together with the flow rate . Account for occurrences wh en the dump valve is improperly open , by determining the number of hours the dump valve is open and scale the emissions upwards using the correction factor. The number of hours the dump valve is open can be determined using the maintenance or operations r ecords. It should be a ssume d that if a dump valve is found open, that it was open from either the beginning of the calendar year , or since the most recent maintenance or operations record confirming proper closure of the dump valve
. Assume that a dump va lve is improperly open until there is a maintenance or operations record showing that the dump valve is closed or to the end of the calendar year
. in the low pressure oil s eparator is emitted
. The low pressure separator oil composition shall be determined using an appropriate sample analysis
.

 Transmission storage tanks . For transmission storage tanks, reporters must monitor the tank vapor vent sta ck using an optical gas imaging instrument, to view the emissions for 5 minutes. If the vent stack emits continuously over th at time period, then the reporter must use a meter to measure the flow rate of the ventPage 2 9 of 265

DRAFT: Please do not cite, quote, or distribute to determine emissions. If a tank is vent ed to a flare, then use the onshore petroleum and natural gas production storage tanks methodology option 1 (simulation) to estimate the volume and composition of vapors flared. Then use the flare stacks methodology to estimate the emissions.

 Associated g as venting and flaring
. Calculate CH 4 and CO 2

 emissions from associated gas venting and flaring by multiplying available data from production records on the gas

- oil ratio for produced hydrocarbon liquids , by the volume of liquids produced in the calendar year . If gas

- oil ratios are not readily available, use a sample analysis to determine gas

- oil ratios. For the calculated associated gas volume that is flared, use the method set forth for flare stacks to estimate the emissions. Flare stacks
. Calculate C H 4 and CO 2

Where methodologies for other sources in subpart W refer to this methodology in order to estimate flaring emissions , use the estimated volume of flared gas from those sources as the gas to flare volume in this methodology , and report those emissions under those sources. Calculate N emissions from flare stacks by metering or using engineering estimation to determine the volume of gas sent to the flare, and the gas composition to then estimat e the portion that is combusted and the portion that is not combusted , using the fla re efficiency.

2

 O from flare stacks using the gas to flares in the calendar year , and multiplying it by an emission factor
. Centrifugal compressor wet seal venting
. Calculate CH 4 and CO 2 emissions from wet seal oil degassing vents in onshore petroleum and natural gas production by counting the total population of centrifugal compressors and multiplying it by appropriate emission factors. Calculate CH 4 and CO 2 emissions from centrifugal compressor blowdown valves, wet seal deg assing, and unit isolation valves (see Table W

- 4 ) found in onshore natural gas processing, onshore natural gas transmission compression, underground natural gas storage, LNG storage, and LNG import and export equipment by :Page 30 of 265

DRAFT: Please do not cite, quote, or distribute  Measur ing venting from blowdown v alves when the compressor is found in the operating mode using a meter.

 Measuring wet seal degassing vent ing when the compressor is found in the operating mode using a meter.

 Measur ing venting from unit isolation valves when the compressor is found in not operating, depressurized mode using a meter. If the sources above are vented through a common manifold, you must measure each vent source separately . Determine average emissions from each mode of operation by summing the emissions from each source in each mode and dividing it by the total population measured. The result will be a n emission factor per compressor per hour for each mode of operation. Multiply each emission factor by the total number of compressor

- hours in each mode of operation. Reporters are not required to shutdown compressors to conduct measurements. The owner or operator must schedule an a nnual measurement of each compressor and the owner or operator can take the measurement in the mode in which the compressor is found during the annua l measurement. H owever, the owner or operator must conduct at least one measurement of each compressor in the no t operating, depressurized mode at any time during the three calendar year s . Please see “As

- is Compressor Mode Emissions Monitoring,” Docket E PA

- HQ

- OAR

- 2009

- 0923. **Table W -**  **4 .**  **Summary of Emission Factor Categories for Centrifugal Compressor Venting.** 

**Component Operating Mode**  **Operating Not Operating**  **– Depressurized**  Blowdown Valve Individual Factor Not Applicable Wet Seal Oil Degassing Vent Ind ividual Factor Not Applicable Unit Isolation Valve Not Applicable Individual Factor

 Reciprocating compressor rod packing venting
. Calculate CH 4 and CO 2 emissions from reciprocating compressor rod packing venting in onshore petroleumPage 31 of 265

DRAFT: Please do not cite, quote, or distribute and natural gas production by counting the total population of reciprocating compressors and multiplying it by the emission factors provided in §98.233(p)(10). Calculate CH 4 and CO 2

 Measur ing venting from blowdown valves when the compressor is fou nd in operating and standby pressurized mode s using a meter. emissions for reciprocating compressor blowdown valves, rod packing, and unit isolation v alves (see Table W

- 5 ) from onshore natural gas processing, onshore natural gas transmission compression, underground natural gas storage, LNG storage, and LNG import and export equipment by:

 Measur ing rod packing vents when the compressor is found in operating and standby pressurized modes using a meter. If there is not a vent line, a rigorous approach of scanning for all potential leakage paths for the gas must be used with a meter, high volume sampler, or calibrated bag as appropriate.

 Measur ing venting from unit isolation valves using a meter when the compressor is found in not operating, depressurized mode. If the sources above a re vented through a common manifold, you must measure each vent source separately . Determine average emissions from each mode of operation by summing the emissions from each source in each mode and dividing it by the total population measured. The result will be a n emission factor per compressor per hour for each mode of operation. Multiply each emission factor by the total number of compressor

- hours in each mode of operation. Reporters are not required to shutdown compressors to conduct measurements. The owner or operator must conduct a n annual measurement of each compressor, and measure the compressor in the mode as it found during the annual measurement
. The owner or operator must then conduct the measurement in the mode in which the compressor is f ound. However, the owner or operator must conduct at least one measurement of each compressor in the not operating, depressurized mode at one time during the three calendar year s . Please see “As

- is Compressor Mode Emissions Monitoring,” Docket EPA

- HQ

- OAR

- 2009

- 0923.Page 32 of 265

DRAFT: Please do not cite, quote, or distribute **Table W -**  **5 .**  **Summary of Emission Factor Categories for Reciprocating Compressor Venting.** 

**Component Operating Mode**  **Operating Standby**  **Pressurized Not Operating**  **– Depressurized**  Blowdown Valve Use measurements in either mode to develop combined factor. Not Applicable Rod Packing Seals Individual Factor Individual Factor Not Applicable Unit Isolation Valve Not Applicable Not Applicable Individual Factor

 Leak detection and leaker factors

 Use an optical gas imaging instrument. This method must be us ed for all sources that cannot be monitored without elevating personnel more than 2 meters above a support surface. (onshore natural gas processing, onshore natural gas transmission compression , underground natural gas storage, LNG storage, LNG import export, natural gas distribution)
. Perform a leak detection survey using one of the three following methods:

 Use an infrared laser beam illuminated instrument.

 Use M ethod 21
. Multiply the count of each type of leaking component by the appropriate leaker factors in Tables W

- 2, W

- 3, W

- 4, W

- 5, W

- 6, and W

- 7. Tubing systems less than 1⁄2 inch are exempt from reporting. For natural gas distribution, leak detection is required only for above ground metering and regulating stations (also called “gate stat ions”) at which custody transfer occurs. The leak detection and monitoring requirements prescribed in subpart W do not include customer meters. A ll facilities under this source must conduct at least one leak survey each calendar year
. M ultiple leak surv eys may be conducted in order to account for leak repairs . If multiple surveys are chosen by the owner or operator and performed , each survey must be facility wide.Page 33 of 265

DRAFT: Please do not cite, quote, or distribute  If only one leak survey is conducted in the calendar year , assume that all leaks found emi t for the entire year.

 If multiple leak surveys are conducted, assume that each leak that is found has been emitting since the last survey; or since the beginning of the calendar year . Assume that each leak found continues to emit until the end of the cal endar year after the last leak survey.

 Population count and emission factor . Calculate CH 4 and CO 2

 For onshore petroleum and natural gas production, each component must either be counted individually ; or ma jor equipment pieces must be counted and the n the appropriate average component counts should be applied using Tables W

- 1B, W

- 1C, and W

- 1D. G as composition o f the produced gas must be used to determine the percent of the leaked gas that is CH emissions from the sources listed in §98.233(r).

4 and CO 2

 Fo r underground natural gas storage, the emission factors in Table W

- 4 must be applied to population counts of components on storage wellheads. .

 For LNG storage , the emission factor for vapor recovery compressors , must be applied to the total population count
.

 For LNG import and export equipment, the emission factor for vapor recovery compressors must be applied to the total population count.

 For natural gas distribution, all emissions from above ground custody transfer metering and regulating stations as dete rmined by leak detection surveys must be totaled and then divide d b y the total number of surveyed meter runs to develop and average emission factor for above grade metering and regulating stations. This average emission factor will be multiplied by the to tal number of above ground metering and regulating stations meter runs at which custody transfer does not occur to estimate emissions from those stations. E mission factors in Table W

- 7 will be used to account for equipment leaks in underground meter and r egulation stations and pipelines.Page 34 of 265

DRAFT: Please do not cite, quote, or distribute  Offshore production
. Calculate CH 4 emissions from offshore petroleum and natural gas production facilities using the methods outlined by MMS 2

 For th e first calendar year, use the latest GOADS methodologies. If you have already reported to MMS, report the latest available emissions from GOADS f rom your facility. Gulfwide Emissions Inventory Study, herein after referred to as

“ GOADS. ”

 When a new GOADS methodology is released, perform a survey in accordance with the new meth odology and report the resulting emissions.

 For calendar years between GOADS reporting years, use the latest submission to EPA, but adjust the emissions based on the operating time for each platform by assuming that components not in operation do not emit while not in service.

 If GOADS is delayed or discontinued, then every fourth year the reporter must collect monthly activity data in accordance with the last GOADS methodologies and report the resulting emissions information to EPA.

 EOR Hydrocarbon liquids dissolved CO 2 . Calculate CO 2 emissions downstream of storage tanks from hydrocarbon liquids produced as a result of enhanced oil recovery operations by conducting annual composition sampling of the produced hydrocarbon liquids by taking samples downstrea m of the storage tank. Use the mass of CO 2 from the sample to determine the mass of CO 2

 dissolved in oil beyond storage per barrel of produced liquid hydrocarbons. EOR injection pump blowdown
. Calculate CO 2 emissions from enhanced oil recovery CO 2

2 Minerals Management Service (MMS) has been renamed to the Bureau of Ocean Energy Management, Regulation, and Enforcement (BOEMRE) injec tion pump blowdowns by calculating the volume of gas

- containing structure s between isolation valves, including piping. Maintain logs of the number of blowdowns in the calendar year for each EOR pump. Using an appropriate standard method published by a co nsensus - based standards organization or, if no such standard exists, an industry standard practice, determine the density of the supercritical EOR injection gas. Calculate emissions using the number of blowdowns, the volume ofPage 35 of 265

DRAFT: Please do not cite, quote, or distribute the blown down equipment, th e mass fraction of CO 2

 in the injection gas, the density of the injection gas, and a conversion factor
. Onshore petroleum and natural gas production combustion emissions
. Calculate CO 2

 If the fuel combusted is listed in Table C

- 1 of subpart C, or any blend of the fuels listed, use the Tier 1 methodology of that subpart. combustion emissions from stationary and portable combustion equipment in onshore petroleum and natural gas production using the following methods:

 If the fuel combusted is neither listed i n Table C

- 1 nor a combination of the listed fuels and the fuel is not field gas, then use either the Tier 3 or Tier 4 methodologies of subpart C.

 If the fuel combusted is field gas or a combination of field gas and one or more fuels listed in Table C

- 1, th en use the volume of fuel and the composition of the fuel to calculate CO 2

External fuel combustion sources with a rated heat capacity less than or equal to 5 mmBtu /hour do not have to be reported
. Calculate N emissions
. If meters are installed on the fuel stream, the meter must be used to determine the volume of fuel combusted; otherwise the reporter can estimate that volume using other methods. If a continuous gas analyzer is installed on the fuel stream, the composition reading must be used; otherwise another accepted method to estimate the composition may be used.

2 O emissions from combustion equipment using emission factors and the fuel volume consumed
. The high heat value of the fuel can be estimated using Table C

- 1 if possible. If the fuel is fie ld gas, a default high heat value is provided. If another fuel, not covered by Table C

- 1 or field gas, is used; then the appropriate methodology from subpart C to estimate high heat value must be used. Data Reporting Requirements
. In addition to the info rmation required to be reported by the General Provisions (40 CFR 98.3(c)), reporters must submitPage 36 of 265

DRAFT: Please do not cite, quote, or distribute additional data that are needed for EPA verification of the reported GHG emissions from petroleum and natural gas systems . The specific data to be reported a re found in 40 CFR part 98, subpart W. Recordkeeping
. In addition to the records required by the General Provisions (40 CFR 98.3(g)), reporters must keep records of additional data used to calculate GHG emissions
. These records are described in 40 CFR part 98, subpart W. Definitions

We are also including two distinctive defini tions of facility for onshore petroleum and natural gas production and the natural gas distribution
. Defining a facility in these cases is not as straightforward as other industry segments covered under Subpart W. For some segments of the . EPA added some definitions specific to subpart W to section 98.238 to avoid any confusion with the definitions found in 98.6. The subpart W specific definitions supersede any of the same definitions also found in subpart A. We are including a definition of the term “Offshore” in §98.238 to fully identify those petroleum and natural gas production platforms, secondary platforms and associated storage tanks covered by this rule.Page 37 of 265

DRAFT: Please do not cite, quote, or distribute industry (e.g., onshore natural gas processing, natural gas transmission compression , and offshore petroleum and natural gas production) identifying the facility is clear since there are physical boundaries and ownership structures that lend themselves to identifying sco pe of reporting and responsible reporting entities. However, in onshore petro leum and natural gas production and natural gas distribution such distinctions are more challenging
. As explained in the April 2010 proposal, EPA evaluated existing definitions used under current regulations and determined that it was necessary to define a unique facility for each of those two segments in order to ensure that the reporting delineation is clear, to avoid double counting, and ensure appropriate emissions coverage. For more information p lease see the preamble for the April 2010 proposal and the Greenhouse Gas Emissions from Petroleum and Natural Gas Industry: Background Technical Support Document (EPA

- HQ

- OAR

- 2009

- 0923). First , a s proposed in April 2010, the defini tion of natural gas distribution facility for this subpart is the distribution pipelines, metering stations, and regulating stations that are operated by a Local Distribution Company (LDC) that is regulated as a separate operating company byPage 38 of 265

DRAFT: Please do not cite, quote, or distribute a public utili ty commission or that are operated as an independent municipally

- owned distribution system. This facility definition provides clear reporting delineation because the equipment that they operate is clearly known, the ownership is clear to one company, and reporting at this level is consistent with 40 CFR Part 98 as well as other existing data reporting mechanisms. In this action, EPA is finalizing this definition for the natural gas distribution industry segment. This facility definition for natural gas di stribution will result in 90% GHG emissions coverage of this industry segment. Second, as proposed in April 2010, the definition of

a n onshore petroleum and natural gas production facility for this subpart is all petroleum or natural gas equipment

assoc iated with all petroleum or natural gas production well s and CO 2 EOR operations that are under common ownership or common control including leased, rented, and contracted activities by an onshore petroleum and natural gas production owner or operator and t hat are located in a single hydrocarbon basin as defined in §98.238. Where a person or entity owns or operates more than one well in a basin, then all onshore petroleum and natural gas production equipment associated with all wells that thePage 39 of 265

DRAFT: Please do not cite, quote, or distribute person or entit y owns or operates in the basin would be considered one facility. In the April 2010 proposal , EPA evaluated at least two industry recognized definitions available that identify hydrocarbon basins: one from the United States Geological Survey (USGS) and th e other from the American Association of Petroleum Geologists. Basins are mapped to county boundaries only to give a surface manifestation to the underground geologic boundaries. EPA decided to use the AAPG geologic definition of basin because it is refere nced to county boundaries and hence likely to be familiar to the industry, i.e., if the owner or operator knows in which county their well is located, then they know to which basin they belong. In addition, the owner or operator of the wells within a basin would have access to the information related to the equipment on the permit. Hence, in this action, EPA is finalizing the facility definition at the basin level for the onshore petroleum and natural gas production industry segment because the operational boundaries and basin demarcations are clearly defined and are widely known, and reporting at this level would provide the necessary coverage of GHG emissions to inform policy. In addition, EPA has clarified its intent by stating that onshore petroleum an d natural gas production equipment associated with all petroleum orPage 40 of 265

DRAFT: Please do not cite, quote, or distribute natural gas production wells and CO 2 EOR operations include any leased, rented or contracted ac t ivities by the owner or operat o r of those wells in that basin. This facility definition for onshore petroleum and natural gas production will result in 85% GHG emissions coverage of this industry segment. E. Summary of Major Changes and Clarifications Since Proposal The major changes and clarifications in this rule since the April 2010 proposal are identified in the following list. For a full description of the rationale for these and any other significant changes to 40 CFR part 98, subpart W, see the “Mandatory Greenhouse Gas Reporting Rule: EPA's Response to Public Comments, Subpart W:
Petro leum and Natural Gas Systems.” The changes are categorized by the different sections of the subpart W regulatory text.

 EPA revised the definition for natural gas processing and onshore petroleum and natural gas production to exclude gathering lines and boosting stations from the source category. Definition of the Source Category

 EPA clarified that meters and regulators in the natural gas distribution industry segment do not include customer meters.
GHGs to Report
.Page 41 of 265

DRAFT: Please do not cite, quote, or distribute  EPA removed the reporting requirement s for produced water from coal bed methane(CBM) and enhanced oil recovery (EOR) operations. Monitoring, QA/QC, and Calculating Emissions

 For industry segments where equipment leak detection is required (onshore natural gas processing, onshore natural ga s transmission compression, underg round natural gas storage, LNG storage and LNG import and export equipment , and natural gas distribution facilities ) EPA is including the option to use Method 21 methods and infrared laser beam illuminated instruments to d etect leaks for sources that are accessible. Inaccessible equipment leaks and vented emissions are still required to be monitored using an optical leak imaging instrument
. .

 For applicable industry segments (onshore petroleum and natural gas production, onshore natural gas processing, onshore natural gas transmission compression, underground natural gas storage, and LNG storage and LNG import and export equipment), EPA clarified the monitoring and reporting requirements for centrifugal and reciprocating c ompressors . Reporters are required to conduct an annual measurement of each compressor in the mode in which it is found at the time of the annual measurement. However, based on commenter feedback, EPA requires reporters to conduct at least one measuremen t of each compressor in the not operating, depressurized mode during every three year period. Commenters suggested to EPA that based on their operational experience, 3 years is an appropriate maximum time period at which compressors will be shutdown for r outine maintenance, and for which operators would not need to shutdown compressors specifically for the purposes of monitoring. For more detail, please see EPA

- HQ

- OAR

2009

- 0923

- 1011 excerpt 44.

 EPA clarified reporting requirements and in some cases incl uded alternative data collection methodologies for certain sources to balance burden with data quality and emissions coverage:

 For onshore petroleum and natural gas production, EPA is allowing the use of major equipment counts and default average counts fo r associated components rather than all individual componentPage 42 of 265

DRAFT: Please do not cite, quote, or distribute counts for equipment leak population factors for onshore petroleum and natural gas production.

 For collecting gas composition data for produced natural gas, EPA is allowing reporters to use exis ting sampling data (e.g., composition analysis of gas sold) if reporters do not have a continuous gas composition analyzer already installed.

 EPA is including emission factors for calculating GHG emissions from the following sources: vented GHG emissions from onshore petroleum and natural gas production tanks with less than 10 barrels per day separator and well production throughput; onshore production and natural gas processing dehydrators with less than 0.4 million standard cubic feet per day; vented GHG emissions from all onshore petroleum and natural gas production pneumatic devices and pneumatic pumps, and pneumatic devices in onshore natural gas transmission compression facilities and underground natural gas storage facilities.

 In all industry segment s, for external fuel combustion emissions from portable and stationary equipment wit h heat input less than or equal to 5 mmBtu/hr, only activity data must be reported.

 For reciprocating and centrifugal compressor measurement requirements, EPA clarified tha t the installation of permanent meters is an option but is not required; temporary meters are acceptable.

 EPA is allowing Best Available Monitoring Methods for certain sources and time periods (for more detailed information, refer to section II F of this preamble).

 To assist reporters in determining applicability , EPA is planning to develop screening tools to assist reporters in threshold determination. Applicability
.

This section contains a brief summary of major

c omments and responses. EPA received many comments on this F. Summary of Comments and ResponsesPage 43 of 265

DRAFT: Please do not cite, quote, or distribute subpart covering numerous topics. EPA’s responses to all comments, including those below, can be found in the comment response document for petroleum and natural gas systems in “Mandatory Greenhou se Gas Reporting Rule: EPA’s Response to Public Comments, Subpart W: Petroleum and Natural Gas Systems.” Additional comments and responses related to cost issues on the proposed rule can be located in Section III.B.2 of the preamble. Definition of the Sou rce Category
Comment : Numerous commenters objected to the inclusion of gathering lines and booster stations in the natural gas processing plant definition
. Commenters specifically stated that including gathering lines and booster stations would result in undue burden on reporters stemming from 1) the additional cost to include gathering lines and boosting stations that typically are associated with a single gas processing plant and 2) the numerous complexities and variations of ownership that currently

ex ist with gathering lines and boosting stations
. One commenter further detailed that there are at least three different owner/operator variations that exist ranging from a scenario where a single company owns and/or operates the wells, gathering lines, and processing plant, to a scenario where a single company owns the wells, a second distinctPage 44 of 265

DRAFT: Please do not cite, quote, or distribute company (or multiple companies) own the gathering lines, and a third distinct company may own the processing plant. The commenter further explained that t h ese scenar ios are further complicated because the variations fluctuate daily due to the need to balance production demands for natural gas against the capacity of the gathering lines and the natural gas processing plant. Finally, a number of commenters requested t hat the gathering lines and boost ing stations be excluded from the natural gas processing plant definition or be defined as a separate industry segment. Response : EPA has decided not to include gathering lines and boosting stations as an emissions source i n subpart W at this time
. The primary reason for exclud ing gathering lines and boosting stations at this time is that emissions coverage from gathering lines and boosting stations within the natural gas processing industry segment require s further analy sis to ensure an effective coverage of emissions from this source in order to appropriately inform future policy decision s . As a result, EPA is continuing to review the comments received and the analysis described above, and is considering the most approp riate mechanism for future actions to ensure the collection ofPage 45 of 265

DRAFT: Please do not cite, quote, or distribute appropriate data on gathering lines and boosting stations while minimizing industry burden
. Comment: Several commenters stated that meters and regulators (M&R) were not clearly defined and co uld result in the inclusion of customer meters in the reporting requirements for the natural gas distribution industry segment. Response: EPA did not intend to require reporting of GHG emissions from customer meters in subpart W. In this final action , EP A has clarified its intent to not require reporting of GHG emissions from customer meters. The definition of the natural gas distribution industry segment and the listing of GHGs to report under this industry segment ha ve been refined to make clear what e missions are to be reported for this industry segment
. GHGs to Report
Comment : Numerous commenters argued against the reporting of emissions, specifically combustion emissions , from portable equipment for the onshore petroleum and natural gas industry s egment. Commenters noted that tracking emissions from portable non

- self propelled equipment would result in heavy burden due to the fact that the majority of portable equipment are operated by an entity that is separate from the owner. Further,Page 46 of 265

DRAFT: Please do not cite, quote, or distribute commenter s stated that the reporting of emissions from portable equipment will only marginally increasing coverage of the proposed rule. Some commenters argued that s ubpart C excludes portable equipment from combustion emissions reporting, and questioned why it wa s required for subpart
W. Response

In order to manage the burden, the emissions estimation methods for portable equipment require the use of existing data , for the most part. Moreove r, the allowance of Best Available Monitoring Methods (described later in this preamble) would provide reporters additional time to modify contractual arrangements with service providers
. The decision to retain the reporting requirements for portable equi pment GHG emissions was based on EPA’s analysis of the contribution to GHG emissions, both combustion and process, from portable equipment in onshore production
. It is estimated that portable non : EPA disagrees with commenters and has finalized the reporting requirements for GHG emissions from portable non

- self propelled equipment in subpart W, including emissions from drilling rigs, dehydrators, compressors, ele ctrical generators, steam boilers, and heaters with exte rnal combustion heat duty above five mmBtu/hour.Page 47 of 265

DRAFT: Please do not cite, quote, or distribute self

- propelled equipment is responsible for over 45 percent of total emissions from onshore petroleum and natural gas production ( Please see Docket EPA

- HQ

- OAR

- 2009

- 0923 for the complete analysis). While EPA is not excluding portable equipment, for certain emissions sources, EPA agrees with comments that alternati ve methodologies are appropriate and viable for collecting these data. EPA has conducted an extensive review of the emissions contribution relative to reporting burden and is modifying the final rule to exemp t external combustion equipment that fall below a minimum heat input of 5 mmBtu /hr
. (Please see Docket EPA

- HQ

- OAR

2009

- 0923 for a full report of the analysis). Equipment that fall below the specified mmBtu level would not have to conduct monitoring for combustion emissions, and would only be required to report activity data. Monitoring, QA/QC, and Calculating Emissions
Comment : EPA received numerous comments on the use of the optical gas imaging instrument for detecting GHG emissions from equipment leaks. Several commenters expressed support for th e use of optical gas imaging instruments prescribed in the rule, stating that using this equipment would result in cost savings to industry as it would reduce burden and time by quick survey of all emissions sources at one time. In addition, s everalPage 48 of 265

DRAFT: Please do not cite, quote, or distribute comme nters specifically requested that EPA also allow the use of organic vapor analyzers (OVA), toxic vapor analyzers (TVA) and infrared laser beam illuminated instruments as alternative technologies to the optical gas imaging instruments proposed for emissions detection. Response : EPA has evalu a ted alternative methods for detection of equipment leaks for their viability and comparative accuracy to the optical gas imaging instrument in the proposed rule. We agreed with commenters and have modified the final ru le to include the options to use OVA/TVA devices or infrared laser beam illuminated instruments for leak detection for all emissions sources across all industry segments with the exception of inaccessible sources. We are still requiring that i naccessible s ources use optical gas imaging instruments due to potential safety and cost concerns related to leak detection of sources that cannot be physically accessed from a fixed, supportive surface with a hand held leak detection device such as OVA/TVA, or which d o not have a reflective background for an IR laser detection device.
W hile EPA has determined that the methodologies in this rule are viable and appropriate for collecting this type of GHG data, EPA will continue to evaluate other potentialPage 49 of 265

DRAFT: Please do not cite, quote, or distribute methods for de tecting methane emissions in the petroleum and natural gas sector 3

. Comment : Numerous commenters disagreed with EPA ’s assessment of the feasibility of conducting one measurement for each reciprocating or centrifugal compressor in each of the operational modes (operating, stand b y depressurized, not operating/pressurize d ) that would occur during a calendar year
. Commenters specifically stated that common industry practice is to have a compressor in operating mode for several years before it is taken offli ne for routine maintenance and servicing, thereby taking a compressor offline for the sole purpose of measurement as prescribed in the rule would result in undue burden to the industry and result in additional GHG emissions. Response

3 W hile this activity is in a nascen t stage, EPA is conducting ongoing research on experimental mobile monitoring methods to locate and quantify equipment leak emissions from petroleum and natural gas fields. In addition to increasing our knowledge about emissions from equipment leaks from petroleum and natural gas fields, if this proves to be a robust method, it could be one viable alternative for measuring emissions and EPA would consider a rulemaking to add it as an acceptable method to this subpart. : EPA did not intend for compressors to be taken offline in order for reporters to collect the data required under subpart W and h as clarified the final rule to allow reporters to conduct an annual measurement of each compressor in the mode as it exists at the time the annual measurement is taken. EPA requires the development ofPage 50 of 265

DRAFT: Please do not cite, quote, or distribute emission factors from these measurements that reporters must apply appropriately to all compressors for the total time each compressor is operated in each mode. However, EPA requires that each compres sor must be measured at least once during every three year period in the “not operating and depressurized” mode without blind flanges in place. Blind flanges are flat plates inserted between flanges on a valve or piping connection to assure absolute isola tion of the equipment from process fluids, and hence, compromise through valve leakage measurement. Isolation valve leakage through the compressor blowdown vent must be measured before blind flange s are installed. Commenters suggested to EPA that based on their operational experience, 3 years is an appropriate maximum operational time period during which compressors will be shutdown for maintenance at least once , and therefore operators would not need to shutdown compressors specifically for the purposes of monitoring. Accordingly, EPA is requiring r eporters to schedule the measurement of compressors in the not operating and depressurized mode at
any one time during a consecutive three year time period.
Comment: EPA received a broad range of comments th at the methodologies for calculating GHG emissions in subpart
W for specific emissions sources were too burdensome. SomePage 51 of 265

DRAFT: Please do not cite, quote, or distribute commenters stated that quarterly samp ling of produced natural gas to determ ine gas composition was overly burdensome and not necessary since produced gas composition does not change significantly from one quarter to the next. Other commenters suggested that requiring component counts for calculating equipment leaks for the onshore petroleum and natural gas industry segment was too onero us and time intensive since a reporter may have hundreds of wells across a large geographical area, and they currently do not have an inventory of all the components, such as valves, connectors and flanges, associated with their equipment. Several comment ers stated that the number of tanks and dehydrators in the onshore petroleum and natural gas industry segment would be very burdensome to estimate emissions from using engineering equations. For example each tank would be required to obtain a sample analys is of low pressure separator oil for doing the engineering calculations. Finally, several commenters stated that the number of pneumatic devices and pneumatic pumps would require extensive time to determine the manufacturer model of each device in their f acilities, and then estimate emissions based on manufacturer data. Lastly, commenters noted that compressor emissions measurement and compressor throughput flow was tooPage 52 of 265

DRAFT: Please do not cite, quote, or distribute burdensome, since many compressors would require the installation of expensive permanen t meters. Response:

 Individual component counts and population based emissions factors for onshore petroleum and natural gas production have been replaced with major equipment counts and default average component counts per primary equipment
. Identification of primary equipment (dehydrators, compressors, heaters, etc.) will result in significantly less burden to reporters than counting each component (valve, flange, open

ended line, etc.). EPA considered all of these comments, and performed extensive evaluation of the methodologies for calculating GHG emissions for each emissions source under each industry segment. EPA compared alternative methodologies that, when pe rformed, would result in reduced burden on industry while maintaining the necessary quality of data to inform policy. (Please see Docket EPA

- HQ

- OAR

2009

- 0923 for a full report of the analysis). Sp ecific ally , certain methodologies for specific emissions

s ources allowed for alternative methods that would reduce bur den and maintain data quality. As a result, EPA determined that the following rule modifications would reduce burden while sustaining the necessary quality of data:

 Quarterly sampling of gas composition has been replaced by an annual sampling. Most producers would have this informa tion already for transaction processing.Page 53 of 265

DRAFT: Please do not cite, quote, or distribute  For onshore petroleum and natural gas production, for separators and well production with less than 10 barrels per day throughput and glycol dehydrators with less than 0.4 million standard cubic feet per day through put, reporters will use emissions factors to determine emissions . B lowdown emissions from equipment vessel chambers totaling less than 5000 cubic feet are not required to be reported. For more information, please see “Equipment Threshold for Tanks ,” “Equ ipment Threshold for Dehydrators ,” and “Equipment Threshold for Blowdowns” under EPA

- HQ

- OAR

2009

- 0923.

 For all pneumatic devices and pneumatic pumps in onshore petroleum and natural gas production and all pneumatic devices in onshore natural gas transmiss ion compression facilities and underground natural gas storage facilities, reporters will utilize population emissions factors instead of engineering estimates.

 The final rule has clarified that emissions from centrifugal and reciprocating compressors do n ot require the installation of a permanent flow meter; use of a portable meter and port are acceptable
. In addition, compressor throughput flow meters are not required; estimates of compressor flow will be sufficient for EPA’s requirements. Data Reporting Requirements
Comment : Numerous commenters stated that there would be insufficient time, leak detection and measurement equipment, or service providers available to fully comply with subpart W reporting requirements
. In particular ,
numerous onshore petro leum and natural gas production
commenters expressed concern with the ability to gather data from geographically dispersed emissions sources starting January 1, 2011. Also numerous commenters from the natural gas processing and natural gas transmission in dustry segments expressed their concern with the irPage 54 of 265

DRAFT: Please do not cite, quote, or distribute ability to comply with monitoring requirements, such as installing necessary measurement ports or meters for
measurement. Response

Best available monitoring methods are available for three specific instances as well as providing a catch

- all provision in the case of unant icipated issues or circumstances . In each category EPA determined the affected sources, reporting requirements and the time period necessary for owner s or operator s to implement the requirements of the rule. In all cases, the owner or operator must use t he equations and methods set forth in : As described below, EPA determined that for specified emissions sources for certain industry segments, some reporters may need more time to comply with the monitoring and QA/QC requirements of this subpart by January 1, 2011. EPA carefully considered each source and the reporting compliance requirements and determined for wh ich monitoring requirements it is appropriate to allow the use of best available monitoring methods, for how long the use of best available monitoring methods will be applicable, and under what circumstances these methods are reasonable. EPA has extensive ly detailed when and how reporters may use best available monitoring methods below and in § 98.23 4 ( f ) of the rule.Page 55 of 265

DRAFT: Please do not cite, quote, or distribute §98.233, but may use best available monitoring methods to estimate the parameters in the equations as specified in the sections below. EPA also carefully considered the timing for allowing application of best available monitoring methods. EPA determined the time duration for specified sources for which reporting entities may apply best available monitoring methods without a petition , and those for which reporting entities must request the use of best available monitori ng methods. Based on EPA’s experience in implementing the 2009 final rule and those BAMM provisions , EPA made the source specific determinations for subpart W as outlined below. Well

- related Emissions Reporting
. Subpart W requires the monitoring of w ell

- related emissions sources for which the owner or operator must collect data during the actual event (for example, a well completion or workover conducted on a specific day in January 2011) and for which it may not be possible to collect or reproduce da ta after the event is over. EPA recognizes that in these cases, owners or operators may need to coordinate and possibly modify contracts, leases or other arrangements with service providers in order to gather data and thus it may not be possible for owner s or operators to begin gathering well

-Page 56 of 265

DRAFT: Please do not cite, quote, or distribute related emissions data as of January 1, 2011
. For these sources EPA will allow the use of best available monitoring methods through June 30, 2010 to allow reporters sufficient time to meet the requirements of the rul e.

 Elligible Sources
. There are three well

- related sources for which s ubpart W requires emissions data collection at the time of the emissions event rather than at the reporter’s discretion during a calendar year and for which use of best available monito ring methods will be allowed
. These sources are as follows:

 Gas well workovers using hydraulic fracture in paragraph § 98.233 (g)

 Gas well completions using hydraulic fracture in paragraph §98.233 (g)

 Well testing/flaring in paragraph § 98.233 (l)
As a si gnificant portion of well drilling activities are conducted by third

- party service providers, it may take owners or operators additional time to finalize arrangements with their service providers or modify existing contracts, leases or other arrangements s uch that said service providers will provide data to owners or operators . Based on this , EPA concluded that it may not be possible for some owners or operators to begin gathering well

- related emissions data as of January 1, 2011.

 Reporting Requirements
. For the sources listed above, an owner or operator must use the equations prescribed in §98.233(g) and §98.233(l) but may use best available monitoring methods to estimate any of the parameters. Best available monitoring methods may be:Page 57 of 265

DRAFT: Please do not cite, quote, or distribute  Monitoring meth ods currently used by the facility that do not meet the specifications of this subpart.

 Supplier data.

 Engineering calculations.

 Other owner or operator records.

 Authorization to Use Best Available Monitoring Methods
. All owners or operators may use bes t available monitoring methods for these sources between January 1, 2011 and June 30, 2011. Owners or operators do not have to submit a request to EPA for the initial six months. Owners or operators will have between the time this rule is signed by the A dministrator until June 30, 2011 to make any necessary arrangements with service providers and other relevant organizations in order for the owner or operator to gather all necessary data to comply with s ubpart W. As this is approximately eight months tim e , starting July 1, 2011, EPA expects that owners or operators will have made arrangements or modified contracts with service providers, such as drilling companies, as necessary to comply fully with s ubpart W for these sources.

 Requests for Extension in 20 11
. If additional time is necessary beyond June 30, 2011 , an owner or operator must request an extension for use of best available monitoring methods by February 28, 2011
. EPA will not consider a company

- wide or basin

- wide extension of best available mon itoring methods for an owner or operator’s emissions reporting requirements for §98.233(g) and §98.233(l) . In order to receive an extension for a time period between July 1, 2011 and December 31, 2011, owners and operators must provide the following infor mation for each source covered under §98.232 (c)(6), §98.232 (c)(8), and §98.232 (c)(12):

 A list of the specific emissions sources within the owner or operator’s facility for which the owner or operator is requesting an extension of best available monitor ing methods.

 A description of the specific requirements in §98.233(g) and §98.233(l) which the owner or operator cannot meet in 2011, including a detailed explanation as to why the requirements can not be met.Page 58 of 265

DRAFT: Please do not cite, quote, or distribute  Supporting documentation such as the date of and copies of correspondence to service providers or other relevant entities whereby the owner or operator clearly requests that said service providers or other relevant entities provide required data.

 Correspondence from specific service providers or ot her relevant entities to the owner or operator, whereby the service provider states that it is unable to provide the necessary data or services requested by the owner or operator that would enable the owner or operator to comply with s ubpart W reporting re quirements. EPA will not consider a request for extension of best available monitoring methods if the service provider requests a contract modification to collect this data and the owner or operator refuses to do so.

 A detailed explanation and supportin g documentation of how and when the owner or operator will receive the required data and/or services to comply with s ubpart W reporting requirements. The Administrator reserves the right to require additional documentation. EPA does not anticipate extendin g the use of best available monitoring methods beyond 2011 as approximately fourteen months will have passed since the Administrator’s signature; however, under extreme and unique circumstances, which include safety, a requirement being technically infeasi ble or counter to other local, State or Federal regulations, EPA may consider granting a further extension. Any such request must be received by June 30, 2011
. The owner or operator must provide the following information in a request for the use of best available monitoring methodsPage 59 of 265

DRAFT: Please do not cite, quote, or distribute beyond 2011 for sources covered under §98.232 (c)(6), §98.232 (c)(8), and §98.232 (c)(12) for beyond 2011 :

 A list of the specific emissions sources within the owner or operator’s facility for which the owner or operator is req uesting an extension of best available monitoring methods.

 A description of the specific requirements in §98.233(g) and §98.233(l) which the owner or operator cannot meet, including a detailed explanation as to why the requirements cannot be met.

 Detailed outline of the unique circumstances necessitating an extension, including specific data collection issues that do not meet safety regulations, technical infeasibility or specific laws or regulations that conflict with data collection for §98.232 (c)(6), § 98.232 (c)(8), and §98.232 (c)(12). The owner or operator must consider all data collection options as outlined in the rule for a specific emissions source before claiming that a specific safety, technical or legal barrier exists. For example, if measuri ng an open - ended line on a rooftop does not meet safety regulations, companies must consider the use of portable meters using a port at ground

- level.

 A detailed explanation and supporting documentation of how and when the owner or operator will receive t he required data and/or services to comply with subpart W reporting requirements in the future
. The Administrator reserves the right to require additional documentation. It is the responsibility of the owner or operator to meet the reporting requirements of this rule. Accordingly, it is up to the owner or operator to best determine how they can obtain the necessary data to timely and fully comply. Stipulated Activity Data Collection
. Several sources require the collection of activity data such as cumula tivePage 60 of 265

DRAFT: Please do not cite, quote, or distribute run time or a cumulative throughput volume to a piece of equipment starting January 1, 2011. Based on industry comments, EPA recognizes that it may not be feasible for an owner or operator to gather these data across all of their facilities as data c ollection in some cases must begin on January 1, 2011. EPA has decided to allow reporters to use best available monitoring methods to estimate specific activity parameters used in the equations and methods outlined in §98.233 for the first six months of 2 011. EPA will allow the use of best available monitoring methods for emissions sources for which the owner or operator must collect activity data sometime between January 1, 2011 and June 30, 2011 and the owner or operator can not reproduce or replicate a fter this time period. As owners or operators will have approximately eight months from the time of Administrator signature to June 30, 2011 to develop systems to collect these data, EPA does not anticipate approving best available monitoring methods for collecting activity data after June 30, 2011.

 Eligible Sources
. Owners and operators may use best available monitoring methods only for the sources listed below:

 Cumulative hours of venting, days, or times of operation in paragraphs §98.233(e), §98.233(f) , §98.233(g), §98.233(h), §98.233(l), §98.233(o), §98.233(p), §98.233(q), and §98.233(r).Page 61 of 265

DRAFT: Please do not cite, quote, or distribute  Number of blowdowns, completions, workovers, or other events §98.233(f), §98.233(g), §98.233(h), §98.233(i), and §98.233(w).

 Cumulative volume produced, volume input or output, or volume of fuel used in paragraphs §98.233(d), (e), (j), (k), (l), (m), (n), (x), (y), and (z). Reporting Requirements
. For the parameters listed above, owners and operators must use the equations prescribed in § 98.233 but may use best avail able monitoring methods to estimate the stipulated activity parameters. Best available monitoring methods are:

 Monitoring methods currently used by the facility that do not meet the specifications of this subpart.

 Supplier data.

 Engineering calculations.

 Other owner or operator records.

 Authorization to Use Best Available Monitoring Methods
. All owners and operators may use best available monitoring methods for the parameters listed above between January 1, 2011 and June 30, 2011. Owners or operators do not have to submit a request to EPA for the initial six months. As owners and operators will have approximately eight months from Administrator signature to June 30, 2011, to prepare for the data collection requirements for the above sources, EPA expec ts that all owners or operators should have had adequate time to comply with the data collection requirements outlined in this subpart and therefore not need the use of best available monitoring methods after June 30, 2011.

 Requests for Extension in 2011
. Only under extreme circumstances, which include safety, a requirement being technically infeasible or counter to other local, State or Federal regulations, will EPA consider extending the use of best available monitoring methods for the collection of act ivity data through the end of 2011. Owners or operators may submit a request for an extension through the end of 2011. These requestsPage 62 of 265

DRAFT: Please do not cite, quote, or distribute must be received by February 28, 2011 and include the following:

 A list of specific source categories and parameters for which the owner or operator is seeking use of best available monitoring methods.

 A description of the specific requirements in §98.233(e), §98.233(f), §98.233(g), §98.233(h), §98.233(i), §98.233(j), §98.233(k), §98.233(l), §98.233(m), §98.233(n), §98.233(o ), §98.233(p), §98.233(q), §98.233(r), §98.233(w), §98.233(x), §98.233(y), and §98.233(z) which the owner or operator cannot meet, including a detailed explanation as to why the requirements can not be met.

 Detailed outline of the unique circumstances nece ssitating an extension, including data collection methods that do not meet safety regulations, technical infeasibility or specific laws or regulations that conflict with the specific sources in this section. The owner or operator must consider all data co llection options as outlined in the rule for a specific emissions source before claiming that a specific safety, technical or legal barrier exists.

 A detailed explanation and supporting documentation of how and when the owner or operator will receive, fo r example, the services or equipment to comply with s ubpart W reporting requirements. The Administrator reserves the right to require additional documentation.

 Requests for Extension beyond 2011
. As approximately fourteen months will have passed between the Administrator’s signature and December 31, 2011, EPA does not anticipate approving requests for best available monitoring methods beyond 2011 for the sources listed above; however, under extreme and unique circumstances, which include safety, a require ment being technically infeasible or counter to other local, State or Federal regulations, it may consider granting a further extension. Any such requests for extensions beyond 2011 must be received by June 30, 2011 and include the following:Page 63 of 265

DRAFT: Please do not cite, quote, or distribute  A list of s pecific source categories and parameters for which the owner or operator is seeking use of best available monitoring methods.

 A description of the specific requirements in §98.233(e), §98.233(f), §98.233(g), §98.233(h), §98.233(i), §98.233(j), §98.233(k), §98.233(l), §98.233(m), §98.233(n), §98.233(o), §98.233(p), §98.233(q), §98.233(r), §98.233(w), §98.233(x), §98.233(y), and §98.233(z) which the owner or operator cannot meet, including a detailed explanation as to why the requirements can not be met.

 Deta iled outline of the unique circumstances necessitating an extension, including data collection methodologies that do not meet safety regulations, technical infeasibility or specific laws or regulations that conflict with sources outlined in this section. The owner or operator must consider all data collection options as outlined in the rule for a specific emissions source before claiming that a specific safety, technical or legal barrier exists.

 A detailed explanation and supporting documentation of how and when the owner or operator will receive, for example, the services or equipment to comply with s ubpart W reporting requirements. The Administrator reserves the right to require additional documentation. Acquisition and implementation of leak detection and monitoring equipment or services
. Based on industry comments, EPA understands that it may not be feasible for all owners or operators to acquire required leak detection and/or measurement equipment or hire a service provider in time to conduct the act ivities necessary to complete leak detection and measurement requirements under s ubpart W within the 2011 calendar year. EPA will consider the usePage 64 of 265

DRAFT: Please do not cite, quote, or distribute of best available monitoring methods for sources requiring leak detection and/or measurement based on eviden ce provided by the owners or operators demonstrating that they have made all efforts but cannot obtain the necessary equipment or services in time to complete s ubpart W reporting in 2011.

 Eligible Sources
. With application approval from the Administrator, o wners and operators may use best available monitoring methods only for the sources listed below:

 Reciprocating compressor rod packing vents for facilities downstream of onshore petroleum and natural gas production (i.e., natural gas processing, natural g as transmission compression, underground natural gas storage, LNG storage, and LNG import and export equipment) in paragraph §98.233(p).

 Centrifugal compressor wet seal oil degassing venting for facilities downstream of petroleum and natural gas production in paragraph §98.233(o).

 Acid gas removal vents in paragraph §98.233(d)

 Equipment leaks in facilities downstream of onshore petroleum and natural gas production in paragraph §98.233(q).

 Transmission storage tanks in paragraph §98.233(k).

 Reporting Requir ements . For the sources listed above, if approved by the Administrator, the owner or operator may use best available monitoring methods to estimate emissions and/or the number of leaking components, and any throughputs, volumes, or owner or operator maint enance records in place of the required monitoring methods outlined for parameters in §98.233. These best available monitoring methods are:Page 65 of 265

DRAFT: Please do not cite, quote, or distribute  Monitoring methods currently used by the facility that do not meet the specifications of this subpart.

 Supplier da ta.

 Engineering calculations.

 Other owner or operator records.

 Authorization to Use Best Available Monitoring Methods
. Because leak detection and/or measurement surveys are one - time actions that can be conducted at any time during the year, by February 28, 2011, reporters must submit an application seeking approval for the use of best available monitoring methods. Upon approval by the Administrator, EPA may allow the use of best available monitoring methods for up to the entire 2011 calendar year . An o wner or operator must submit this request no later than February 28, 2011 and include, at a minimum:

 A list of specific source categories and parameters for which the owner or operator is seeking use of best available monitoring methods.

 A description of t he specific requirements in §98.233(d), §98.233(k), §98.233(o), §98.233(p), and §98.233(q) which the owner or operator cannot meet and an explanation of how the owner or operator has diligently tried and why it cannot meet the requirements.

 Certification t hat the owner or operator does not already own relevant detection or measurement equipment.

 Documentation that at least four service providers that provide leak detection and measurement services relevant to s ubpart W will not supply their service to the o wner or operator in time to meet s ubpart W reporting requirements for 2011. The documentation must demonstrate that the owner or operator made all reasonable efforts to obtain the service necessary to comply with s ubpart W reporting requirements in 2011. EPA recognizes that some owners or operators may choose to conduct their own leak detection and measurement activities and therefore purchase equipment for that purpose
. It is the owner or operator’s responsibility to purchase allPage 66 of 265

DRAFT: Please do not cite, quote, or distribute necessary equipment in time to meet 2011 reporting requirements. If relevant equipment vendors can not deliver hardware in time for an owner or operator to meet s ubpart W requirements, the owner or operator must attempt to use outside service providers, as stipulated above, pr ior to seeking a request for best available monitoring methodology extension.

 A detailed explanation and supporting documentation of how and when the owner or operator will receive the services or equipment to comply with s ubpart W reporting requirements in 2012. The Administrator reserves the right to require additional documentation.

 Requests for Extension
. As owners and operators will have had approximately fourteen months since the date of the Administrator’s signature and December 31, 2011, EPA does not anticipate extending best available monitoring methods beyond 2011; however, under extreme and unique circumstances, which include safety, a requirement being technically infeasible or counter to other local, State or Federal regulations, EPA may cons ider granting a further extension. Any such request for extensions beyond 2011 must be received by June 30, 2011 and include the following:

 A list of specific source categories and parameters for which the owner or operator is seeking use of best availab le monitoring methods.

 A description of the specific requirements in §98.233(d), §98.233(k), §98.233(o), §98.233(p), and §98.233(q) of the unique circumstances necessitating an extension, including specific data collection methodologies that do not meet sa fety regulations, technical infeasibility or specific laws or regulations that conflict with sources outlined in this section. The owner or operator must consider all data collection options as outlined in the rule for a specific emissions source before c laiming that a specific safety, technical or legal barrier exists.

 D etailed explanation and supporting documentation of how and when the owner or operator willPage 67 of 265

DRAFT: Please do not cite, quote, or distribute receive the services or equipment to comply with s ubpart W reporting requirements. The Adminis trator reserves the right to require additional documentation. Other Sources

 Requests for 2011 : Emissions sources not covered above are under operational control of the owner or operator, require one time data collection at any point during the calendar y ear and do not require leak detection or measurement equipment
. For these reasons, for the sources not covered above, EPA does not anticipate the need for best available monitoring methods; however, EPA reserves the right to review such requests submitted by February 28, 2011 and consider approval of the use of best available monitoring methods for 2011 under unique and extreme circumstances which include safety, a requirement being technically infeasible or counter to other local, State or Federal regulat ions
. Requests for the use of best available monitoring methods for sources not covered above must include:

 A list of specific source categories and parameters for which the owner or operator is seeking use of best available monitoring methods.

 Detailed o utline of the unique circumstances necessitating an extension, which must include data collection methodologies that do not meet safety regulations, technical infeasibility or specific laws or regulations that conflict with specific sources for which owner s or operators are requesting best available monitoring methods. The owner or operator must consider all data collection options as outlined in the rule for a specific emissions source before claiming that a specific safety, technical or legal barrier exi sts.

 A detailed explanation and supporting documentation of how and when the owner or operator will receive the services or equipment to comply with s ubpart W reporting requirements in 2012.Page 68 of 265

DRAFT: Please do not cite, quote, or distribute The Administrator reserves the right to require additional do cumentation.

 Requests beyond 2011: For s ources not covered above, EPA does not anticipate the need for best available monitoring methods beyond 2011 ; however, EPA reserves the right to review such requests submitted by June 30, 201 1 and consider approval o f the use of best available monitoring methods for 2012 under unique and extreme circumstances which include safety, a requirement being technically infeasible or counter to other local, State or Federal regulations
. Requests for the use of best available monitoring methods for sources not covered above must include:

 A list of specific source categories and parameters for which the owner or operator is seeking use of best available monitoring methods.

 Detailed outline of the unique circumstances necessitat ing an extension, which must include data collection methodologies that do not meet safety regulations, technical infeasibility or specific laws or regulations that conflict with specific sources for which owners or operators are requesting best available monitoring methods. The owner or operator must consider all data collection options as outlined in the rule for a specific emissions source before claiming that a specific safety, technical or legal barrier exists.

 A detailed explanation and supporting d ocumentation of how and when the owner or operator will receive the services or equipment to comply with s ubpart W reporting requirements. The Administrator reserves the right to require additional documentation.
5
. Legal Authority
Comment: Several commenters asserted that EPA is

over - reaching its CAA 114 authority. These commenters specifically stated that CAA 114 does not authorize EPA toPage 69 of 265

DRAFT: Please do not cite, quote, or distribute require indefinite and sweeping monitoring, recordkeeping, and reporting from the facilities covered by proposed
S ubpart W. On the other hand , several commenters asserted that the proposal was within EPA’s authority under the CAA. Response: As explained in section I. C. of this preamble, section I. C and Q of the 2009 final rule preamble (74 FR 56260), and the Mandat ory Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments, Volume 9, Legal Issues (EPA

- HQ

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- 2008

- 0508), EPA is promulgating this rule under its existing CAA authority provided in CAA section 114. EPA disagrees with the commenters that it doe s not have statutory authority to require monitoring, reporting and recordkeeping from facilities in the petroleum and natural gas systems source category. T he Administrator may gather information under CAA section 114, as long as that information is for purposes of carrying out any provision of the CAA. For example, s ection 103 of the CAA authorizes EPA to establish a national research and development program, including non

- regulatory approaches and technologies, for the prevention and control of air poll ution, including GHGs. The data collected under this rule will also inform EPA’s implementation of CAA section 103(g) regarding improvement in sector based non

- regulatory strategies and technologies for preventing or reducing airPage 70 of 265

DRAFT: Please do not cite, quote, or distribute pollutants. For more inf ormation about EPA’s legal authority please see the sections and documents noted above. Designated Representative
Comment: Several commenters stated that EPA lacked the authority to require facilities to collect data on equipment and activities that may be operated or provided by a third party service provider and then require a designated representative to certify those emissions data. Other commenters supported the inclusion of emissions data from equipment operated by third party service providers by

s tating that these emissions are critical to ensuring that facilities with different operational structures have equitable coverage in a reporting program and that a complete profile of emissions from the production sector is obtained. Response : As explaine d in section V of the preamble of the 2009 final rule, all reporters must select a designated representative (DR) who is responsible for certifying, signing, and submitting all submissions to EPA. This provision provides flexibility to the owners and opera tors to choose any individual, employee or non

- employee, to represent them, while ensuring EPA has one accountable point of contact. As explained in the final rule, the highPage 71 of 265

DRAFT: Please do not cite, quote, or distribute level of public interest in the data collected, as well as its importance to futur e policy, warrants establishment of a high standard for data quality and consistency and high level of accountability for reported data. The DR provisions and certification requirements help ensure the standard for high quality data and consistency is met
. The DR provisions are crafted similarly to the provisions of the Acid Rain Program (ARP), 40 CFR Part 72 and EPA has found that this approach provides a high degree of both data quality and consistency and accountability
. Similar comments were made ab out the data coming from multiple owners and operators and the concerns about the certification of those data upon promulgation of the ARP and the 2009 final GHG reporting rule to which we responded, and which response s are summarized . We have attempted t o provide maximum flexibility while ensuring accountability. For integrity of the program, one representative of the owners and operators must report for important reasons. Doing so ensures the accountability of owners or operators by, inter alia , reduci ng the likelihood of inconsistent submissions by a facility. Interposing another person or party between the facility and the Agency would dilute the DR’s responsibility and in effect create multiple DRs for the facility. Additionally, leaving thePage 72 of 265

DRAFT: Please do not cite, quote, or distribute ultima te responsibility of submission with the designated representative has the salutary effect of clarifying that the DR should be aware of all submissions and should inquire of the persons with personal knowledge of the information in those submissions. T he DR has the flexibility to delegate duties, such as the preparation of submissions, but retains the ultimate responsibility to sign and certify all submissions. See , 58 FR 3590, 3598 (Jan. 11, 1993). Furthermore, while the DR or his delegatee may need to a cquire necessary reporting information from a third party, the DR must make the appropriate inquiries and certification when reporting; ultimate responsibility rests and must necessarily rest on him or her. The DR may provide in contracts, leases, or othe r agreements with third parties that true, accurate, and correct reporting information must be provided to the DR in a timely fashion. If the third party fails to provide timely, true, accurate, or correct information to the DR , then the DR has recourse contractually, or otherwise, on the third party. Finally, in recognition of their potential need to adjust contracts, leases, or agreements accordingly, additional flexibility has been provided in the rule to allow facilities to utilize best available mon itoring methods for a limited period. ForPage 73 of 265

DRAFT: Please do not cite, quote, or distribute more information see section V of the 2009 final rule (74 FR 56260) and the Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments, Volume 11, Designated Representative and Data Collection, Rep orting, Management and Dissemination (EPA

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- 0508). Applicability
Comment : Multiple commenters requested that EPA develop a set of screening tools to assist in the determination of which entities would be required to report under s ubpart W of 40 CFR part 98
. Response : Similar to what EPA has already provided for other subparts of the Mandatory Reporting Program to help reporters assess their applicability to the GHG reporting program 4

4 http://www.epa.gov/climatechange/emi ssions/GHG

- calculator/index.html , EPA plans to develop voluntary screening tools for each pet roleum and natural gas industry segment
. EPA anticipates that such tools would be based on easily determined inputs such as major equipment or operational
counts. While the tools would be designed to provide help to potential reporters for complying with the rule, compliance with all Federal, State, and Local laws and regulations remain the sole responsibility of each facility owner or operator subject to those laws and regulations. The tools would be a guide to determine those facilitiesPage 74 of 265

DRAFT: Please do not cite, quote, or distribute that are clearl y well below the reporting threshold, those clearly above, and those close to the threshold who will need to collect further data to make a proper determination. **III. Economic Impacts of the Rule** This section of the preamble summarizes the costs and

ec onomic impacts of the final rulemaking, including the estimated costs and benefits of the rule, and the estimated economic impacts on affected facilities, including estimated impacts on small entities. Complete details of the economic impacts of the final rule can be found in the Economic Impact Analysis (EIA) in the rulemaking docket (EPA

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- 0923). This section also contains a brief summary of major comments and responses on the economic impacts of the rule
. EPA received a number of comments on the estimated compliance costs as well as other comments covering a variety of topics. Responses to significant comments can be found in “Mandatory Greenhouse Gas Reporting Program: 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 of the Final RulePage 75 of 265

DRAFT: Please do not cite, quote, or distribute EPA estimated costs for each affected petroleum and natural gas industry facility to comply with subpart W. These estimates capture the costs associated with monitoring and reporting both equipment leaks and vented emissions and incremental combustion

- related emissions. 5

Staff activitie s and associated labor costs may also vary over time. In particular, start

- up activities, such as the installation of ports for compressors to allow for spot measurements, results in notably higher costs in the EPA based the estimates on the number of labor hours to perform specific activities, the cost of labor, and the cost of monitoring equipment. The costs of complying with the rule will vary from one petroleum and gas industry segment and facility to another, depending on factors such as the types of emissions, the number of affected sources at the facility, existing mainten ance practices, monitoring, recordkeeping, and reporting activities at the facility. The costs include expenditures related to monitoring, recording, and reporting process emissions and, as relevant, emissions from stationary combustion.

5 Reporting entities that equal or exceed the Subpart W threshold for equipment leak and vented emissions must report combustion emissions under Subpart C, except for onshore production, which must report combustion emissio ns under Subpart W. Incremental combustion emissions refer to those from entities that did not trigger the Subpart C threshold in the absence of Subpart W.Page 76 of 265

DRAFT: Please do not cite, quote, or distribute first year. Costs would also vary over time when site

specific emissions factors are developed every two or three years. Thus, EPA developed cost estimates for year one, which includes start

- up and first

- time reporting, and for subsequent year reporting. EPA estimated annual costs in 2006 dollars using the 2006 population of emitting sources. In addition, the agency estimated costs on a per entity basis and weighted them by the number of entities affected at the 25,000 metric tons CO 2

Next, EPA estimated the number of affected facilities in each source category, the number and types of process equipment at each facility, the number and types of processes that emit GHGs, process inputs and outputs (especially for monitoring procedures that involve a carbon mass balance), and data that are already being collected e threshold. To develop compliance cost estimates, EPA gathered existing data from EPA studies and publications, industry trade associations and publicly available data sources (e.g., labor rates from the Bureau of Labor Statistics) to characterize the processes, sources, segments, facilities, and companies/entities a ffected. EPA also considered cost data submitted in public comments on the proposed rule.Page 77 of 265

DRAFT: Please do not cite, quote, or distribute for reasons not associated with the rule (to allow only the incremental costs to be es timated). Labor Costs

 Developing a plan: rep orting entity management, legal, and technical staff hours to determine applicability to the rule, organize training on rule requirements, identify staffing assignments, train staff, schedule activities as required below. . The costs of complying with and administering this rule include time of managers, technical, operational and administrative staff in the private sector. Staff hours were estimated for activities, including:

 Setting up records: technical and field staff hours to develop data collection sheets and analytical model equations or linkages to input data into software programs.

 Collecting field data: technical and field staff hours to collect necessary site

- specific data and input that data into the analytical input tables.

 Monitoring: staff hours to procure, install, operate and maintain emissions monitoring equipment, instruments and engineering analysis systems.

 Engineering models: technical staff hours to link and execute engineering emissions es timation models and analytical procedures and to organize output data as required for reporting emissions.

 Recordkeeping: staff hours required to organize, file and secure critical data and emissions quantification results as required for reporting and for documenting determinations of facilities exceeding and not exceeding reporting thresholds.

 Reporting: management and staff hours to organize data, perform quality assurance/quality control, inform key management personnel, and report it to EPA through ele ctronic systems.Page 78 of 265

DRAFT: Please do not cite, quote, or distribute Estimates of labor hours were based on economic analyses 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. See the Economic Impact Analysis for the Mandatory Reporting of Greenhouse Gas Emissions under subpart W Final Rule ( EPA

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- 0923 ) for a detailed discussion about the engine ering analysis used to develop these estimates. In addition, the Greenhouse Gas Emissions from the Petroleum and Natural Gas Industry: Background TSD ( EPA

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- 0027 ) provides a discussion of the applicable engineering estimating and measuremen t technologies and any existing programs and practices. EPA monetized the labor hours using wage rates from the Bureau of Labor Statistics (BLS). The agency also adjusted the wage rates to account for overhead. Equipment Costs. Equipment costs includ e both the initial purchase price of monitoring equipment and installation cost. For example, the cost estimation method for large compressor seal emissions includes both purchase of a flow measurement instrument and installation of a measurement port in the vent piping where the end of thePage 79 of 265

DRAFT: Please do not cite, quote, or distribute vent is inaccessible. Based on expert judgment, the engineering cost analyses annualized capital equipment costs with appropriate lifetime and interest rate assumptions. Cost recovery periods and interest rates vary b y industry, but typically, one

- time capital costs are amortized over a 5

- year cost recovery period at a rate of seven percent. Not all segments require monitoring equipment capital expenditures but those that do are clearly documented in the Economic Impa ct Analysis
. Incremental Combustion Costs.

The costs to monitor and report incremental combustion

- related emissions were estimated based on the approach used under 40 CFR Part 98, Subpart C. EPA estimated the costs to monitor and report incremental combustion emissions, which are combustion

- related emissions from entities that did not trigger the Subpart C threshold in the absence of Subpart W. As d iscussed above, reporting entities that equal or exceed the Subpart W threshold must report combustion emissions following the methods under Subpart C, except for onshore production, which must report combustion emissions following the methods under Subpar t W.

6

6 40 CFR Part 98 use s the IPCC Tier concept to estimate combustions emissions (74 FR 56260, Octob er 30, 2009). See EPA

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- 0004, U.S. EPA, Technical Support Document for Stationary Fuel Combustion Emissions: Proposed Rule for Mandatory Reporting of Greenhouse Gases, January 30, 2009, for more information about the IPCC Tier methodology ( pgs 10

- 15).Page 80 of 265

DRAFT: Please do not cite, quote, or distribute Specifically, EPA applied the Tier 1 methodology to estimate the costs to monitor combustion emission s that became subject to reporting as a result of this final action . The Tier 1 approach bases estimates on a fuel

specific default CO 2

EPA base d this conclusion on three considerations for applicability of the Tier 2 methodology and higher, as specified in Subpart C, to the petroleum and natural gas industry: (1) availability of high heating values (HHVs) for the fuels combusted at the frequency required by the Tier 2 methodology, (2) the maximum rated heat input capacity of the equipment, and (3) the type of fuel being combusted. First, in order to be required to use a Tier 2, units must have a rated heat input capacity less than or equal to 250 MMBtu/hr, combust a fuel found in Table C

- 1, and sample the HHV of the fuel consumed at the required frequency in Part 98.34(a). It was determined that this minimum required sampling frequency is not currently emission factor, a default high heating value of the fuel, and the annual fuel consumption from company records. EPA d etermined that entities that need to report incremental combustion

- related emissions, as defined above, would use the Tier 1 method as set forth in Subpart C; these entities would likely not meet the requirements for the Tier 2 or higher methods.Page 81 of 265

DRAFT: Please do not cite, quote, or distribute carried out at these smaller units and theref ore these units would not be required to use Tier 2 or higher. These units will generally follow Tier 1. Second, Tier 3 and Tier 4 methodologies generally apply to equipment with a maximum rated heat input capacity greater than 250 MMBtu/hr. A 250 MMBtu /hr rating means that the emissions from that individual unit alone will be greater than 25,000 metric tons CO 2

Third, the predominant fuels used in the petroleum and natural gas industry are produced natural gas, pipeline quality natural gas, distillate fuel, and any products recovered from equipment l eaks and vents. Of these fuels, equipment using pipeline quality natural gas, distillate fuel, or products recovered from equipment leaks and vents are required to use Tier 2 or higher. As described above, if the unit has a rated heat

- input less than or e qual to 250 MMBtu/hr, then the unit probably does not currently receive HHV at the required frequency for a Tier 2 and could use a Tier 1. If the unit has a maximum rated heat input capacity greater than 250 MMBtu/hr, then as just e; these emissions would be subject to reporting under Subpart C even in the absence of Subpart W and therefore would not fall in the category of incremental combustion emissions considered in this analysis.Page 82 of 265

DRAFT: Please do not cite, quote, or distribute noted, emissions from a unit of this size would already be subject to reporting and would not be included in the incremental combustion emissions category considered in this analysis. Finally, the use of produced natural gas is predominant in onshore petroleum and natural gas
pro duction. Under the final rule, reporters are allowed to use methods similar to Tier 1 for all combustion emissions sources that use produced natural gas. In sum, the use of Tier 1 costs for incremental combustion is a reasonable assumption. Reporting Dete rmination Costs

EPA received many comments on the method used to estimate the rule’s compliance costs. Nearly all of these comments focused on both the methodology and the resulting cost estimates. Therefore, a summary of these comments and EPA’s response is presented in the next section, III.B.2, “What are the costs of the rule?” For the detailed . Facilities will have to estimate their emissions to determine whether they exceed the reporting threshold. The costs for making a reporting determination includes primarily the use of screening tools, which EPA plans to develop. The cos ts also account for cases in which preliminary monitoring is also required to make a reporting determination. 2. Summary of Comments and ResponsesPage 83 of 265

DRAFT: Please do not cite, quote, or distribute responses to all comments r eceived, see “Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments, Subpart W: Petroleum and Natural Gas Systems.”

Table W

- 6 of this preamble presents the types of emissions covered under this final rule; the first year total costs and the first year cost per ton for process and combustion emissions; and these values for the subsequent years. EPA estimates that the total cost for process emissions in the first year is $40.1 million, and the total national annualized cost for subsequent years is $15.1 million (2006$). Of these costs, roughly 30 percent fall upon the onshore production segment in the first year, while about 38 percent fall upon the gas transmission segment. O ffshore production, which is largely covered by the Bureau of Ocean Energy Management, Regulation, and Enforcement (formerly MMS) Gulfwide Emissions Inventory study data, is estimated to incur approximately 0.7 percent of costs every three or four years; o ther segments incurring relatively large shares of costs in subsequent years are gas transmission (37.8 percent), onshore production (33.9 percent) and gas processing (12.0 percent). The reporting of incremental combustion related B. What are the costs of the rule? 1. Summary of CostsPage 84 of 265

DRAFT: Please do not cite, quote, or distribute emission for all segment s of the petroleum and natural gas industry is estimated to cost $3.3 million in both the first year and in the subsequent years. The reporting threshold determines the number of entities required to report GHG emissions and hence the costs of the rule. T he number of entities excluded increases with higher thresholds. Table W

- 7 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 using 25,000 metric tons CO 2

**Subpart W –**  equivalent as the datum. For more information about the first year capital costs (unamortized), project lifetime and the amortized (annualized) costs for each petroleum and gas industry segment please refer to section 4 of the Economic Impact Analysis for the final rule.

**TABLE W -**  **6 NATIONAL COST ESTIMATES FOR PETROLEUM AND**  **NATURAL GAS SYSTEMS (2006$)**  **First Year Subsequent Years** Page 85 of 265

DRAFT: Please do not cite, quote, or distribute **Petroleum and**  **Natural Gas**  **systems 2006$**  **Million Million**  **MtCO 2**  **2006 $/ton**  **e 2006$**  **Million Million**  **MtCO 2**  **2006 $/ton**  **e**
Equipment Leaks and Vented Emissions 40.1 253.9 $0.16 $15.1 253.9 $0.06

Combustion Emissions 3.3 83.5 $0.04 $3.3 83.5 $0.04

Total Emissions 43.4 337.4 $0.13 $18.4 337.4 $0.05

**TABLE W -**  **7 . THRESHOLD COST**  **- EFFECTIVENESS ANALYSIS**  **(SUBSEQUENT YEAR, 2006$)**
**Threshold**

**(metric**

**tons CO**  **2 Facilit**  **ies Require** 

**d to Report**  **e) Total**  **Costs** 1 **Downstream Emissions**  **Reported (MtCO**  **(million**

**$2006) 2**  **Percentage of Total**  **Downstream Emissions**  **Reported e/**  **year) Aver**  **age Reporting**  **Cost ($/Mt) Increm**  **ental Cost**  **($/Mt)** 2 1,000 12,622 $71.60 391 99% $0.18 $0.99 10,000 4,400 $29.48 362 91% $0.08 $0.44 25,000 2,786 $18.43 337 85% $0.05 $0.00 100,000 1,062 $9.61 273 69% $0.04 ($0.14 )
1 Excludes determination cos ts for non

- reporters.
2 Cost per metric ton relative to the selected option.

2. Summary of Comments and Responses Overview
. EPA received extensive comments on the methodology and cost data presented in the Economic Impact Analysis for the proposal (EP A

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- 0020). The comments can be sorte d into two major categories: 1)
comments on the costs for facilities to make a reporting determination and 2) comments on cost estimates of laborPage 86 of 265

DRAFT: Please do not cite, quote, or distribute and equipment for certain industry segments to monitor an d report emissions
. Reporting Determination.

EPA agrees with commenters that the EIA would better reflect the rule’s tota l economic burden by including all reporting determination costs. While EPA’s compliance cost estimates accounted for the reporting determination burden in the proposal, it did not include the determination burden for non

- reporters. Therefore, EPA has es timated the burden for reporting determinations made by non

- reporters and included it in the EIA for the final rule. EPA based this estimate on the assumption that non

- reporters will use a screening tool, which EPA intends to provide to C ommenters stated that EPA’s analysis underestimated the true compliance burden by omitting the costs for facilities to make a reporting determination

— i.e., estimate annual emissions to determine whether they meet the reporting threshold. These commenters recommended that EPA account for reporting determination costs incurred by both facilities that report as well as non

- reporters, i.e., those that monitor emissions but do not meet the reporting threshold. A s discussed in preamble section II.F.6, the commenters also recommended that EPA develop screening tools to reduce the burden for facilities to make a reporting determination.Page 87 of 265

DRAFT: Please do not cite, quote, or distribute facilitate reporti ng determinations. The estimated total cost for all non

- reporters to make a reporting determination is about $18.4 million, which accounts for use of the screening tool and, if required, the cost to conduct preliminary screening; section 4 of the EIA
prov ides a complete discussion of the basis for this estimate. In addition, as discussed in preamble section II.F.6, EPA plans to develop screening tools to facilitate reporting determinations. EPA expects this to minimize burden by allowing facilities to en ter basic activity data, such as well count and drilling activity, into the tool to roughly assess whether they meet the threshold. Labor and Equipment Costs

In development of this rule and in response to comments, EPA collected and evaluated cost data from . M any commenters disagreed with EPA’s cost estimates in particular segments and presented alterna tive estimates that in some cases differed from the agency’s estimates by orders of magnitude. Many of t he comments suggested that EPA’s estimates of labor costs (e.g., number of labor hours required to collect field data, to use equipment and engineering analysis systems to measure emissions, and to manage the emissions data) and equipment costs (e.g., purchase of flow meters) were too low.Page 88 of 265

DRAFT: Please do not cite, quote, or distribute multiple sour ces, closely reviewed the input received through public comments, and weighed the analysis prepared against this input. While EPA has adjusted its estimates in response to some of the comments, EPA concludes that its methodology and final cost estimates a ppropriately account for the compliance burden under this rule. EPA determined that the commenters’ alternative estimates are much higher than the agency’s because of assumptions and interpretations that were inconsistent with EPA’s intent; the alternativ e estimates were also based on higher

- cost, optional monitori ng methods.
EPA summarizes below the key assumptions, misinterpretations, and use of higher

- cost, optional methods and the resulting costs estimates that dif fered most from EPA’s estimates. The se comments were concentrated in three industry segments: 1) onshore production, 2) natural gas processing, and 3) natural gas distribution segments. Onshore Production
Comment : Commenters stated that EPA’s estimated compliance costs for the onshore pe troleum and natural gas production segment were too low. Overall, the commenters concluded that EPA should reassess the analysis of entitiesPage 89 of 265

DRAFT: Please do not cite, quote, or distribute covered by the rule, the assumptions underlying the cost estimates, and reduce the monitoring and reporting burden
. One commenter provided detailed, alternative cost estimates and concluded that costs could be as high as $1.8 billion for the onshore production segment in the first year, which is notably higher than EPA’s proposal estimate of $30.4 million for this seg ment. The basis for the commenter’s cost analysis was an estimate of the number of sources in the onshore production segment subject to monitoring. Specifically, the commenter assumed that because the proposed rule would cover about 80 percent of emissio ns from the petroleum and gas industry, approximately 80 percent of the sites and equipment at each onshore production facility would be subject to the rule. The commenter therefore concluded that the rule would cover 80 percent of the 823,000 wells in th e nation, or about 667,000 wells, which exceeds EPA’s estimated coverage of about 467,000 wells, plus sources at non

- well sites. 7

The commenter also presented a breakdown of the labor and equipment costs, such as labor wages and time spent on In particular, the commenter said that counting components to estimate emissions from equipment leaks would be onerous.

7 Commenter estimated 823,000 wells based on a “US Energy Information Administration’s 2008 report,” but did not provide any other citation information.Page 90 of 265

DRAFT: Please do not cite, quote, or distribute sampling activities. Sampling activities accounted for a notable fraction of the commenter’s estimates. For example, the commenter estimated cos ts for sampling activity to determine the composition of produced natural gas and low pressure separator oil and to analyze all tanks for hydrocarbon liquids and produced water. In addition, data management software constituted a substantial fraction o f the commenter’s total cost estimate. The commenter stated that individual reporters would spend between $100,000 and $850,000 for data management software, which totals to approximately $123 million to $1 billion for the entire segment. EPA has carefull y reviewed these comments and disagrees that the agency’s cost estimates should be orders of magnitude higher. First, EPA disagrees with the commenter’s estimate of the number of sources subject to reporting because it incorrectly assumed that the prop osed rule covered 80 percent of all wells in the United States. The commenter’s assumption that each reporter would need to monitor 80 percent of its wells in order to report about 80 percent of its emissions implies that the type and quant ity of emission s from each well are identical. This assumption, which resulted in much more labor and complex monitoringPage 91 of 265

DRAFT: Please do not cite, quote, or distribute than required under the proposal, is incorrect. The quantity and type of emissions from wells are variable; therefore, monitoring 80 percent of the wells does not necessarily account for 80 percent of emissions. Moreover, the final rule targets only those wells that have the highest emissions. Based on its threshold analysis, EPA estimates that approximately 60 percent of the wells are subject to the monitoring requirements, not 80 percent. EPA conducted the threshold analysis using actual data available through the commercial database from HPDI LLC, which collects these data primarily from individual petroleum and natural gas producing States that r equire petroleum and natural gas producing companies to report field data. The HPDI database includes operator well count. In most cases, HPDI provides data for each well on the production of petroleum and natural gas by operator and basin; some data are l isted by property, which is a collection of wells. EPA developed a reasonable estimate of the emissions per well by apportioning the national emissions from each emissions source type to each of the wells based on the contribution of petroleum and natural gas production from each well to the national total. This analysis suggests that approximately 60 percent of the wells are covered by the reporters, not 80 percent
.Page 92 of 265

DRAFT: Please do not cite, quote, or distribute The commenter’s analysis of the onshore production burden also incorrectly assumed t hat the rule required all onshore production reporters to spend up to $1 billion on data management software. EPA disagrees with this assumption for two key reasons. First, EPA notes that the rule does not require reporters to purchase data collection

so ftware. It is at the reporters’ discretion to do so. Second, a lthough the commenter did not provide any information about the software represented in its analysis (except for cost), a system in the price range assumed by the commenter is usually customize d to accommodate data needs that extend far beyond the scope of this rule. For example, such systems are typically tailored to an individual facility and used to simultaneously manage, among other things, criteria pollutants under the CAA, water discharge and permit data under the Clean Water Act, employee accident and injury reporting under Occupational Safety and Health Administration requirements, and onsite hazardous and non

- hazardous solid waste information for the Resource Conservation and Recovery A ct . In contrast, even the largest of reporters under this final action will be able to use standard spreadsheets or databases to collect the emissions data and perform calculations at a facility level. Spreadsheet software can store and manipulate tensPage 93 of 265

DRAFT: Please do not cite, quote, or distribute o f thousands of data points, and database software can store hundreds of thousands of data points. In short, spreadsheet and database software systems are capable of managing far more data than will be necessary for even the largest onshore production repo rter under Subpart W. Accordingly, EPA accounted for data management costs by factoring in estimates of labor to set up spreadsheets and other archiving and recordkeeping activities, as well as equipment costs like file cabinets and external hard drives; see the EIA for a complete discussion. Another assumption contributing to the commenters’ high cost estimates concerned the extent of sampling required. For example, commenters assumed that reporters would need to sample produced natural gas. EPA disag rees in part because it expects reporters to already have this information and would therefore not need to sample. In particular, producers conduct composition analysis of produced natural gas in order to pay royalties and taxes; they could use these data to estimate the percentage of GHGs instead of analyzing additional samples. The commenters also assumed that sampling would be required for tanks and dehydrators, which resulted in cost estimates significantly higher than EPA’s. Although not explicitly stated in the proposal, EPA did not intend forPage 94 of 265

DRAFT: Please do not cite, quote, or distribute reporters to sample either the low pressure separator oil associated with tanks or natural gas going to dehydrators. Therefore, EPA has clarified the final rule to allow reporters that use the engineering mode ling software to rely on the software’s default values. In addition, commenters also assumed that produced water and hydrocarbon liquids produced from all reporting wells in the country would have to be sampled to determine and report CO 2

Finally, in response to comments about the costs to count all components to deter mine equipment leaks, EPA has revised the rule to require reporters to count only major equipment (see preamble section II.E). EPA expects this revision to reduce the reporters’ burden because in many cases they already have an inventory of the major equi pment at each well site. content; thi s assumption resulted in a large sampling cost. However, EPA never intended for reporters to sample produced water and hydrocarbon liquids from all wells but instead targeted EOR operations. Therefore, EPA clarified in this final action that the sampling requirement for hydrocarbon liquids applies only to EOR operations; EPA also clarified in the final rule that reporting from produced water emissions sources is not required.Page 95 of 265

DRAFT: Please do not cite, quote, or distribute For the detailed responses to all of the comments received about the costs for onshore production, see “Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments, Subpart W: Petroleum and Natural Gas Systems.”
N atural Gas Processing
Comment : Commenters stated that EPA’s estimated compliance costs for the natural gas processing segment were too low. They recommended that EPA reassess the costs for the processing segment and simplify the reporting requirements. In particular, one commenter estimated compliance costs at $4.5 billion for the processing segment. Of the $4.5 billion, the commenter attributed $3.9 billion to monitoring activities at gathering lines and boosting stations. The commenter attributed the remainder of its estimate to processing plants. Response : Based on its thorough review of the comments, EPA determined that the commenter’s estimates for processing plants were higher in part because it made assumptions that were inconsistent with EPA’s intent. Specifically, it assumed higher

- cost, optional monitoring methods for processing plants in its analysis. However, EPA agrees with the commenter that the agency’s analysis partly underestimated the costs at processing plants toPage 96 of 265

DRAFT: Please do not cite, quote, or distribute place meters on acid gas removal units. Likewise, EPA agrees that the agency’s analysis did not accurately account for the compliance costs for gathering lines and boosting stations in the processing segment. In the case of processing plants, the commenter assumed that the rule would require reporters to install permanent flow meters, at an assumed cost of $100,000 per meter, to measure emissions from compressor venting. However, the rule does not require this and allows installation of a port for using a temporary insertion flow meter for an annual one

- time estimate of vented emissions. Temporary flow meters are a significantly cheaper option than permanent meters. Based on current market data, EPA estimated approximately $1,000 for each installation of a tempora ry meter port for reciprocating compressors; about $5,000 for centrifugal compressors; and about $800 in capital costs for a reporter’s hotwire anemometer. 8

In addition, EPA considered and responded to the commenter’s assumption about the burden to install permanent outflow meters at acid gas removal (AGR) vents. Reporters will only need to purchase one hotwire anemometer per facility; the hotwire anemometer c an be used to measure the flow rate at multiple comressors at the facility
.

8 For example, see Global Water Instrumentation Inc. , at http://www.globalw.com/products/407119.htmlPage 97 of 265

DRAFT: Please do not cite, quote, or distribute EPA incorrectly assume d that outlet meters were already installed at most sites. Specifically, EPA determined upon further analysis that the flow rates at the inlet and outlet streams for an acid gas removal unit are roughly similar. EPA therefore adjusted the calculation meth od in the final rule to allow the use of flow rate at the inlet or outlet, where available, based on its assumption that the outlet flow is the same as the inlet flow. In addition, if equipment to measure the flow rate, such as CEMS or a meter on the vent stack of the acid gas removal unit, is not available, the final rule allows reporters to use engineering estimates of flow rate of natural gas into the AGR. Therefore, the cost analysis in the final EIA is consistent with the monitoring requirements by n ot accounting for the cost to meter flow rates. Finally, EPA used data about the number of gathering lines and boosting stations presented by the commenter as a basis to modify the rule requirements. EPA agrees that its EIA did not accurately reflect the number of gathering lines and boosting stations that would have been subject to the rule. The costs for gathering lines and boosting stations is not relevant to this analysis, however, because they are not covered under the final rule. Instead, EPA will co ntinue to evaluate options for obtaining emissionsPage 98 of 265

DRAFT: Please do not cite, quote, or distribute data from gathering lines and boosting stations in a way that maximizes data quality while minimizing industry burden; see preamble section II.F.1 for further discussion
. Natural Gas Distribution
Comment : Commenters stated that EPA’s estimated compliance costs for the natural gas distribution segment were too low by orders of magnitude. For example, one commenter estimated approximately $11.3 billion for all reporters in the natural gas distribution segme nt to comply with the rule. A large fraction of this estimate was based on the commenter’s assumption that the leak detection requirements applied to customer meters, i.e., industrial, commercial, and residential meters. The commenter did not, however, p rovide adequate information about the basis for the remainder of its cost estimate. In particular, the commenter stated that in addition to the costs of using an infrared camera, each LDC would spend on average about $41 million annually to comply with th e rule, but did not specify any compliance activities that accounted for the $41 million. Response : EPA has carefully reviewed these comments and disagrees that the agency’s cost estimates should be orders of magnitude higher. EPA has determined that

commenters’ interpretations of the proposed rule werePage 99 of 265

DRAFT: Please do not cite, quote, or distribute inconsistent with the Agency’s intent and accounted for the discrepancies between the estimates. EPA disagrees with the commenter’s cost estimate because it is based on an incorrect assumption about the number of meters subject to leak detection requirements. The commenter assumed that the proposed rule required leak detection and emissions estimates for customer meters, i.e., industrial, commercial, and residential meters; the commenter estimated report ers would spend approximately $5.4 billion to monitor these meters. EPA never intended to require reporting for customer meters, which would involve a major cost and have minimal effect on the quality of emissions estimates. EPA has therefore clarified t he final rule to note that sources subject to reporting in the natural gas distribution segment do not include customer meters for natural gas. In addition, EPA has responded to the commenter’s recommendation to reduce the compliance costs by simplifying the requirements for optical gas imaging equipment equipment, e.g., infrared cameras. As discussed previously in preamble section II.E, this final action provides more flexibility and further reduces the compliance cost by allowing facilities to use alt ernative leak detection equipment.Page 100 of 265

DRAFT: Please do not cite, quote, or distribute Finally, the commenter did not identify the monitoring activities and assumptions comprising its estimate of $5.9 billion to comply with leak detection requirements. The commenter noted that it obtained the estimate from an informal survey of its members but did not provide sufficient information or documentation substantiating what was included in this estimate. The commenter also noted that this estimate did not include the costs to use infrared cameras; a separate est imate was given for this and discussed in the previous paragraph. EPA is not aware of requirements other than those the commenter accounted for in the estimates based on infrared cameras and therefore did not change its cost estimate. C. What are the eco nomic impacts of the rule? 1. Summary of Economic Impacts EPA prepared an economic impact analysis to evaluate the impacts of the rule on affected small to large reporting entities. 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 the final rule.Page 101 of 265

DRAFT: Please do not cite, quote, or distribute To estimate the economic impacts of the rule, EPA first con ducted a screening assessment, comparing the estimated total annualized compliance costs for the petroleum and gas industry, where industry is defined in terms of North American Industry Classification System (NAICS) code, with industry average revenues. 9

These low average cost

- to

- sales ratios indicate that the final rule is unlikely to result in significant changes in firms’ p roduction decisions or other behavioral changes, and thus unlikely to result in significant changes in prices or quantities in affected markets. Consistent with the agency’s guidelines for economic analyses, EPA used the engineering cost estimates to meas ure the social cost of the rule, rather than modeling market responses and using The national costs of the rule are notable because there are a large number of affected entities, but per

- entity costs are low due to large coverage of emissions from these entities. Average cost

- to

- sales ratios for establishments in the affected NAICS c odes for all segments is less than 1 percent, except in the 1

- 20 employee range for the onshore petroleum and natural gas segment.

9 Note: Before totaling the industry compliance costs, EP A estimated costs for each of the industry segments. EPA then summed t he costs for each segment cost at the NAICS level for this screening assessment.Page 102 of 265

DRAFT: Please do not cite, quote, or distribute the resulting measures of social cost. 10

**NAICS** Table W

- 8 of this preamble summarizes cost

- to

- sales ratios for affected industries.

**TABLE W -**  **8 . ESTIMATED COST**  **- TO**  **- SALES RATIOS FOR A**  **FFECTED ENTITIES (Year 1)** 

**NAICS Description**  **MRR Segments Included**  **Average Cost Per**  **Entity ($1,000/en**  **tity) Average**  **Entity Cost**  **- to**  **** **Sales Ratio**  **1**

211 Crude Petroleum and Natural Gas Extraction Onshore Production, Offshore Production, Processing $17.1 0.08%

486210 Pipeline Transportatio n of Natural Gas Transmission, Underground Storage, LNG Storage, and LNG Import Terminals $15.7 0.08% 221210 Natural Gas Distribution Distribution $13.9 0.06%

1

While EPA received a substantial number of comments on the estimated costs for reporters to comply with the rule, there were min imal additional comments on the economic impacts, such as changes in production or effects on small entities in particular. As discussed in the previous section, commenters said that EPA underestimated the compliance costs and recommended that EPA careful ly review the economic impact analysis. See the previous section for a summary; the response to comments document, “Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to Public

This ratio reflects first year costs. Subsequent yea r costs will be slightly lower because they do not include initial start

- up activities. 2. Summary of Comments and Responses

10 Guidelines for Preparing Economic Analyses (EPA, 2002, p.124

- 125)Page 103 of 265

DRAFT: Please do not cite, quote, or distribute Comments, Subpart W: Petroleum and Natural Gas Systems,” provides detaile d comments. As discussed previously, EPA collected and evaluated cost data from multiple sources, thoroughly reviewed the input received through public comments, and weighed the analysis prepared for the proposal against this input. EPA has determined tha t this analysis provides a reasonable characterization of costs and that the documentation provides adequate explanation of how the costs were estimated.

EPA has determined the selected threshold maximizes the rule coverage with 85 percent of U.S. GHG emissions from the industry segments reported by approximately 2,786 reporters, while keeping reporting burden to a mini mum. Furthermore, many industry stakeholders that EPA met with expressed support for a 25,000 metric ton CO 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 IV.C of this preamble for definitions of small entities.)

2 e thresholdPage 104 of 265

DRAFT: Please do not cite, quote, or distribute because it sufficiently captures the majority of GHG emissions in the U nited States ., while excluding most of the smaller facilities an d sources. In response to the comments EPA received about the monitoring and reporting requirements in specific source categories, EPA incorporated changes that reduce burden on reporters while maximizing emissions coverage. For information on these issu es, refer to the discussion of each segment in this preamble. EPA conducted a screening assessment comparing compliance costs to onshore petroleum and natural gas industry specific receipts data for establishments owned by small businesses. This ratio c onstitutes a “sales” test that computes the annualized compliance costs of this rule as a percentage of sales and determines whether the ratio exceeds one percent. 11

11 EPA’s RFA guidance for rule writers suggests the “sales” test continues to be the preferred quantitative metric for economic impact screening analysis. The cost

- to

- sales ratios were constructed at the establishment level (average reporting
pr ogram 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 ac ross affectedPage 105 of 265

DRAFT: Please do not cite, quote, or distribute industries. The results of the screening assessment are shown in Table W

- 9 of this preamble.Page 106 of 265

DRAFT: Please do not cite, quote, or distribute **TABLE W -**  **9 . ESTIMATED COST**  **- TO**  **- SALES RATIOS FOR FIRST YEAR COSTS BY INDUSTRY AND ENTERPRISE SIZE**  a

**SBA Size Standard**  **(effective March 11,**  **2008) Average**  **Cost Per**

**Entity ($1,000/**  **entity) All**  **Enter**   ** prises** **Owned by Enterprises with:**

**Industry NAICS**  **NAICS Description**  **1 to 20 Employees**  **20 to 99 Employees**  **100 to 499**  **Employees 500 to**  **749 Employees**  **< 500 Employees**  **750 to 999**  **Employees 1,000 to**  **1,499 E**  **mployees** Onshore

petroleum and natural gas production; offshore petroleum and natural gas production; LNG storage; LNG import and export 211 Crude Petroleum and Natural Gas Extraction 500 $17.1 0.08% 1.32% 0.11% 0.05% 0.02% 0.47% 0.03% 0.02%

Onshore

nat ural gas processing; onshore natural gas transmission; underground natural gas storage 486210 Pipeline Transportat ion of Natural Gas b $15.7 0.08% 0.12% 0.40% 0.24% c 0.10% c c

Natural gas

distribution 221210 Natural Gas Distribution 500 $13.9 0.06% 0.27% 0.03% 0.06% 0.11% 0.07% 0.02% 0.03%

a The Census Bureau defines an enterprise as a business organization consisting of one or more domestic establishments that w ere specified under common ownership or control. The enterprise and the establishment are the same for single

- establishment firms. Each multi

- establishment company forms one enterprise

— the enterprise employment and annual payroll are summed from the associated establishments. Enterprise size designations are determined by t he summed employm ent of all associated establishments. Since the SBA’s business size definitions (http://www.sba.gov/size) apply to an establishment’s ultimate parent company, EPA assumes in this analysis that the enterprise definition above is consistent with the concept of ultimate parent company that is typically used for Small Business Regulatory Enforcement Fairness Act (SBREFA) screening analyses. b The SBA size standard for NAICS 486210 is $7 million in average annual receipts. c The U.S. Census Bureau has missing d ata for this employee range; some estimates were possible using partial data. The receipts for these categories underestimate true value.Page 107 of 265

DRAFT: Please do not cite, quote, or distribute As shown, the cost

- to

- sales ratios are less than one percent for establishments owned by small businesses that
EPA c onsiders most likely to be covered by the reporting program. The only exception is the ratio for enterprises with 1

- 20 employee s for crude petroleum and natural gas extraction, which is greater than 1 percent but less than 2 percent. While a majority of the enterprises in the petroleum and natural gas industry fall in the 1

- 20 employee range, most of the production, and therefore emissions, comes from large corporations. In most cases, the smaller enterprises have very small operations (such as a single family owning a few production wells) that are highly unlikely to cross the 25,000 metric tons CO 2 e reporting threshold. In other cases, a small enterprise (less than 20 employee) may own large operations but conduct nearly all of its operations through service providers. Such enterprises, however, tend to have higher annual revenues than those with small operations. In addition, these enterprises constitute a small fraction of the over 19,000 enterprises in the less than 20 employee category subject
to this final rule.Page 108 of 265

DRAFT: Please do not cite, quote, or distribute 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. 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, inclu ding 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 industr y 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 wit h lower emissions to report. The Agency also recommended a reasonable balance of direct measurement, engineering estimation, and emission factors based monitoring methods to quantify emissions, which provides flexibility to entities and helps minimize rep orting costs.Page 109 of 265

DRAFT: Please do not cite, quote, or distribute 2. Summary of Comments and Responses
Comment : Some commenters noted concerns about the rule’s impact on small businesses, in particular that small businesses would have to apply the monitoring methods specified in the rule to determine whether they have to report under the rule . One commenter recommended that EPA redo its analysis of the rule’s impacts on small businesses using “more accurate economic impact data,” but did not appear to include or identify alternative data sources for such an analysis. See the response to comments document, “Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments, Subpart W: Petroleum and Natural Gas Systems,” for the detailed comments. Response : 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. While the commenter did not provide details in its recommendation that EPA redo the small business ana lysis using “more accurate economic impact data,” EPA acknowledges the importance of using the best available economic data. Accordingly, EPA analyzed the economic impact on small entities using the revised cost estimates discussed in this section and in the EIA.Page 110 of 265

DRAFT: Please do not cite, quote, or distribute These cost estimates were the same order of magnitude as those estimated under the proposal; the estimates also reflected improvements made in response to comments as well as changes to the monitoring requirements in the final rule. In addition, EPA’s assessment of the economic impacts on small entities continued to rely on data from the Statistics of U.S. Businesses, a well

- known database that provides national information on the distribution of economic variables by the size of entity. As note d in the EIA, these data were developed in cooperation with, and partially funded by, the Office of Advocacy of the Small Business Administration. Complete documentation of this analysis can be found in section 5.2 of the EIA for the final rule. Finally, in response to concerns about the cost to make a reporting determination, EPA intends to provide screening tools. As discussed above, these tools will aid small businesses and other potential reporters to determine whether or not they have to report. The response to comments document, “Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments, Subpart W: Petroleum and Natural Gas Systems,”Page 111 of 265

DRAFT: Please do not cite, quote, or distribute presents the detailed comments and responses related to the rule’s impact on small businesses.

A mandatory reporting system for petroleum and natural gas systems will benefit policymakers and the public by increased transparency of facility emissions data. Transparent, public data on emissions allows for accountability of polluters to the public s takeholders 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 regu lation. Publicly available emissions data also will allow individuals to alter their E. What are the benefits of the rule for society? EPA examined the potential benefits of the final GHG reporting rule for petroleum and natural gas systems. 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.Page 112 of 265

DRAFT: Please do not cite, quote, or distribute consumption habits based on the GHG emissions of producers. Facility

- specific emissions data will also aid local, state, and national policymakers as they evaluate and

c onsider future climate change policy decisions. The benefits of mandatory reporting of petroleum and natural gas systems GHG emissions to government also include enhancing existing programs, such as the Natural Gas STAR Program, and provide significant eco nomic and environmental benefits. Through the Natural Gas STAR Program, EPA has identified over 120 proven, cost effective technologies and practices to reduce emissions of methane

— the primary constituent of natural gas

— from operations in all of the major industry sectors

— production, gathering and processing, transmission, and distribution. The final reporting rule will increase knowledge of the location and magnitude of significant methane emissions sources in the petroleum and natural gas industry, whic h can result in

cross - cutting benefits on domestic energy supply, industrial efficiency and safety, and revenue generation. Benefits to industry of GHG emissions monitoring include the value of having verifiable data to present to the public to demonstrat e appropriate environmental stewardship, and a better understanding of their emission levels and sources to identify opportunities to reducePage 113 of 265

DRAFT: Please do not cite, quote, or distribute emissions. Such monitoring allows for inclusion of standardized GHG data into environmental management systems, pr oviding the necessary information to achieve and disseminate their environmental achievements. Standardization will also be a benefit to industry. Once facilities invest in the institutional knowledge and systems to report emissions, the cost of monitori ng 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. The E IA for this final rule as well as the RIA for 40 CFR Part 98 summarize the anticipated benefits, which include providing the government with sound data on which to base future policies and providing industry and the public independently verified informatio n 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. **IV. Statutory and Executive Order Review**
A. Executive Ord er 12866: Regulatory Planning and ReviewPage 114 of 265

DRAFT: Please do not cite, quote, or distribute Under Executive Order (EO) 12866 (58 FR 51735, October 4, 1993), this action is a "significant regulatory action” because it raises novel legal or policy issues arising out of legal mandates, t he President’s priorities, or the principles set forth in the EO. Accordingly, EPA submitted this action to the Office of Management and Budget (OMB) for review under EO 12866 B. Paperwork Reduction Act The information collection re quirements in this final 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

EPA plans to collect complete and accurate facility

level GHG emissions from the petroleum and natural gas industry. Accurate and timely information on GHG emissions is essential for informing future climate change policy decisions. T hrough data collected under this rule, EPA will gain a better understanding of the relative emissions of different segments of the petroleum and natural gas industry and the distribution of emissions from individual facilities within those industries. The facility

- specific data will also improve our understanding of the factors . The Information Collection Request (ICR) document prepared by EPA has been assigned
EPA I CR number 2376.0 2
.Page 115 of 265

DRAFT: Please do not cite, quote, or distribute 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 facilities within the petroleum and natural gas industry 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 segments of the petroleum and gas industry would be affected, and how these segments would be affected by the options. This information collection is mandatory and will be carried out under CAA section 114. Information identified and marked as CBI will not be disc losed except in accordance with procedures set forth in 40 CFR part 2. However, emissions data collected under CAA section 114 cannot generally be claimed as CBI and will be made public. The projected cost and hour burden for non

- federal respondents is $ 27.7 million and 396,474 hours per year. The estimated average burden per response is 90.71 hours; the frequency of response is annual for all respondents that must comply with the final rule’s reporting requirements; and the estimated average number of l ikely respondents per year is 2,786. The cost burden to respondents resulting from the collection of informationPage 116 of 265

DRAFT: Please do not cite, quote, or distribute includes the total capital cost annualized over the equipment’s expected useful life (averaging $0.74 million), a total operation and maintena nce component (averaging $1.7 million per year), and a labor cost component (averaging $25.3 million per year) 12

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, . Burden is defined at 5 CFR 1320.3(b). These cost numbers differ from those shown elsewhere in the EIA for these subparts because the informati on collection request (ICR) costs represent the average cost over the first three years of the rule, but costs are reported elsewhere in the EIA for the subparts for the first year of the rule and for subsequent years of the rule. In addition, the ICR foc uses on respondent burden, while the EIA includes both national compliance costs and the burden for EPA to implement the rule.

12 Burden is defined at 5 CFR 1320.3(b). These cost numbers differ from those shown elsewhere in the Economic Analysis because the ICR costs represent the average cost over the first three years of the proposed rule, but costs are reported elsewhere in the E conomic Analysis for the first year of the proposed rule and for subsequent years of the proposed rule. In addition, the ICR focuses on respondent burden, while the Economic Analysis includes EPA Agency costs.Page 117 of 265

DRAFT: Please do not cite, quote, or distribute 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 b usinesses, small organizations, and small governmental jurisdictions. For purposes of assessing the impacts of this final rule on small entities, small entity is defined as: (1) a small business as defined by the Small Business Administration’s regulations at 13 CFR 121.201; (2) a small governmental jurisdiction that is a government of a city, county, town, school district or special district with a population of less than 50,000; and (3) a small organization that is any not

- for

- profit enterprise which is i ndependently owned and operated and is not dominant in its field.Page 118 of 265

DRAFT: Please do not cite, quote, or distribute After considering the economic impacts of this final action on small entities, I certify that this action will not have a significant economic impact on a substantial number of small entitie s. The small entities directly regulated by this final rule include small businesses in the petroleum and gas industry, small governmental jurisdictions and small non

profits. EPA has determined that some small businesses will be affected because their production processes emit GHGs exceeding the reporting threshold. For affected small entities, EPA conducted a screening assessment comparing compliance costs for affected industry segments to petroleum and gas

- specific data on revenues for small businesse s. 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., 1 percent or 3 percent). The cost

- to

- sales ratios were construct ed at the establishment level (average compliance cost for the establishment/ average establishment revenues). As shown in Table W

- 10, the average ratio of annualized reporting program costs to receipts of establishments owned by model small enterprises was less than 1 percent for industries presumed likely to have smallPage 119 of 265

DRAFT: Please do not cite, quote, or distribute businesses covered by the reporting program. Although the costs to receipts for entities in onshore production with
1

- 20 employees is slightly over 1 percent, most of these facilities wo uld likely not exceed the 25,000 mtCO 2

EPA also concluded that t he final rulemaking would not affect a small organization that is any not

- for

- profit enterprise, which is independently owned and operated and is not dominant in its field. Specifically, the data listing entities in each segment of the petroleum and
natur al gas industry did not include any non

- profit entities. e threshold, a threshold supported by many stakeholders as one that sufficiently captures the majority of GHG emissions while excluding small facilities. Further, these sales tests examine the average establishment’s total annualized mandatory reporting costs to the average establishment receipts for enterprises within several employment categories. The average entity costs used to compute the sales test are the same across all of these enterprise size categories. As a result, the sales

- test will overstate the cost

- to

- receipt ratio for establishments owned by small businesses, because the reporting costs are likely lower than average entity estimates provided by the engineering cost analysis.Page 120 of 265

DRAFT: Please do not cite, quote, or distribute In addition, EPA determined that the final rulemaking would not have a significant impact on small governmental jurisdictions. EPA determined that one segment of the petroleum and natural gas indust ry might include small governments affected by the final rulemaking. A comparison of the compliance costs to the revenue of potentially affected small governmental jurisdictions revealed that the costs of the rule are less than 1 percent of revenues. Alt hough 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 final rule on small entities. For example, EPA determined appropriate thresholds t hat reduce the number of small businesses reporting. In addition, EPA allows different monitoring methods for different emissions sources, requiring direct measurement only for selected sources. Also, EPA intends to provide a screening tool that will hel p small businesses make a reporting determination with minimal burden (see preamble Section II.F.6). Finally, EPA is establishing annual instead of more frequent reporting. Through comprehensive outreach activities prior to proposal of the initial rule, E PA held approximately 100 meetings and/or conference calls with representatives ofPage 121 of 265

DRAFT: Please do not cite, quote, or distribute the primary audience groups, including numerous trade associations and industries in the petroleum and gas industry that include small business members. EPA’s outreach acti vities prior to proposal of the initial 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

- 053. After the initial proposal, EPA posted a guide for small businesses on the EPA 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 final rule. EPA continued to meet with stakeholders and entered documentation of all meetings into the docket. During rule implementation, EPA would maintain an “open door” policy for stakeholders to ask questions about the final 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. EPA has therefore concluded that this final acti on will not have a significant economic impact on a substantial number of small entities.Page 122 of 265

DRAFT: Please do not cite, quote, or distribute D. Unfunded Mandates Reform Act (UMRA) This rule does not contain a Federal mandate that may result in expenditures of $100 million or more for State, local, and t ribal governments, in the aggregate, or the private sector in any one year. EPA estimated the cost to individual facilities that may have to report to this final rule using actual facility characteristics such as throughput and size. EPA also determined the costs to non

reporters for determination to report. The sum of these costs for the entire industry has been estimated to be less than $100 million. Thus, this rule is not subject to the requirements of sections 202 or 205 of UMRA. This rule is also not subject to the requirements of section 203 of UMRA because it contains no regulatory requirements that might significantly or uniquely affect small governments. Based on EPA’s analysis of the rule’s impact on small entities, the Agency determined tha t natural gas distribution is the only industry segment that would potentially have small governments affected by the rule. In this segment, however, the facilities owned or operated by small governments are expected to be too small to trigger the 25,000 m etric tons CO 2 e reporting threshold. E. Executive Order 13132: FederalismPage 123 of 265

DRAFT: Please do not cite, quote, or distribute This action does not have federalism implications. It will not have substantial direct effects on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government, as specified in Executive Order 13132. This regulation applies directly to petroleum and natural gas facilities that emit greenhouse gases. Few, if any, state or l ocal 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, Executive Order 13132 does not apply to this action.

EPA has concluded that this action may have tribal implications. However, it will neither impose substantial direct compliance costs on tribal govern ments, nor preempt Tribal law. EPA conducte d an analysis to determine potential impact of this action on tribes that own or operate petroleum and natural gas systems (EPA

- HQ

- OAR

- 2009

- 0923

- XXX). First, EPA analyzed a comprehensive listing of all operators of petroleum and natural gas systems in the United States in conducting the threshold analysis
. In a separate analysis , EPA researched additional available data F. Executive Order 13175: Consultation and Coordination with Indian Tribal GovernmentsPage 124 of 265

DRAFT: Please do not cite, quote, or distribute to determine which tribal entities may own or operate petroleum and natural gas systems that could be impacted by this final action. As a r esult of those analysis, EPA found one tribe that may potentially be impacted by this final action. Finally, during the comment period for the April 2010 proposal, EPA received comment from one tribe, Southern Ute, which were specific to the proposed repor ting methodologies. As further discussed in the 2009 final rule that established the Greenhouse Gas reporting program, EPA believes that there are minimal impacts to tribes. Tribes could be required to submit an annual GHG report for any facility they ow n or operate that is subject to the rule. Landfills and stationary combustion equipment are the types of facilities owned or operated by tribes that would most likely trigger applicability. Tribes that own or operate large industrial emission sources such as cement plants, coal mines, or oil and gas operations could also be required to report emissions under this rulemaking. It should be noted that the owner or operator of any privately owned sources located on a reservation would be required to report for any applicable facility. The rule would apply to all types of stationary combustion equipment (except for emergency generators and portable equipment) if thePage 125 of 265

DRAFT: Please do not cite, quote, or distribute aggregate maximum rated heat input capacity of all stationary fuel combustion units at a facility is 30 million British thermal units per hour (mmBtu/hr) or greater, and the facility emits 25,000 metric tons of CO2e or more per year from all stationary fuel combustion

sources. EPA sought opportunities to provide information to tribal governments and r epresentatives during rule development
. As stated in Section F: Executive Order 13175: Consultation and Coordination with Indian Tribal Governments of 40 CFR part 98, and i n consultation with EPA’s American Indian Environment Office, EPA’s outreach plan fo r the Greenhouse Gas Reporting Rule included tribes. EPA conducted several conference calls with Tribal organizations during the proposal phase of the mandatory reporting rule. For example, EPA staff provided information to tribes through conference call s with multiple Indian working groups and organizations at EPA that interact with tribes and through individual calls with two Tribal board members of The Climate Registry ( TCR )
. In addition, EPA prepared a short article on the GHG
R eporting Program that appeared on the front page of a Tribal newsletter

— Tribal Air News

— that was distributed to EPA/OAQPS’s network of Tribal organizations. EPA gave aPage 12 6 of 265

DRAFT: Please do not cite, quote, or distribute presentation on various climate efforts, including the Greenhouse Gas R eporting Program , at the National Tri bal Conference on Environmental Management on June 24

- 26, 2008. In addition, EPA distributed copies of a short information sheet 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 final rule. It was posted on th e Greenhouse Gas Reporting Program website and published in the Tribal Air Newsletter. As required by section 7(a), EPA’s Tribal Consultation Official has certified that the requirements of the Executive Order have been met in a meaningful and timely

ma nne r. A copy of the certification is included in the docket for this action.

EPA interprets EO 13045 (62 F.R. 19885, April 23, 1997) as applying only to th ose regulatory actions that concern health or safety risks, such that the analysis required under section 5

- 501 of the EO has the potential to G. Executive Order 13045: Protection of Children from Environmental Health Risks and Safety RisksPage 127 of 265

DRAFT: Please do not cite, quote, or distribute 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) b ecause it is not likely to have a significant adverse effect on the supply, distribution, or use of energy. Further, EPA has concluded that this final rule is not likely to have any adverse energy effects. This final rule relates to monitoring, reporting and recordkeeping at petroleum and gas facilities that emit over 25,000 mtCO 2

Section 12(d) of the National Technology Transfer and Advancement Act of 1995 (NTTAA), Public Law No. 104

- 113 (15 U.S.C. 272 note) directs EPA to use voluntary consensus standards in its regula tory 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, e and does not impact energy supply, distribution or use. Therefore, EPA concludes that this final rule is not likely to have any adverse effects on energy supply, distribution, or use. I. National Technology Transfer and Advancement ActPage 128 of 265

DRAFT: Please do not cite, quote, or distribute 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 s tandards. EPA provides the flexibility to use any one of the voluntary consensus standards from at least seven different voluntary consensus standards bodies, including the following: ASTM, ASME, ISO, Gas Processors Association, and American Gas Associat ion. These voluntary consensus standards will help facilities monitor, report, and keep records of greenhouse gas emissions. No new test methods were developed for this final rule. Instead, EPA reviewed existing rules for source categories and voluntary greenhouse gas programs and identified existing means of monitoring, reporting, and keeping records of greenhouse gas emissions. The existing methods (voluntary consensus standards) include a broad range of measurement techniques, including many for comb ustion 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.Page 129 of 265

DRAFT: Please do not cite, quote, or distribute By incorporating voluntary consensus standards into this final rule, E PA is both meeting the requirements of the NTTAA and presenting multiple options and flexibility for measuring greenhouse gas emissions. J. Executive Order 12898: Federal Actions to Address Environmental Justice in Minority Populations and Low

Income Po pulations Executive Order (EO) 12898 (59 FR 7629 (Feb. 16, 1994)) establishes federal executive policy on environmental justice. Its main provision directs federal agencies, to the greatest extent practicable and permitted by law, to make environmental ju stice 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 Unite d States. 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 because it is a rule addressing information collection and reporting procedures. K. Congressional Review ActPage 130 of 265

DRAFT: Please do not cite, quote, or distribute The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the Small Business Regulatory Enforcement Fairness Act of 1996 (SBREFA), 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 sub mit 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 not a “major rule” as defined by 5 U.S.C. 804(2). This rule will be effective [ INSERT THE DATE 60 DAYS AFTER PUBLICATION IN THE FEDERAL REGISTER ].Page 131 of 265

DRAFT: Please do not cite, quote, or distribute **List of Subjects in 40 CFR Part 98** Environmental protection, Administrative practice and procedure, Greenhouse gases, Incorporation by reference, Suppliers, Reporting and recordkeeping requirements.

Lisa P. Jackson, Administrator. Dated:Page 132 of 265

DRAFT: Please do not cite, quote, or distribute For the reasons stated in the preambl e, title 40, chapter I, of the Code of Federal Regulations is amended as follows:
**PART 98** – **[AMENDED]** 1. The authority citation for part 98 continues to read as follows: **Authority:** 42 U.S.C. 7401

- 7671q. **Subpart A —**  **[Amended]** 2. Section 98.2 is amended by revising paragraph (a) introductory text , (a )( 1) introductory text and (a )( 2) introductory text to read as follows:

(1) A facility that contains any source category that is listed in Table A

- 3 of this subpart in any calendar year starting in 2010. For these facilities, the annual G HG §98.2 Who Must Report ? (a) The GHG reporting requirements and related monitoring, recordkeeping, and reporting requirements of this part appl y to the owners and operators of any facility that is located in the United States or under or attached to the Outer Continental Shelf (as defined in 43 U.S.C.
§ 1331) and that meets the requirements of either paragraph (a)(1), (a)(2), or (a)(3) of this sec tion; and any supplier that meets the requirements of paragraph (a)(4) of this section:Page 133 of 265

DRAFT: Please do not cite, quote, or distribute report must cover stationary fuel combustion sources (subpart C), miscellaneous use of carbonates (subpart U), and all applicable source categories listed in Table A

- 3 and Table A

- 4 of this subpart. For these facilities, the annual GHG report shall not cover onshore petroleum and natural gas production as defined in § 98.232(c) except as specified in subpart RR
.

* * * * * (2) A facility that contains any source category that is listed in Table A

- 4 of this subpart that emits 25,000 metric tons CO 2 e or mo re per year in combined emissions from stationary fuel combustion units, miscellaneous uses of carbonate, and all applicable source categories that are listed in Table A

- 3 and Table A

- 4 of this subpart. For these facilities, the annual GHG report must cov er stationary fuel combustion sources (subpart C), miscellaneous use of carbonates (subpart U), and all applicable source categories listed in Table A

- 3 and Table
A

- 4 of this subpart. Onshore petroleum and natural gas production facilities must report emi ssions only from sources specified in § 98.232(c).

* * * * *Page 134 of 265

DRAFT: Please do not cite, quote, or distribute 3 . Table A

- 4 of subpart A is amended by adding “Petroleum and Natural Gas Systems (subpart W)” at the end of the table to read as follows:
**Table A -**  **4 of Subpart A —**  **Source Category List for §98.2(a)( 2)**  Source Categories a Applicable in 2010 and Future Years

* * * * * * * Additional Source Categories a Applicable in 2011 and Future Years Petroleum and Natural Gas Systems (subpart W)

a Source categories are defined in each applicable subpart
.

* * * * *

4 . Section 98.6 is amended by adding the following definitions in alphabetical order and revising the definition of “United States” to read as follows: §98.6 Definitions. Absorbent circulation pump means a pump commonly powered by natural gas press ure that circulates the absorbent liquid between the absorbent regenerator and natural gas contactor.

* * * * *Page 135 of 265

DRAFT: Please do not cite, quote, or distribute Air injected flare means a flare in which air is blown into the base of a flare stack to induce complete combustion of gas.

* * * * * Blowdown v ent stack emissions mean natural gas and/or
CO 2 released due to maintenance and/or blowdown operations including compressor blowdown and emergency shut

- down (ESD) system testing.

* * * * * Calibrated bag means a flexible, non

- elastic, anti

static bag of a calibrated volume that can be affixed to an emitting source such that the emissions inflate the bag to its calibrated volume.

* * * * * Centrifugal compressor means any equipment that increases the pressure of a process natural gas or CO 2 by centrifugal ac tion, employing rotating movement of the driven shaft. Centrifugal compressor dry seals mean a series of rings around the compressor shaft where it exits the compressor case that operates mechanically under the opposing forces to prevent natural gas or CO 2 from escaping to the atmosphere.Page 136 of 265

DRAFT: Please do not cite, quote, or distribute Centrifugal compressor dry seal emissions mean natural gas or CO 2 released from a dry seal vent pipe and/or the seal face around the rotating shaft where it exits one or both ends of the compressor case. Centrifugal compre ssor wet seal degassing vent emissions means emissions that occur when the high

- pressure oil barriers for centrifugal compressors are depressurized to release absorbed natural gas or CO 2 . High

- pressure oil is used as a barrier against escaping gas in cent rifugal compressor shafts. Very little gas escapes through the oil barrier, but under high pressure, considerably more gas is absorbed by the oil. The seal oil is purged of the absorbed gas (using heaters, flash tanks, and degassing techniques) and recir culated. The separated gas is commonly vented to the atmosphere.

* * * * * Dehydrator means a device in which a liquid absorbent (including desiccant, ethylene glycol, diethylene glycol, or triethylene glycol) directly contacts a natural gas
stream to absorb water vapor. Dehydrator vent stack emissions means natural gas and
CO 2 released from a natural gas dehydrator system absorbent (typically glycol) reboiler or regenerator to thePage 137 of 265

DRAFT: Please do not cite, quote, or distribute atmosphere or a flare, including stripping natural gas and motive natur al gas used in absorbent circulation pumps.

* * * * *
De

- methanizer means the natural gas processing unit that separates methane rich residue gas from the heavier hydrocarbons (e.g., ethane, propane, butane, pentane

- plus) in feed natural gas stream.

* * * * * Desiccant means a material used in solid

- bed dehydrators to remove water from raw natural gas by adsorption or absorption. Desiccants include activated alumina, p e ll e tized calcium chloride, lithium chloride and granular silica gel material
. Wet natur al gas is passed through a bed of the granular or pelletized solid adsorbent or absorbent in these dehydrators. As the wet gas contacts the surface of the particles of desiccant material, water is adsorbed on the surface or absorbed and dissolves the surf ace of these desiccant particles. Passing through the entire desiccant bed, almost all of the water is adsorbed onto or absorbed into the desiccant material, leaving the dry gas to exit the contactor.

* * * * * Gas conditions mean the actual temperature, volume, and pressure of a gas sample.Page 138 of 265

DRAFT: Please do not cite, quote, or distribute * * * * * Gas to oil ratio (GOR) means the ratio of the volume of gas at standard temperature and pressure that is produced from a volume of oil when depressurized to standard temperature and pressure.

* * * * * Hig h

- Bleed Pneumatic Devices are automated , continuous bleed flow control devices powered by pressurized natural gas and used for maintaining a process condition such as liquid level, pressure, delta

- pressure and temperature. Part of the gas power stream whi ch is regulated by the process condition flows to a valve actuator controller where it vents continuously (bleeds) to the atmosphere at a rate in excess of six standard cubic feet per hour. Intermittent Bleed Pneumatic Devices mean automated flow control devices powered by pressurized natural gas and used for maintaining a process condition such as liquid level, pressure, delta

- pressure and temperature. These are
snap - acting or throttling devices which discharge the full volume of the actuator intermitten tly when control action is necessary, but does not bleed continuously.

* * * * *
Low

- Bleed Pneumatic Devices mean automated flow control devices powered by pressurized natural gas and usedPage 139 of 265

DRAFT: Please do not cite, quote, or distribute for maintaining a process condition such as liquid level,
pressure, delta

- pressure and temperature. Part of the gas power stream which is regulated by the process condition flows to a valve actuator controller where it vents continuously (bleeds) to the atmosphere at a rate equal to or less than six standard cubic feet p er hour.

* * * * * Natural gas driven pneumatic pump means a pump that uses pressurized natural gas to move a piston or diaphragm, which pumps liquids on the opposite side of the piston or diaphragm.

* * * * *
Outer Continental Shelf means all submerged la nds lying seaward and outside of the area of lands beneath navigable waters as defined in 43 U.S.C. § 1301 , and of which the subsoil and seabed appertain to the United States and are subject to its jurisdiction and control.

* * * * * Reciprocating compresso r means a piece of equipment that increases the pressure of a process natural gas or CO 2 by positive displacement, employing linear movement of a shaft driving a piston in a cylinder. Reciprocating compressor rod packing means a series of flexible rings in machined metal cups that fit around thePage 140 of 265

DRAFT: Please do not cite, quote, or distribute reciprocating compressor piston rod to create a seal limiting the amount of compressed natural gas or CO 2 that escapes to the atmosphere.
Re

- condenser means heat exchangers that cool compressed boil

- off gas to a tem perature that will condense natural gas to a liquid.

* * * * * Sales oil means produced crude oil or condensate measured at the production lease automatic custody transfer (LACT) meter or custody transfer tank gauge.

* * * * * Sour natural gas means natura l gas that contains significant concentrations of hydrogen sulfide (H 2 S) and/or carbon dioxide (CO 2 ) that exceed the concentrations specified for commercially saleable natural gas delivered from transmission and distribution pipelines.

* * * * *
Sweet Gas i s natural gas with low concentrations of hydrogen sulfide (H 2 S) and/or carbon dioxide (CO 2 ) that does not require (or has already had) acid gas treatment to meet pipeline corrosion

- prevention specifications for transmission and distribution.

* * * * *Page 141 of 265

DRAFT: Please do not cite, quote, or distribute Unit ed States means the 50 States, the District of Columbia, the Commonwealth of Puerto Rico, American Samoa, the Virgin Islands, Guam, and any other Commonwealth, territory or possession of the United States, as well as the territorial sea as defined by Presi dential Proclamation No. 5928.

* * * * * Vapor recovery system means any equipment located at the source of potential gas emissions to the atmosphere or to a flare, that is composed of piping, connections, and, if necessary, flow

- inducing devices, and that is used for routing the gas back into the process as a product and/or fuel. Vaporization unit means a process unit that performs controlled heat input to vaporize LNG to supply transmission and distribution pipelines or consumers with natural gas.

* * * * * Vented emissions means intentional or designed releases of CH 4 or CO 2 containing natural gas or hydrocarbon gas (not including stationary combustion flue gas), including process designed flow to the atmosphere through seals or vent pipes, equipment blow down for maintenance,Page 142 of 265

DRAFT: Please do not cite, quote, or distribute and direct venting of gas used to power equipment (such as pneumatic devices).

* * * * * Well completions means the process that allows for the flow of petroleum or natural gas from newly drilled wells to expel drilling and reservoir fluids and test the reservoir flow characteristics, steps which may vent produced gas to the atmosphere via an open pit or tank. Well completion also involves connecting the well bore to the reservoir, which may include treating the formation or installing tubing, packer(s), or lifting equipment, steps which do not significantly vent natural gas to the atmosphere. This process may also include high

- rate flowback of injected gas, water, oil, and sand used to fracture or re

- fracture and prop open new fractur es in existing lower permeability gas reservoirs, steps which may vent large quantities of produced gas to the atmosphere. Well workover means the process(es) of performing one or more of a variety of remedial operations on producing petroleum and natural gas wells to try to increase production. This process also includes high

- rate flowback of injected gas, water , oil, and sand used to re

- fracture and prop

- open new fractures in existing low permeabilityPage 143 of 265

DRAFT: Please do not cite, quote, or distribute gas reservoirs , steps which may vent large quantities of produced gas to the atmosphere
. Wellhead means the piping, casing, tubing and connected valves protruding above the e arth’s surface for an oil and/or natural gas well. The wellhead ends where the flow line connects to a wellhead valve. Wellhead equipm ent includes all equipment, permanent and portable, located on the improved land area (i.e. well pad) surrounding one or multiple wellheads. Wet natural gas means natural gas in which water vapor exceeds the concentration specified for commercially saleabl e natural gas delivered from transmission and distribution pipelines. This input stream to a natural gas dehydrator is referred to as “wet gas .” 5 . Section 98.7 is amended by adding paragraphs (p), (q), and (r) to read as follows: §98.7 What standardize d methods are incorporated by reference into this part ?

* * * * * (p) The following material is available for purchase from the American Association of Petroleum Geologists, 1444 South Boulder Avenue, Tulsa, Oklahoma 74119, (918) 584

- 2555, http://www.aapg .org.Page 144 of 265

DRAFT: Please do not cite, quote, or distribute (1) Geologic Note: AAPG

- CSD Geologic Provinces Code Map: AAPG Bulletin, Prepared by Richard F. Meyer, Laure G. Wallace, and Fred J. Wagner, Jr., Volume 75, Number 10 (October 1991), pages 1644

- 1651, IBR approved for §98.238. (2) Alaska Geological Pr ovince Boundary Map, Compiled by the American Association of Petroleum Geologists Committee on Statistics of Drilling in cooperation with the USGS, 1978, IBR approved for §98.238. (q) The following material is available from the Energy Information Adminis tration (EIA), 1000 Independence Ave., SW, Washington, DC 20585, (202) 586

- 8800, http://www.eia.doe.gov/pub/oil_gas/natural_gas/da ta_publica tions/field_code_master_list/current/pdf/fcml_all.pdf
. (1) Oil and Gas Field Code Master List 2008, DOE/EIA0370(08), January 2009, IBR approved for §98.238. (2) [Reserved] (r) The following material is available from the United
States Environmen tal Protection Agency, Air Docket, EPA Docket Center, Public Reading Room, EPA West Building, Room 3334, 1301 Constitution Avenue., NW., Washington, DC 20004. http://www. regulations.gov
. (1) Year 2005 Gulfwide Emission Inventory Study, OCS Study MMS 2007

- 067, December 2007, IBR approved for §98.232(b)and §98.233(s).Page 145 of 265

DRAFT: Please do not cite, quote, or distribute (2) [Reserved]Page 146 of 265

DRAFT: Please do not cite, quote, or distribute 6 . Add subpart W to read as follows: **Subpart W —**  **Petroleum and Natural Gas Systems** Sec
. 98.230 Definition of the source category. 98.231 Reporting threshold. 98.232 GHGs to report. 98.233 Calculating GHG emissions. 98.234 Monitoring and QA/QC requirements. 98.235 Procedures for estimating missing data. 98.236 Data reporting requirements. 98.237 Records that must be retained. 98.238 Definitions.

§98.230 Definition of t he source category

(1) **.** (a) This source category consists of the following: Offshore petroleum and natural gas production
. Offshore petroleum and natural gas production is any platform structure, affixed temporarily or permanently to offshore submerge d lands, that houses equipment to extract hydrocarbons from the ocean or lake floor and that processes and/or transfers such hydrocarbons to storage, transport vessels, or onshore. In addition, offshore production includes secondary platform structures con nectedPage 147 of 265

DRAFT: Please do not cite, quote, or distribute to the platform structure via causeways or walkways, storage tanks associated with the platform structure and floating production storage and offloading equipment (FPSO)
. (2) Onshore petroleum and natural gas production
. Onshore petroleum and natur al gas production equipment means all structures associated with wells (including compressors, generators, or storage facilities), and portable non

- self

- propelled equipment (including well drilling and completion equipment, workover equipment, gravity sepa ration equipment, auxiliary non

- transportation

related equipment, and leased, rented or contracted equipment) used in the production, extraction, recovery, lifting, stabilization, separation or treating of petroleum and/or natural gas (including condensate ). This also includes associated storage or measurement and all enhanced oil recovery ( EOR ) operations using CO 2

(3) , and all petroleum and natural gas production located on islands, artificial islands , or structures connected by a causeway to land, an island , or artificial island. Onshore natural gas processing plants . Natural gas processing plants are designed to separate and recover natural gas liquids (NGLs) and/ or other non

- methane gases and liquids from a stream of produced natural gas throughPage 148 of 265

DRAFT: Please do not cite, quote, or distribute eq uipment performing one or more of the following processes: oil and condensate removal, water removal, separation of natural gas liquids, sulfur and carbon dioxide removal, fractionation of NGLs, or other processes, and also the capture of CO 2 separated fr om natural gas streams for delivery outside the facility. This source category also includes all residue gas compression equipment owned or operated by the natural gas processing plant, whether inside or outside the processing plant fence.
(4) Onshore na tural gas transmission compression
. Onshore natural gas transmission compression means any fixed combination of compressors that move natural gas at elevated pressure from production fields or natural gas processing facilities, in transmission pipelines, t o natural gas distribution pipelines, or into storage. In addition, transmission compressor station includes equipment for liquids separation, natural gas dehydration, and tanks for the storage of water and hydrocarbon liquids. Residue (sales) gas compres sion operated by Natural Gas Processing Facilities are included in the processing category and excluded from this category.Page 149 of 265

DRAFT: Please do not cite, quote, or distribute (5) Underground natural gas storage . Underground natural gas storage means subsurface storage, including depleted gas or oil reser voirs and salt dome caverns utilized for storing natural gas that has been transferred from its original location for the primary purpose of load balancing (the process of equalizing the receipt and delivery of natural gas); natural gas underground storage processes and operations (including compression, dehydration and flow measurement, and excluding transmission pipelines); and all the wellheads connected to the compression units located at the facility. (6) Liquefied natural gas (LNG) storage

(7) . LNG stor age means onshore LNG storage vessels located above ground, equipment for liquefying natural gas, compressors to capture and re

- liquefy boil

- off

- gas, re - condensers, and vaporization units for re

- gasification of the liquefied natural gas. LNG import an d export equipment . LNG import equipment means all onshore or offshore equipment that receives imported LNG via ship transport, stores LNG, re

gasifies LNG, and delivers re

- gasified natural gas to a natural gas transmission or distribution system. LNG

ex port equipment means all onshore or offshore equipment that receives natural gas, liquefies natural gas, storesPage 150 of 265

DRAFT: Please do not cite, quote, or distribute LNG, and transfers the LNG via ocean transportation to any location, including locations in the United States.
(8) Natural Gas Distribution
. N atural gas distribution means the distribution pipelines (not interstate pipelines or intrastate pipelines) and metering and regulating at city gate stations that physically deliver natural gas to end users
. This category excludes all customer meters and t he infrastructure and pipelines delivering natural gas directly to major industrial users and "farm taps" upstream of the local distribution company inlet. (b) [RESERVED] §98.231 Reporting threshold

(c) For applying the threshold defined in §98.2(a)(2), natural gas processing plants must also . (a) You must report GHG emissions under this subpart if your facility contains petroleum and natural gas systems and the facility meets the requirements of §98.2(a)(2). (b) For applying the threshold defined in
§ 98.2(a)(2), an onshore petroleum and natural gas production facility shall consider emissions only from the equipment specified in 98.232(c).Page 151 of 265

DRAFT: Please do not cite, quote, or distribute include owned or operated residue gas compression equipment. §98.232 GHGs to report **.** (a) You must report CO 2 , CH 4 , and N 2 O emissions from each industry segment specified in paragraph (b) through (i) of this section , CO 2 , CH 4 , and N 2 O emissions from each flare as specified in paragraph (j) of this section, and stationary combustion emissions as applicable as speci fied in paragraph (k) if this section
. (b) For offshore petroleum and natural gas production, report CO 2 and CH 4 emissions from all “stationary fugitive” and “stationary vented” source as identified in the United States Department of the Interior, Mineral s Management Service (MMS), Gulf of Mexico OCS Region, Year 2005 Gulfwide Emission Inventory Study, OCS Study MMS 2007

- 067, December 2007,(incorporated by reference, see §98.7). (c) For onshore petroleum and natural gas production, report CO 2 , CH 4 and N 2

(4) Well venting for liquids unloading. O emissions from the following source types: (1) Natural gas pneumatic device venting. (2) [ Reserved ] (3) Natural gas driven pneumatic pump venting.Page 152 of 265

DRAFT: Please do not cite, quote, or distribute (5) Gas well venting during well completions without hydraulic fracturing. (6) Gas well venting during well completions with hydraulic fracturing. (7) Gas well venting during well workovers without hydraulic fracturing. (8) Gas well venting during well workovers with hydraulic fracturing. (9) Flare stack emissions
. (10) Storage tanks. (11) Reciprocating compressor rod packing venting. (12) Well testing venting and flaring. (13) Associated gas venting and flaring. (14) Dehydrator vent stacks. (15) [ Reserved ] (16) EOR injection pump blowdown. (17) Acid gas re moval vent stack. (18) EOR hydrocarbon liquids dissolved CO 2

(2 1 ) Equipment leaks from valves, connectors, open ended lines, pressure relief valves, pumps, flanges, and other equi pment leak sources (such as instruments, loading . (19) Centrifugal compressor wet seal degassing venting. (20) [ Reserved ]Page 153 of 265

DRAFT: Please do not cite, quote, or distribute arms, pressure relief valves, stuffing boxes, compressor seals, dump lever arms, and breather caps). (2 2 ) You must use the methods in subpart W and report
CO 2 , CH 4 , and N 2 O from c ombustion emissions from st ationary and portable equipment that cannot move on roadways under its own power and drive train, and that are located at an onshore production wellhead
. Stationary and portable equipment are well drilling and completion equipment, workover equipment, deh ydrators, compressors, electrical generators, steam boilers, and heaters. (d) For onshore natural gas processing, report CO 2 and
CH 4

(e) For onshore natural gas transmission compression, report CO emissions from the following sources: (1) Reciprocating compressor rod packing venting. (2) Centrifugal compressor wet seal degassing venting. (3) Blowdown vent stacks. (4) Dehydrator vent stacks. (5) Acid gas removal vent stack. (6) Flare stack emissions
. (7) Equipment leaks from: valves, connectors, open ended lines, pressure relief valves, meters, and centrifugal c ompressor dry seals.

2 and CH 4 emissions from the following sources:Page 154 of 265

DRAFT: Please do not cite, quote, or distribute (1) Reciprocating compressor rod packing venting. (2) Centrifugal compressor wet seal degassing venting. (3) Transmissio n storage tanks. (4) Blowdown vent stacks. (5) Natural gas pneumatic device venting. (6) [Reserved] (7) Equipment leaks from connectors, block valves, control valves, compressor blowdown valves, pressure relief valves, orifice meters, other meters, reg ulators, and open ended lines. (f) For underground natural gas storage, report CO 2 and CH 4

(g) For LNG storage, report C O emissions from the following sources: (1) Reciprocating compressor rod packing venting. (2) Centrifugal compressor wet seal degassing venting. (3) Natural gas p neumatic device venting. (4) [Reserved] (5) Equipment leaks from connectors, block valves, control valves, compressor blowdown valves, pressure relief valves, orifice meters, other meters, regulators, and open ended lines.

2 and CH 4 emissions from the following sources:Page 155 of 265

DRAFT: Please do not cite, quote, or distribute (1) Reciprocating compressor rod packing venting. (2) Centrifugal compressor wet seal degassing venting. (3) Equipment leaks from valves; pump seals; connectors; vapor recovery compressors, and other equi pment leak sources. (h) LNG import and export equipment, report CO 2 and
CH 4 emissions from the following sources: (1) Reciprocating compressor rod packing venting. (2) Centrifugal compressor wet seal degassing venting. (3) Blowdown vent stacks. (4) E quipment leaks from valves, pump seals, connectors, vapor recovery compressors, and other equipment leak sources. (i) For natural gas distribution, report emissions from the following sources: (1) Above ground meters and regulators at custody transfer c ity gate stations , including equipment leak s from connectors, block valves, control valves, pressure relief valves, orifice meters, other meters, regulators, and open ended lines. Customer meters are excluded.Page 156 of 265

DRAFT: Please do not cite, quote, or distribute (2) Above ground meters and regulators at n on - custody transfer city gate stations, including station equipment leaks. Customer meters are excluded. (3) Below ground meters and regulators and vault equipment leaks. Customer meters are excluded. (4) Pipeline main equipment leaks. (5) Service lin e equipment leaks. (j) All applicable industry segments must report the
CO 2 , CH 4 , and N 2 O emissions from each flare. (k) External fuel combustion sources with a rated heat input capacity equal to or less than 5 mm B tu/hr do not need to report combustion emissions. All applicable industry segments 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 fuel combustion unit by following the requirements of subpart C. Ons hore petroleum and natural gas production must report stationary and portable combustion emissions as specified in paragraph (c) of this section under this subpart. (l) You must report under subpart PP of this part (Suppliers of Carbon Dioxide), CO 2 em issions captured and transferred off site by following the requirements of subpart PP. §98.233 Calculating GHG emissions **.**Page 157 of 265

DRAFT: Please do not cite, quote, or distribute (a) Natural gas pneumatic device venting



### 365 * 24 * * * *

, i i i s 

### Conv GHG EF Count Mass **=** . Calculate emissions from continuous high bleed, continuous low bleed, and intermittent ble ed natural gas pneumatic devices using Equation W

- 1 of this section.

(Eq. W

- 1)

Where:

Mass s,i = Annual total mass GHG emissions in metric tons CO 2 e per year at standard conditions from a natural gas pneumatic device vent, for GH G i. Count = Total number of continuous high bleed, continuous low bleed, or intermittent bleed natural gas pneumatic devices of each type. EF = Population emission factors for natural gas pneumatic device venting listed in Tables W

1A, W

- 3, and W

- 4 of this subpart for onshore petroleum and natural gas production, onshore natural gas transmission, and underground natural gas storage facilities, respectively. GHG i = For onshore petroleum and natural gas production facilities, concentration of GHG i, CH 4 or CO 2 , in produced natural gas; for facilities listed in §98.230(a)(3) through (a)(8), GHG i equals 1. Conv i = Conversion from standard cubic feet to metric tons CO 2 e; 0.000410 for CH 4 , and 0.00005357 for CO 2 . 24 * 365 = Conversion to yearly emissions estimate. (b) [Reserved] (c) Natural gas driven pneumatic pump venting. Calculate emissions from natural gas driven pneumatic pump venting using Equation W

- 2 of this section.Page 158 of 265

DRAFT: Please do not cite, quote, or distribute 

### 365 * 24 * * * *

, i i i s 

### Conv GHG EF Count Mass **=** (Eq. W

- 2) Where:

Mass s,i = Annual total mass GHG em issions in metric tons CO 2 e per year at standard conditions from all natural gas pneumatic pump venting, for GHG i. Count = Total number of natural gas pneumatic pumps. EF = Population emission factors for natural gas pneumatic pump venting listed in Ta bles W

- 1A of this subpart for onshore petroleum and natural gas production. GHG i = Concentration of GHG i, CH 4 or CO 2 , in produced natural gas. Conv i = Conversion from standard cubic feet to metric tons CO 2 e; 0.000410 for CH 4 , and 0.00005357 for CO 2 . 2 4 * 365 = Conversion to yearly emissions estimate. (d) Acid gas removal (AGR) vent stacks . For AGR vent (including processes such as amine, membrane, molecular sieve or other absorbents and adsorbents), calculate emissions for CO 2 only (not CH 4

(1) ) vented directly to the atmosphere or through a flare, engine (e.g. permeate from a membrane or de

- adsorbed gas from a pressure swing adsorber used as fuel supplement), or sulfur recovery plant using any of the calculation methodologies described in paragraph (d) of this section
. Calculation Methodology 1. If you operate and maintain a CEMS that measures CO2 emissions according to subpart C of this part, you must calculate CO2 emissions under this subpart by following the Tier 4 CalculationPage 159 of 265

DRAFT: Please do not cite, quote, or distribute Methodology and al l associated requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources). If CEMS and/or volumetric flow rate monitor are not available, you may install a CEMS that complies with the Tier 4 Calculation Methodology in sub part C of this part (General Stationary Fuel Combustion)
. (2) Calculation Methodology 2. If CEMS is not available, use the CO 2 composition and annual volume of vent stack gas to calculate emissions using Equation W

- 3 of this section.

E a,CO2 = V S * Vol CO2 (Eq. W

- 3)
Where: E a,CO2 = Annual volumetric CO 2 emissions at actual condition, in cubic feet per year. V S = Total annual volume of vent stack gas flowing out of the AGR unit in cubic feet per year at ambient condition as determined by flow meter using m ethods set forth in §98.234(b) or engineering calculation and process knowledge using best available data. Vol CO2 = Volume fraction of CO 2 content in vent gas out of the AGR unit as determined in (d)(5) of this section. (3) Calculation Methodology 3. If the CO 2 composition and annual volume of vent stack gas is not known, use the inlet or outlet gas flow rate of the acid gas removal unit to calculate emissions for CO 2 using Equation W

- 4 of this section.Page 160 of 265

DRAFT: Please do not cite, quote, or distribute E a,CO2 = V * (Vol I - Vol O ) (Eq. W

- 4)
Where: E a,CO2 = Annual volumetric CO 2 emissions at actual condition, in cubic feet per year. V = Total annual volume of natural gas flow through the AGR unit in cubic feet per year at actual condition as determined using methods specified in paragraph (d)(4) of this s ection. Vol I = Volume fraction of CO 2 content in natural gas into the AGR unit as determined in paragraph (d)(6) of this section. Vol O = Volume fraction of CO 2

(4) Record the gas flow rate of the inlet and outlet natural gas stream of an AGR unit using a meter according to methods set forth in §98.234(b). If you do not have a continuous flow meter , either install a continuous flow
meter or use an engineering calcula tion to determine the flow rate. (5) If continuous gas analyzer is not available, either install a continuous gas analyzer or take quarterly gas samples from the vent gas stream to determine Vol content in natural gas out of the AGR unit as determined in paragraph (d)(7) of this section.

CO2

(6) If a co ntinuous gas analyzer is installed on the inlet gas stream, then the continuous gas analyzer results must be used. If continuous gas analyzer is not available, either install a continuous gas analyzer or take quarterly according to methods set forth in §98.234(b).Page 161 of 265

DRAFT: Please do not cite, quote, or distribute gas samples from the inlet gas strea m to determine Vol I according to methods set forth in §98.234(b). (7) Determine volume fraction of CO 2 content in natural gas out of the AGR unit using one of the methods specified in paragraph (d)(7). (i) If a continuous gas analyzer is installed on the outlet gas stream, then the continuous gas analyzer results must be used. If a continuous gas analyzer is not available, you may install a continuous gas analyzer. (ii) If a continuous gas analyzer is not available or installed, quarterly gas samples m ay be taken from the outlet gas stream to determine Vol O according to methods set forth in §98.234(b). (iii) Use sales line quality specification for CO 2 in natural gas. (8) Calculate CO 2 volumetric emissions at standard conditions using calculations in paragraph (t) of this section. (9) Mass CO 2 emissions shall be calculated from volumetric CO 2

(e) emissions using calculations in paragraph (v) of this section. Dehydrator vent stacks . For dehydrator vent stacks, calculate annual CH 4 and CO 2 emissions u singPage 162 of 265

DRAFT: Please do not cite, quote, or distribute calculation methodologies described in paragraph s (e)(1) or (e)(2) of this section. (1) Calculation Methodology 1. Calculate annual mass emissions from dehydrator vent stacks with throughput greater than or equal to 0.4 million standard cubic feet
p er day using a software program, such as AspenTech HYSYS®
or GRI

- GLYCalc, that uses the Peng

- Robinson equation of state to calculate the equilibrium coefficient, speciates
CH 4 and CO 2 emissions from dehydrators, and has provisions to include regenerator co ntrol devices, a separator flash tank, stripping gas and a gas injection pump or gas assist pump. A minimum of the following parameters determined by engineering estimate based on best available data must be used to characterize emissions from dehydrators : (i) Feed natural gas flow rate. (ii) Feed natural gas water content. (iii) Outlet natural gas water content. (iv) Absorbent circulation pump type (natural gas pneumatic/ air pneumatic/ electric). (v) Absorbent circulation rate. (vi) Absorbent type: including triethylene glycol (TEG), diethylene glycol (DEG) or ethylene glycol (EG). (vii) Use of stripping natural gas.Page 163 of 265

DRAFT: Please do not cite, quote, or distribute (viii) Use of flash tank separator (and disposition of recovered gas). (ix) Hours operated. (x) Wet natural gas temperature and pr essure. (xi) Wet natural gas composition. Determine this parameter by selecting one of the methods described under paragraph (e)(2)(xi) of this section. (A) Use the wet natural gas composition as defined in paragraph (u)(2)(i) of this section. (B) If we t natural gas composition cannot be determined using paragraph (u)(2)(i) of this section, select a representative analysis
. (C) You may use an appropriate standard method published by a consensus

- based standards organization if such a method exists or you may use an industry standard practice as specified in §98.234 (b)(1) to sample and analyze wet natural gas composition. (D) If only composition data for dry natural gas is available, assume the wet natural gas is saturated. (2) Calculation Methodology 2. Calculate annual CH 4 and CO 2 emissions from glycol dehydrators with throughput less than 0.4 million cubic feet per day using Equation W

- 5 of this section:Page 164 of 265

DRAFT: Please do not cite, quote, or distribute 

### 1000 * *

, 

### Count EF E i i s 

### = (Eq. W

- 5 ) Where:

E s,i = Annual total volumetric GHG emissions (either C O 2 or CH 4 ) at standard conditions in cubic feet. EF i = Population emission factors for glycol dehydrators in thousand standard cubic feet per dehydrator per year. Use 73.4 for CH 4 and 3.21 for CO 2 . Count = Total number of glycol dehydrators with throughpu t less than 0.4 million cubic feet. 1000 = Conversion of EF i

(5) Dehydrators that use desiccant shall calculate emissions from the amo unt of gas vented from the vessel in thousand standard cubic to cubic feet. (3) Determine if dehydrator unit has vapor recovery. Adjust the emissions estimated in paragraphs (e)(1) or (e)(2) downward by the magnitude of emissi ons captured. (4) Calculate annual emissions from dehydrator vent stacks to flares or regenerator fire

- box/fire tubes as follows: (A) Use the dehydrator vent stack volume and gas composition as determined in paragraphs (e)(1) and (e)(2) of this section. (B) Use the calculation methodology of flare stacks in paragraph (n) of this section to determine dehydrator vent stack emissions from the flare or regenerator combustion gas vent.Page 165 of 265

DRAFT: Please do not cite, quote, or distribute every time it is depressurized for the desiccant refilling process using Equation W

- 6 of this section.
E s,n = (H*D 2 *P*P 2 *%G*365days/yr) (Eq. W

- 6 ) (4*P 1 *T*1,000cf/Mcf *100 ) Where: E s,n = Annual natural gas emissions at s tandard conditions in cubic feet. H = Height of the dehydrator vessel (ft). D = Inside diameter of the vessel (ft). P 1 = Atmospheric pressure (psia). P 2 = Pressure of the gas (psia). P = pi (3.14). %G = Percent of packed vessel volume that i s gas. T = Time between refilling (days). 100 = Conversion of %G to fraction (6) Both CH 4 and CO 2 volumetric and mass emissions shall be calculated from volumetric natural gas emissions using calculations in paragraphs (u) and (v) of this section. (f) Well venting for liquids unloadings

(1) . The emissions for well venting for liquids unloading shall be determined using one of the calculation methodologies described in paragraphs (f)(1), (f)(2) or (f)(3) of this section. Calculation Methodology 1 . F or one well of each unique well tubing diameter and producing horizon/formation combination in each gas producing field (see §98.238 forPage 166 of 265

DRAFT: Please do not cite, quote, or distribute the definition of Field) where gas wells are vented to the atmosphere to expel liquids accumulated in the tubing, a

rec ording flow meter shall be installed on the vent line used to vent gas from the well (e.g. on the vent line off the wellhead separator or atmospheric storage tank) according to methods set forth in §98.234(b). Calculate emissions from well venting for liq uids unloading using Equation W

- 7 of this section. 

## ∑ **∑ =**  h t t h t h n a FR T E

, , , * (Eq. W

- 7 )

Where: E a,n = Annual natural gas emissions at actual conditions in cubic feet. T h,t = Cumulative amount of time in hours of venting from all wells of the same tubing di ameter and producing horizon/formation combination during the year. FR h,t

(A) The average flow rate per hour of venting is calculated for each unique tubing diameter and producing horizon/formation combination in each producing field by averaging the rec orded flow rates for the recorded time of one representative well venting to the atmosphere. = Average flow rate in cubic feet per hour of the measured well venting, under actual conditions as determined in paragraph (f)(1)(i) of this section.
(i) Determine the well vent average flow rate as specified under paragraph (f)(1)(i) of this section.Page 167 of 265

DRAFT: Please do not cite, quote, or distribute (B) This average flow rate is applied to all wells in the field that have the same tubing diameter and producing horizon/formation combination, for the number of hours of venting these wells. (C) A new average flow rate is calculated every other calendar year for each reporting field and horizon starting the first calendar year of data collection. (ii) Calculate natural gas volumetric emissions at standard cond itions using calculations in paragraph (t) of this section. (2) Calculation Methodology 2 . Calculate emissions from each well venting for liquids unloading using Equation
W

- 8 of this section.

E a,n = {(0.37×10
- 3 )*CD 2 *WD*SP* N V }+{SFR*(HR

- 1.0)*Z} (Eq. W

- 8 )
Where: E a,n = Annual natural gas emissions at actual conditions, in cubic feet/year. 0.37×10 - 3 = {3.14 (pi)/4}/{14.7*144} (psia converted to pounds per square feet) CD = Casing diameter (inches). WD = Well depth to first producing horizon (feet). SP = Shu t

- in pressure (psia). N V = Number of vents per year. SFR = Average sales flow rate of gas well in cubic feet per hour. HR = Hours that the well was left open to the atmosphere during unloading.Page 168 of 265

DRAFT: Please do not cite, quote, or distribute 1.0 = Hours for average well to blowdown casing volume at shut

- in pressure. Z = If HR is less than 1.0 then Z is equal to 0. If HR is greater than or equal to 1.0 then Z is equal to 1.
(i) Calculate natural gas volumetric emissions at standard conditions using calculations in paragraph (t) of this section. (3) Calculation Methodology 3 . Calculate emissions from each well venting to the atmosphere for liquids unloading with plunger lift assist using Equation W

- 9 of this section.

E a,n = {(0.37×10
- 3 )*TD 2 *WD*SP* N V }+{SFR*(HR

- 0.5)*Z} (Eq. W

- 9 )
Where: E a,n = Annual n atural gas emissions at actual conditions, in cubic feet/year. 0.37×10 - 3 = {3.14 (pi)/4}/{14.7*144} (psia converted to pounds per square feet) TD = Tubing diameter (inches). WD = Tubing depth (feet). SP = Sales line pressure (psia). N V = Number of vents p er year. SFR = Average sales flow rate of gas well in cubic feet per hour. HR = Hours that the well was left open to the atmosphere during unloading. 0.5 = Hours for average well to blowdown tubing volume at sales line pressure.Page 169 of 265

DRAFT: Please do not cite, quote, or distribute Z = If HR is less than 0.5 then Z is equal to 0. If HR is greater than or equal to 0.5 then Z is equal to 1.
(i) Calculate natural gas volumetric emissions at standard conditions using calculations in paragraph (t) of this section. (4) Both CH 4 and CO 2 volumetric and mass e missions shall be calculated from volumetric natural gas emissions using calculations in paragraphs (u) and (v) of this section. (g) Gas well venting during completions and workovers from hydraulic fracturing . Calculate emissions from gas well venting du ring completions involving hydraulic fracturing in new wells and well workovers using Equation
W

- 10 of this section.

E a,n = T * FR (Eq. W

- 10 )
Where: E a,n

(1) The average flow rate for gas well venting to the atmosphere or to a flare during well completions and = Annual emissions in cubic feet at actual conditions from gas well venting during completions fol lowing hydraulic fracturing T = Cumulative amount of time in hours of all well completion venting in a field during the year. FR = Average flow rate in cubic feet per hour, under actual conditions, as required in paragraph (g)(1) of this section.Page 170 of 265

DRAFT: Please do not cite, quote, or distribute workovers from hydraulic fracturing shall be determined using either of the calculation methodologies described in this paragraph (g)(1). (i) Calculatio n Methodology 1

(ii) . For one well completion in each gas producing field and for one well workover in each gas producing field, a recording flow meter shall be installed on the vent line , ahead of a flare if used, to measure the backflow venting event accordi ng to methods set forth in §98.234(b). (A) The average flow rate in cubic feet per hour of venting to the atmosphere or a flare is determined from the flow recording over the period of backflow venting. (B) The respective flow rates are applied to all well completions in the field and to all well workovers in the field for the number of hours of venting these wells. (C) New flow rates for completions and workovers are calculated every other calendar year for each reporting field and horizon starting i n the first calendar year of data collection
. Calculation Methodology 2 . For one well completion in each gas producing field and for one well workover in each gas producing field, record the well flowing pressure upstream (and downstream in subsonic flow) of a well choke according to methods set forth inPage 171 of 265

DRAFT: Please do not cite, quote, or distribute §98.234(b) to calculate intermittent well flow rate of gas during venting to the atmosphere or a flare
. Calculate emissions using Equation W

- 11 for subsonic flow or Equation
W

- 12 for sonic flow:
** **  ** **  ** **  ** **  ** **  ** **  ** **  ** ** 

**− **  ** **  ** **  ** **  ****

**=** 758

. 1

1 2 515

. 1

1 2 * * 3430 * * 3

. 35 P P P P T A FR (W

- 11)

Where :
FR = Average flow rate in cubic feet per hour, under subsonic flow conditions , in cubic feet per second.
A = Cross sectional area of orifice (m 2 )
. P 1 = Upstream pressure (Pa)
. T = Upstream temperature (K)
. P 2 = Dow nstream pressure (Pa)
. 3430 = Constant with units of m 2 /sec 2 * K
. 35.3 = Conversion from m 3 to ft 3

T A FR * 08

. 187 * * 3

. 35 **=** .
(W

- 12) Where:
FR = Average flow rate in cubic feet per hour, under sonic flow conditions, in cubic feet per second.
A = Cros s sectional area of orifice (m 2 )
. T = Upstream temperature (K)
. 187.08 = C onstant with units of m 2 /sec 2 * K
. 35.3 = C onversion from m 3 to ft 3

.Page 172 of 265

DRAFT: Please do not cite, quote, or distribute (A) The average flow rate in cubic feet per hour of venting across the choke is calculated for one well

co mpletion in each field and for one well workover in each field by averaging the gas flow rates during venting to the atmosphere or a flare
. (B) The respective flow rates are applied to all well completions in the field and to all well workovers in the fi eld for the number of hours of venting these wells. (C) New flow rates for completions and workovers are calculated every other calendar year for each reporting field and horizon starting in the first calendar year of data collection
. (2) Calculate nat ural gas volumetric emissions at standard conditions using calculations in paragraph (t) of this section. (3) Both CH 4 and CO 2

(4) Calculate annual emissions from gas well venting during well completions and workovers from hydraulic fracturing to flares as follows: volumetric and mass emissions shall be calculated from volumetric natural gas emissions using calculations in paragraphs (u) and (v) of this section.Page 173 of 265

DRAFT: Please do not cite, quote, or distribute (i) Use the gas well venting volume during well completions and workovers as determined in pa ragraph (g) of this section. (ii) Use the calculation methodology of flare stacks in paragraph (n) of this section to determine gas well venting during well completions and workovers using hydraulic fracturing emissions from the flare. (h) Gas well venti ng during completions and workovers without hydraulic fracturing



### T V E n

a 

### *

, 

### = . Calculate emissions from each gas well venting during well completions and workovers not involving hydraulic fracturing using Equation W

- 1 3 of this section:
(Eq. W

- 1 3 )

Where: E a,n = Annual natural gas emissions in cubic feet at actual conditions from gas well venting during well completions or workovers without hydraulic fracturing. V = Average daily gas production rate in cubic feet per minute. This is the total annual gas production volume divided by total number of minutes the well is producing to the sales line. T = Cumulative amount of time of well venting in minutes during the year. (1) Calculate natural gas volumetric emissions at standard conditions usi ng calculations in paragraph (t) of this section.Page 174 of 265

DRAFT: Please do not cite, quote, or distribute (2) Both CH 4 and CO 2 volumetric and mass emissions shall be calculated from volumetric natural gas emissions using calculations in paragraphs (u) and (v) of this section. (3) Calculate annual emissions f rom gas well venting during well completions and workovers not involving hydraulic fracturing to flares as follows: (i) Use the gas well venting volume during well completions and workovers as determined in paragraph (h) of this section. (ii) Use the cal culation methodology of flare stacks in paragraph (n) of this section to determine gas well venting during well completions and workovers emissions without hydraulic fracturing from the flare. (i) Blowdown vent stacks

(1) Calculate the total volume (including pipelines, compressor case or cylinders, manifolds, suction and discharge bottles and vessels) between isolation valves . Calculate blowdown vent stack emissi ons from depressuri zi ng equipment to the atmosphere (excluding depressuri zi ng to a flare, over

pressure relief, operating pressure control venting and blowdown of non

- GHG gases; desiccant dehydrator blowdown venting before reloading is covered in §98.233(e )(5)) as follows:Page 175 of 265

DRAFT: Please do not cite, quote, or distribute determined by engineering estimate based on best available data. (2) If t he total volume between isolation valves is greater than or equal to 5000 standard cubic feet, retain logs of the number of blowdowns for each equipment type (including but not limited to compressors, vessels, pipelines, headers, fractionators, and tanks). Blowdown volumes smaller than 5000 standard cubic feet are exempt from reporting under paragraph (i) of this section. (3) Calculate the total annual venting emissions for each equipment type using Equation W

- 1 4 of this section: 

## ( **) (**  **) **  ** **  ** **  ** **  ****

**− **  ** **  ** **  ** **  ** +**  **+ =**  C V P T P T V N E v s a a s v n s * 67

. 459 67

. 459 *

, ( Eq. W

- 1 4 )

Where: E s,n = Annual natural gas venting emissions at standard conditions from blowdowns in cubic feet. N = Number of repetitive blowdowns for each equipment type of a unique volume in calendar year. V v = Total volume of blowdown equipment ch ambers (including pipelines, compressors and vessels) between isolation valves in cubic feet. C = Purge factor that is 1 if the equipment is not purged or zero if the equipment is purged using non - GHG gases. T s = Temperature at standard conditions ( o F). T a = Temperature at actual conditions in the blowdown equipment chamber ( o F).Page 176 of 265

DRAFT: Please do not cite, quote, or distribute P s = Absolute pressure at standard conditions (psia). P a = Absolute pressure at actual conditions in the blowdown equipment chamber (psia). (4) Calculate both CH 4 and CO 2 mass emissions from volumetric natural gas emissions using calculations in paragraph (v) of this section. (5) Calculate total annual venting emissions for all blowdown vent stacks by adding all standard volumetric and mass emissions determined in Equation W

- 1 4 and paragraph (i)(4) of this section, respectively. (j) Onshore production storage tanks . For emissions from atmospheric pressure fixed roof storage tanks receiving produced liquids from onshore petroleum and natural gas production facilities (inclu ding stationary liquid storage not owned or operated by the reporter), calculate annual CH 4 and CO 2

(1) emissions using any of the calculation methodologies described in paragraph (j) of this section. Calculation Methodology 1. For separators with oil t hroughput greater than or equal to 10 barrels per day. Calculate annual CH 4 and CO 2 emissions from onshore production storage tanks using operating conditions in the last wellhead gas

- liquid separator before liquid transfer to storage tanks
. Calculate fl ashing emissions with a software program, such as AspenTech HYSYS® or API 4697 E&PPage 177 of 265

DRAFT: Please do not cite, quote, or distribute Tank, that uses the Peng

- Robinson equation of state, models flashing emissions, and speciates CH 4 and CO 2

(B) If separator oil composition and Reid vapor pressure data are available through your previous analysis, emissions that will result when the oil from the separator enters a n atmospheric pressure storage tank. A minimum of the following parameters determined for typical operating conditions over the year by engineering estimate and process knowledge based on best available data must be used to characterize emissions from liq uid transferred to tanks. (i) Separator temperature. (ii) Separator pressure. (iii) Sales oil or stabilized oil API gravity. (iv) Sales oil or stabilized oil production rate. (vi) Ambient air temperature. (vii) Ambient air pressure. (viii) Separato r oil composition and Reid vapor pressure. If this data is not available, determine these parameters by selecting one of the methods described under paragraph (j)(1)(viii) of this section. (A) If separator oil composition and Reid vapor pressure data are provided with the software program, select the default values which most closely match your separator pressure first, and API gravity secondarily.Page 178 of 265

DRAFT: Please do not cite, quote, or distribute select the latest available analysis that is representative of produced crude oil or condensate from the field. (C) Analyze a representative sample of separator oil in each field for oil composition and Reid vapor pressure using an appropriate standard method published by a

consensus - based standards organization. (2) Calculation Methodology 2. Calculate annual CH 4 and CO 2 emissions from onshore production storage tanks for wellhead gas

- liquid separators with oil throughput greater than or equal to 10 ba rrels per day by assuming that all of the CH 4 and CO 2 in solution at separator temperature and pressure is emitted from oil sent to storage tanks. You may use an appropriate standard method published by a

consensus - based standards organization if such a me thod exists or you may use an industry standard practice as described in § 98.234(b)(1) to sample and analyze separator oil composition at separator pressure and temperature. (3) Calculation Methodology 3 . For wells with oil production greater than or equal to 10 barrels per day that flow directly to atmospheric storage tanks without passing through a wellhead separator, calculate CH 4 and CO 2 emissions by either of the methods in paragraph (j)(3) of this section :Page 179 of 265

DRAFT: Please do not cite, quote, or distribute (i) If well production oil and gas compositi ons are available through your previous analysis, select the latest available analysis that is representative of produced oil and gas from the field and assume all of the CH 4 and CO 2 in both oil and gas are emitted from the tank. (ii) If well production oi l and gas compositions are not available, use default oil and gas compositions in software programs, such as API 4697 E&P Tank, that most closely match your well production gas/oil ratio and API gravity. (4) Calculation Methodology 4 . For wells with oil
pr oduction greater than or equal to 10 barrels per day that flow to a separator not at the well pad, calculate CH 4 and
CO 2 emissions by either of the methods in paragraph (j)(4) of this section : (i) If well production oil and gas compositions are available through your previous analysis, select the latest available analysis that is representative of oil at separator pressure determined by best available data and assume all of the CH 4 and CO 2

(ii) If well production oil co mposition is not available, use default oil composition in software programs, such as API 4697 E&P Tank, that most closely in the oil is emitted from the tank.Page 180 of 265

DRAFT: Please do not cite, quote, or distribute match your well production API gravity and pressure in the off

- well pad separator determined by best available data. Assume all of th e CH 4 and CO 2 in the oil phase is emitted from the tank. (iii) Assume all of the flash gas from the default flash data is emitted from the tank for flare emissions calculation in paragraph (j) (7) of this section
. (5) Calculation Methodology 5. Calculate a nnual CH 4 and CO 2



### Count EF E i i s 

### *

, 

### = emissions from onshore production tanks based on well head gas

- liquid separators and wells flowing off the well pad without passing through a gas

- liquid separator with crude oil of less than 45 ° API gravity and throughput less than 10 bar rels per day using Equation W

- 1 5 of this section:

(Eq. W

- 1 5 ) Where:

E s,i = Annual total volumetric GHG emissions (either CO 2 or CH 4 ) at standard conditions in cubic feet. EF i = Populations emission factor for separators and wells in thousand standard cubic feet per separator or well per year, 16.1 for CH 4 and 0.707 for CO 2 . Count = Total number of separators and wells with crude oil of less than 45 ° API gravity throughput less than 10 barrels per day.Page 181 of 265

DRAFT: Please do not cite, quote, or distribute (6) Determine if the storage tan k receiving your separator oil has a vapor recovery system. (i) Adjust the emissions estimated in paragraphs (j)(1) through (j) (5) of this section downward by the magnitude of emissions recovered using a vapor recovery system as determined by engineering estimate based on best available data. (ii) [Reserved] (7) Determine if the storage tank receiving your separator oil is vented to flare(s). (i) Use your separator flash gas volume and gas composition as determined in this section. (ii) Use the calcula tion methodology of flare stacks in paragraph (n) of this section to determine your contribution to storage tank emissions from the flare. (8) Calculate emissions from occurrences of well pad
gas - liquid separator liquid dump valves not closing during the calendar year by using Equation W

- 1 6
. 

## ( **) (**  **) (**  **)** n t n n n i s 

### T E T E CF E

**− +**  **=** 8760 * * *

, (Eq. W

- 1 6 )

Where: E s,i = Annual total volumetric GHG emissions at standard conditions from each storage tank in cubic feet. E n = Storage tank emissions as determined in calculation methods 1, 2, o r 5 (with wellhead separators) of this section during time T n in cubic feet per hour.Page 182 of 265

DRAFT: Please do not cite, quote, or distribute T n = Total time the dump valve is not closing properly in the calendar year in hours. T n is estimated by maintenance or operations records (records) such that when a rec ord shows the valve to be open improperly, it is assumed the valve was open for the entire time period preceding the record starting at either the beginning of the calendar year or the previous record showing it closed properly within the calendar year . If a subsequent record shows it is closing properly, then assume from that time forward the valve closed properly until either the next record of it not closing properly or, if there is no subsequent record, the end of the calendar year
. CF n = Correction fa ctor for tank emissions for time period T n is 3.87 for sales oil less than 45 API gravity. Correction factor for tank emissions for time period T n is 5.37 for sales oil equal to or greater than 45 API gravity. Correction factor for tank emissions for tim e period T n is 1.0 for periods when the dump valve is closed. E t = Storage tank emissions as determined in calculation methods 1, 2, or 3 of this section at maintenance or operations during the time the dump valve is closing properly (ie.8760

- T n ) in cubic feet per hour. (k) Transmission storage tanks

(1) Monitor the tank vapor vent stack annually for emissions using an optical gas imaging instrument according to methods set forth in §98.234(a)(1) for a duration of 5 . For condensate storage tanks, either water or hydrocarbon, without vapor recovery or thermal control devices in onshore natural gas transmission compression facilities calculate annual emissions from compre ssor scrubber dump valve leakage as follows:Page 183 of 265

DRAFT: Please do not cite, quote, or distribute minutes . O r you may annually monitor le akage through compressor scrubber dump valve(s) into the tank using an acoustic detection device according to methods set forth in §98.234(a)(5). (2) If the tank vapors are continuous for 5 minutes , or the acoustic detection device detects a leak, then us e one of the following two methods in paragraph (k)(2) of this section to quantify emissions: (i) Use a meter, such as a turbine meter, to estimate tank vapor volumes according to methods set forth in §98.234(b). If you do not have a continuous flow

mea surement device, you may install a flow measuring device on the tank vapor vent stack. (ii) Use an acoustic detection device on each scrubber dump valve connected to the tank according to the method set forth in §98.234(a)(5). (iii) Use the appropriate ga s composition in paragraph (u)(2)(iii) of this section. (3) If the leaking dump valve(s) is fixed following leak detection, the annual emissions shall be calculated from the beginning of the calendar year to the time the valve(s) is repaired. (4) Calculat e emissions from storage tanks to flares as follows:Page 184 of 265

DRAFT: Please do not cite, quote, or distribute (i) Use the storage tank emissions volume and gas composition as determined in paragraph (j)(1) of this section. (ii) Use the calculation methodology of flare stacks in paragraph (n) of this section to determine storage tank emissions from the flare. (l) Well testing venting and flaring.



### D FR GOR E n

a 

### * *

, 

### = Calculate well testing venting and flaring emissions as follows: (1) D etermine the gas to oil ratio (GOR) of the hydrocarbon production from each well tested. (2) I f GOR cannot be determined from your available data, then you must measure quantities reported in §98.233 according to one of the two procedure s in paragraph (l)(2) of this section to determine GOR : (i) You may use an appropriate standard method published by a consensus

- based standards organization if such a method exists
. (ii) Or you may use an industry standard practice as described in § 98.234(b)(1). (3) Estimate venting emissions using Equation W

- 1 7 of this section.
(Eq. W

- 1 7 )

Where:Page 185 of 265

DRAFT: Please do not cite, quote, or distribute E a,n = Annual volumetric natural gas emissions from well testing in cubic feet under actual conditions. GOR = Gas to oil ratio in cubic feet of gas per barrel of oil; oil here refers to hydrocarbon liquids produced of all API gravities. FR = Flow r ate in barrels of oil per day for the well being tested. D = Number of days during the year, the well is tested. (4) Calculate natural gas volumetric emissions at standard conditions using calculations in paragraph (t) of this section. (5) Calculate bot h CH 4 and CO 2

(m) volumetric and mass emissions from volumetric natural gas emissions using calculations in paragraphs (u) and (v) of this section. (6) Calculate emissions from well testing to flares as follows: (i) Use the well testing emissions volume and gas composition as determined in paragraphs (l)(1) through (3) of this section. (ii) Use the calculation methodology of flare stacks in paragraph (n) of this section to determine well testing emissions from the flare. Associated gas venting and flari ng . Calculate associated gas venting and flaring emissions not in conjunction with well testing (refer to paragraph (l) of this section) as follows:Page 186 of 265

DRAFT: Please do not cite, quote, or distribute (1) D etermine the GOR ratio of the hydrocarbon production from each well whose associated natural gas is vented or flared. If GOR from each well is not available, the GOR from a cluster of wells in the same field shall be used. ( 2 ) If GOR cannot be determined from your available data, then use one of the two procedures in paragraph (m)(2) of this section to determine GOR: (i) Y ou may use an appropriate standard method published by a consensus

- based standards organization if such a method exists. (ii) Or you may use an industry standard practice as described in § 98.234(b)(1). ( 3 ) Estimate venting emissions using Equation W

- 1 8 of this section.


### V GOR E n

a 

### *

, 

### = (Eq. W

- 1 8 )

Where: E a,n = Annual volumetric natural gas emissions from associated gas venting under actual conditions, in cubic feet. GOR = Gas to oil ratio in cubic feet of gas per barrel of oil ; oil here refers to hydrocarbon liquids produced of all API gravities. V = Total volume of oil produced in barrels in the calendar year.Page 187 of 265

DRAFT: Please do not cite, quote, or distribute ( 4 ) Calculate natural gas volumetric emissions at standard conditions using calculations in paragraph (t) of this sec tion. ( 5 ) Calculate both CH 4 and CO 2 volumetric and mass emissions from volumetric natural gas emissions using calculations in paragraphs (u) and (v) of this section. ( 6 ) Calculate emissions from associated natural gas to flares as follows: (i) Use the associated natural gas volume and gas composition as determined in paragraph (m)(1) through ( 4 ) of this section. (ii) Use the calculation methodology of flare stacks in paragraph (n) of this section to determine associated gas emissions from the flare. (n ) Flare stack emissions . Calculate emissions from a flare stack as follows: (1) If you have a continuous flow measurement device on the flare, you must use the measured flow volumes to calculate the flare gas emissions. If you do not have a continuous flow measurement device on the flare, you can install a flow measuring device on the flare or use engineering calculations based on process knowledge, company records, and best available data.Page 188 of 265

DRAFT: Please do not cite, quote, or distribute (2) If you have a continuous gas composition analyzer
on gas to the flare, you must use these compositions in calculating emissions. If you do not have a continuous gas composition analyzer on gas to the flare, you must use the appropriate gas compositions for each stream of hydrocarbons going to the flare as follo ws: (i) For onshore natural gas production, determine natural gas composition using (u)(2)(i) of this section. (ii) For onshore natural gas processing, when the stream going to flare is natural gas, use the GHG mole percent in feed natural gas for all st reams upstream of the de

- methanizer or dew point control, and GHG mole percent in facility specific residue gas to transmission pipeline systems for all emissions sources downstream of the de

methanizer overhead or dew point control for onshore natural gas processing facilities. (iii) When the stream going to the flare is a hydrocarbon product stream, such as ethane, propane, butane, pentane

- plus and mixed light hydrocarbons , then use a representative composition from the source for the stream determined b y engineering calculation based on process knowledge and best available data.Page 189 of 265

DRAFT: Please do not cite, quote, or distribute (3) Determine flare combustion efficiency from manufacturer. If not available, assume that flare combustion efficiency is 98 percent. (4) Calculate GHG volumetric emissions at actual conditions using Equations W

- 1 9 , W

- 20 , and W

- 21 of this section. 

### ( **)** 4 4 , * ) 1 ( * CH a CH a X V combusted un E **η −**  **= −**  (Eq. W

- 1 9 ) 

## ( **)** 2 2 , * CO a CO a X V combusted un E **= −**  (Eq. W

- 20 ) 

## ( **)** 

## ∑ **=** j j j a CO a R Y V combusted E * * * 2 , **η** (Eq. W

- 21 )

Where: E a,CH4 (un

- combusted) = Contribution of annual un

- combusted CH 4 emissio ns from flare stack in cubic feet, under actual conditions. E a,CO2 (un

- combusted) = Contribution of annual un

- combusted CO 2 emissions from flare stack in cubic feet, under actual conditions. E a,CO2 (combusted) = Contribution of annual combusted CO 2 emissions from flare stack in cubic feet, under actual conditions. V a = Volume of gas sent to flare in cubic feet, during the year. η = Fraction of gas combusted by a burning flare (default is 0.98). For gas sent to an unlit flare, η is zero.X CH4 = Mole fraction of CH 4 in gas to the flare. X CO2 = Mole fraction of CO 2 in gas to the flare. Y j = Mole fraction of gas hydrocarbon consti tuents j (such as methane, ethane, propane, butane, and pentanes

plus).Page 190 of 265

DRAFT: Please do not cite, quote, or distribute R j = Number of carbon atoms in the gas hydrocarbon constituent j : 1 for methane, 2 for ethane, 3 for propane, 4 for butane, and 5 for pentanes plus). (5) Calculate GHG volumetric emis sions at standard conditions using calculations in paragraph (t) of this section. (6) Calculate both CH 4 and CO 2 mass emissions from volumetric CH 4 and CO 2 emissions using calculation in paragraph (v) of this section. (7) Calculate total annual emission from flare stacks using Equation W

- 4 0 in paragraph (z) of this section
. (8) Calculate N 2 O emissions from flare stacks using Equation W

- 39 in paragraph (z) of this section. (9) The flare emissions determined under paragraph (n) of this section must be co rrected for flare emissions calculated and reported under other paragraphs of this section to avoid double counting of these emissions. (o) Centrifugal compressor venting

(1) For each centrifugal compressor covered by §98.232 (d)(2), (e)(2), (f)(2), (g)(2), and (h)(2) determine the volume of vapors from wet seal oil degassing tank sent to an atmospheric vent or flare , using a temporary or permanent flow meter such as a vane anemometer . Calculate emissions from centrifugal compressor vents as follows:Page 191 of 265

DRAFT: Please do not cite, quote, or distribute according to methods set forth in §98.234(b) , and the steps listed in paragraphs (o)(2) through (o)(8) of this section
. If you do not have a permanent flow meter , you may install

a permanent flow meter on the wet seal oil degassing tank
vent. (i) Estimat e annual emissions using the flow meter measurement and Equation W

- 2 2 of this section. 

### ) 1 ( * * *

, 

### B M T MT E i i s 

### −

**=** (Eq. W

- 2 2 )

Where: E s,i = Annual GHG i (either CH 4 or CO 2 ) volumetric emissions at standard conditions, as specified in paragraph s (o)(3)(i) t hrou gh (iv) of this section in cubic feet. MT = Meter reading of gas emissions in standard cubic feet per hour. T = Total time the compressor associated with the wet seal(s) is operational in the calendar year in hours. M i

(2) You must conduct an annual measurement for each compressor, except as specified in paragraph (o)(4) of this section. Measure em issions from all vents (including emissions manifolded to common vents) including unit = Mole fraction of GHG i in the degas sing vent gas; use the appropriate gas compositions in paragraph (u)(2) of this section. B = Fraction of operating time that centrifugal compressor wet seal degassing vent gas is sent to vapor recovery or fuel gas as determined by keeping logs of the numbe r of operating hours for the vapor recovery system and the time that vent gas is directed to the fuel gas system or sales
.Page 192 of 265

DRAFT: Please do not cite, quote, or distribute isolation valves and blowdown vents using a temporary meter such as a vane anemometer or a permanent meter such as an orifice meter according to methods set forth in §98 .234(b). If you do not have a flow meter , you may install a port for insertion of a temporary meter , or a permanent flow meter, on the vents. For blowdown vents, you can use one of the following end of pipe methods: calibrated bagging or high volume samp ler according to methods set forth in §98.234 (c) and §98.234(d), respectively. For through

- valve leakage to open ended vents, such as unit isolation valves on shutdown, depressurized compressors and blowdown valves on pressurized compressors, you may use an acoustic detection device according to methods set forth in §98.234(a). Record the vent type and the mode of the compressor, during the annual measurement as follows: (i) Operating mode, blowdown vents. (ii) Operating mode, wet seal oil degassing v ents. (iii) Not operating, depressurized mode, unit isolation valves , without blind flanges, leakage through open blowdown vent. (3) Each compressor must be measured at least once in any three consecutive calendar year s , in each mode in paragraph s (o)(3) (i) through (o)(3)(iii) of this section.Page 193 of 265

DRAFT: Please do not cite, quote, or distribute (4) You must combine emissions separately from paragraph (o)(3)(i) of this section for blowndown vents, measured in the operating or standby, pressurized mode, and from paragraph (o)(3)(iii) of this section for uni t isolation valve leakage in shutdown, depressurized mode. (5) You must combine emissions from paragraph (o)(3)(ii) for seal oil degassing vent in the operating mode. (6) You shall use the flow meter readings at standard conditions for all vented sources calculated in paragraph (o)(1), (o)(2), (o)(3), (o)(4), (o)(5), (o)(6), and (o)(7) of this section to develop for each reporter the three emission factors using Eq uation W

- 2 3 of this section. The emission factors must be calculated annually
. You must us e all measurements from the current calendar year and the preceding two calendar years, totaling three consecutive calendar year s of measurements in paragraph (o)(4) of this section
. 

## ∑ **=**
m m m Count MT EF (Eq. W

- 2 3 )
Where:

EF m = Reporter emission factors for compressor in the three modes i (operating blowdown vent, operating wet seal oil degassing vent, and not operating, depressurized) in cubic feet per hour.Page 194 of 265

DRAFT: Please do not cite, quote, or distribute MT m = Meter readings from all centrifugal compressor vents in each mode in (o)(3)(i) through (o) (3)(iii) of this section in cubic feet per hour. Count m



## ∑ **=** i i i i i s GHG T EF E * *

, = Total number of compressors measured from paragraphs (o)(3)(i) through (o)(3)(iii) of this section
. (7) Calculate emissions from each centrifugal compressor, with wet or dry seals, using Equation W

- 2 4 of this section.
(Eq. W

- 2 4 )

Where: E s,i = Annual total volumetric GHG emissions at standard conditions from each centrifugal compressor in cubic feet. EF m = Reporter emission factor for each mode i, in cubic feet per hour, from Eq. W

- 2 3 of this section. T m = Total time in hours per year the compressor was in each mode of Eq. W

- 2 3 of this section, with operating blowdown vent time including time in standby, depressurized mode. GHG i = For onshore natural gas processing facilities, concentration of GHG i, CH 4 or CO 2 , in produced natural gas or feed natural gas; for other facilities listed in §98.230 (a)(3) through (a)(8),GHG i

i i s 

### EF Count E *

, 

### = equals 1. (8) Onshore petroleum and natural gas production shall calculate emissions from centrifugal compre ssor wet seal oil degassing vents as follows:
(Eq. W

- 2 5 )

Where:Page 195 of 265

DRAFT: Please do not cite, quote, or distribute E s,i = Annual total volumetric GHG emissions at standard conditions from centrifugal compressor wet seals in cubic feet. Count = Total number of centrifugal compressors for the reporter. EF i = Emission factor for GHG i. Use 12 thousand standard cubic feet per year per compressor for CH 4 and 530 thousand standard cubic feet per year per compressor for CO 2 .
( 9 ) Calculate both CH 4 and CO 2 mass emissions from volumetric e missions using calculations in paragraph (v) of this section. ( 10 ) Calculate emissions from seal oil degassing vent vapors to flares as follows: (i) Use the seal oil degassing vent vapor volume and gas composition as determined in paragraphs (o)(1) throu gh (3) of this section. (ii) Use the calculation methodology of flare stacks in paragraph (n) of this section to determine degassing vent vapor emissions from the flare. (p) Reciprocating compressor venting

(1) For each reciprocating compressor rod packing vent covered in §98.232 (d)(1), (e)(1), (f)(1), (g)(1), and (h)(1) using a meter flow measurement according to methods set forth in §98.234(b) and Equation W

- 2 6 of this section. . Calculate emissions from all reciprocating co mpressor vents as follows:Page 196 of 265

DRAFT: Please do not cite, quote, or distribute i i s 

### M T MT E * *

, 

### = (Eq. W

- 2 6 )

Where: E s,i = Annual GHG i (either CH 4 or CO 2 ) volumetric emissions at standard conditions, as specified in paragraph s (p)(4)(i) through (v) of this section in cubic feet. MT = Meter volumetric reading of gas emissions s tandard cubic feet per hour. T = Total time the compressor associated with the venting is operational in the calendar year in hours. M i

(ii) Use a temporary meter such as a vane anemometer
or a pe rmanent meter such as an orifice meter to measure emissions from all vents (including emissions manifolded to a common vent) including rod packing vents, unit isolation valve vents, and blowdown vents according to methods set = Mole fraction of GHG i in the vent gas; use the appropriate gas compositions in paragraph (u)(2) of this section. (2 ) If the rod packing case is connected to an open ended vent line then use one of the following two methods to calculate emissions **.** (i) Measure emissions from all vents (including emissions manifolded to common vents) including rod packing, unit isolatio n valves, and blowdown vents using one of the following end of pipe methods: calibrated bagging or high volume sampler according to methods set forth in §98.234 (c) and §98.234(d), respectively.Page 197 of 265

DRAFT: Please do not cite, quote, or distribute forth in §98.234(b). If you d o not have a permanent flow
meter , you may install a port for insertion of a temporary meter or a permanent flow meter on the vents. For through

valve leakage to open ended vents, such as unit isolation valves on shutdown, depressurized compressors and bl owdown valves on pressurized compressors, you may use an acoustic detection device according to methods set forth in §98.234(a). (3) If a rod packing case is not equipped with a vent line use the following method to measure emissions: (i) You must use th e methods described in §98.234 (a) to conduct annual leak detection of equipment leaks from the packing case into an open distance piece, or from the compressor crank case breather cap or other vent with a closed distance piece. (ii) Measure emissions fou nd in paragraph (p)(3)(i) of this section using a appropriate meter, or calibrated bag, or high volume sampler according to methods set forth in §98.234(b), (c), and (d), respectively. (4) You must conduct an annual measurement for each compressor, except as specified in paragraph (p)(5) of this section. Record the vent type and the mode of the compressor during the annual measurement as follows:Page 198 of 265

DRAFT: Please do not cite, quote, or distribute (i) Operating and standby pressurized mode, blowdown vent not manifolded to rod packing vents. (ii) Operati ng mode, rod packing emissions from paragraphs (p)(2) or (p)(3) of this section. (iii) Not operating, depressurized mode, unit isolation valves , without blind flanges, leakage through open blowdown vent. (5) Each compressor must be measured at least once in any three consecutive calendar year s , in each mode in paragraph s (p)(4)(i) through (iii) of this section. (6) You must combine emissions separately from paragraph (p)(4)(i) of this section for blowndown vents, measured in the operating and standby pres surized modes, and from (p)(4)(iii) for unit isolation valve leakage in shutdown depressurized mode. (7) You must combine emissions separately from paragraph (p)(4)(ii) for rod packing in operating mode and in standby pressurized mode. (8) You shall use the meter readings at standard conditions for all vented sources calculated in paragraph (p)(1), (p)(2), (p)(3), (p)(4), (p)(5), (p)(6), and (p)(7) of this section to develop for each reporter the three emission factors using Eq uation W

- 2 7 of this section. The emission factors must be calculated annually. You must usePage 199 of 265

DRAFT: Please do not cite, quote, or distribute all measurements from the current calendar year and the preceding two calendar years, totaling three consecutive calendar year s of measurements in paragraph (p)(5) of this section
. 

## ∑ **=**
m m m Count MT EF (Eq. W

- 2 7 )
Where:

EF m = Reporter emission factor for compressor in the three modes i (operating and standby pressurized, operating mode rod packing, and not operating, depressurized) in cubic feet per hour. MT m = Meter readings from all reci procating compressor vents in each mode in paragraphs (p)(4)(i) through (p)(4)(iii) of this section in cubic feet per hour. Count m



## ∑ **=** i i i i i s GHG T EF E * *

, = Total number of compressors measured from paragraphs (p)(4)(i) through (p)(4)(iii) of this section
. (9) Calculate emissions from each compressor using Equation W

- 2 8 of this section.
(Eq. W

- 2 8 )

Where: E s,i = Annual total volumetric GHG emissions at standard conditions from each compressor in cubic feet. EF m = Reporter emission factor for each mode i, in cubic feet per hour, from Eq. W

- 2 7 of this section. T m = Total time in hours per year the compressor was in each mode of Eq. W

- 2 7 of this section.Page 200 of 265

DRAFT: Please do not cite, quote, or distribute GHG i = For onshore natural gas processing facilities, concentration of GHG i, CH 4 or CO 2 , in produced natural gas or feed natural gas; for other facilities listed in §98.230 (a)(3) through (a)(8),GHG i

i i s 

### EF Count E *

, 

### = equals 1. (10) Onshore petroleum and natural gas production shall calculate emissions from reciprocating compressor rod packing venting as follows:
(Eq. W

- 2 9 )

Where: E s,i = Annual total volumetric GHG emissions at standard conditions from reciprocating compressor rod packings in cubic feet. Count = Total number of reciprocating compressors for the reporter. EF i = Emission factor for GHG i. U se 9.48 thousand standard cubic feet per year per compressor for CH 4 and 0.527 thousand standard cubic feet per year per compressor for CO 2 . ( 11 ) Estimate CH 4 and CO 2

(q) volumetric and mass emissions from volumetric natural gas emissions using the calculatio ns in paragraphs (u) and (v) of this section. Leak detection and leaker emission factors . You must use the methods described in §98.234(a) to conduct leak detection(s) of equipment leaks from all sources listed in **§** 98.232(d)(7), (e)(7), (f)(5), (g)(3 ), (h)(4), and (i)(1). This paragraph (q) applies to emissions sources in streams with gas content greater than 10 percent
CH 4 plus CO 2 by weight. Emissions sources in streams withPage 201 of 265

DRAFT: Please do not cite, quote, or distribute gas content less than 10 percent CH 4 plus CO 2

s s i s i s 

### T Count GHG EF E * * *

, 

### = by weight do not need to b e reported. Tubing systems equal to or less than one half inch diameter are exempt from the requirements of paragraph (q) of this section and do not need to be reported. If equipment leaks are detected for sources listed in this paragraph, calculate emis sions using Equation W

- 30 of this section for each source with equipment leaks.
(Eq. W

- 30 )

Where: E s,i = Annual total volumetric GHG emissions at standard conditions from each equipment leak source in cubic feet. EF s = Leaker emis sion factor for specific sources listed in Table W

- 2 through Table W

- 7 of this subpart. GHG i = For onshore natural gas processing facilities, concentration of GHG i , CH 4 or CO 2 , in the total hydrocarbon of the feed natural gas; for other facilities listed i n §98.230(a)(3) through (a)(8), GHG i equals 1 for CH 4 and 1.1 × 10 - 2 for CO 2 . Count s = Total number of this type of emission source found to be leaking during T s T .

s = The total time the component was found leaking and operational, in hours. If one leak d etection survey is conducted, assume the component was leaking for the entire calendar year . If multiple leak detection surveys are conducted, assume that the component found to be leaking has been leaking since the previous survey or the beginning of the calendar year . For the last leak detection survey in the calendar year ,Page 202 of 265

DRAFT: Please do not cite, quote, or distribute

assume that all leaking components continue to leak until the end of the calendar year
. (1) You must select to conduct either one leak detection survey in a calendar year or multiple complete leak detection surveys in a calendar year . The number of leak detection surveys selected must be conducted during the calendar year
. (2) Calculate GHG mass emissions in carbon dioxide equivalent at standard conditions using calculations in
para graph (v) of this section. (3) Onshore natural gas processing facilities shall use the appropriate default leaker emission factors listed in Table W

- 2 of this subpart for equipment leaks detected from valves , connectors , open ended lines , pressure relief valves , and meters. (4) Onshore natural gas transmission compression facilities shall use the appropriate default leaker emission factors listed in Table W

- 3 of this subpart for equipment leaks detected from connectors , block valves , control valves , compr essor blowdown valves , pressure relief valves , orifice meters , other meters , regulators , and open ended lines. (5) Underground natural gas storage facilities for storage stations shall use the appropriate default leaker emission factors listed in Table W

- 4 of this subpart forPage 203 of 265

DRAFT: Please do not cite, quote, or distribute equipment leaks detected from connectors , block valves , control valves , compressor blowdown valves , pressure relief valves , orifice meters , other meters , regulators , and open ended lines. (6) LNG storage facilities shall use the app ropriate default leaker emission factors listed in Table W

- 5 of this subpart for equipment leaks detected from valves , pump seals , connectors , and other. (7) LNG import and export facilities shall use the appropriate default leaker emission factors listed in Table
W

- 6 of this subpart for equipment leaks detected from valves , pump seals , connectors , and other. (8) Natural gas distribution facilities for above ground meters and regulators at city gate stations at custody transfer, shall use the appropriate default leaker emission factors listed in Table W

- 7 of this subpart for equipment leak detected from connectors , block valves , control valves , pressure relief valves , orifice meters , other meters , regulators , and open ended lines. (r) Population count and emission factors . This paragraph applies to emissions sources listed in **§** 98.232 (c)(1), (c)(3), (c)(21), (e)(5), (f)(3), (f)(5), (g)(1), (g)(2), (h)(1), (h)(2), (i)(2), (i)(3), (i)(4) and (i)(5) , on streams with gas content greater than 10 percent CH 4Page 204 of 265

DRAFT: Please do not cite, quote, or distribute p lus CO 2 by weight. Emissions sources in streams with gas content less than 10 percent CH 4 plus CO 2

s i s s i s 

### T GHG EF Count E * * *

, 

### = by weight do not need to be reported. Tubing systems equal or less than one half inch diameter are exempt from the requirements of paragraph (r) of this se ction and do not need to be reported. Calculate emissions from all sources listed in this paragraph using Equation W

- 3 1 of this section.
(Eq. W

- 3 1 )

Where: E s,i = Annual volumetric GHG emissions at standard conditions from each equi pment leak source in cubic feet. Count s = Total number of this type of emission source at the facility. Average component counts are provided by major equipment piece in Table W

- 1B and Table W

- 1 C . Use average component counts as appropriate for operation s in Eastern and Western U.S., according to Table W

- 1D
. EF s = Population emission factor for the specific source, s listed in Table W

- 1 A and Table W

- 3 through Table W

- 7 of this subpart. Use appropriate population emission factor for operations in Eastern and Western U.S., according to Table W

- 1D
. EF for non

- custody transfer city gate stations is determined in Eq. W

- 3 2
. GHG i = For onshore petroleum and natural gas production facilities and onshore natural gas processing facilities, concentration of GHG i, CH 4 or CO 2 , in produced natural gas or feed natural gas; for other facilities listed in §98.230 (a)(3) through (a)(8),GHG i equals 1 for CH 4 and 1.1 × 10 - 2 for CO 2 .Page 205 of 265

DRAFT: Please do not cite, quote, or distribute T s = Total time the specific source s associated with the equipment leak emission was operat ional in the calendar year, in hours.
(1) Calculate both CH 4 and CO 2 mass emissions from volumetric emissions using calculations in paragraph (v) of this section. (2) Onshore petroleum and natural gas production facilities shall use the appropriate defa ult population emission factors listed in Table W

- 1A of this subpart for equipment leaks from valves , connectors , open ended lines , pressure relief valves , pump , flanges , and other. Where components are in multi

- phase service, use the gas service emission s factors if one of the phases is gas. Where facilities conduct EOR operations the emissions factor listed in Table W

- 1A shall be used to estimate all streams of gases, including recycle CO 2 stream. The component count can be determined using either of t he methodologies described in this paragraph (r)(2). The same methodology must be used for the entire calendar year. (i) Component Count Methodology 1 . For all onshore natural gas and oil production operations in the facility perform the following activ ities ; (A) Count all major equipment listed in Table W

- 1B and Table W

- 1C.Page 206 of 265

DRAFT: Please do not cite, quote, or distribute (B) Multiply major equipment counts by the average component counts listed in Table W

- 1B and W

- 1C for onshore natural gas production and onshore oil production respectively. Use th e appropriate factor in Table W

- 1A for operations in Eastern and Western U.S. according to the mapping in Table W

- 1D. (ii) Component Count Methodology 2 . Count each component individually for the facility. Use the appropriate factor in Table W

- 1A for op erations in Eastern and Western U.S. according to the mapping in Table W

- 1D. (3) Underground natural gas storage facilities for storage wellheads shall use the appropriate default population emission factors listed in Table W

- 4 of this subpart for equipme nt leak from connectors , valves , pressure relief valves , and open ended lines. (4) LNG storage facilities shall use the appropriate default population emission factors listed in Table W

- 5 of this subpart for equipment leak from vapor recovery
compressors. (5) LNG import and export facilities shall use the appropriate default population emission factor listed in Table W

- 6 of this subpart for equipment leak from vapor
recovery compressors.Page 207 of 265

DRAFT: Please do not cite, quote, or distribute (6) Natural gas distribution facilities shall use the appropriate e mission factors as described in paragraph (r)( 6 ) of this section. (i) Below grade meters and regulators ; mains; and services, shall use the appropriate default population emission factors listed in Table W

- 7 of this subpart. (ii) Above grade meters and regulators at city gate stations not at custody transfer as listed in §98.232(i)(2), shall use the total volumetric GHG emissions at standard conditions for all equipment leak sources calculated in paragraph (q)( 8 ) of this section to develop facility emiss ion factors using Equation W

- 3 2 of this section. The calculated facility emission factor from Equation W

- 3 2 of this section shall be used in Equation W

3 1 of this section.

Count E EF i s , 

## ∑ **=** (Eq. W

- 3 2 )
Where:

EF = Facility emission factor for a meter at above grade M&R at city gate stations not at custody transfer in cubic feet per meter per year. E s,i = Annual volumetric GHG emissions at standard condition from all equipment leak sources at all above grade M&R city gate stations at custody transfer, from paragraph (q)(8) of this section
. Count = Total number of meter runs at all above grade M&R city gate stations at custody transfer.Page 208 of 265

DRAFT: Please do not cite, quote, or distribute (s) Offshore petroleum and natural gas production facilities.

(ii) In subsequent calendar years when MMS publishes an updated Gulfwide Air Emissions I nventory study, reporters shall report emissions based on the latest MMS GOADS/DBMS methodology. Report GHG emissions from all “stationary fugitive” and “stationary vented” sources for each platform as identified in the United States Department of the Interior, Minerals Management Service (MMS), Gulf of Mexico OCS Region, Year 2005 Gulfwide Emission Inventory Study, OCS Study MMS 2007

- 067, December 2007, (incorporated by reference, see §98.7). (1) MMS Gulfwide Emissions Inventory Study Reporters. Offshore production facilities reporting under the MMS Gulfwide Emissions Inventory Study (referred to as GOADS, although GOADS is an emissions activity database) will report where available the same annual emissions as calculated by MMS using activity data submitted by platform operators in the latest Gulfwide Offshore Activity Data System (GOADS) program and emissions calculated by MMS’s Data Base Management Syst em (DBMS). (i) For 2011 calendar year, report the latest published emissions from MMS GOADS/DBMS methodology for platforms in service in the GOADS/DBMS study year.Page 209 of 265

DRAFT: Please do not cite, quote, or distribute (iii) For each calendar year that does not overlap with the MMS publication of a new study, report for platforms operating in the current year that were opera ting in the last published MMS Gulfwide Air Emissions study, adjusted based on the operating time for each platform relative to the latest published MMS study. (2) Non

- MMS GOADS Reporters. Offshore production facilities that do not report under the MMS G OADS program shall collect monthly activity data from platform sources for the first calendar year in accordance with the latest MMS GOADS program instructions and calculate GHG emissions using the latest MMS GOADS program emission factors and methodologie s. (i) In subsequent calendar years, facilities not under GOADS jurisdiction shall follow the data collection cycle as required in the MMS Gulfwide Air Emissions Study by collecting new monthly activity data, estimating GHG emissions using the latest MM S GOADS program emission factors and methodologies and report those emissions. (ii) For each calendar year that does not overlap with a new MMS GOADS study publication, report the last reported emissions data with emissions adjusted based on the operating time for each platform relative to operating time in the latest MMS published study.Page 210 of 265

DRAFT: Please do not cite, quote, or distribute (3) For either first or subsequent year reporting, platforms either within or outside of MMS GOADS jurisdiction that were not covered in the previous MMS data collectio n cycle shall collect monthly activity data from platform sources in accordance with the latest MMS GOADS program instructions and calculate GHG emissions using the latest MMS GOADS program emission factors and methodologies. (4) If MMS discontinues or delays their GOADS survey by more than 4 years, then Platform operators shall collect monthly activity data every 4 years from platform sources in accordance with the latest published version of the MMS GOADS program instructions, beginning in the year tha t the GOADS survey would have been conducted, and annual GHG emissions shall be calculated using latest MMS GOADS program emission factors and methodologies. (t) Volumetric emissions

(1) Calculate natural gas volumetric emissions at standard conditions by converting actual temperature and pressure of n atural gas emissions to standard temperature . Calculate volumetric emissions at standard conditions as specified in paragraphs (t)(1) or (2) of this section determined by engineering estimate based on best available data unless otherwise specified
.Page 211 of 2 65

DRAFT: Please do not cite, quote, or distribute and pressure of natural gas using Equation W

- 3 3 of this section. 

## ( **) (**  **)** a a a s n a n s P T P T E E * 67

. 459 * 67

. 459 *

,

, **+ +** 
**=** (Eq. W

- 3 3 )

Where: E s,n = Natural gas volumetric emissions at standard temperature and pressure (STP) conditions in cubic feet. E a,n = Natural gas volumetric emissions at actual conditions in cubic feet. T s = Temperature at standard conditions. ( o F). T a = Temperature at actual emission conditions. ( o F). P s = Absolute pressure at standard conditions (psia). P a



### ( **) (**  **)** s a a s i a i s P T P T E E * 67

. 459 * 97

. 459 *

,

, **+ +** 

**=** = Abso lute pressure at actual conditions (psia).
(2) Calculate GHG volumetric emissions at standard conditions by converting actual temperature and pressure of GHG emissions to standard temperature and pressure using Equation W

- 3 4 of this section.
(Eq. W

- 3 4 )

Where: E s,i = GHG i volumetric emissions at standard temperature and pressure (STP) conditions in cubic feet. E a,i = GHG i volumetric emissions at actual conditions in cubic feet. T s = Temperature at standard conditions. ( o F). T a = Temperature at actual emission conditions. ( o P F).

s = Absolute pressure at standard conditions (psia).Page 212 of 265

DRAFT: Please do not cite, quote, or distribute P a = Absolute pressure at actual conditions (psia).
(u) GHG volumetric emissions
. Calculate GHG volumetric emissions at standard conditions as specified in
parag raphs (u)(1) and (2) of this section determined by engineering estimate based on best available data unless otherwise specified
. (1) Estimate CH 4 and CO 2

i n s i s M E E *

, , **=** emissions from natural gas emissions using Equation W

- 3 5 of this section.
(Eq. W

- 3 5 )
Where: E s,i = GHG i (either CH 4 or CO 2 ) volumetric emissions at standard conditions in cubic feet. E s,n = Natural gas volumetric emissions at standard conditions in cubic feet. M i = Mole fraction of GHG i in the natural gas. (2) For Equation W

- 3 5 of this section, th e mole fraction , M i

(i) GHG mole fraction in produced natural gas for onshore petroleum and natural gas production facilities
. If you have a continuous gas composition analyzer for produced natural gas, you must use these values for determining the mole fraction . If you do not have a , shall be the annual average mole fraction for each facility, as specified in paragraphs (u)(2)(i) through (vii) of this section.Page 213 of 265

DRAFT: Please do not cite, quote, or distribute continuous gas composition analyzer, then you must use your annual average gas composition bas ed on available sample analysis. (ii) GHG mole fraction in feed natural gas for all emissions sources upstream of the de

- methanizer and GHG mole fraction in facility specific residue gas to transmission pipeline systems for all emissions sources downstrea m of the de

- methanizer overhead for onshore natural gas processing facilities. If you have a continuous gas composition analyzer on feed natural gas, you must use these values for determining the mole fraction . If you do not have a continuous gas composi tion analyzer, then annual samples must be taken according to methods set forth in §98.234(b). (iii) GHG mole fraction in transmission pipeline natural gas that passes through the facility for onshore natural gas transmission compression facilities. (iv) GHG mole fraction in natural gas stored in underground natural gas storage facilities. (v) GHG mole fraction in natural gas stored in LNG storage facilities. (vi) GHG mole fraction in natural gas stored in LNG import and export facilities.Page 214 of 265

DRAFT: Please do not cite, quote, or distribute (vii) GHG mole fraction in local distribution pipeline natural gas that passes through the facility for natural gas distribution facilities. (v) GHG mass emissions

3

, , 10 * * * **− =**  GWP

E Mass i i s i s **ρ** . Calculate GHG mass emissions in carbon dioxide equivalent at standard conditions by converting the GHG volumetric emissions into mass emissions using Equation W

- 3 6 of this section.
(Eq. W

- 3 6 ) Where: Mass s,i = GHG i (either CH 4 or CO 2 ) mass emissions at standard conditions in metric tons CO 2 e. E s,i = GHG i (either CH 4 or CO 2

i **ρ** ) volumetric emissio ns at standard conditions, in cubic feet.

= Density of GHG i, 0.053 kg/ft 3 for CO 2 and 0.0193 kg/ft 3 for CH 4 . GWP = Global warming potential, 1 for CO 2 and 21 for CH 4 . (w) EOR injection pump blowdown . Calculate pump blowdown emissions as follows: (1) Calculate the total volume in cubic feet (including pipelines, manifolds and vessels) between isolation valves. (2) Retain logs of the number of blowdowns per calendar year
. (3) Calculate the total annual venting emissions using Equation W

- 3 7 of this s ection:Page 215 of 265

DRAFT: Please do not cite, quote, or distribute 3

, 10 * * * * **− =**  i c v i c GHG R V N Mass (Eq. W

- 3 7 )

Where: Mass c,i = Annual EOR injection gas venting emissions in metric tons at critical conditions “c” from blowdowns. N = Number of blowdowns for the equipment in the calendar year. V v = Total volume in cubic feet of blowdown equipment chambers (including pipelines, manifolds and vessels) between isolation valves. R c = Density of critical phase EOR injection gas in kg/ft 3 . You may use an appropriate standard method published by a consensus

- based standards organizat ion if such a method exists or you may use an industry standard practice to determine density of super critical EOR injection gas. GHG i = Mass fraction of GHG i in critical phase injection gas. 1 × 10 - 3 = Conversion factor from kilograms to metric tons. (x) EOR hydrocarbon liquids dissolved CO 2 . Calculate dissolved CO 2 in hydrocarbon liquids produced through EOR operations as follows: (1) Determine the amount of CO 2 retained in hydrocarbon liquids after flashing in tankage at STP conditions. Annual sampl es must be taken according to methods set forth in §98.234(b) to determine retention of
CO 2 in hydrocarbon liquids immediately downstream of the storage tank. Use the annual analysis for the calendar
year .Page 216 of 265

DRAFT: Please do not cite, quote, or distribute (2) Estimate emissions using Equation W

- 3 8 of th is section.

Mass s,CO2 = S hl * V hl (Eq. W

- 3 8 )
Where: Mass s,CO2 = Annual CO 2 emissions from CO 2 retained in hydrocarbon liquids produced through EOR operations beyond tankage, in metric tons. S hl = Amount of CO 2 retained in hydrocarbon liquids in metric to ns per barrel, under standard conditions. V hl = Total volume of hydrocarbon liquids produced at the EOR operations in barrels in the calendar year. (y) [Reserved] (z) Onshore petroleum and natural gas production combustion emissions.

(2) If the fuel combusted in the stationary or portable equipment is not found in Table C

- 1 and is not a blend containing only fuels listed in Table C

- 1, and you are not consuming field gas, you must follow the Tier 3 or Calculate combust ion

- related emissions from stationary and portable equipment as follows: (1) If the fuel combusted in the stationary or portable equipment is listed in Table C

- 1, or is a blend of fuels listed in Table C

- 1, use the Tier 1 methodology described in subpart C of this part (General Stationary Fuel Combustion Sources).Page 217 of 265

DRAFT: Please do not cite, quote, or distribute Tier 4 method in paragraphs §§98.33(b)(3)or 98.33(b)(4) of this part, as applicable. (3) For fuel combustion units that combust field gas, or any blend of field gas and fuels listed in Table C

- 1, calculate combustion emissions as follows: (i) If you have a continuous flow meter on the combustion unit, you must use the measured flow volumes to calculate the total flow of gas to the unit. If you do not have a permanent flow meter on the combustion unit, you may install a perman ent flow meter on the combustion unit, or use company records or engineering calculations based on best available data to estimate volumetric unit gas flow. (ii) If you have a continuous gas composition analyzer on fuel to the combustion unit, you must u se these compositions for determining the concentration of gas hydrocarbon constituent in the flow of gas to the unit. If you do not have a continuous gas composition analyzer on gas to the combustion unit, you must use the appropriate gas compositions fo r each stream of hydrocarbons going to the combustion unit as specified in paragraph (u)(2)(i) of this section. (iii) Calculate GHG volumetric emissions at actual conditions using Equations W

- 3 9 of this section.Page 218 of 265

DRAFT: Please do not cite, quote, or distribute 

## ∑ **=** j j j a CO a R Y V E * * 2 , (Eq. W

- 3 9 )

Where:

E a,CO2 = Contribution of annual emissions from portable or stationary fuel combustion sources in cubic feet, under actual conditions. V a = Volume of gas sent to combustion unit in cubic feet, during the year. Y j = Concentration of gas hydrocarbon consti tuents j (such as methane, ethane, propane, butane, and pentanes plus). R j = Number of carbon atoms in the gas hydrocarbon constituent j ; 1 for methane, 2 for ethane, 3 for propane, 4 for butane, and 5 for pentanes plus).
(5) External fuel combustion sou rces with a rated heat input capacity equal to or less than 5 mm B tu/hr do not need to report combustion emissions. You must report the type of fuel combustion unit and the number of each type. (6) Calculate GHG volumetric emissions at standard conditions using calculations in paragraph (t) of this section. (7) Calculate both combustion

- related CH 4 and CO 2 mass emissions from volumetric CH 4 and CO 2 emissions using calculation in paragraph (v) of this section.Page 219 of 265

DRAFT: Please do not cite, quote, or distribute (8) Calculate N 2

(Eq. W

- 40 ) Where:

N O mass emissions using Equat ion W

- 40 of this section.

2 O = Annual N 2 O emissions from the combustion of a particular type of fuel (metric tons). Fuel = Mass or volume of the fuel combusted (mass or volume per year , choose appropriately to be consistent with the un its of HHV ). HHV = High heat value of the fuel from paragraphs (z) (8) (i) , (z) (8) (ii) or (z)(8)(iii) of this section (units must be consistent with Fuel)
. EF = Use 1.0 × 10 - 4 kg N 2 O/mmBtu. 1 × 10 - 3 = Conversion factor from kilograms to metric tons.
(i) For fuels listed in Table C

- 1 of subpart C, use the provided default HHV in the table. (ii) For field gas, use 1.235 × 10 - 3 mm B tu/scf for
HHV. (iii) For fuels not listed in Table C

- 1 of subpart C and not field gas, you must use the methodology set fort h in the Tier 2 methodology described in subpart C of this part to determine HHV. 

# ( **)** EF HHV Fuel O N **× ×**  **× ×**  **=** 3 2 10 1

§98.234 Monitoring and QA/QC requirements **.**Page 220 of 265

DRAFT: Please do not cite, quote, or distribute (a) You must use any of the methods described as follows in this paragraph to conduct leak detection(s) of equipment leaks and th rough

- valve leakage from all source types listed in §98.233(k), (o), (p) and (q) that occur during a calendar year , except as provided in paragraph (a)(4) of this section. (1) Optical gas imaging instrument. Use an optical gas imaging instrument for eq uipment leak detection in accordance with 40 CFR part 60, subpart A, §60.18 (i)(1) and (2) Alternative work practice for monitoring equipment leaks. Any emissions detected by the optical gas imaging instrument is a leak unless screened with Method 21 moni toring, in which case 10,000 ppm or greater is designated a leak. In addition, you must operate the optical gas imaging instrument to image the source types required by this subpart in accordance with the instrument manufacturer’s operating parameters. (2 ) Method 21. Use the equipment leak detection methods in 40 CFR part 60, Appendix A

- 7, Method 21. If using Method 21 monitoring, if an instrument reading of 10,000 ppm or greater is measured, a leak is detected. Inaccessible emissions sources, as defin ed in 40 CFR part 60, are not exempt from this subpart. Owners or operators must use alternative leak detection devices as described inPage 221 of 265

DRAFT: Please do not cite, quote, or distribute paragraph (a)(1)of this section to monitor inaccessible equipment leaks or vented emissions. (3) Infrared laser beam illuminated instrument. Use an infrared laser beam illuminated instrument for equipment leak detection. Any emissions detected by the infrared laser beam illuminated instrument is a leak unless screened with Method 21 monitoring, in which case 10,000 ppm or greater is designated a leak . In addition, you must operate the infrared laser beam illuminated instrument to detect the source types required by this subpart in accordance with the instrument manufacturer’s operating parameters. (4) An optical gas i maging instrument must be used for all source types that are inaccessible and cannot be monitored without elevating the monitoring personnel more than 2 meters above a support surface. (5) Acoustic leak detection instrument. Use the acoustic leak detect ion instrument to detect through

- valve leakage. The acoustic leak detection instrument must have instrument manufacturer’s calcu la tion methods to quantify the through

- valve leak. When using the acoustic leak detection instrument, if a leak of 3.1 scf per hour or greater is calculated , a leak is detected. In addition, you must operate the acoustic leak detection instrument toPage 222 of 265

DRAFT: Please do not cite, quote, or distribute monitor the source valves required by this subpart in accordance with the instrument manufacturer’s operating parameters. (b) You must operate and calibrate all flow meters, composition analyzers and pressure gauges used to measure quantities reported in §98.233 according to the procedures in §98.3(i) and the procedure s in paragraph (b) of this section. You may use an appropriate st andard method published by a consensus

- based standards organization if such a method exists or you may use an industry standard practice. Consensus

- based standards organizations include, but are not limited to, the following: ASTM International, the Ameri can 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). (c) Use calibrated bags (also known as vent bags) only where the emissions are at near

- atmospheric pressures such that it is safe to handle and can capture all the emissions, below the maximum temperature specified by the vent bag manufacturer, and the entire emissions volume can be en compassed for measurement.Page 223 of 265

DRAFT: Please do not cite, quote, or distribute (1) Hold the bag in place enclosing the emissions source to capture the entire emissions and record the time required for completely filling the bag. If the bag inflates in less than one second, assume one second inflation tim e. (2) Perform three measurements of the time required to fill the bag, report the emissions as the average of the three readings. (3) Estimate natural gas volumetric emissions at standard conditions using calculations in §98.233(t). (4) Estimate CH 4 an d CO 2

(2) If the high volume sampler, along with all attachments available from the manufacturer, is not able to volumetric and mass emissions from volumetric natural gas emissions using the calculations in §98.233(u) and (v). (d) Use a high volume sampler to measure emissions within the capacity of the instrument. (1) A technician following manufacturer ins tructions shall conduct measurements, including equipment manufacturer operating procedures and measurement methodologies relevant to using a high volume sampler, including positioning the instrument for complete capture of the equipment leak without creat ing backpressure on the

source.Page 224 of 265

DRAFT: Please do not cite, quote, or distribute capture all the emissions from the source then use anti

static wraps or other aids to capture all emissions without violating operating requirements as provided in the instrument manufacturer’s manual. (3) Estimate CH 4 and CO 2 volumetric and mass emissions from volumetric natural gas emissions using the calculations in §98.233(u) and (v). (4) Calibrate the instrument at 2.5 percent methane with 97.5 percent air and 100 percent CH 4

2 2 2 b bV V a b V RT p

m m m **− +**  **−**

**− =**  **α** by using calibrated gas samples and by following manufacturer’s instructions for calibration. (e) Peng Robinson Equation of State means the equation of state defined by:

Where, p = absolute pressure R = universal gas constant T = absolute temperature
V m

c c p T R 2

2 45724

. 0 = molar volume

a =

b =

c c p RT 7780

. 0Page 225 of 265

DRAFT: Please do not cite, quote, or distribute α = 

# ( **)** 2 2 1 26992

. 0 54226

. 1 37464

. 0 1 ** **  ** **  ** **  ** **  ** **  ** **  ** **  ** ** 

**− −**  **+ +** 

c T T **ω ω** 
ω = acentric factor of the species
T c = critical temperature
P c = critic al pressure (f) Special reporting provisions. (1) Best available monitoring methods.

(2) EPA will allow owners or operators to use best available monitoring methods for parameters in §98.233 ‘‘Calculating GHG Emissions’’ as specified in paragraphs ( f )(2), ( f )(3), and ( f )(4) of this section. The owner or operator must use the calculation methodologies and equations in §98.233 ‘‘Calculating GHG Emissions.’’ Best available monitoring methods means any of the following methods specified in paragraph (f)(1) of t his section : (i) Monitoring methods currently used by the facility that do not meet the specifications of this subpart. (ii) Supplier data. (iii) Engineering calculations. (iv) Other company records. Best available monitoring methods for well

rela ted emissions . During January 1, 2011 through June 30, 2011, owners or operators may use best available monitoring methods for any well

- related data that cannot reasonably bePage 226 of 265

DRAFT: Please do not cite, quote, or distribute measured according to the monitoring and QA/QC requirements of this subpart, and only where required measurements cannot be duplicated due to technical limitations after June 30, 2011. These well

- related sources are: (i) §98.233 (g) Gas well venting during well completions and workovers with hydraulic fracturing. (ii) §98.233 (l) W ell testing venting and flaring. (3) Best available monitoring methods for specified activity data

(iii) Cumulative volume produced, volume input or output, or volume of fuel used in paragraphs §98.233(d), (e), (j), (k), (l), (m), (n), (x), (y), and (z). . During January 1, 2011 through June 30, 2011, owners or operators may use best available monitoring methods for activity data as listed below that cannot reasonably be obtained according to the monitoring and QA/QC requirements of this subpart, specifically for events that generate data which can only be collected between January 1, 2011 and June 30, 2011 and cannot be duplicated after June 30, 2011. These sources are: (i) Cumulative hours of venting, days, or times of operation in paragraphs §98.233(e), (f), (g), (h), (l), (o), (p), (q), and (r). (ii) Number of blowdowns, completions, workovers, or other events §98.233(f), (g), (h), (i), and (w).Page 227 of 265

DRAFT: Please do not cite, quote, or distribute (4) Best available monitoring methods for leak detection and measurement

(iv) Section 98.232 (d)(7 ), (e)(7), (f)(5), (g)(3), (h)(4), and (i)(1) equipment leak emissions from valves, connectors, open ended lines, pres sure relief valves, block valves, control valves, compressor blowdown valves, orifice meters, other meters, regulators, vapor recovery compressors, centrifugal compressor dry seals, and/or other . The owner or operator may
requ est use of best available monitoring methods between January 1, 2011 and December 31, 2011 for sources requiring leak detection and/or measurement. These sources include: (i) Section 98.232 (d)(1), (e)(1), (f)(1), (g)(1), and (h)(1) reciprocating compres sor rod packing venting in onshore natural gas processing, onshore natural gas transmission compression, underground natural gas storage, LNG storage, and LNG import and export equipment. (ii) Section 98.232 (d)(2), (e)(2), (f)(2), (g)(2), and (h)(2) cent rifugal compressor wet seal oil degassing venting in onshore natural gas processing, onshore natural gas transmission compression, underground natural gas storage, LNG storage, and LNG import and export equipment. (iii) Section 98.232 (c)(17) and (d)(6) a cid gas removal vent stacks in onshore petroleum and natural gas production and onshore natural gas processing.Page 228 of 265

DRAFT: Please do not cite, quote, or distribute equipment leaks in onshore natural gas processing, onshore

na tural gas transmission compression, underground natural gas storage, LNG storage, LNG import and export equipment, and natural gas distribution. (v) Section 98.232 (e)(3) condensate (oil and/or water) storage tanks in onshore natural gas transmission
comp ression. (5) Requests for 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. (i) No request or approval by the Administrator is necessary to use best available monitoring methods between January 1, 2011 and June 30, 2011 for the sources outlined in paragraph §98.23 4 ( f )(2). (ii) No request or approval by the Administrator is necessary to use best available monitoring methods between January 1, 2011 and June 30, 2011 for the sources outlined in paragraph §98.23 4 ( f )(3). (iii) Owners or operators must submit a request and receive approval by the Administrator to use best available monitoring methods between January 1, 2011 and December 31, 2011 f or sources outlined in §98.23 4 ( f )(4).Page 229 of 265

DRAFT: Please do not cite, quote, or distribute (A) Timing of request
. The request to use best available monitoring methods for §98.23 4 ( f )(4) must be submitted to EPA no later than February 28, 2011. (B) Content of request

( 4 ) A description of the specific actions the facility will take to obtain and/or install the equipment or obtain the monitoring service as soon as reasonably feasible and the expected date by which the equipment will be obtained and operating or service will be provided. . Requests must contain the following i nformation for §98.23 4 ( f )(4) : ( 1 ) A list of specific source types and specific equipment, monitoring instrumentation, and/or services for which the request is being made and the locations where each piece of monitoring instrumentation will be installed

or monitoring service will be supplied. ( 2 ) Identification of the specific rule requirements (by subpart, section, and paragraph numbers) for which the instrumentation or monitoring service is needed. ( 3 ) Documentation of correspondences to and from at lea st four s ubpart W

- relevant service providers demonstrating the request for services and responses stating the service provider will not provide necessary equipment or services in time to meet requirements in this subpart for 2011.Page 230 of 265

DRAFT: Please do not cite, quote, or distribute (C) Ap proval criteria
. To obtain approval, the owner or operator must demonstrate to the Administrator’s satisfaction that it does not own the required monitoring equipment, and it is not reasonably feasible to acquire, install, and operate a required piece of monitoring equipment or to obtain leak detection or measurement services in order to meet the requirements of this subpart for 2011. (iv) EPA does not anticipate a need to approve the use of best available monitoring methods for sources not listed in §98.2 3 4 ( f )(2), ( f )(3), and ( f )(4); however, EPA reserves the right to review such requests. (A) Timing of request
. The request to use best available monitoring methods for §98. 23 4 ( f )(4) must be submitted to EPA no later than February 28, 2011. (B) Content of request

( 2 ) A description of the data collection methodologi es that do not meet safety regulations, technical infeasibility, or specific laws or regulations that conflict with each specific source for which an owner . Requests must contain the following information: ( 1 ) A list of specific source categories and parameters for which the owner or operator is seeking use of best available monitoring methods.Page 231 of 265

DRAFT: Please do not cite, quote, or distribute or operator is requesting use of best available monitoring methodologies. ( 3 ) A detailed explanat ion and supporting documentation of how and when the owner or operator will receive the services or equipment to comply with all subpart W reporting requirements. (C) Approval criteria
. To obtain approval, the owner or operator must demonstrate to the Administrator’s satisfaction that the owner or operator faces unique safety, technical or legal issues rendering them unable to meet the requirements of this subpart for 2011. (6) Requests for extension of the use of best available monitoring methods th rough December 31, 2011 for sources in §98. 23 4 ( f )(2) . The owner or operator may submit a request to the Administrator to use one or more best available monitoring methods described in §98. 23 4 ( f )(2) beyond June 30, 2011. (i) Timing of request
. The exte nsion request must be submitted to EPA no later than February 28, 2011. (ii) Content of request

(A) A list of specific source types and specific equipment, monitoring instrumentation, contract modifica tions, and/or services for which the request is . Requests must contain the following information:Page 232 of 265

DRAFT: Please do not cite, quote, or distribute being made and the locations where each piece of monitoring instrumentation will be installed, monitoring service will be supplied, or contracts will be modified. (B) Identification of the specific rule req uirements (by subpart, section, and paragraph numbers) for which the instrumentation, contract modification, or monitoring service is needed. (C) A description and applicable correspondence outlining the diligent efforts of the owner or operator in obtai ning the needed equipment or service and why they could not be obtained and installed in a period of time enabling completion of applicable requirements of this subpart within the 2011 calendar year. (D) If the reason for the extension is that the owner or operator cannot collect data from a service provider or relevant organization in order for the owner or operator to meet requirements of this subpart for the 2011 calendar year, the owner or operator must provide documentation of a good faith effort to obtain relevant data, including the modification of relevant contracts , leases or arrangements
. The owner or operator must include correspondence to the service provider requesting relevant data and from the service provider or relevant organization stati ng that they will not provide relevant data, and documentation of whyPage 233 of 265

DRAFT: Please do not cite, quote, or distribute the owner or operator could not collect the necessary data themselves or modify applicable contracts leases or arrangements by June 30, 2011. (E) A description of the specific actions the owner or operator will take to comply with monitoring requirements in 2012 and beyond. (iii) Approval criteria
. To obtain approval, the owner or operator must demonstrate to the Administrator’s satisfaction that it is not reasonably feasible to obta in the data necessary to meet the requirements of this subpart for the sources outlined in §98. 23 4 ( f )(2) by June 30, 2011. (7) Requests for extension of the use of best available monitoring methods through December 31, 2011 for sources in §98. 23 4 ( f )(3)
. The owner or operator may submit a request to the Administrator to use one or more best available monitoring methods described in §98. 23 4 ( f )(3) beyond June 30, 2011. (i) Timing of request . The extension request must be submitted to EPA no later than Fe bruary 28, 2011. (ii) Content of request . Requests must contain the following information: (A) A list of specific source types for which data collection could not be implemented.Page 234 of 265

DRAFT: Please do not cite, quote, or distribute (B) Identification of the specific rule requirements (by subpart, sectio n, and paragraph numbers) for which the data collection could not be implemented. (C) A description of the data collection methodologies that do not meet safety regulations, technical infeasibility, or specific laws or regulations that conflict with each specific source for which an owner or operator is requesting use of best available monitoring methodologies for which data collection could not be implemented in the 2011 calendar year. (iii) Approval criteria

(8) . To obtain approval, the owner or operator must demonstrate to the Administrator’s satisfaction that it is not reasonably feasible to implement the data collection for the sources described in §98. 23 4 ( f )(3) for the methods required in this subpart by July 1, 2011. Requests for extension of the use of best available monitoring methods beyond 2011 for sources listed in §98. 23 4 ( f )(2), ( f )(3), ( f )(4), ( f )(5)(iv) and other sources in s ubpart W . EPA does not anticipate a need for approving the use of best available methods beyond December 31, 2011, except in extreme circumstances which include safety, a requirement being technically infeasible or counter to other local, State or Federal regulations.Page 235 of 265

DRAFT: Please do not cite, quote, or distribute (i) Timing of request
. The request to use best available monitoring methods for §98. 23 4 ( f )(2), ( f )( 3), ( f )(4), ( f )(5)(iv) and s ources not listed in §98. 234 ( f )(2), ( f )(3), ( f )(4), ( f )(5)(iv) must be submitted to EPA no later than June 30, 2011. (ii) Content of request

(C) . Requests must contain the following information: (iii) A list of specific source categories and parameters for which the owner or operator is seeking use of best available monitoring methods. (iv) A description of the data collection methodologies that do not meet safety regulations, technical infeasibility, or specific laws or regula tions that conflict with each specific source for which an owner or operator is requesting use of best available monitoring methodologies. (v) A detailed explanation and supporting documentation of how and when the owner or operator will receive the

serv ices or equipment to comply with all s ubpart W reporting requirements. Approval criteria . To obtain approval, the owner or operator must demonstrate to the Administrator’s satisfaction that the owner or operator faces uniquePage 236 of 265

DRAFT: Please do not cite, quote, or distribute safety, technical or leg al issues rendering them unable to meet the requirements of this subpart. §98.235 Procedures for estimating missing data. A complete record of all estimated and/or measured parameters used in the GHG emissions calculations is required. If data are lost or an error occurs during annual emissions estimation or measurements, you must repeat the estimation or measurement activity for those sources as soon as possible, including in the subsequent calendar year if missing data are not discovered until after D ecember 31 of the year in which data are collected , until valid data for reporting is obtained. Data developed and/or collected in a subsequent calendar year to substitute for missing data cannot be used for that subsequent year’s emissions estimation. W here missing data procedures are used for the previous year, at least 30 days must separate emissions estimation or measurements for the previous year and emissions estimation or measurements for the current year of data collection. §98.236 Data reporting requirements **.** In addition to the information required by §98.3(c), each annual report must contain reported emissions and related information as specified in this section.Page 237 of 265

DRAFT: Please do not cite, quote, or distribute (a) Report annual emissions separately for each of the industry segments listed in paragraphs (a)(1) through (8) of this section in metric tons CO 2 e per year at standard conditions . For each segment, report emissions from each source type §98.23 2 (a) in the aggregate, unless specified otherwise. For example, an onshore natural gas prod uction operation with multiple reciprocating compressors must report emissions from all reciprocating compressors as an aggregate number. (1) Onshore petroleum and natural gas production. (2) Offshore petroleum and natural gas production. (3) Onshore na tural gas processing. (4) Onshore natural gas transmission compression. (5) Underground natural gas storage. (6) LNG storage. (7) LNG import and export. (8) Natural gas distribution
. Report each source in the aggregate for pipelines and for Metering and Regulating (M&R) stations. (b) [Reserved] (c) For each aggregated source, r eport activity data and emissions (in metric tons CO 2 e per year at standard conditions) for each aggregated source type as follows:Page 238 of 265

DRAFT: Please do not cite, quote, or distribute (1) For natural gas pneumatic devices (re fer to §98.233, Equation W

- 1), report the following: (i) Count of natural gas pneumatic high bleed devices. (ii) Count of natural gas pneumatic low bleed devices. (iii) Count of natural gas pneumatic intermittent bleed devices. (iv) Report emissions c ollectively. (2) For natural gas driven pneumatic pumps (refer to §98.233, Equation W

- 2), report the following, (i) Count of natural gas driven pneumatic pumps. (ii) Report emissions collectively. (3) For each acid gas removal unit (refer to §98.233, Equation W

- 3, and Equation W

- 4), report the following: (i) Total volume of natural gas flow into the acid gas removal unit and/or total volume of natural gas flow out of the acid gas removal unit in cubic feet per year
. (ii) For method 1 and method 2, fra ction of CO 2 content in the vent from the acid gas removal unit (refer to §98.233(d)(1) or (d)(5)). (iii) For method 3, volume fraction of CO 2

(iii) Rep ort emissions individually. content of natural gas into and out of the acid gas removal unit (refer to §98.233(d)(6) and (d)(7)).Page 239 of 265

DRAFT: Please do not cite, quote, or distribute (4) For dehydrators, report the following: (i) For each Glycol dehydrator with a throughput greater than or equal to 0.4 mmscfd (refer to §98.233(e)(1)), report the following: (A) Glycol dehydrator feed natural gas flow rat e in mmscfd, determined by engineering estimate based on best available data. (B) Glycol dehydrator absorbent circulation pump type. (C) Whether stripper gas is used in glycol dehydrator. (D) Whether a flash tank separator is used in glycol dehydrator. (E) Type of absorbent. (F) Total time the glycol dehydrator is operating in hours
. (G) Temperature , in degrees Fahrenheit and pressure , in psig, of the wet natural gas. ( H ) Concentration of CH 4 and CO 2 in natural gas. ( I ) What vent gas controls are used (refer to §98.233(e)(3) and (e)(4)). ( J ) Report vent and flared emissions individually.Page 240 of 265

DRAFT: Please do not cite, quote, or distribute (ii) For all Glycol dehydrators with a throughput less than 0.4 mmscfd (refer to §98.233, Equation W

- 5 ), report the following: (A) Count of glycol dehydrators. (B) Whether any vent gas controls are used (refer to §98.233, paragraph (e)(3) and (e)(4)). (C) Report vent and flared emissions collectively. (iii) For absorbent desiccant dehydrators (refer to §98.233, Equation W

- 6 ), report the following: (A) Count of des iccant dehydrators. (B) Report emissions collectively. (5) For well venting for liquids unloading (refer to §98.233, Equations W

- 7 , W

- 8 and W

- 9 ), report the following by field: (i) Count of wells vented to the atmosphere for liquids unloading. (ii) Coun t of plunger lifts. (iii) Collective number of unloadings vented to the atmosphere. (iv) Average flow rate of the measured well venting in cubic feet per hour (refer to §98.233 (f)(1)(i)(A)). (v) Average casing diameter in inches
. (vi) Report emissions col lectively.Page 241 of 265

DRAFT: Please do not cite, quote, or distribute (6) For well completions and workovers, report the following for each field: (i) For gas well completions and workovers with hydraulic fracturing (refer to §98.233, Equation W

- 10 ): (A) Total count of completions in calendar year. (B) Average flow rate of the measured well completion venting in cubic feet per hour (refer to §98.233 Paragraph (g)(1)(i)(A) or (g)(1)(ii)(A))
. (C) Total count of workovers in calendar year. (D) Average flow rate of the measured well workover venting in cubic feet pe r hour (refer to §98.233 (g)(1)(i)(A) or (g)(1)(ii)(A))
. (E) Total number of days of gas venting to the atmosphere during backflow for completion. (F) Total number of days of gas venting to the atmosphere during backflow for workovers. (G) Report number of completions and workovers employing reduced emissions completions and engineering estimate based on best available data of the amount of gas recovered to sales. (H) Report vent and flared emissions collectively. (ii) For gas well completions and work overs without hydraulic fracturing (refer to §98.233, Equation W

- 1 3 ): (A) Total count of completions in calendar year.Page 242 of 265

DRAFT: Please do not cite, quote, or distribute (B) Total count of workovers in calendar year. (C) Total number of days of gas venting to the atmosphere during backflow for completion. (D) Total number of days of gas venting to the atmosphere during backflow for workover. (E) Report vent and flared emissions collectively. (7) For each blowdown vent stack (refer to §98.233, Equation W

- 1 4 ), report the following: (i) Total number of blo wdowns per equipment type in calendar year. (ii) Report emissions collectively per equipment type. (8) For gas emitted from produced oil sent to atmospheric tanks: (i) For wellhead gas

- liquid separator with oil throughput greater than or equal to 10 barrels per day, using methodology 1 and 2 (refer to §98.233(j)(1) and (j)(2)), report the following by field: (A) Number of wellhead separators sending oil to atmospheric tanks. (B) Separator temperature , in degrees Fahrenheit, and
pressure , in psig, ra nges . (C) Sales oil stabilized API gravity range , in degrees
.Page 243 of 265

DRAFT: Please do not cite, quote, or distribute (D) Count of stock tanks at well pads. (E) Best estimate of count of stock tanks not at well pads receiving your oil. (F) Total volume of oil from all wellhead separators sent to tank(s) in b arrels per year. (G) Count of tanks with emissions control measures, either vapor recovery system or flaring, for tanks at well pads. (H) Best estimate of count of stock tanks assumed to have emissions control measures not at well pads, receiving your oil
. (F) Range of concentrations of flash gas, CH 4 and CO 2

(C) Total number of wells sending oil to separators off the well pads. . (G) Report emissions individually for methodology 1 and 2. (ii) For wells with oil production greater than or equal to 10 barrels per day, using methodology 3 and 4 (refer to §98.233, paragraph (j) (3) and (j)(4)), report the following by field: (A) Total volume of sales oil from all wells in barrels per year. (B) Total number of wells sending oil directly to tanks.Page 244 of 265

DRAFT: Please do not cite, quote, or distribute (D) Sales o il API gravity range for (B) and (C) of this section , in degrees
. (E) Count of tanks on wellpads (F) Count of tanks, both on and off well pads assumed to have emissions control measures: either vapor recovery system or flaring of tank vapors. (G) Report emissions collectively for methodology 3 and methodology 4. (iii)For wellhead gas

- liquid separators and wells with throughput less than 10 barrels per day, using methodology 5 (refer to §98.233, Equation W

- 1 5 ), report the following: (A) Number of wellhe ad separators. (B) Number of wells without wellhead separators. (C) Total volume of oil production in barrels per
year. (D) Best estimate of fraction of production sent to tanks with assumed control measures: either vapor recovery system or flaring of t ank vapors. (E) Count of stock tanks on well pads. (F) Report CO 2 and CH 4 emissions collectively. (iv) If wellhead separator dump valve is functioning improperly during the calendar year (refer to §98.233, Equation W

- 1 6 ), report the following:Page 245 of 265

DRAFT: Please do not cite, quote, or distribute (A) Count of wellhead separators that dump valve factor is applied. (9) For transmission tank emissions identified using optical gas imaging instrument per §98.234(a) (refer to §98.233, Paragraph (k)), report the following for each tank: (i) Report emissions indi vidually. (10) For well testing (refer to §98.233, Equation W

1 7 ), report the following for each field in the basin: (i) Number of wells tested per field in calendar
year . (ii ) Average gas to oil ratio for each field. (iii) Average number of days the w ell is tested. (iv) Report emissions of the venting gas collectively
. (11) For associated natural gas venting (refer to §98.233, Equation W

- 1 8 ), report the following for each field in the basin: (i) Number of wells venting or flaring associated natural gas in a calendar year
. (ii) Average gas to oil ratio for each field. (iii) Report emissions of the flaring gas collectively.Page 246 of 265

DRAFT: Please do not cite, quote, or distribute (12) For flare stacks (refer to §98.233, Equation W

1 9 , W

- 20 and W

- 21 ), report the following for each flare: (i) Whether flar e has a continuous flow monitor. (ii) Volume of gas sent to flare in cubic feet per
year . (iii) Percent of gas sent to un

- lit flare determined by engineering estimate and process knowledge based on best available data and operating records. (iv) Whether flare has a continuous gas analyzer. (v) Flare combustion efficiency. (vi) Report uncombusted and combusted CO 2 and CH 4 emissions separately. (13) For each centrifugal compressor: (i) For compressors with wet seals in operational mode (refer to §98.2 33, Equations W

- 2 2 through W

- 2 4 ), report the following for each degassing vent: (A) Number of wet seals connected to the degassing
vent. (B) Fraction of vent gas recovered for fuel or sales or flared. (C) Annual throughput in million scf. (D) Type of m eters used for making measurements.Page 247 of 265

DRAFT: Please do not cite, quote, or distribute (E) Reporter emission factor for wet seal oil degassing vents in cubic feet per hour (refer to §98.233, Equation W

- 2 3 ). (F) Total time the compressor is operating in hours
. (G) Report seal oil degassing vent emission s for compressors measured (refer to §98.233, Equation W

- 2 2 ) and for compressors not measured (refer to §98.233, Equation W

2 3 ). (ii) For wet and dry seal centrifugal compressors in operating and standby, pressurized mode, (refer to §98.233, Equations W

- 2 3 and W

- 2 4 ), report the following: (A) Total time in hours the compressor is in operating mode. (B) Total time in hours the compressor is in standby, pressurized mode. (c) Reporter emission factor for blowdown vents in cubic feed per hour (refer to §98.23 3, Equation W

- 2 3 ). (D) Report blowdown vent emissions when operating and standby pressurized modes (refer to §98.233, Equation W

2 3 ). (iii) For wet and dry seal centrifugal compressors in shutdown, depressurized mode (refer to §98.233, Equations
W

- 2 3 and W

- 2 4 ), report the following:Page 248 of 265

DRAFT: Please do not cite, quote, or distribute (A) Total time in hours the compressor is in shutdown, depressurized mode. (B) Reporter emission factor for isolation valve emissions in shutdown, depressurized mode in cubic feet per hour (refer to §98.233, Equation W

- 2 3 ). (C ) Report the isolation valve leakage emissions in shutdown, depressurized mode in cubic feet per hour (refer to §98.233, Equation W

- 2 3 ). (iv) Report total annual compressor emissions from all modes of operation (refer to §98.233, Equation W

- 2 4 ). (v) F or centrifugal compressors in onshore petroleum and natural gas production (refer to §98.233, Equation W

2 5 ), report the following: (A) Count of compressors. (B) Report emissions (refer to §98.233, Equation W

2 5 ) collectively. (14) For reciprocating compr essors: (i) For reciprocating compressors rod packing emissions with or without a vent in operating mode, report the following: (A) Annual throughput in million scf
. (B) Total time in hours the reciprocating compressor is in operating mode.Page 249 of 265

DRAFT: Please do not cite, quote, or distribute (C) Report ro d packing emissions for compressors measured (refer to §98.233, Equation W

- 2 6 ) and for compressors not measured (refer to §98.233, Equation W

- 2 7 ). (ii) For reciprocating compressors blowdown vents not manifold to rod packing vents, in operating and standb y pressurized mode (refer to §98.233, Equations W

- 2 7 and W

2 8 ), report the following: (A) Total time in hours the compressor is in standby, pressurized mode. (B) Reporter emission factor for blowdown vents in cubic feet per hour (refer to §98.233, Equati on W

- 2 7 ). (C) Report blowdown vent emissions when in operating and standby pressurized modes (refer to §98.233, Equation
W

- 2 8 ). (iii) For reciprocating compressors in shutdown, depressurized mode (refer to §98.233, Equations W

- 2 7 and W

2 8 ), report the fo llowing: (A) Total time the compressor is in shutdown, depressurized mode. (B) Reporter emission factor for isolation valve emissions in shutdown, depressurized mode in cubic feet per hour (refer to §98.233, Equation W

- 2 7 ). (C) Report the isolation valve l eakage emissions in shutdown, depressurized mode.Page 250 of 265

DRAFT: Please do not cite, quote, or distribute (iv) Report total annual compressor emissions from all modes of operation (refer to §98.233, Equation W

- 2 8 ). (v) For reciprocating compressors in onshore petroleum and natural gas production (refer to §98 .233, Equation W

- 2 9 ), report the following: (A) Count of compressors. (B) Report emissions collectively. (15) For each equipment leak sources that uses emission factors for estimating emissions (refer to §98.233, paragraphs (q) and (r). (i) For equipment leaks found in each leak survey (refer to **§** 98.233(q)), report the following: (A) Total count of leaks found in each complete survey listed by date of survey and each type of leak source for which there is a leaker emission factor in Tables W

- 2, W

- 3, W

- 4, W

- 5, W

- 6 and W

- 7. (B) Concentration of CH 4 and CO 2 as described in §98.233, Equation W

- 30
. (C) Report CH 4 and CO 2 emissions (refer to §98.233, Equation W

- 30 ) collectively by equipment type. (ii) For equipment leaks calculated using population counts and f actors (refer to **§** 98.233(r)), report the following:Page 251 of 265

DRAFT: Please do not cite, quote, or distribute (A) For source categories §98.230 (a) (3), (a) (4), (a) (5), (a) (6), and (a) (7), total count for each type of leak source in Tables W

- 2, W

- 3, W

- 4, W

- 5 and W

- 6 for which there is a population emission factor , listed by major heading and component type. (B) For onshore production (refer to §98.230 paragraph (a) (2)), total count for low bleed, high bleed and intermittent bleed pneumatic devices and pneumatic pumps in Table W

- 1A, and each type of major equipment in Table W

- 1B, by field. (C) Report CH 4 and CO 2

(iii) Number of blowdowns per year. emissions (refer to §98.233, Equation W

- 30 ) collectively by equipment type. (16) For Local Distribution Companies, report the following: (i) Number of custody transfer gate stations. (ii) Number of non

- custo dy transfer gate stations. (iii)Custody transfer gate station meter run leak factor (refer to §98.233, Equation W

- 3 2 ). (17) For each EOR injection pump blowdown (refer to §98.233, Equation W

- 3 7 ), report the following: (i) Pump capacity , in barrels per day
. (ii) Volume of critical phase gas between isolation valves.Page 252 of 265

DRAFT: Please do not cite, quote, or distribute (iv) Critical phase EOR injection gas density. (v) Report emissions collectively. (18) For hydrocarbon liquids dissolved CO 2 for each field (refer to §98.23 3, Equation W

- 37 ), report the following: (i) Volume of crude oil produced in barrels per year
. (ii) Amount of CO 2 retained in hydrocarbon liquids in metric tons per barrel, under standard conditions
. (iii) Report emissions individually. (d) Report annua l throughput as determined by engineering estimate based on best available data for each operation listed in paragraphs (a)(1) through (a)(8) of this section. (e) For offshore petroleum and natural gas production facilities, report the number of connecte d wells, and whether the wells are producing oil, gas, or both. (f) Report emissions separately for portable equipment for the following source types: drilling rigs, dehydrators, compressors, electrical generators, steam boilers, and heaters. (1) Aggreg ate emissions by source type. (2) Report count of each source type. §98.237 Records that must be retained **.**Page 253 of 265

DRAFT: Please do not cite, quote, or distribute In addition to the information required by §98.3(g), you must retain the following records: (a) Dates on which measurements were conducted. (b) R esults of all emissions detected and
measurements. (c) Calibration reports for detection and measurement instruments used. (d) Inputs and outputs of calculations or emissions computer model runs used for engineering estimation of emissions. §98.238 Defi nitions. Except as provided below, all terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Acid Gas means hydrogen sulfide (H 2 S) and/or carbon dioxide (CO 2 ) contaminants that are separated from sour
natur al gas by an acid gas removal unit. Acid Gas Removal unit (AGR) means a process unit that separates hydrogen sulfide and/or carbon dioxide from sour natural gas using liquid or solid absorbents or membrane separators. Acid gas removal vent stack emissions mean the acid gas separated from the acid gas absorbing medium (e.g., anPage 25 4 of 265

DRAFT: Please do not cite, quote, or distribute amine solution) and released with methane and other light hydrocarbons to the atmosphere or a flare. Basin means geologic provinces as defined by the American Association of Petroleum Geologists (AAPG) Geologic Note: AAPG

- CSD Geologic Provinces Code Map: AAPG Bulletin, Prepared by Richard F. Meyer, Laure G. Wallace, and Fred J. Wagner, Jr., Volume 75, Number 10 (October 1991) (incorporated by reference, see §98.7)and the Alaska Geologi cal Province Boundary Map, Compiled by the American Association of Petroleum Geologists Committee on Statistics of Drilling in Cooperation with the USGS, 1978 (incorporated by reference, see §98.7). Component means each metal to metal joint or seal of

non - welded connection separated by a compression gasket, screwed thread (with or without thread sealing compound), metal to metal compression, or fluid barrier through which natural gas or liquid can escape to the atmosphere. Compressor means any machine for r aising the pressure of a natural gas or CO 2 by drawing in low pressure natural
gas or CO 2 and discharging significantly higher pressure natural gas or CO 2 . Condensate means hydrocarbon and other liquid, including both water and hydrocarbon liquids, separat ed from natural gas that condenses due to changes in thePage 255 of 265

DRAFT: Please do not cite, quote, or distribute temperature, pressure, or both, and remains liquid at storage conditions. Engineering estimation , for purposes of subpart W, means an estimate of emissions based on engineering principles applied to measured and/or approximated physical parameters such as dimensions of containment, actual pressures, actual temperatures, and compositions. Enhanced Oil Recovery (EOR) means the use of certain methods such as water flooding or gas injection into existing wells to increase the recovery of crude oil from a reservoir. In the context of this subpart, EOR applies to injection of critical phase or immiscible carbon dioxide into a crude oil reservoir to enhance the recovery of oil. Equipment leak means those e missions which could not reasonably pass through a stack, chimney, vent, or other functionally

- equivalent opening. Equipment leak detection means the process of identifying emissions from equipment, components, and other point sources. Field means oil and gas fields identified in the United States as defined by the Energy Information Administration Oil and Gas Field Code Master List 2008, DOE/EIA 0370(08) (incorporated by reference, see §98.7).Page 256 of 265

DRAFT: Please do not cite, quote, or distribute Flare stack emissions means CO 2 and N 2 O from partial combustion of hydrocarbon gas sent to a flare plus CH 4 emissions resulting from the incomplete combustion of hydrocarbon gas in flares. Flare combustion efficiency means the fraction of hydrocarbon gas, on a volume or mole basis, that is combusted at the flare burne r tip. Liquefied natural gas (LNG) means natural gas (primarily methane) that has been liquefied by reducing its temperature to

- 260 degrees Fahrenheit at atmospheric
pressure. LNG boil

- off gas means natural gas in the gaseous phase that vents from LNG sto rage tanks due to ambient heat leakage through the tank insulation and heat energy dissipated in the LNG by internal pumps. Natural gas

Facility for purposes of this s ubpart and for subpart A with respect to natural gas distribution means the means a naturally occurring mixture of hydrocarbon gases found in geologic formations beneath the earth’s surface, of wh ich its constituents include, but are not limited to, methane, heavier hydrocarbons and carbon dioxide. Natural gas for the purposes of subpart W is composed of a minimum high heat value of 910 Btu per standard cubic foot.Page 257 of 265

DRAFT: Please do not cite, quote, or distribute distribution pipelines, metering stations, and regulating stations that are operated by and a Local Distribution Company (LDC) that is regulated as a separate operating company by a public utility commission or that are operated as an independent municipally

- owned distribution system. Facility for purposes of this subpart and for subpart A with respect to onshore petroleum and natural gas production facility means all petroleum or n atural gas equipment associated with all petroleum or natural gas production wells and CO 2

Offshore means seaward of the terrestrial borders of the United States, including waters subject to the ebb and flow of the tide, as well as adjacent bays, lakes or other normally standing waters, and extending to the outer EOR operations that are under common ownership or common control including leased , rented, or contracted activities by an onshore petroleum and natural gas productio n owner or operator and that are located in a single hydrocarbon basin as defined in §98.238. Where a person or entity owns or operators more than one well in a basin, then all onshore petroleum and natural gas production equipment associated with all wel ls that the person or entity owns or operates in the basin would be considered one facility.Page 258 of 265

DRAFT: Please do not cite, quote, or distribute boundaries of the jurisdiction and control of the United States under the Outer Continental Shelf Lands Act
. Onshore petroleum and natural gas production owner or operator means the person or e ntity who holds the permit to operate petroleum and natural gas wells on the drilling permit or an operating permit where no drilling permit is issued **,** which operates an onshore petroleum and/or natural gas production facility (as described in §98.230(a)(2 ). Where petroleum and natural gas wells operate without a drilling or operating permit, the person or entity that pays the state or federal business income taxes is considered the owner or operator. Operating pressure means the containment pressure that characterizes the normal state of gas or liquid inside a particular process, pipeline, vessel or tank. Pump means a device used to raise pressure, drive, or increase flow of liquid streams in closed or open conduits. Pump seals means any seal on a pump dri ve shaft used to keep methane and/or carbon dioxide containing light liquids from escaping the inside of a pump case to the atmosphere. Pump seal emissions means hydrocarbon gas released from the seal face between the pump internal chamber and the atmosphe re.Page 259 of 265

DRAFT: Please do not cite, quote, or distribute Reservoir means a porous and permeable underground natural formation containing significant quantities of hydrocarbon liquids and/or gases. A reservoir is characterized by a single natural pressure system. Separator means a vessel in which streams of m ultiple phases are gravity separated into individual streams of single phase. Transmission pipeline means high pressure cross country pipeline transporting sellable quality natural gas from production or natural gas processing to natural gas distribution p ressure let

- down, metering, regulating stations where the natural gas is typically odorized before delivery to customers. Turbine meter means a flow meter in which a gas or liquid flow rate through the calibrated tube spins a turbine from which the spin ra te is detected and calibrated to measure the fluid flow rate.

**TABLE W -**  **1A OF SUBPART W** – **DEFAULT WHOLE GAS EMISSION FACTORS FOR ONSHORE PRODUCTION**  **Onshore production Emission Factor**  **(scf/hour/component) Eastern U.S.**  **Population Emission Factors -**  **All Compo nents,**  **Gas Service 1**  Valve 0.640 Connector 0.083 Open

- ended Line 1.460 Pressure Relief Valve 0.970Page 260 of 265

DRAFT: Please do not cite, quote, or distribute Low Continuous Bleed Pneumatic Device Vents 1.39 2 High Continuous Bleed Pneumatic Device Vents 37.3 2 Intermittent Bleed Pneumatic Device Vents 13.5 2 Pneumatic Pumps 10.3 3 **Population Emission Factors -**  **All Components, Light Crude Service**  **4** Valve 0.04 Flange 0.002 Connector 0.01 Open

- ended Line 0.04 Pump 0.01 Other 0.24 5 **Population Emission Factors -**  **All Components, Heavy Crude Service**  **6** Valv e 0.001 Flange 0.001 Connector (other) 0.0004 Open

- ended Line 0.01 Other 0.003 5 **Western U.S. Population Emission Factors**  **- All Components,**  **Gas Service 1**  Valve 2.903 Connector 0.396 Open

- ended Line 0.748 Pressure Relief Valve 4.631 Low Continuou s Bleed Pneumatic Device Vents 1.39 2 High Continuous Bleed Pneumatic Device Vents 37.3 2 Intermittent Bleed Pneumatic Device Vents 13.5 2 Pneumatic Pumps 10.3 3 **Population Emission Factors -**  **All Components, Light Crude Service**  **4** Valve 0.04 Flange 0.002 Connector 0.01 Open

- ended Line 0.04 Pump 0.01 Other 0.24 5 **Population Emission Factors -**  **All Components, Heavy Crude Service**  **6** Valve 0.001 Flange 0.001 Connector (other) 0.0004 Open

- ended Line 0.01 Other 0.003 5 1 For multi

- phase flow that include s gas, use the gas service emissionsPage 261 of 265

DRAFT: Please do not cite, quote, or distribute **TABLE W -**  **1B OF SUBPART W** – **DEFAULT AVERAGE COMPONENT COUNTS FOR MAJOR NATURAL GAS PRODUCTION EQUIPMENT**  **Major Equipment**  **Valves Connectors**  **Open -**  **ended Lines**  **Pressure relief**  **valves Eastern U.S.**  Wellheads 8 38 0.5 0 Separators 1 6 0 0 Meters/pipi ng 12 45 0 0 Compressors 12 57 0 0 In

- line heaters 14 65 2 1 Dehydrators 24 90 2 2 **Western U.S.** Wellheads 11 36 1 0 Separators 34 106 6 2 Meters/piping 14 51 1 1 Compressors 73 179 3 4 In

- line heaters 14 65 2 1 Dehydrators 24 90 2 2

**TABLE W -**  **1C OF SUBPART W** – **DEFAULT AVERAGE COMPONENT COUNTS FOR MAJOR CRUDE OIL PRODUCTION EQUIPMENT**  **Major Equipment**  **Valves Flanges**  **Connecto rs**  **Open**   ** ended** **Lines Other**  **Components Eastern U.S.**  Wellhead 5 10 4 0 1 Separator 6 12 10 0 0 Heater

- treater 8 12 20 0 0 Header 5 10 4 0 0 **Western U.S.** Wellhead 5 10 4 0 1 Separator 6 12 10 0 0 Heater

- treater 8 12 20 0 0 Header 5 10 4 0 0

**TABLE W -**  **1D OF SUBPART W** – **DESIGNATION OF EASTERN AND WESTERN U.S.** 

**Eastern U.S. Western U.S.**  Connecticut Alabama factors
2 Emission Factor is in units of "scf/hour/device" 3 Emission Factor is in units of "scf/hour/pump" 4 Hydrocarbon liquids greater t han or equal to 20  ̊API are considered "light crude" 5 ”Others” category includes instruments, loading arms, pressure relief valves, stuffing boxes, compressor seals, dump lever arms, and vents.
6 Hydrocarbon liquids less than 20  ̊API are considered "heavy crude"Page 262 of 265

DRAFT: Please do not cite, quote, or distribute Delaware Al aska Florida Arizona Georgia Arkansas Illinois California Indiana Colorado Kentucky Hawaii Maine Idaho Maryland Iowa Massachusetts Kansas Michigan Louisiana New Hampshire Minnesota New Jersey Mississippi New York Missouri North Carolina Montan a Ohio Nebraska Pennsylvania Nevada Rhode Island New Mexico South Carolina North Dakota Tennessee Oklahoma Vermont Oregon Virginia South Dakota West Virginia Texas Wisconsin Utah Washington Wyoming

**TABLE W -**  **2 OF SUBPART W** – **DEFAULT TOTAL HYDROC ARBON EMISSION**  **FACTORS FOR PROCESSING Processing**  **Emission Factor (scf/hour/component)**  **Leaker Emission Factors -**  **Compressor Components, Gas Service** Valve 14.84 Connector 5.59 Open

- Ended Line 17.27 Pressure Relief Valve 39.66 Meter 19.33 **Leaker Emissi on Factors**  **– Non**  **- Compressor Components, Gas Service**  Valve 6.42 Connector 5.71 Open

- Ended Line 11.27 Pressure Relief Valve 2.01 Meter 2.93Page 263 of 265

DRAFT: Please do not cite, quote, or distribute **TABLE W -**  **3 OF SUBPART W** – **DEFAULT METHANE EMISSION FACTORS FOR TRANSMISSION** 
**Transmission Emission Factor**  **(scf/hour /component)**  **Leaker Emission Factors -**  **Compressor Components, Gas Service** Valve 14.84 Connector 5.59 Open

- Ended Line 17.27 Pressure Relief Valve 39.66 Meter 19.33 **Leaker Emission Factors –**  **Non -**  **Compressor Components, Gas Service** Valve 6.42 Connector 5.71 Open

- Ended Line 11.27 Pressure Relief Valve 2.01 Meter 2.93 **Population Emission Factors –**  **Gas Service** Low Continuous Bleed Pneumatic Device Vents 1 1.39 High Continuous Bleed Pneumatic Device Vents 1 19.82 Intermittent Bleed Pneumatic Device Ven ts 1 19.82 1 Emission Factor is in units of "scf/hour/device"

**TABLE W -**  **4 OF SUBPART W** – **DEFAULT METHANE EMISSION FACTORS FOR UNDERGROUND STORAGE** 
**Underground Storage Emission Factor**  **(scf/hour/componen t)**  **Leaker Emission Factors -**  **Storage Station, Gas Service** Connector 0.96 Block Valve 2.02 Control Valve 3.94 Compressor Blowdown Valve 66.15 Pressure Relief Valve 19.80 Orifice Meter 0.46 Other Meter 0.01 Regulator 1.03 O pen - ended Line 6.01 **Population Emission Factors -**  **Storage Wellheads, Gas Service** Connector 0.01 Valve 0.10 Pressure Relief Valve 0.17 Open

- ended Line 0.03 **Population Emission Factors -**  **Other Components, Gas Service** Low Continuous Bleed P neumatic Device Vents 1.39 1Page 264 of 265

DRAFT: Please do not cite, quote, or distribute **Underground Storage Emission Factor**  **(scf/hour/componen t)**  **Leaker Emission Factors -**  **Storage Station, Gas Service** High Continuous Bleed Pneumatic Device Vents 19.82 1 Intermittent Bleed Pneumatic Device Vents 19.82 1 1 Emission Factor is in units of "scf/hour/device"

**TABLE W -**  **5 OF SUBPART W** – **DEFAULT METHANE EMISSION FACTORS FOR LIQUEFIED N**  **ATURAL GAS (LNG) STORAGE**
**LNG Storage Emission Factor**  **(scf/hour/compon ent)**  **Leaker Emission Factors -**  **LNG Storage Components, LNG Service** Valve 1.19 Pump Seal 4.00 Connector 0.34 Other 1.77 1 **Population Emission Factors -**  **LNG Storage Compressor, Gas Ser vice**  Vapor Recovery Compressor 6.81 1 "other" equipment type should be applied for any equipment type other than connectors, pumps, or valves.

**TABLE W -**  **6 OF SUBPART W** – **DEFAULT METHANE EMISSION FACTORS FOR LNG TERMINALS** 
**LNG Terminals Emission Factor**  **(scf/ hour/compone**  **nt) Leaker Emission Factors**  **- LNG Terminals Components, LNG Service**  Valve 1.19 Pump Seal 4.00 Connector 0.34 Other 1.77 1 **Population Emission Factors -**  **LNG Terminals Compressor, Gas Service** Vapor Recovery Compressor 6.81 1 "other" equipm ent type should be applied for any equipment type other than connectors, pumps, or valves.

**TABLE W -**  **7 OF SUBPART W** – **DEFAULT METHANE EMISSION FACTORS FOR DISTRIBUTION**  **Distribution Emission Factor**  **(scf/hour/component) Leaker Emission Factors**  **- Above Grade M**  **&R at City Gate Stations 1**  **Components, Gas Service** Connector 1.69Page 265 of 265

DRAFT: Please do not cite, quote, or distribute **Distribution Emission Factor**  **(scf/hour/component)** Block Valve 0.557 Control Valve 9.34 Pressure Relief Valve 0.270 Orifice Meter 0.212 Regulator 0.772 Open

- ended Line 26.131 **Population Emission Factors -**  **Below Grade M&R 2**  **Components, Gas Service**  **3** Below Grade M&R Station, Inlet Pressure > 300 psig 1.30 Below Grade M&R Station, Inlet Pressure 100 to 300 psig 0.20 Below Grade M&R Station, Inlet Pressure < 100 psig 0.10 **Population Emission Factors -**  **Distribution Mains, Gas Service 4**  U nprotected Steel 12.58 Protected Steel 0.35 Plastic 1.13 Cast Iron 27.25 **Population Emission Factors -**  **Distribution Services, Gas Service 5**  Unprotected Steel 0.19 Protected Steel 0.02 Plastic 0.001 Copper 0.03 1 City gate stations at custody transf er and excluding customer meters 2 E xcluding customer meters 3 Emission Factor is in units of "scf/hour/station" 4 Emission Factor is in units of "scf/hour/mile" 5 Emission Factor is in units of “scf/hour/number of services”