Page 1 of 497

***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review*** E.O. 12866 NSPS and NESHAP for Oil and Gas 2060

- AP76 Final Rule 20120223

ENVIRONMENTAL PROTECTION AGENCY 40 CFR Part 63 [EPA - HQ - OAR - 2010 - 0505 ; FRL - XXXX - X ]

RIN 2060 - AP76 Oil and Natural Gas Sector: New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants Reviews
AGENCY : Environmental Protection Agency (EPA).
ACTION : Final rule.
SUMMARY : This action finalizes the review conducted under section 111(b) of the Clean Air Act of new source performance standards for the listed oil and natural gas s ource category . In this action the EPA revised the new source performance standards for volatile organic compou nds from leaking components at onshore natural gas processing plants (40 CFR part 60, subpart KKK) and new source performance standards for sulfur dioxide emissions from natural gas processing plants (40 CFR part 60, subpart LLL). The EPA also established standards (40 CFR part 60, subpart OOOO) for certain oil and gas operations not coveredPage 2 of 497

by the existing standards. In addition to the operations covered by subparts KKK and LLL, subpart OOOO will regulate volatile organic compound emissions from gas well s, centrifugal compressors, reciprocating compressors, pneumatic controllers, and storage vessels. This action also finalizes the residual risk and technology review conducted under section 112 of the Clean Air Act for the Oil and Natural Gas Production Faci lities source category (40 CFR part 63, subpart HH) and the Natural Gas Transmission and Storage Facilities source category (40 CFR part 63, subpart HHH) . This action include s revisions to the existing emission limit for glycol dehydration unit process ven ts and leak detection and repair requirements . In addition, pursuant to section 112(d)(2) and (3), the EPA has established in this action emission limits reflecting maximum achievable control technology for certain currently uncontrolled emission sources in these source categories . This action also includes modification and addition of testing and monitoring and related notification, recordkeeping and reporting requir ements , as well as other minor technical revisions to the national emission standards for hazardous air pollutants . This action finalizes revisions to the regulatory provisions re la ted to emissions during periods of startup, shutdown and malfunction. DATES : This final rule is effective on [INSERT DATE 60 DAYS AFTER THE DATE OF PUBLICATION IN THE FEDERAL REGISTER]. ThePage 3 of 497

incorporation by reference of certain publications listed in this rule is approved by the Director of the Federal Register as of [INSERT DATE 60 DAYS AFTER THE DATE OF PUBLICATION IN THE FEDERAL REGISTER].
ADDRESSES: The EPA has established a docket for this action
under Docket ID. No. EPA

- HQ

- OAR

- 2010

- 0505. All documents in the docket are listed on the http: //www.regulations.gov w ebsite. Altho ugh listed in the index, s ome information is not publicly available, e.g., confidentia l business information or other information whose disclosure is restricted by statute. Certain other material, such as copyrighted material, is not placed on the Internet and will be publi cly available only in hard copy form. Publicly available docket materials are available either electronically through http:/ /www.regulations.gov or in hard copy at the EPA’s Docket Center , Public Reading Room, EPA West Building, Room Numb er 3334, 1301 Const itution Avenue, NW, Washington, D.C. 20004. This Docket Facility is open from 8:30 a.m. to 4:30 p.m. Eastern Standard Time , 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 INFORMATION CONTACT: For further information about this final action, contact Mr. Bruce Moore, Sector Policies and Programs Division, Office of Air Q uality and Standards (E143

-Page 4 of 497

05 ), Environmental Protection Agency, Research Triangle Park, North Carolina 27711, telephone number: (919) 541

- 5460; facsimile number: (919) 685

- 3200; email address: moore.bruce@epa.gov
. For additional contact information, see the following SUPPLEMENTARY INFORMATION section.
SUPPLEMENTARY INFORMATION : For specific information regarding risk assessment and exposure modeling methodology, contact Mr. Mark Morris , Health and Environmental Impa cts Division, Office of Air Quality Planning and Standards (C504

- 06), U.S. Environmental Protection Agency, Research Triangle Park, NC 27711; telephone number (919) 541

- 5416 ; fax number: (919) 541

- 0840 ; and e

- mail address: morris.mark @epa.gov
. Organization of This Document
. The information presented in this preamble is organized as follows:
I. Preamble Acronyms and Abbreviations
II. General Information A. Executive Summary
B . Does this action apply to me?
C . What are the emission sources affected by this action?
D . Where can I get a copy of this document?
E . Judicial Review
II I . Background Information on the NSPS and NESHAP
A. What are the statutory authorities for the NSPS and NESHAP?
B . What is the litig ation history?Page 5 of 497

C . W hat is the sector

- based approach?
D . What are the health effects of pollutants emitted from the oil and natural gas sector?
IV . Summary of the Final NSPS Rule
A. What are the final rule revisions to the NSPS for the Crude Oil and Natural Gas Production, Transmission, and Distribution source category ?
B. What are the effective and compliance dates for the final
NSPS ?
V . Summary of the Significant Changes to the NSPS Since Proposal
A. Gas well affected faciliti es B. Centrifugal and reciprocating compressor affected facilities
C . Pneumatic controller affected facilities D. Storage vessel affected facilities
E. Equipment leaks a ffected facilities and sweetening unit affected facilities at o nshore natural gas processing plant s
F. Changes to notification, recordkeeping and reporting requirements
V I . Summary of the F inal NESHAP Rules A. What are the final rule amendments for the Oil and Natural Gas Production Facilities (subpart HH) source category?
B . What are the final rule amendments for the Natural Gas Transmission and Storage facilities (subpart HHH) source category?Page 6 of 497

C. What are the effective and compliance dates of the standards ? D. How do the final NESHAPs provide for compliance assurance?
E . What are the requirements for submission of performance test data to the EPA?
VI I . Summary of the Significant Changes to the NESHAP Since Proposal
A. What are the significant changes since proposal for the Oil and Natural Gas Production Facilities (subpart HH) source

c ategory ?
B. What are the significant changes since proposal for the Natural Gas Transmission and Storage facilities (subpart HHH) source category ? VIII. Compliance Related Issues Common to the NSPS and NESHAP A. How do the rules address startup, shutdown a nd malfunction? B. How do the NSPS and NESHAP provide for compliance assurance? C. What are the requirements for submission of performance test data to the EPA?
IX . Summary of Significant NSPS Comments and Responses
A. Major comments concerning a pplicability
B. Major comments concerning well completions C. Major comments concerning pneumatic controllers
D . Major comments concerning compressors E. Major comments concerning storage vessels F. Major comments concerning equipment leaksPage 7 of 497

G . Major comme nts concerning notification, recordkeeping and reporting requirements
X . Summary of Significant NESHAP Comments and Responses A. Major comments concerning applicability B. Major comments concerning the risk review C. Major comments concerning the previously unregulated sources D. Major comments concerning the technology review E. Major comments concerning notification, recordkeeping and reporting requirements
XI . What are the cost, environmental and economic impacts of the final NSPS and NESHAP ame ndments?
A. What are the air impacts?
B. What are the energy impacts?
C. What are the cost impacts?
D. What are the economic impacts?
E. What are the benefits of this final rule?
XII . Statutory and Executive Order Reviews
A. Executive Order 12866 : Regulato ry Planning and Review and Executive Order 13563 : Improving Regulation and Regulatory Review
B. Paperwork Reduction Act
C. Regulatory Flexibility Act
D. Unfu nded Mandates Reform Act
E. Executive Order 13132 : FederalismPage 8 of 497

F. E xecutive Order 13175 : Con sultation and Coordination with Indian Tribal Governments
G. Executive Order 13045 : Protection of Children from Environmental Health Risks and Safety Risks
H. Executive Order 13211 : Acti ons Concerning Regulations That Significantly Affect Energy Supply, Di stribution, or Use
I. National Technology Transfer and Advancement Act
J. Executive Order 12 898: Federal Actions to Address Environmental Justice in Mino rity Populations and Low

- Income Populations
K. Congressional Review Act
I. Preamble Acronyms and Abbreviations Several acronyms and terms used to describe industrial processes, data inventories, and risk modeling are included in this preamble. While this may not be an exhaustive list, to ease the reading of this preamble and for reference purposes, th e following terms and acronyms are defined here: ACGIH American Conference of Governmental Industrial Hygienists ADAF Age

- Dependent Adjustment Factors AEGL Acute Exposure Guideline Levels AERMOD The air dispersion model used by the HEM

– 3 model API American Petroleum Institute BACT Best Available Control Technology BID Background Information DocumentPage 9 of 497

BPD Barrels Per Day BSER Best System of Emission Reduction BTEX Benzene, Ethylbenzene, Toluene and Xylene CAA Clean Air Act CalEPA California Environmental Prot ection Agency CBI Confidential Business Information CEM Continuous Emissions Monitoring CEMS Continuous Emissions Monitoring System CFR Code of Federal Regulations CIIT Chemical Industry Institute of Toxicology CO Carbon Monoxide
CO 2 Carbon Dioxide
CO 2 e Carbon Dioxide Equivalent DOE Department of Energy ECHO Enforcement and Compliance History Online

e - GGRT Electronic Greenhouse Gas Reporting Tool EJ Environmental Justice EPA Environmental Protection Agency ERPG Emergency Response Planning Guidelines
ERT E lectronic Reporting Tool GCG Gas Condensate Glycol GHG Greenhouse Gas GOR Gas to Oil Ratio GWP Global Warming PotentialPage 10 of 497

HAP Hazardous Air Pollutants
HEM

– 3 Human Exposure Model, version 3 HI Hazard Index HP Horsepower HQ Hazard Quotient
H 2 S Hydrogen Sulfide ICR Information Collection Request IPCC Intergovernmental Panel on Climate Change IRIS Integrated Risk Information System km Kilometer kW Kilowatts LAER Lowest Achievable Emission Rate lb Pounds LDAR Leak Detection and Repair MACT Maximum Achievable Control Technology MACT Code NEI c ode used to identify processes included in a source category Mcf Thousand Cubic Feet Mg/yr Megagrams per year MIR Maximum Individual Risk MIRR Monitoring, Inspection, Recordkeeping and Reporting
MMtCO 2 e Million Metric Tons of Carbon Dioxide Equivalents NAAQS National Ambient Air Quality StandardsPage 11 of 497

NAC/AEGL National Advisory Committee for Acute Exposure Guideline Levels for Hazardous Substances NAICS North American Industry Classification System NAS National Academy of Scienc es NATA National Air Toxics Assessment NEI National Emissions Inventory NEMS National Energy Modeling System NESHAP National Emissions Standards for Hazardous Air Pollutants NGL Natural Gas Liquids NIOSH National Institutes for Occupational Safety and Heal th
NO X Oxides of Nitrogen NRC National Research Council NSPS New Source Performance Standards NSR New Source Review NTTAA National Technology Transfer and Advancement Act OAQPS Office of Air Quality Planning and Standards OMB Office of Management and Budge t
PB

– HAP Hazardous air pollutants known to be persistent and bio

accumulative in the environment PFE Potential for Flash Emissions PM Particulate Matter
PM 2.5 Particulate Matter (2.5 microns and less) POM Polycyclic Organic Matter PPM Parts Per MillionPage 12 of 497

PPMV Parts Per Million by Volume PSIG Pounds P er S quare I nch G auge PSIA Pounds Per Square Inch Absolute PTE Potential to Emit QA Quality Assurance RACT Reasonably Available Control Technology RBLC RACT/BACT/LAER Clearinghouse REC Reduced Emissions Completions REL CalEPA Reference Exposure Level RFA Regulatory Flexibility Act RfC Reference Concentration RfD Reference Dose RIA Regulatory Impact Analysis RICE Reciprocating Internal Combustion Engines RTR Residual Risk and Technology Review SAB Science Advisory Board SBREFA Small Business Regulatory Enforcement Fairness Act SCC Source Classification Codes SCFH Standard Cubic Feet Per Hour SCFM Standard Cubic Feet Per Minute SCM Standard Cubic Meters SCMD Standard Cubic Meters Per Day SCOT Shell Claus Off gas Treatment SIP State Implementation PlanPage 13 of 497

SISNOSE Significant Economic Impact on a Substantial Number of Small Entities S/L/T State and Local and Tribal Agencies SO2 Sulfur Dioxide SSM Startup, Shutdown and Malfunction STEL Short

- term Exposure Limit
TLV Threshold Limit Value TOSHI Target Organ

- Specific Hazard Index TPY Tons per Year TRIM Total Risk Integrated Modeling System TRIM.FaTE A spatially explicit, compartmental mass balance model that describes the movement and transformation of pollutants
over t ime, through a user

- defined, bounded system that includes both biotic and abiotic compartments TSD Technical Support Document UF Uncertainty Factor UMRA Unfunded Mandates Reform Act URE Unit Risk Estimate VCS Voluntary Consensus Standards VOC Volatile Organic Compounds VRU Vapor Recovery Unit
I I . General Information A. Executive Summary 1. Purpose of the Regulatory ActionPage 14 of 497

On January 14, 2009, pursuant to section 304(a)(2) of the CAA, WildEarth Guardians and the San Juan Citizens Alliance filed a Compla int alleging that the EPA failed to meet its obligations under CAA sections 111(b)(1)(B), 112(d)(6) and 112(f)(2) to take actions relative to the review/revision of the NSPS and the NESHAP with respect to the Oil and Natural Gas Production source category. On February 4, 2010, the Court entered a consent decree that, as modified, requires the EPA to sign by July 28, 2011, proposed standards and/or determinations not to issue standards pursuant to CAA sections 111(b)(1)(B), 112(d)(6) and 112(f)(2) and to ta ke final action by April 3, 2012. This action finalizes the review conducted under section 111(b) of the Clean Air Act of new source performance standards for the listed oil and natural gas source category. This action also finalizes the residual risk and technology review conducted under section 112 of the Clean Air Act for the Oil and Natural Gas Production Facilities source category (40 CFR part 63, subpart HH) and the Natural Gas Transmission and Storage Facilities source category (40 CFR part 63, subp art HHH). In addition, pursuant to section 112(d)(2) and (3), the EPA has established in this action emission limits reflecting maximum achievable control technology for certain currently uncontrolled emission sources in these source categories.Page 15 of 497

2. Summary of the Major Provisions of the Regulatory Action In this action the EPA revised the new source performance standards for volatile organic compounds from leaking components at onshore natural gas processing plants (40 CFR part 60, subpart KKK) and new sou rce performance standards for sulfur dioxide emissions from natural gas processing plants (40 CFR part 60, subpart LLL). The EPA also established standards (40 CFR part 60, subpart OOOO) for certain oil and gas operations not covered by the existing standa rds. In addition to the operations covered by subparts KKK and LLL, subpart OOOO will regulate volatile organic compound emissions from gas wells, centrifugal compressors, reciprocating compressors, pneumatic controllers, and storage vessels. For gas wel l affected facilities, we are finalizing operational standards for completions of hydraulically fractured gas wells. The final rule applies to three subcategories of fractured gas wells for which well completion operations are conducted: (1) wildcat (explo ratory) and delineation wells; (2)

non - wildcat and non

- delineation wells for which the reservoir pressure is insufficient for a reduced emissions completion (REC), commonly referred to as a “green completion,” to be performed, as determined by a simple cal culation involving reservoir pressure, well depth and gathering line pressure at the sales meter (we refer to these wells as “low pressurePage 16 of 497

wells”) and (3) all other fractured gas wells. For category (3) wells, each well completion operation must employ REC in combination with use of a completion combustion device to control gas not suitable for entering the gathering line. For category (1) wells (exploratory and delineation wells) and category (2) wells (low pressure wells), the final rule contains
an opera tional standard that requires the use of a completion combustion device. However, the final rule does not prohibit the use of REC for completion of these wells. For compressor affected facilities, the final rule requires measures to reduce VOC emissions from centrifugal and reciprocating compressors. The final rule contains standards for wet seal centrifugal compressors located between the wellhead and the point a t which the gas enters the transmission and storage segment. The final standards require 95 percent reduction of VOC emissions from each wet seal centrifugal compressor affected facility. The standard can be achieved by capturing and routing the emissions to a control device that achieves an emission reduction of 95 percent. The operational standards for reciprocating compressors in the final rule require replacement of the rod packing based on usage. The rod packing must be changed every 26,000 hours of operation. Alternatively, owners or operators can elect toPage 17 of 497

change the rod packing every 36 months in lieu of monitoring compressor operating hours. We are also finalizing VOC standards to reduce emissions from individual natural gas

- driven pneumatic cont rollers that vent continuously to the atmosphere and are located between the wellhead and the point at which the gas enters the transmission and storage segment. At natural gas processing plants, the final rule includes a natural gas bleed rate limit of ze ro standard cubic feet per hour for each individual pneumatic controller. At other locations in the oil and natural gas production segment, the final rule includes a natural gas bleed rate limit of 6 standard cubic feet of gas per hour for an individual pn eumatic controller. The final rule contains VOC standards for new or modified storage vessels. The final rule, which applies to individual vessels, requires that storage vessels with emissions equal to or greater than 6 tpy achieve at least 95 percent re duction in VOC emissions. For onshore natural gas processing plants, we are revising the existing NSPS requirements for leak detection and repair (LDAR) to reflect the procedures and leak thresholds established by 40 CFR 60, subpart VVa. This action als o includes revisions to the national emission standards for hazardous air pollutants for glycolPage 18 of 497

dehydration unit process vents and leak detection and repair requirements. In the final rule, we have revised the new source MACT standards for “large” glycol d ehydrators as well as the leak detection and repair requirements. In addition, pursuant to section 112(d)(2) and (3), we have established MACT standards for “small” glycol dehydrators and storage vessels that were not controlled under the initial NESHAP. In this final rule, we have established for the first time MACT standards for “small” glycol dehydration units, which were left unregulated under the initial NESHAP. This subcategory consists of glycol dehydrators with an actual annual average natural gas flowrate less than 85,000 standard cubic meters per day (scmd) or actual average benzene emissions less than 0.9 megagrams per year (Mg/yr). The final MACT standards for the subcategory of small dehydrators at oil and gas production facilities require th at existing affected sources meet a unit

- specific BTEX limit of 3.28x10

- 4 grams BTEX/standard cubic meters (scm)

- parts per million by volume (ppmv) and that new affected sources meet a BTEX limit of 4.66 x10

- 6 grams BTEX/scm

- ppmv. In the final rule, we ha ve also established for the first time MACT standards for certain storage vessels that were not previously regulated under the initial NESHAP. The standard isPage 19 of 497

the same as that promulgated in the initial NESHAP for the other storage vessels (i.e., 95 percen t emission reduction). In the subpart HH final rule, as a result of our review under section 112(d)(6), we are revising the leak definition for valves to 500 ppm, thus requiring the application of the leak detection and repair requirement at this lower d etection level. This leak definition applies only to valves and not other components. In the subpart HHH final rule, as a result of our review under section 112(d)(6), we have revised the new source MACT standards for “large” glycol dehydrators. In additi on, pursuant to section 112(d)(2) and (3), we have established MACT standards for “small” glycol dehydrators that were not controlled under the initial NESHAP. In this final rule, we have established for the first time MACT standards for “small” glycol d ehydration units in the Natural Gas Transmission and Storage source category. This subcategory consists of glycol dehydrators with an actual annual average natural gas flowrate less than 283,000 scmd or actual average benzene emissions less than 0.9 Mg/yr. The final MACT standard for this subcategory of small dehydrators requires existing affected sources to meet a unit

specific BTEX emission limit of 3.01 x 10 - 4 grams BTEX/scm

- ppmvPage 20 of 497

and new affected sources are required to meet a BTEX limit of 5.44 x 10 - 5 grams BTEX/scm

- ppmv. 3. Costs and Benefits The estimated total capital cost to comply with the final amendments to 40 CFR part 63, subpart HH for major sources in the Oil and Natural Gas Production source category is approximately $47 million. The total c apital cost for the final amendments to 40 CFR part 63, subpart HHH for major sources in the Natural Gas Transmission and Storage source category is estimated to be approximately $370 thousand. All costs are in 2008 dollars. The total estimated net annual cost to industry to comply with the final amendments to 40 CFR part 63, subpart HH for major sources in the Oil and Natural Gas Production source category is approximately $18 million. The total net annual cost for final amendments to 40 CFR part 63, subp art HHH for major sources in the Natural Gas Transmission and Storage source category is estimated to be approximately $360,000. All costs are in 2008 dollars. The estimated total capital cost to comply with the final NSPS is approximately $340 million in 2008 dollars. The total estimated net annual cost to industry to comply with the final NSPS is approximately $340 million in 2008 dollars.Page 21 of 497

The final Oil and Natural Gas NSPS and NESHAP amendments are expected to result in significant reductions in exist ing emissions and prevent new emissions from expansions of the industry. These final rules combined are anticipated to reduce 20,000 tons of HAP, 300,000 tons of VOC (a precursor to both
PM 2.5 and ozone formation) and 1.7 million tons of methane (a GHG and a precursor to global ozone formation).
B . Does this action apply to me ? The regulated categories and entities potentially affected by the final standards are shown in Table 1 of this preamble.
TABLE 1
. INDUSTRIAL SOURCE CATEGORIES AFFECTED BY THIS PROPOSED ACTION Category NAICS code 1 Examples of regulated entities Industry . . . . 211111 Crude Petroleum and Natural Gas Extraction 211112 Natural Gas Liquid Extraction 221210 Natural Gas Distribution 486110 Pipeline Distribution of Crude

Oil 486210 Pipeline Transportation of

Natural Gas Federal government
. . . . Not affected. State/local/tribal government . . . . Not affected.

1 North American Industry Classification System.

This table is not intended to be exhaustive, but rather is meant to provide a guide for re aders regarding entities likely to be affected by this actio n. If y ou have any questions regarding thePage 22 of 497

applicability of this action to a particular entity, consu lt either the air permitting autho rity for the entity or your EP A regional representative as listed in 40 CFR 60.4 or 40 CFR 63.13 (General Provisions).
C . What are the emission sources affected by this action? 1. What are the emission sources affected by the NSPS? The emission sources affected by the NSPS include well completions, pneumatic controllers, equipment leaks from natural gas processing plants, sweetening units at natural gas processing plants, reciprocating compressors, centrifugal compressors, and storage vessel s . Well completions subject to the NSPS are limited to the flowback period following hydraulic fracturing operations at a gas well affected facility. These completions include those conducted at newly drilled and fractured wells, as well as completions conducted following refracturing operations at various times over the life of the well. Pneumatic controllers affected by the NSPS include continuous bleed na tural gas

- driven pneumatic controllers (including replacement of an existing device ). The NSPS applies to centrifugal compressors with wet seals and reciprocating compressors located in the oil and natural gas production and processing segments. The NSPS a lso applies to equipment leak s from onshore natural gas processing plants and new or modified storage vessels located in all of the oil and natural gasPage 23 of 497

segments. The NSPS also affects sweetening units located onshore that process natural gas from onshore o r offshore wells. 2. What are the emission sources affected by the NESHAP? The emission sources that are affected by the Oil and Natural Gas Production NESHAP (subpart HH) and the Natural Gas Transmission and Storage NESHAP (subpart HHH) include glycol de hydrators , equipment leaks and storage vessels.
D . Where can I get a copy of this document ? In addition to being available in the docket, an electronic copy of this actio n will also be available on the Worldwide Web (WWW). Following signature by t he Administrator, a copy of the action will be posted on the EPA’s website at the following
address: http://www.epa.gov/airquality/oilandgas

. Additional information is available on the EPA’s Residual
R isk and Technology Review (RTR) Web site at http://www.epa.gov/ttn/atw/rrisk/oarpg.html . This information includes the most recent version of the rule, source category descriptions, detailed emissio ns and other data were used as inputs to the risk assessments.
E . Judicial Review Under CAA section 307(b)(1), judicial review of this final rule is available only by filing a petition for review in the U.S. Court of Appeals for the District of Columbia C ircuit by [INSERT DATE 60 DAYS AFTER PUBLICATION IN THE FEDERAL REGISTER ]
.Page 24 of 497

Under CAA section 307(d)(7)(B), only an objection to this final rule that was raised with reasonable specificity du ring the period for public comment (inclu ding any public hearing) can be raised during judicial revie w. This section also provides a mechanism for the EPA to convene a proceeding for reconsideration “[i]f the person raising an objection can demonstrate to the Administrat or that it was impracticab le to raise such objection within [th e period for public comment] or if the grounds for such objec tion 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
outcom e of the rule[.]” An y person seeking to make such a demonstration to us should submit a Petition for Reconsideration to the Office of the Administ rator, Environmental Protection Agency, Room 3000, Ariel Rios Building, 1200 Pennsylvania Ave., NW., Washingto n, D.C. 20004, with a copy to the person listed in the preceding FOR FURTHER INFORMATION CONTACT section, and the Associate General Counsel for th e Air and Radiation Law Office, Office of General Counsel ( Mail Code 2344A), Environmental Protection Agency, 1200 Pennsylv ania Ave., NW, Washington, D.C. 20004. Note, under CAA sect ion 307(b)(2), the requirements established by this final rule m ay not be challenged separately in any civil or criminal procee dings brought by the EPA to enforce these requirements.Page 25 of 497

III. Background Information on the NESHAP and NSPS
A. What are the statutory authorities for the N SPS and N ESHAP ? 1. What is the statutory authority for the NSPS? Section 111 of the Clean Air Act (CAA) requires the EPA Administrator to list categories of stationary sources, if such sources cause or contribute significantly to air pollution, which may reasonably be anticipated to endanger public health or welfare. The EPA must then issue performance standards for such source categories. Whereas CAA section 112 standards are issued for new and existing stationary sources, standards of performance are issued for new and modified stationary sources. These standards are referred to as new source performance standards (NSPS). The EPA has the authority to define t he source categories, determine the pollutants for which standards should be developed, identify the facilities within each source category to be covered and set the emission level of the standards. CAA section 111(b)(1)(B) requires the EPA to ‘‘at least every 8 years review and, if appropriate, revise’’ performance
standards . However, the Administrator need not review any such standard if the ‘‘Administrator determines that such review is not appropriate in light of readily available information on the ef ficacy’’ of the standard. When conducting a review of an existing performance standard, the EPA has discretion to revisePage 26 of 497

that standard to add emission limits for pollutants or emission sources not currently regulated for that source category. In setting or revising a performance standard, CAA section 111(a)(1) provides that performance standards are to “ reflect the degree of emission limitation achievable through the application of the best system of emission reduction which (taking into account the cost of achieving such reduction and any nonair quality health and environmental impact and energy requirements) the Administrator determines has been adequately demonstrated. ” In this notice, we refer to this level of control as the BSER. In determining BSER, we typically conduct a technology review that identifies what emission reduction systems exist and how much they reduce air pollution in practice. Next, for each control system identified, we evaluate its costs, secondary air benefits (or disbenefits) resu lting from energy requirements and nonair quality impacts such as solid waste generation. Based on our evaluation, we would determine BSER. The resultant standard is usually a numerical emissions limit, expressed as a performance level (i.e., a rate

based standard or percent control), that reflects the BSER. Although such standards are based on the BSER, the EPA may not prescribe a particular technology that must be used to comply with a performance standard, except in instances where the Administrator dete rmines it is not feasible to prescribe orPage 27 of 497

enforce a standard of performance. Typically, sources remain free to elect whatever control measures that they choose to meet the emission limits. Upon promulgation, an NSPS becomes a national standard to which all new, modified or reconstructed sources must comply. 2 . What is the statutory authority for the NESHAP? Section 112 of the CAA establishes a two

- stage regulatory process to address emissions of HAP from stationary sources. In the first stage, after the EPA has identified categories of sources emitting one or more of the HAP listed in section 112(b) of the CA A, section 112(d) of the CAA calls for us to promulgate national emission standards for hazardous air pollutants (NESHAP) for those sources. “ Major sources ” are those that emit or have the potential to emit (PTE) 10 tons per year (tpy) or more of a single HAP or 25 tpy or more of any combination of HAP. For major sources, these technology

- based standards must reflect the maximum degree of emission reductions of HAP achievable (after considering cost, energy requirements and nonair quality health and environ mental impacts) and are commonly referred to as maximum achievable control technology (MACT) standards. MACT standards are set to reflect application of measures, processes, methods, systems or techniques, including, but not limited to, measures which, (1 ) reduce the volume of orPage 28 of 497

eliminate pollutants through process changes, substitution of materials or other modifications, (2) enclose systems or processes to eliminate emissions, (3) capture or treat pollutants when released from a process, stack, storage or fugitive emissions point, (4) are design, equipment, work practice or operational standards (including requirements for operator training or certification) or (5) are a combination of the above. CAA section 112(d)(2)(A)

– (E). A MACT standard may take the form of a design, equipment, work practice or operational standard where the EPA first determines either that, (1) a pollutant cannot be emitted through a conveyance designed and constructed to emit or capture the pollutant or that any requirement for or use of such a conveyance would be inconsistent with law or (2) the application of measurement methodology to a particular class of sources is not practicable due to technological and economic limitations. CAA sections 112(h)(1) , (2). The MACT “ floor ” is the minimum control level allowed for MACT standards promulgated under CAA section 112(d)(3) and may not be based on cost considerations. For new sources, the MACT floor cannot be less stringent than the emission control that is achieved in practice by the best

- controlled similar source. The MACT floors for existing sources can be less stringent than floors for new sources but cannot be less stringent than thePage 29 of 497

average emission limitation achieved by the best

- performing 12 percent of existing sources in the category or subcategory (or the best

- performing five sources for categories or subcategories with fewer than 30 sources). In developing MACT standards, we must also consider control options that are more stringent than the floor. We may establish stand ards more stringent than the floor based on the consideration of the cost of achieving the emissions reductions, any nonair quality health and environmental impacts and energy requirements. The EPA is then required to review these technology

- based standar ds and to revise them “ as necessary (taking into account developments in practices, processes, and control technologies) ” no less frequently than every 8 years, under CAA section 112(d)(6). In conducting this review, the EPA is not obliged to completely re calculate the prior MACT determination. NRDC v.
EPA , 529 F.3d 1077, 1084 (D.C. Cir. 2008). The second stage in standard

- setting focuses on reducing any remaining “ residual ” risk according to CAA section 112(f). This provision requires, first, that the EPA prepare a Report to Congress discussing (among other things) methods of calculating risk posed (or potentially posed) by sources after i mplementation of the MACT standards, the public health significance of those risks, and the EPA’s recommendations as to legislation regarding such remaining risk. The EPA prepared andPage 30 of 497

submitted this report ( Residual Risk Report to Congress , EPA

– 453/R

– 99

– 001) in March 1999. Congress did not act in response to the report, thereby triggering the EPA’s obligation under CAA

se ction 112(f)(2) to analyze and address residual risk. CAA section 112(f)(2) requires us to determine for source categories subject to MACT standards, whether the emissions standards provide an ample margin of safety to protect public health. Section 112(f) (2) expressly preserves our use of a two

step process for developing standards to address any residual risk and our interpretation of “ample margin of safety” developed in the National Emission Standards for Hazardous Air Pollutants: Benzene Emissions from Maleic Anhydride Plants, Ethylbenzene/Styrene Plants, Benzene Storage Vessels, Benzene Equipment Leaks, and Coke By

- Product Recovery Plants (Benzene NESHAP) (54 FR 38044, September 14, 1989). The first step in this process is the determination of acceptab le risk. The second step provides for an ample margin of safety to protect public health, which is the level at which the standards must be set (unless a more stringent standard is required to prevent an adverse environmental effect, taking into considerat ion costs, energy, safety, and other relevant factors). If the MACT standards for HAP that are “ classified as a known, probable, or possible human carcinogen do not reduce lifetime excess cancer risks to the individual most exposed toPage 31 of 497

emissions from a sou rce in the category or subcategory to less than 1

- in

- 1 million, ” the EPA must promulgate residual risk standards for the source category (or subcategory), as necessary, to provide an ample margin of safety to protect public health. In doing so, the EPA may adopt standards equal to existing MACT standards if the EPA determines that the existing standards are sufficiently protective. NRDC v. EPA , 529 F.3d 1077, 1083 (D.C. Cir. 2008). ( “ If EPA determines that the existing technology

- based standards provide an ‘ ample margin of safety, ’ then the Agency is free to readopt those standards during the residual risk rulemaking.”) As mentioned, t he EPA must also adopt more stringent standards, if necessary, to prevent an adverse environmental effect, 1 but must consider cost, energy, safety and other relevant factors in doing so. The terms “ individual most exposed, ” “ acceptable level, ” and “ ample margin of safety ” are not specifically defined in the CAA. However, CAA section 112(f)(2)(B) preserves the interpretation se t out in the Benzene NESHAP, and the United States Court of Appeals for the District of Columbia Circuit has concluded that the EPA’s interpretation of subsection 112(f)(2) is a reasonable one. See NRDC v. EPA , 529 F.3d at 1083

1 “ Adverse environmental effect ” is defined in CAA section 112(a)(7) as any significant and widespread adverse effect, which may be reasonably anticipated to wildlife, aquatic life or natural resources, including adverse impacts on populations of endangered or threatened species or signi ficant degradation of environmental qualities over broad areas.Page 32 of 497

( “ [S]ubsection 112(f)(2)(B) expressly incorporates the EPA’s interpretation of the Clean Air Act from the Benzene standard, complete with a citation to the Federal Register ” ). See also , A Legislative History of the Clean Air Act Amendments of 1990 , volume 1, p. 877 (Senate debate on Conference Report). We notified Congress in the Residual Risk Report to Congress that we intended to use the Benzene NESHAP approach in making CAA section 112(f) residual risk determinations (EPA

– 453/R

– 99

– 001, p. ES

– 11). In the B enzene NESHAP, we stated as an overall objective: * * * in protecting public health with an ample margin of safety, we strive to provide maximum feasible protection against risks to health from hazardous air pollutants by, (1) protecting the greatest numbe r of persons possible to an individual lifetime risk level no higher than approximately 1

- in

- 1 million; and (2) limiting to no higher than approximately 1

- in

- 10 thousand [ i.e. , 100

- in

- 1 million] the estimated risk that a person living near a facility woul d have if he or she were exposed to the maximum pollutant concentrations for 70 years. The Agency also stated in the Residual Risk Report to Congress that “ The EPA also considers incidence (the number of persons estimated to suffer cancer or other serious health effects as a result of exposure to a pollutant) to be an important measure ofPage 33 of 497

the health risk to the exposed population. Incidence measures the exten t of health risk to the exposed population as a whole, by providing an estimate of the occurrence of cancer or other serious health effects in the exposed population. ” The Agency went on to conclude that “ estimated incidence would be weighed along with oth er health risk information in judging acceptability. ” As explained more fully in our Residual Risk Report to Congress , the EPA does not define “ rigid line[s] of acceptability, ” but considers rather broad objectives to be weighed with a series of other heal th measures and factors (EPA

– 453/R

– 99

– 001, p. ES

– 11). The determination of what represents an

“ acceptable ” risk is based on a judgment of “ what risks are acceptable in the world in which we live ” ( Residual Risk Report to Congress , p. 178, quoting the Vinyl Chloride decision at 824 F.2d 1165) recognizing that our world is not risk

- free. In the Benzene NESHAP, we stated that “ EPA will generally presume that if the risk to [the maximum exposed] individual is no higher than approximately 1

- in

- 10 thousand, that risk level is considered acceptable. ” 54 FR 38045. We discussed the maximum individual lifetime cancer risk (or maximum individual risk (MIR)) as being “ the estimated risk that a person living near a plant would have if he or she were exposed to the maxim um pollutant concentrations for 70 years. ” Id
. We explained that this measure of risk “ is an estimate of the upper bound of riskPage 34 of 497

based on conservative assumptions, such as continuous exposure for 24 hours per day for 70 years. ” Id
. We acknowledge that maxi mum individual lifetime cancer risk “ does not necessarily reflect the true risk, but displays a conservative risk level which is an upper

- bound that is unlikely to be exceeded. ” Id
. Understanding that there are both benefits and limitations to using maximu m individual lifetime cancer risk as a metric for determining acceptability, we acknowledged in the 1989 Benzene NESHAP that “ consideration of maximum individual risk * * * must take into account the strengths and weaknesses of this measure of risk. ” Id
. Consequently, the presumptive risk level of 100

- in

- 1 million (1

- in

- 10 thousand) provides a benchmark for judging the acceptability of maximum individual lifetime cancer risk, but does not constitute a rigid line for making that determination. The Agency a lso explained in the 1989 Benzene NESHAP the following: “ In establishing a presumption for MIR, rather than a rigid line for acceptability, the Agency intends to weigh it with a series of other health measures and factors. These include the overall inciden ce of cancer or other serious health effects within the exposed population, the numbers of persons exposed within each individual lifetime risk range and associated incidence within, typically, a 50

- kilometer (km) exposure radius around facilities, the sci ence policyPage 35 of 497

assumptions and estimation uncertainties associated with the risk measures, weight of the scientific evidence for human health effects, other quantified or unquantified health effects, effects due to co

- location of facilities and co

- emission of pollutants. ” Id
. In some cases, these health measures and factors taken together may provide a more realistic description of the magnitude of risk in the exposed population than that provided by maximum individual lifetime cancer risk alone. As explained in the Benzene NESHAP, “ [e]ven though the risks judged ‘acceptable’ by the EPA in the first step of the Vinyl Chloride inquiry are already low, the second step of the inquiry, determining an ‘ample margin of safety,’ again includes consideration of all of the health factors, and whether to reduce the risks even further. ” In the ample margin of safety decision process, the Agency again considers all of the health risks and other health information considered in the first step. Beyond that information, addit ional factors relating to the appropriate level including costs and economic impacts of controls, technological feasibility, uncertainties and any other relevant factors. Considering all of these factors, the Agency will establish the standard at a level t hat provides an ample margin of safety to protect the public health, as required by CAA section 112(f). See 54 FR 38046.Page 36 of 497

B . What is the litigation history? On January 14, 2009, pursuant to section 304(a)(2) of the CAA, WildEarth Guardians and the San Juan Citizens Alliance filed a Complaint alleging that the EPA failed to meet its obligations under CAA sections 111(b)(1)(B), 112(d)(6) and 112(f)(2) to take actions relative to the review/revision of the NSPS and the NESHAP with respect to the Oil and Natura l Gas Production source category. On February 4, 2010, the Court entered a consent decree that, as modified, requires the EPA to sign by July 28, 2011, 2 proposed standards and/or determinations not to issue standards pursuant to CAA sections 111(b)(1)(B), 112(d)(6) and 112(f)(2) and to take final action by April 3 , 2012.
C . What is the sector

- based approach?
Sector

- based approaches are based on integrated assessments that consider multiple pollutants in a comprehensive and coordinated manner to manage emissions and CAA requirements. One of the many ways we can address sector

- based approaches is by reviewing multiple regulatory programs together whenever possible, consistent with all applicable legal requirements.

2 On April 27, 2011, pursuant to paragraph 10(a) of the Consent Decree, the parties filed with the Court a written stipulation to extend the proposal date from January 31, 2011, to July 28, 20 11, and the final action date from November 30, 2011, to February 28, 2012. On October 28, 2011, pursuant to paragraph 10(a) of the Consent Decree, the parties filed with the Court a written stipulation to extend the final action date from February 28, 20 12, to April 3, 2012.Page 37 of 497

This approach essentially expands the te chnical analyses on costs and benefits of particular technologies, to consider the interactions of rules that regulate sources. The benefit of multi

- pollutant and sector

- based analyses and approaches includes the ability to identify optimum strategies, con sidering feasibility, cost impacts and benefits across the different pollutant types while streamlining administrative and compliance complexities and reducing conflicting and redundant requirements, resulting in added certainty and easier implementation o f control strategies for the sector under consideration. In order to benefit from a sector

- based approach for the oil and gas industry, the EPA analyzed how the NSPS and
NESHAP under consideration relate to each other and other regulatory requirements curr ently under review for oil and gas facilities. In this analysis, we looked at how the different control requirements that result from these requirements interact, including the different regulatory deadlines and control equipment requirements that result, the different reporting and recordkeeping requirements and opportunities for states to account for reductions resulting from this rulemaking in their State Implementation Plans (SIP). The requirements analyzed affect criteria pollutant, HAP and methane emissions from oil and natural gas processes and cover the NSPS and NESHAP reviews.Page 38 of 497

As a result of the sector

- based approach, this rulemaking will reduce conflicting and redundant requirements. Also, the
sector

- based approach facilitate s the streamlining of monitoring, recordkeeping and reporting requirements, thus reducing administrative and compliance complexities associated with complying with multiple regulations. In addition, the
sector

- based approach promotes a comprehensive control strategy that max imizes the co

- control of multiple regulated pollutants while obtaining emission reductions as co

- benefits.
D . What are the health effects of pollutants emitted from the oil and natural gas sector? The final o il and n atural g as sector NSPS and NESHAP amendments are expected to result in significant reductions in existing emissions and prevent new emissions from expansions of the industry. These emissions include HAP, VOC (a precursor to both PM2.5 and ozone formation), and methane (a G HG and a precursor to global ozone formation). These emissions are associated with substantial health effects, welfare effects and climate effects. One HAP of particular concern from the oil and natural gas sector is benzene, which is a known human carcino gen. PM2.5 is associated with health effects including premature mortality for adults and infants, cardiovascular morbidity, such as heart attacks, hospital admissions and respiratory morbidity such as asthma attacks, acute and chronicPage 39 of 497

bronchitis, hospital and emergency room visits, work loss days, restricted activity days and respiratory symptoms, as well as visibility impairment. Ozone is associated with health effects , including hospital and emergency department visits, school loss days and premature mor tality, as well as injury to vegetation and climate effects. IV. Summary of the Final NSPS Rule A. What are the final actions relative to the NSPS for the Crude Oil and Natural Gas source category?
We are revising the existing NSPS, which regulate VOC emissions from equipment leaks and SO 2 emissions from sweetening units at onshore gas processing plants. In addition, we are promulgating standards for several new oil and natural gas affected facilities. The final standards apply to affected facilities th at commence construction, reconstruction or modification after August 23, 2011 , the date of the proposed rule
. The listed oil and gas source category covers all operations in this industry (production, processing, transmission, storage, and distribution) , including those for which we are establish ing standards in this final rule. To the extent there are operations not covered by the currently listed category, pursuant to section 111(b), we have modified the list to include all operations in this industry as mentioned above.Page 40 of 497

1. Standards for gas well affected facilities We are finalizing operational standards for completions of hydraulically fractured gas wells. For purposes of this rule, well completion is defined as the flowback period beginning after h ydraulic fracturing and ending with either well shut in

or continuous flow of gas to the sales line, whichever occurs first. The final rule applies to three subcategories of fractured gas wells for which well completion operations are conducted: (1) wildca t (exp l oratory) and delineation wells; (2)

non - wildcat and non

- delineation wells for which the reservoir pressure is insufficient for a reduced emissions completion (REC), commonly referred to as a “green completion,” to be performed, as determined by a simple calculation involving reservoir pressure, well depth and gathering line pressure at the sales meter (we refer to these wells as “low pressure wells”) and (3) all other fractured gas wells . For category (3) wells , each well completion operation begun on or after [INSERT
DATE TWO YEARS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER] , must employ REC in combination with use of a completion combustion device to control gas not suitable for entering the gathering li ne. For w ell completion operations begun prior to [INSERT DATE TWO YEARS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER] at category (3) wells , the final rule requires the control of emissions either using REC or aPage 41 of 497

completion combustion device. Owners and operators are encouraged to use REC during this period if possible
. For category (1) wells ( exploratory and delineation wells ) and category (2) wells (low pressure wells) , the final rule contains an operational standard that requires the use of a completion combustion device. However, the final rule does not prohibit the use of REC for completion of these wells. Well completions subject to the standards are limited to gas well completions following hydraulic fracturing operations. These comple tions include those conducted at newly drilled and fractured wells, as well as completions conducted following refracturing operations at various times over the life of the well. We have determined that completion operations associated with refracturing pe rformed at an existing well ( i.e. , a well existing prior to August 23, 2011) is considered a modification under CAA section 111(a), because physical change occurs to the existing well resulting in emissions increase s during the refracturing and completion operation. Therefore, the final standards apply to completions at new gas wells that are fractured or refractured as well as completions associated with fracturing or refracturing of existing gas wells. The modificat ion determination and resulting applicability of NSPS to the completion operation following fracturing or refracturing of existing gas wells ( i.e. , wells existing before August 23,Page 42 of 497

2011) , is limited strictly to the wellhead, well bore, casing and tubing, a nd any conveyance through which gas is vented to the atmosphere . It does not extend beyond the wellhead to other ancillary components that may be at the well site such as existing storage vessels, process vessels, separators, dehydrators or any other compo nents or apparatus. 2. Standards for compressor affected facilities The final rule requires measures to reduce VOC emissions from centrifugal and reciprocating compressors. The final rule contains standards for wet seal centrifugal compressors located b etween the wellhead and the point at which the gas enters the transmission and storage segment
. Compressors located in the transmission and storage segment are not affected facilities. The final standards require 95 percent reduction of the emissions from each wet seal centrifugal compressor affected facility. The standard can be achieved by capturing and routing the emissions to a control device that achieves an emission reduction of 95 percent
. The operational standards for reciprocating compressors in the final rule require replacement of the rod packing based on usage. The owner or operator of a reciprocating compressor affected facility is required to monitor the duration (in hours) that the compressor is operated, beginning on the date of initial sta rtup of the reciprocating compressor affectedPage 43 of 497

facility, or on [INSERT DATE 60 DAYS FOLLOWING DATE OF PUBLICATION IN THE FEDERAL REGISTER] , or on the date of the previous packing rod replacement, whichever is later. When the hours of operation reach 26,000 hours (equivalent to 36 months of continuous usage) , the owner or operator is required to change the rod packing immediately. Alternatively, o wners or operators can elect to change the rod packing every 36 months in lieu of monitoring compressor operating hours. 3. Standards for pneumatic controller affected facilit ies We are also finalizing VOC standards to reduce emissions from individual natural gas

- driven pneumatic controllers that vent continuously to the atmosphere and are located between the wellhe ad and the point at which the gas enters the transmission and storage segment. Pneumatic controllers located in the transmission and storage segment and distribution segme nts are not affected facilities . Each continuous bleed, natural gas driven pneumatic device is an affected facility. Accordingly, the final standards apply to each newly installed pneumatic controller (including replacement of an existing controller ). At natural gas processing plants, the final rule includes a natural gas bleed rate limit of zero standard cubic feet per hour for each individual pneumatic controller. The final emission standards for pneumatic controllers at natural gas processing plants reflect the emission level achievable from the use ofPage 44 of 497

non - natural gas

- driven pneumatic co ntrollers. At other locations in the oil and natural gas production segment , the final rule includes a natural gas bleed rate limit of 6 standard cubic feet of gas per hour for an individual pneumatic controller, which would reflect the emission level achi evable from the use of low bleed natural gas - driven pneumatic controllers. In both cases, the standards provide exemptions for certain critical applications based on functional considerations. 4. Standards for storage vessels The final rule contains VOC standards for new or modified storage vessels. The final rule, which applies to individual vessels, requires that storage vessels with emissions equal to or greater than 6 tpy achieve at least 95

- percent reduction in VOC emissions. For storage vessels inst alled at well sites with no wells already in production at the time of installation, or in situations where a storage vessel currently emitting less than 6 tpy experiences an increase in throughput due to an additional well coming on line or other factor, the final rule provides a 30

- day period for the owner or operator to determine whether the magnitude of VOC emissions from the storage vessel will be at least 6 tpy. If the storage vessel requires control, the final rule provides an additional 30 days for the control device to be installed and operational. For well sites with one or more wells already in production at the time of installation,Page 45 of 497

or in situations where an existing storage vessel is replaced,
t hese estimation and installation periods are not pr ovided. 5. Standards for affected facilities located at onshore natural gas processing plants For onshore natural gas processing plants, we are revising the existing NSPS requirements for leak detection and repair (LDAR) to reflect the procedures and lea k thresholds established by 40 CFR 60, subpart VVa. 6. Standards for sweetening unit affected facilities at onshore natural gas processing plants The final rule is a revision to the current standard, which regulates SO 2 emissions from natural gas process ing plants by requir ing affected facilities to reduce SO 2 emissions by recovering sulfur. B. What are the effective and compliance dates for the final
NSPS? The revisions to the NSPS standards being promulgated in this action are effective on [INSERT DAT E 60 DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER] . Affected facilities must be in compliance with the final standards on the effective date, [INSERT DATE 60 DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER]
. V. Summary of the Significant Changes to the NSPS s ince ProposalPage 46 of 497

The previous section described the requirements that the EPA is finalizing in this rule. This section will discuss in greater detail the key changes the EPA is making from the proposal
. These changes result from the EPA’s review of the additional data and information provided to us and our consideration of the many substantive and thoughtful comments submitted on the proposal. While our approach and methodology to establishing the standards remain the same, the changes make the final rule more flexible and cost

- effective, address concerns with equipment

a vailability, streamline recordkeeping and reporting requirements, and improve clarity, while fully preserving or improving the pub lic health and environmental protection required by the CAA.
A. Gas well affected facilities In the final rule, we are revising the requirements for gas well affected facilities. In the proposed subpart OOOO, the rule requirements applied to gas well affe cted facilities that commenced construction, modification or reconstruction after August 23, 2011. Because of uncertainties in the supply of equipment and labor over the near

- term we are now requiring RECs for completion operations begun at category (3) we lls ( non exploratory and non

- delineation wells ) on or after [INSERT DATE TWO YEARS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER].Page 47 of 497

Until this date, flowback emissions must either be controlled using REC or routed to a completion combustion device unless it is technically infeasible or unsafe to do so. Owners and operators are encouraged to use REC during this period if possible. Completion operations at category (1) wells (wildcat and delineation wells) and category (2) wells (non

- wildcat and

non - d elineation low pressure wells) begun on or after [INSERT
DATE 60 DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER] are required to perform REC in combination with a completion combustion device unless it is technically infeasible or unsafe to do so. Additionally, we are finalizing our proposed definition of modification as it pertains to well completion operations following fracturing or refracturing. The final rule provides clarification of what we consider to be a modification for gas well affecte d facilities by specifying that well completion operations following hydraulic fracturing or refracturing at gas well facilities in existence before August 23, 2011 are considered modification s with respect to the gas well affected facility and are therefo re subject to the requirements of the
NSPS . In the proposed rule, we prescribed specific equipment to accomplish an REC. For the final rule, we have removed the required equipment specifications for RECs.Page 48 of 497

Initial compliance requirements for gas well affected facilities have also been revised. Owners and operators are now required to notify the Administrator by the first of each month of all anticipated well completion operations during that month, rather than the proposed requirement of notifying the Administrator of the date of the well completion operation within 30 days of the commencement of each well completion operation. We have also added a requirement that the owner or operator notify the Administrator of the actual date of each well completio n operation by email no t earlier than 3 days or later than 2 days prior to the well completion operation. In the final rule, we have also added a recordkeeping requirement for each gas well facility for which an exemption from combustion requirements is c laimed. Owners and operators are now required to record the location of the well; the specific exemption claimed; the starting and ending date of the period the well operated under the exemption; and an explanation of why the well meets the claimed exempti on. Refer to section IX .B of this preamble and the Responses to Comments document, available in the docket, for detailed discussion regarding these changes. B. Centrifugal and reciprocating compressor affected facilities In the final rule in response to comments requesting clarification , we have made changes that impact bothPage 49 of 497

reciprocating and centrifugal compressors affected facilities. We have clarified that the NSPS does not apply to centrifugal and reciprocating compressors located in the natural gas
t ransmission and storage se gment . We are not requiring that all centrifugal compressors use dry seals, as we proposed, due to technical infeasibility of using dry seals for certain applications . Instead, we are requiring that centrifugal compressor s with wet seals reduce emissions by 95 percent. Centrifugal compressors with dry seals are not affected facilities. The standard can be achieved by capturing and routing emissions from the wet seal fluid degassing system to a control device that reduces VO C emissions by 95 percent. Testing, monitoring, recordkeeping, reporting and notification requirements associated with the control devices have also been added. As proposed, owners or operators of reciprocating compressor affected facilit ies were require d to change rod packing after 26,000 hours of operation. This is equivalent to approximately 36 months of continuous operation. Based on comments we received, we are changing the final rule to provide operators the option of changing the rod packing every 36 months instead of tracking compressor hours of operation
.Page 50 of 497

Refer to section IX .D of this preamble and the Responses to Comments document, available in the docket, for detailed discussion regarding these changes. C. Pneumatic controller affected faciliti es For pneumatic controller affected facilities, we have revised the definition of pneumatic controller affected facility from a single pneumatic controller to a single natural gas operated pneumatic controller that vents continuously to the atmosphere. A s explained further in section IX .C of this preamble, this change provides clarity by more specifically defining the pneumatic controllers we intended to be regulated by the final rule. In addition, only pneumatic controllers located prior to the point at which the gas enters the transmission and storage segment are subject to the NSPS
. Controllers located in the transmission and storage segment are not affected facilities. In the proposed rule, a pneumatic controller affected facility installed after Aug ust 23, 2011 was subject to the requirements. The final rule now applies to pneumatic controller affected facilities installed after [INSERT DATE OF PUBLICATION
IN THE FEDERAL REGISTER]. All new , modified , and reconstructed pneumatic controllers are requir ed, in the final rule, to be tagged with the month and year of installation andPage 51 of 497

identification that allows traceability to the records for that controller. Finally, in order to streamline the recordkeeping and reporting requirements associated with pneuma tic controllers, we are requiring only information on those affected facilities installed during the reporting period to be included in the annual report. Refer to section IX .C of this preamble and the Responses to Comments document, available in the dock et, for detailed discussion regarding these changes. D. Storage vessel affected facilities We have modified the definition of “storage vessel” to
exclude surge control vessels, knockout vessels and pressure vessels designed to operate without emissions to the atmosphere. In addition, we have clarified that we consider a storage vessel that is skid

- mounted or permanently attached to a motor vehicle (such as trucks, railcars, barges or ships) to be stationary once it is located at a site for at least 180 days. In the proposed rule, we established a throughput threshold for storage vessels, below which they were not subject to the NSPS. In order to remove con fusion with respect to the emission factors used to develop the throughput threshold and to address comments indicating significant difficulty measuring throughput , we have revised the final rule such that storage vessels th atPage 52 of 497

emit less than 6 tpy of VOC a re not required to be controlled. In the final rule, for storage vessels installed at well sites with no wells already in production at the time of installation, or in situations where a storage vessel currently emitting less than 6 tpy experiences an incr ease in throughput due to an additional well coming on line or other factor, the final rule provides a 30

- day period for the owner or operator to determine whether the magnitude of VOC emissions from the storage vessel will be at least 6 tpy. If the storag e vessel requires control, the final rule provides an additional 30 days for the control device to be installed and operational. For well sites with one or more wells already in production at the time of installation, or in situations where an existing sto rage vessel is replaced, these estimation and installation periods are not provided. Several requirements for storage vessels in the proposed rule pointed to 40 CFR part 63, subpart HH (the oil and natural gas production NESHAP). However, subpart HH regul ates HAP while this NSPS regulates VOC. Therefore, in order to eliminate confusion caused by cross

- referencing another regulation and to tailor the requirements for VOC regulation, we have incorporated the storage vessel requirements from subpart HH into subpart OOOO and modified those requirements as appropriate for this rule.Page 53 of 497

Refer to section IX .E of this preamble and the Responses to Comments doc ument, available in the docket, for detailed discussion regarding these changes.
E. Equipment leaks a ffected facilities and sweetening unit affected facilitie s a t onshore natural gas processing plant affected facilities We have not made any changes since proposal to the requirements for affected facilities and sweetening unit affected facilities at onshore natural gas processing plants for the final rule. Refer to section IX .F of this preamble and the Responses to Comments document, available in the docket , for detailed discussion regarding these affected facilities. F. Changes to notification, recordkeeping and reporting requirements We have analyzed the notification, recordkeeping and reporting requirements throughout the proposed rule and eliminated duplicative and unnecessary requirements for all emission points. For well completions, compressors, pneumatic controllers and storage v essels we have removed the General Provisions notification requirements under section 60.7(a)(1), (3) and (4). In the affirmative defense provisions of the rule, a citation was corrected, minor wording changes were made, and reporting requirements were refined. The provisions we retainedPage 54 of 497

in the final rule are those we believe are necessary to assure regulatory agen cies and the public that the owner or operator is in compliance with the final rule. Refer to section IX .G of this preamble and the Responses to Comments document, available in the docket, for detailed discussion regarding these changes. VI. Summary of the Final NESHAP Rules A. What are the final rule amendments for the Oil and Natural Gas Production Facilities (subpart HH) source category?
P ursuant to section 112(d)(2) and (3), we have established MACT standards for “small” glycol dehydrators and storage vessels that were not controlled under the initial NESHAP. We have also amended subpart HH to apply the standards at all times , including periods of startup, shutdown and malfunction. Lastly, the final rule includes modification and addition of testing and monitoring and related notification, recordkeeping and reporting requirements, as well as other minor technical revisions to the NESHAP. Our review under section 112(f)(2) did not result in revision to the standards. 1. Standards for glycol dehydration un it process vents In this final rule, we have established for the first time MACT standards for “ small ” glycol dehydration units , which were left unregulated under the initial NESHAP . This subcategory consists of glycol dehydrators with an actual annual av erage natural gas flowrate less than 85,000 standard cubic meters perPage 55 of 497

day (scmd) or actual average benzene emissions less than 0.9 megagrams per year (Mg/yr). The final MACT standards for the subcategory of small dehydrators at oil and gas production faci lities require that existing affected sources meet a unit

- specific BTEX limit of 3.28x10 - 4 grams BTEX/standard cubic meters (scm)

- parts per million by volume (ppmv) and that new affected sources meet a BTEX limit of 4.66 x10 - 6 grams BTEX/scm

- ppmv. 2. Stan dards for storage vessels In the final rule, we have also established for the first time MACT standards for certain storage vessels that were not previously regulated under the initial NESHAP. The standard is the same as that promulgated in the initial NE SHAP for the other storage vessels ( i.e. , 95 percent emission reduction). Thus, the storage vessel requirements will apply to all storage vessels at major sources, not just to those storage vessels with hydrocarbon liquid throughput equal to or greater than 79,500 liters per day
. In addition, we have amended the definition of associated equipment to exclude all storage vessels, and not just those with the PFE, from being considered “associated equipment.” This means that emissions from all storage vessel s, and not just those from storage vessels with the PFE, are to be included in the major source determination. 3. Standards for equipment leaksPage 56 of 497

In t he final rule , as a result of our review under section 112(d)(6), we are revising the leak definition for v alves to 500
ppm , thus requiring the application of the leak detection and repair requirement at this lower detection level
. This leak definition applies only to valves and not other components. 4. Notification, recordkeeping and reporting requirements
Th e final rule revise s certain recordkeeping requirements of 40 CFR part 63, subpart HH. Specifically, facilities using carbon adsorbers as a control device are required to keep records of their carbon replacement schedule and records for each carbon replace ment. In addition, owners and operators are required to keep records of the occurrence and duration of each malfunction or operation of the air pollution control equipment and monitoring equipment. In addition, in conjunction with the new MACT standards f or small glycol dehydration units and storage vessels that do not have the PFE in the final amendments to 40 CFR part 63, subpart HH, owners and operators of affected small glycol dehydration units and storage vessels are required to submit an initial noti fication within 1 year after becoming subject to subpart HH (as revised in this final rule) or by the date of publication of the final rule in the Federal Register , whichever is later. Newly a ffected sources under 40 CFR part 63, subpart HH that plan to be area sources by the major source compliancePage 57 of 497

dates will be required to submit a notification describing their schedule for the actions planned to achieve area source status. The final amendme nts to the NESHAP also include additional requirements for the contents of the periodic reports. The periodic reports are required to include periodic test results and information regarding any carbon replacement events that occurred during the reporting p eriod. B. What are the final rule amendments for the Natural Gas Transmission and Storage facilities (subpart HHH) source category?
P ursuant to section 112(d)(2) and (3), we have established MACT standards for “small” glycol dehydrators that were not
cont rolled under the initial NESHAP. We have also amended subpart HHH to apply the standards at all times, including periods of startup, shutdown and malfunction. Lastly, the final rule includes modification and addition of testing and monitoring and related n otification, recordkeeping and reporting requirements, as well as other minor technical revisions to the NESHAP. Our review under section 112(f)(2) did not result in revision to the standards
. 1. Standards for glycol dehydration units In this final rule, we have established for the first time MACT standards for “ small ” glycol dehydration units in the Natural Gas Transmission and Storage source category . ThisPage 58 of 497

subcategory consists of glycol dehydrators with an actual annual average natural gas flowrate less than 283,000 scmd or actual average benzene emissions less than 0.9 Mg/yr.
The final MACT standard for this subcategory of small dehydrators requires existing affected sources to meet a unit

specific BTEX emission limit of 3.01 x10 - 4 grams BTEX/scm

- ppmv and new affected sources are required to meet a BTEX limit of
5.44 x10 - 5 grams BTEX/scm

- ppmv. 2. Notification, recordkeeping and reporting requirements The final rule revise s certain recordkeeping requirements of 40 CFR part 63, subpar t HHH. Specifically, facilities using carbon adsorbers as a control device are required to keep records of their carbon replacement schedule and records for each carbon replacement. In addition, owners and operators are required to keep records of the occu rrence and duration of each malfunction or operation of the air pollution control equipment and monitoring equipment. In conjunction with the promulgation of the MACT standards for small glycol dehydration units in 40 CFR part 63, subpart HHH, the final r ule requires that owners and operators of small glycol dehydration units submit an initial notification within 1 year after becoming subject to subpart HHH or by the date of publication of the final rule in the Federal Register , whichever is later. Affecte d sources under 40 CFR part 63, subpart HHHPage 59 of 497

that plan to be area sources by the compliance dates will be required to submit a notification describing their schedule for the actions planned to achieve area source status. The final amendments to the NESHAP also include additional requirements for the contents of the periodic reports. For 40 CFR part 63, subpart HHH, the periodic reports are required to include periodic test results and information regarding any carbon replacement events that occurred during the reporting period. C. What are the effective and compliance dates of the standards? The revisions to the MACT standards being promulgated in this action are effective on [INSERT DATE 60 DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER]
. The compliance date for e xisting small glycol dehydration units and storage vessels that are subject to MACT for the first time ( i.e. , those that commenced construction before August 23, 2011 ) is 3 years after the date of promulgation of the standards, [INSERT DATE THREE YEARS AFTER THE DATE OF PUBLICATION IN THE FEDERAL REGISTER]
. The compliance date for n ew affected sources (those that commence construction or reconstruction on or after August 23, 2011) is immediately upon initial startup or the effective da te of the standards, [INSERT DATE 60 DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER] , whichever is later
.Page 60 of 497

The compliance date for p roduction field facilities constructed before August 23, 2011, that were previously determined to be area sources bu t become a major sources on [INSERT DATE 60 DAYS AFTER THE DATE OF PUBLICATION IN THE FEDERAL REGISTER] is 3 years after the promulgation of the standards [INSERT DATE THREE YEARS AFTER THE DATE OF PUBLICATION IN THE FEDERAL REGISTER]
. VII. Summary of the Significant Changes to the NESHAP s ince Proposal The previous section described the requirements that the EPA is finalizing in this rule. This section discusses in greater detail the key changes the EPA is making from the proposal . These changes result from the EPA’s review of the additional data and information provided to us and our consideration of the many substantive and thoughtful comments submitted on the proposal. While our approach and methodology to establishing the standards re main the same, the changes modify the emission limits for glyc ol dehydration units and extend the storage vessel requirements to all storage tanks at major sources, while fully preserving, or improving, the public health and environmental protection requir ed by the CAA.Page 61 of 497

A. What are the significant changes since proposal for the Oil and Natural Gas Production Facilities (subpart HH) source category? 1. Small glycol dehydration units In the final amendments for subpart HH, we have revised the proposed MACT standards for small glycol dehydration units in response to comments . In our proposal, the MACT standards for existing affected sources was a unit

- specific BTEX limit of 1.10x10 - 4 g BTEX/scm

- ppmv and for new affected sources was a BTEX limit of 4.66 x10 - 6 g BTEX/scm

- ppmv. In this final rule, the BTEX emission limit for existing small glycol dehydration units is 3.28x10 - 4 grams BTEX/standard cubic meters (scm)

- parts per million by volume (ppmv) and for new small glycol dehydration units the revised BTEX limi t is 4.66 x10 - 6 grams BTEX/scm

- ppmv. 2. Large glycol dehydration unit 0.9 Mg/yr benzene compliance alternative
We had proposed to eliminate the 0.9 Mg/yr benzene compliance option for large glycol dehydration unit process
vents. This was due to our estima te of the Maximum Individual Risk (MIR) allowed under the 0.9 Mg/yr benzene compliance option to be 400

- in

- 1

- million. Our estimates of the source category maximum cancer risks have changed since proposal due to information received during the comment perio d. For the two facilities determined to have the highest MIRs based onPage 62 of 497

allowable emissions, we found that the actual emissions used for each facility were incorrect and the multipliers used for the allowable calculation were too high. After correcting the multipliers for each facility, the MIR became 3 for the highest facility and less than 1 for the second highest facility
. Based on actual emissions estimates for the Oil and Natural Gas Production source category, the estimated MIR is now 10

- in

- 1 million 3 , compared to 40

- in

- 1 million estimated in the proposed rule. We also estimate that the MIR based on the MACT

- allowable emissions level is now 10

- in

- 1 million, compared to 400

- in

- 1 million estimated in the proposed rule. The total estimated cancer incidenc e from the source category is 0.02 excess cancer cases per year (0.007 excess cancer cases per year based on the lower end of the benzene URE range), or one case in every 50 years. This estimate is unchanged from the proposed rule. Approximately 120,000 p eople are estimated to have cancer risks at or above 1

- in

- 1 million, compared to 160,000 people estimated in the proposed rule. The estimates from the proposed rule of maximum chronic non

- cancer TOSHI value (0.1) and maximum acute

non - cancer hazard quotien t value (9, based on the benzene REL)

3 Three other facilities had an MIR of 20 based on our risk assessment at proposal. All three were determined to be area sources for HAP based on discussions with the permitting authority. Area sources are not within the scope of our risk assessment under section 112(f)(2).Page 63 of 497

are unchanged. Facility

- wide risk estimates are also unchanged from the proposed rule. In accordance with the approach established in the Benzene NESHAP, the EPA weighed all health risk measures and information, incl uding the maximum individual cancer risk, the cancer incidence, the number of people exposed to a risk greater than 1

- in

- 1

- million, the distribution of risks in the exposed population, and the uncertainty of our risk calculations in determining whether the risk posed by emissions from oil and natural gas production is acceptable. In determining whether risk is acceptable, we considered the available health information, as described above. In this case, because the MIR is less than 100

- in

- 1

- million, and bec ause a number of other factors indicate relatively low risk concern (e.g., low cancer incidence, low potential for adverse environmental effects or human health multi

- pathway effects, chronic and acute noncancer health impacts unlikely), we conclude that t he risk is acceptable. Although we have concluded that risks from this source category are acceptable, risk estimates for individuals in the exposed population are above 1

- in

- 1

- million. Consequently, we considered whether the MACT standards (including tho se promulgated today) provide an ample margin of safety. In this analysis, we investigated available emissions control optionsPage 64 of 497

that might reduce the risk associated with emissions from the source category and considered this information along with all of t he health risks and other health information considered in the risk acceptability determination. As stated above, after corrections, the MIR is 10

- in

- 1 million for the major source category. The source of the emissions driving th is risk is a glycol dehydr ator at the Vintage Production facility in Ventura, CA. Since the unit at this facility is a small glycol dehydrator (this unit has a design throughput of 1 MMSCFD), it will be subject to the small dehydrator BTEX limit in the final rule. We determined the applicable BTEX limit for this unit under the final MACT provisions and determined that the resulting MIR would be less than 1

- in

- 1

- million . Because this unit is subject to a standard under the final rule, we do not consider that limit to be required unde r section 112(f)(2). Therefore, to complete our risk analysis, we looked at the facility with the next

- highest
MIR 4 . This facility has a MIR of 10

- in

- 1 million driven by naphthalene emissions from fugitive sources. We considered requiring a LDAR program t o reduce fugitive emissions. Requiring an LDAR program equivalent to NSPS subpart VV would reduce HAP emissions approximately 1 percent, which

4 Aera Energy LLC in Ventura, CA.Page 65 of 497

would equate to 0.6 tons 5 . The estimated annual costs for this option would be $97,000. The cost effectiveness wo uld be $160,000 per ton of HAP reduced. The additional LDAR program requirement would not reduce the MIR for this source category based on both actual and allowable emissions. We consider all of these factors in our ample margin of safety decision and co nclude that the costs of a LDAR program discussed above is not reasonable considering the emission reduction and cancer health benefits potentially achievable with this work practice. As a result, we are concluding that the MACT standards (including those promulgated today) provide an ample margin of safety (considering cost, technical feasibility, and other factors) to protect public health for this source category. Based on the above corrections and analysis, we are retaining the 0.9 Mg/yr benzene compli ance option in the final subpart HH amendments. Large glycol dehydration units now have the option of compliance with either the emission reduction limitation or reducing actual annual benzene emissions to less than 0.9 Mg/yr. 3. Other Changes We are lowe ring the emission reduction allowance for combustion control devices that are tested under, and pass, the

5 Total HAP and naphthalene emissions are approximately 64 tons and 9.5 tons, respectively.Page 66 of 497

manufacturers performance test, from 98.0 percent to 95.0 percent. This change is a result of comments and data provided on the actual performance of these devices in the field. Consistent with the changes in the proposed rule to address SSM, we are removing the monitoring and reporting provisions related to excursions from the final rule. No significant changes since proposal were made to the storag e vessel and equipment leak standards. Refer to sections X .C and X. D of this preamble and the Reponses to Comments document, available in the docket, for detailed discussion regarding these changes. B. What are the significant changes since proposal for the Natural Gas Transmission and Storage facilities (subpart HHH) source category? 1. Small glycol dehydration units In the final amendments for subpart HHH, we have revised the proposed BTEX limits for small glycol dehydration units in response to commen ts . We had proposed a unit

- specific BTEX emission limit of 6.42x10 - 5 grams BTEX/scm

- ppmv for existing

sources and a BTEX limit of 1.10x10

- 5 g BTEX/scm

- ppmv for new

sources . In the final rule, the MACT standards for existing small glycol dehydration units i s an emission limit of 3.10 x10 - 4 g BTEX/scm

- ppmv and for new affected sources is a BTEX limit of 5.44 x10 - 5 grams BTEX/scm

- ppmv.Page 67 of 497

2. Large glycol dehydration unit 0.9 Mg/yr benzene compliance alternative
We had proposed to eliminate the 0.9 Mg/yr compliance option for large glycol dehydration unit process vents. This was due to our estimate of the MIR allowed under the 0.9 Mg/yr benzene compliance option to be 90

- in

- 1

- million. Our estimates of the source category maximum cancer risks have changed since proposal due to information received during the comment period.
We re

- examined our risk assessment and determined that the two facilities 6 that we identified as the risk drivers at proposal are area sources of HAP a nd not part of this major source category that is the subject of the section 112(f)(2) review. Based on actual emissions estimates for the Natural Gas Transmission and Storage source category, the estimated MIR is now 20

- in

- 1 million (5

- in

- 1 million bas ed on the lower end of the benzene URE range), compared to 90

- in

- 1 million estimated in the proposed rule. We also estimate that the MIR based on the
MACT

- allowable emissions levels is now 20

- in

- 1 million (5

- in

- 1 million based on the lower end of the benze ne URE range) compared to 90

- in

- 1 million estimated in the proposed rule. The total estimated cancer incidence from the source category is 0.001 excess cancer cases per year (0.003 excess cancer cases per year based on the lower end of the benzene URE rang e), or

6 Bradley and Danville Compressor Stations. Both in West Virginia.Page 68 of 497

one case in every 1000 years. This estimate is unchanged from the proposed rule. Approximately 2,200 people are estimated to have cancer risks at or above 1

- in

- 1 million, compared to 2,500 people estimated in the proposed rule. The maximum chronic n on cancer TOSHI value is now estimated to be 0.06, compared to 0.4 in the proposed rule. The maximum acute non

- cancer hazard quotient value is now estimated to be 4 (based on the benzene REL), compared to 5 in the proposed rule (also based on the benzene R EL). Facility

- wide risk estimates are unchanged from the proposed rule. These corrections to the risk assessment do not change our overall judgment of risk acceptability. Although we have concluded that risks from this source category are acceptable, risk estimates for individuals in the exposed population are above 1

- in

- 1

- million. Consequently, we considered whether the MACT standards (including those promulgated today) provide an ample margin of safety. In this analysis, we investigated available emissio ns control options that might reduce the risk associated with emissions from the source category and considered this information along with all of the health risks and other health information considered in the risk acceptability determination. As stated above, after corrections, the MIR is 20

- in

- 1 million for the major source category. The so urce of the emissions driving this risk at this facility is fugitivePage 69 of 497

emissions. As we explained in the proposal preamble, under the ample margin of safety analysis, w e investigate available emissions control options that may reduce the risk associated with emissions from the source category and considered this information, along with all of the health risks and other health information considered in the risk acceptabil ity determination. We considered requiring a LDAR program to reduce fugitive emissions, which our revised assessment identifies as the risk driver for this source category. Requiring an LDAR program equivalent to NSPS subpart VV would reduce emissions
appr oximately 1 percent, which would equate to 0.2 tons 7 . The estimated annual costs for this option would be $97,000. The cost effectiveness would be $485,000 per ton of HAP reduced. The additional LDAR program requirement would not reduce the MIR for this s ource category based on both actual and allowable emissions. Considering the factors discussed above regarding acceptable risk, we conclude that the costs of a LDAR program discussed above are not reasonable considering the emission reduction s potentially achievable with this work practice. As a result, we are concluding that the MACT standards (including those promulgated today) provide an ample margin of safety (considering cost, technical feasibility, and other factors) to protect public health for this source category.

7 We speciated facility VOC emissions into HAP and we estimate site

- wide fugitive emissions to be 18 tons per year.Page 70 of 497

Based on the above corrections and analysis, we are retaining the 0.9 Mg/yr benzene compliance option in the final subpart HHH amendments. Large glycol dehydration units now have the option of compliance with either the emission reduction limitation or reducing actual annual benzene emissions to less than 0.9 Mg/yr. 3. Other Changes We are lowering the emission reduction allowance for combustion control devices that are tested under, and pass, the manufacturer ’ s performance test, from 98. 0 percent to 95.0 percent, as a result of comments and data provided on the actual performance of these devices in the field. Consistent with the changes in the proposed rule to address SSM, we are removing the monitoring, recordkeeping and reporting provi sions related to excursions from the final rule. VIII. Compliance Related Issues Common to the NSPS and NESHAP A. How do the rules address startup, shutdown and malfunction? The United States Court of Appeals for the District of Columbia Circuit vacated p ortions of two provisions in the EPA’s CAA section 112 regulations governing the emissions of HAP during periods of startup, shutdown and malfunction (SSM). Sierra Club v. EPA , 551 F.3d 1019 (D.C. Cir. 2008), cert. denied, 130 S. Ct. 1735 (U.S. 2010). Specifically, the Court vacated the SSM exemption contained in 40 CFR 63.6(f)(1) and 40Page 71 of 497

CFR 63.6(h)(1), that are part of a regulation, commonly referred to as the “General Provisi ons Rule,” that the EPA promulgated under section 112 of the CAA. When incorporated into CAA Section 112(d) regulations for specific source categories, these two provisions exempt sources from the requirement to comply with the otherwise applicable CAA sec tion 112(d) emission standard during periods of SSM. As proposed in the NESHAP, we have eliminated the SSM exemption in this rule. Consistent with Sierra Club v. EPA , the EPA has established standards in both rules that apply at all times. We have also re vised Table 3 (the NESHAP General Provisions table) in several respects. For example, we have eliminated the incorporation of the NESHAP General Provisions’ requirement that the source develop an SSM plan. We have also eliminated or revised certain NESHAP recordkeeping and reporting that related to the SSM exemption. The EPA has attempted to ensure that we have not included in the regulatory language, for the NSPS and NESHAP, any provisions that are inappropriate, unnecessary, or redundant in the absence of the SSM exemption. In establishing the standards in both rules, the EPA has taken into account startup and shutdown periods and, for the reasons explained in Section IX for the NSPS and in Section X for the NESHAP, did not establish different standards for those periods. We believe that operations and emissions do not differPage 72 of 497

from normal operations during these periods such that it warrants a separate standard. Therefore, we have not proposed different standards for these periods. Periods of startup, nor mal operations, and shutdown are all predictable and routine aspects of a source’s operations. However, by contrast, malfunction is defined as a “sudden, infrequent, and not reasonably preventable failure of air pollution control and monitoring equipment, process equipment or a process to operate in a normal or usual manner * * * ” (40 CFR 60.2 and 63.2). The EPA has determined that CAA section 111 and 112 do not require that emissions that occur during periods of malfunction be factored into development of CAA section 111 or 112 standards. Section 111 standards

– See section III of the preamble for a detailed discussion on how the EPA sets or revises section 111 new source performance standards (NSPS) to reflect the degree of emission limitation achievabl e through the application of the best system of emission reduction (BSER). Section 112 standards

- Under section 112, emissions standards for new sources must be no less stringent than the level “achieved” by the best controlled similar source and for

e xisting sources generally must be no less stringent than the average emission limitation “achieved” by the best performing 12 percent of sources in the category. There is nothing in sectionPage 73 of 497

112 that directs the Agency to consider malfunctions in determinin g the level “achieved” by the best performing or best controlled sources when setting emission standards. Moreover, while the EPA accounts for variability in setting emissions standards consistent with the section 112 case law, nothing in that case law req uires the Agency to consider malfunctions as part of that analysis. Section 112 uses the concept of “best controlled” and “best performing” unit in defining the level of stringency that section 112 performance standards must meet. Applying the concept of “ best controlled” or “best performing” to a unit that is malfunctioning presents significant difficulties, as malfunctions are sudden and unexpected events. Further, accounting for malfunctions in setting NESHAP or NSPS standards would be difficult, if no t impossible, given the myriad different types of malfunctions that can occur across all sources in the category and given the difficulties associated with predicting or accounting for the frequency, degree, and duration of various malfunctions that might occur. As such, the performance of units that are malfunctioning is not “reasonably”
foreseeable. See, e.g. , Sierra Club v EPA , 167 F. 3d 658, 662 (D.C. Cir. 1999) (“[T]he EPA typically has wide latitude in determining the extent of data

- gathering necessar y to solve a problem. We generally defer to an agency's decision to proceed on the basis of imperfect scientific information, rather than toPage 74 of 497

‘invest the resources to conduct the perfect study.’”). See also Weyerhaeuser Co. v Costle , 590 F.2d 1011, 1058 (D. C. Cir. 1978) (“In the nature of things, no general limit, individual permit, or even any upset provision can anticipate all upset situations. After a certain point, the transgression of regulatory limits caused by ‘uncontrollable acts of third parties,’ s uch as strikes, sabotage, operator intoxication or insanity, and a variety of other eventualities, must be a matter for the administrative exercise of case

- by

- case enforcement discretion, not for specification in advance by regulation.”). In addition, in t he NESAHP context, the goal of a best controlled or best performing source is to operate in such a way as to avoid malfunctions of the source and accounting for malfunctions could lead to standards that are significantly less stringent than levels that are achieved by a well

- performing non

- malfunctioning source. Similarly, In the NSPS context, accounting for malfunctions when setting standards of performance under section 111 which reflect the degree of emission limitation achievable through “the applicatio n of the best system of emission reduction” that the EPA determines is adequately demonstrated could lead to standards that are significantly less stringent than levels that are achieved by a well

- performing non

malfunctioning source. The EPA’s approach to malfunctions isPage 75 of 497

consistent with section 112 and section 111 and is a reasonable interpretation of the statute. Finally, the EPA recognizes that even equipment that is properly designed and maintained can sometimes fail and that such failure can sometimes cause a violation of the relevant emission standard. See, e.g. , State Implementation Plans: Policy Regarding Excessive Emissions During Malfunctions, Startup, and Shutdown (Sept. 20, 1999); Policy on Excess Emissions During Startup, Shutdown, Maintenance, and Malfunctions (Feb. 15, 1983). The EPA is therefore adding to the final NSPS and NESHAP an affirmative defense to civil penalties for violations of emission standards that are caused by malfunctions. See 40 CFR 63.761 for sources subject to the oil and natural gas production MACT standards, or 40 CFR 63.1271 for sources subject to the natural gas transmission and storage MACT standards (defining “affirmative defense” to mean, in the context of an enforcement proceeding, a response or defense put forward by a defendant, regarding which the defendant has the burden of proof, and the merits of which are independently and objectively evaluated in a judicial or administrative proceeding). We also have added other regulatory provisions to specify the elements that are necessary to establish this affirmative defense; a source subject to the oil and natural gas production facilities or natural gas transmission MACT standards must prove by a preponderance of thePage 76 of 497

evidence that it has met all of the elements set for th in 40 CFR 63.762 and a source subject to the natural gas transmission and storage facilities NSPS standards must prove by a preponderance of the evidence that it has met all of the elements set forth in 40 CFR 60.41Da (NSPS). See 40 CFR 22.24. The crite ria ensure that the affirmative defense is available only where the event that causes an exceedance of the emission limit meets the narrow definition of malfunction in 40 CFR 60.2 (NSPS) and 40 CFR 63.2 (NESHAP), respectively, (sudden, infrequent, not reas onably preventable and not caused by poor maintenance and or careless operation). For example, to successfully assert the affirmative defense, the source must prove by a preponderance of the evidence that the violation “[w]ere caused by a sudden, infrequen t, and unavoidable failure of air pollution control and monitoring equipment, process equipment, or a process to operate in a normal or usual manner....” The criteria also are designed to ensure that steps are taken to correct the malfunction, to minimize emissions in accordance with 40 CFR 63.762 for sources subject to the oil and natural gas production facilities MACT standards, 40 CFR 63.1272 for sources subject to the natural gas transmission and storage facilities MACT standards, and 40 CFR 60.5415 (h) for the Standards of Performance for Crude Oil and Natural Gas Production, Transmission, and Distribution, and to prevent future malfunctions. For example, the source must provePage 77 of 497

by a preponderance of the evidence that “[r]epairs were made as expeditiously as possible when the applicable emission standards were being exceeded...” and that “[a]ll possible steps were taken to minimize the impact of the violation on ambient air quality, the environment and human health....” In any judicial or administrative pr oceeding, the Administrator may challenge the assertion of the affirmative defense and, if the respondent has not met its burden of proving all of the requirements in the affirmative defense, appropriate penalties may be assessed in accordance with Section 113 of the Clean Air Act ( see also 40
CFR p art 22.27). The EPA proposed and is now finalizing an affirmative defense in the final NSPS and NESHAP in an attempt to balance a tension, inherent in many types of air regulation, to ensure adequate compliance while simultaneously recognizing that despite the most di ligent of efforts, emission standards may be violated under circumstances beyond the control of the source. The EPA must establish emission standards that “limit the quantity, rate, or concentration of emissions of air pollutants on a continuous basis.” 42 U.S.C. §7602(k)(defining “emission limitation and emission standard”). See generally Sierra Club v.
EPA , 551 F.3d 1019, 1021 (D.C. Cir. 2008). Thus, the EPA is required to ensure that section 112 emissions standards are continuous. The affirmative defense for malfunction events meetsPage 78 of 497

this requirement by ensuring that even where there is a malfunction, the emission standard is still enforceable through injunctive relief. While “continuous” standards, on the one hand, are required, there is also case law ind icating that in many situations it is appropriate for the EPA to account for the practical realities of technology. For example, in Essex Chemical v. Ruckelshaus , 486 F.2d 427, 433 (D.C. Cir. 1973), the D.C. Circuit acknowledged that in setting standards u nder CAA section 111 “variant provisions” such as provisions allowing for upsets during startup, shutdown and equipment malfunction “appear necessary to preserve the reasonableness of the standards as a whole and that the record does not support the ‘never to be exceeded’ standard currently in force.” See also Portland Cement Ass’n v. Ruckelshaus , 486 F.2d 375 (D.C. Cir. 1973). Though intervening case law such as Sierra Club v. EPA and the CAA 1977 amendments call into question the relevance of these cases today, they support the EPA’s view that a system that incorporates some level of flexibility is reasonable. The affirmative defense simply provides for a defense to civil penalties for violations that are proven to be beyond the control of the source. By i ncorporating an affirmative defense, the EPA has formalized its approach to upset events. In a Clean Water Act setting, the Ninth Circuit required this type of formalized approach when regulating “upsets beyond the controlPage 79 of 497

of the permit holder.” Marathon O il Co. v. EPA , 564 F.2d 1253, 1272

- 73 (9th Cir. 1977); s ee also , Mont. Sulphur & Chem. Co. v.
EPA , 2012 U.S. App. LEXIS 1056 (Jan 19, 2012) (rejecting industry argument that reliance on the affirmative defense was not adequate). But see Weyerhaeuser Co. v. Costle , 590 F.2d at 1057

- 58 (holding that an informal approach is adequate). The affirmative defense provisions give the EPA the flexibility to both ensure that its emission standards are “continuous” as required by 42 U.S.C. §7602(k), and account for unp lanned upsets and thus support the reasonableness of the standard as a whole. Refer to preamble section I X for the NSPS , sections X.C and
X. D for the NESHAP, and the Reponses to Comments document for both the NSPS and the NESHAP, available in the docket, for a detailed discussion regarding these changes. B. How do the NSPS and NESHAP provide for compliance assurance? The final rule includes various notification, recordkeeping and reporting requirements that we believe provide a robust compliance assurance program while reducing burden and streamlining requirements. The EPA also considered a variety of innovative compliance approaches that could maximize compliance and transparency while minimizing burden on the regulated community and regulators. More deta iled information on public comments received and the EPA’s responses are included in

s ection s IX and X of the preamble or in the RTC document.Page 80 of 497

1. Notification, recordkeeping and reporting requirements
NSPS For well completions, owners or operators are requir ed to submit each month a single notification of all anticipated well completions for the upcoming month and provide the geographical coordinates of the affected wells and the estimated date of commencement of the flowback period immediately following hydr ofracturing. No t earlier than 3 days or later than 2 days before each well completion, the owner or operator must notify the appropriate regulatory agency via e

- mail of the impending completion. Records of each well completion that document how the completion operation was conducted are retained for 5 years
. Annually, owners or operators of all affected facilities under the NSPS, including gas wells, compressors, pneumatic controllers, storage vessels, and gas processing plants, must report any deviation from the NSPS requirements and document periods of n oncompliance during the reporting period. Each annual report must include a signed certification by a senior company official that attests to the truth, accuracy, and completeness of the report. For affected gas wells, the reports must also include certain details of each well completion conducted during the reporting period. For compressors, pneumatic controllers, and storage vessels, the annual reports must include certain information on all affected facilities thatPage 81 of 497

were constructed, modified or reconstru cted during the reporting period. Owners or operators who conduct certain performance tests on control devices must report results of those tests using the Electronic Reporting Tool (ERT). Further discussion of reporting of emissions tests is presented in Section VIII .D.
NESHAP The final amendments to 40 CFR part 63, subparts HH and 40 CFR part 63, subpart HHH revise certain recordkeeping requirements. Specifically, facilities using carbon adsorbers as a control device are now required to keep records of their carbon replacement schedule and records of each carbon replacement. We are requiring that owners and operators that use a manufacturer’s tested control device keep records of visible emissions readings and flowrate calculations and records of
per iods when the pilot flame is absent. The final amendments require records of the date of each semi

- annual maintenance inspection be maintained. Finally, owners and operators are required to keep records of the occurrence and duration of each malfunction or operation of the air pollution control equipment and monitoring equipment. In conjunction with the final MACT standards for small glycol dehydration units and storage vessels that do not have the PFE in the final amendments to 40 CFR part 63, subpart HH,Page 82 of 497

owners and operators of affected small glycol dehydration units and storage vessels are required to submit an initial notification within 1 year after becoming subject to subpart HH or by [INSERT DATE 1 YEAR AFTER DATE OF PUBLICATION IN THE
FEDERAL REGIST ER] , whichever is later. If owners and operators of affected small glycol dehydration units and storage vessels plan to become area sources by [INSERT DATE 3 YEARS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER] , is required to submit in the initial not ification a brief, nonbinding description of a schedule for the planned action(s) to achieve area source
status. Similarly, in conjunction with the final MACT standards for small glycol dehydration units in the final 40 CFR part 63, subpart HHH amendments , owners and operators of small glycol dehydration units are required to submit an initial notification within 1 year after becoming subject to subpart HHH or by [INSERT DATE 1 YEAR AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER] , whichever is later.

T he final amendments to 40 CFR part 63, subpart HH and 40 CFR part 63, subpart HHH include new requirements for the contents of Notification of Compliance Status Reports. The owners and operators are required to include an electronic copy of the performance test results for the manufacturer’s tested control device, if applicable; the predetermined carbonPage 83 of 497

replacement schedule for carbon adsorbers, if applicable; and data related to the manufacturer’s performance tests conducted for certain models of control d evices, if compliance is being achieved using the manufacturer’s performance tests. The final amendments to the NESHAP also include additional requirements for the contents of periodic reports. Each semiannual report must include a signed certification by a senior company official that attests to the truth, accuracy, and completeness of the report. For both 40 CFR part 63, subpart HH and 40 CFR part 63, subpart HHH, in the final amendments, periodic reports are required to include periodic test results and information regarding any carbon replacement events that occurred during the reporting period. Owners and operators are also required to include in the periodic reports, information regarding any excursions that occur when the inlet gas flowrate identifie d in the manufacturer’s performance test, and any excursions caused when visible emissions exceed the maximum allowable duration. Owners or operators who conduct certain performance tests on control devices must report results of those tests using the Ele ctronic Reporting Tool (ERT). Further discussion of reporting of emissions tests is presented in s ection VIII.C below
. 2. Innovative compliance approachesPage 84 of 497

At proposal, given the potential number and diversity of sources potentially affected by the NSPS an d/or the NESHAP , we solicited comments on optional compliance tools that could reduce compliance burden and enhance transparency. Specifically, we asked for suggestions on: (1) registration of wells and advance notification of planned completions; (2) use of third party verification; and (3) electronic reporting using existing mechanisms. We received comments on each of the topics above and have presented summaries of those comments and the EPA’s responses in the RTC document. The commenters were generally opposed to third party verification. However, one suggestion was a voluntary random verification program, similar to one used in the past for gasoline marketing, where operators who participated in this program potentially could receive lower priority for enforcement inspections by regulators. Other suggested innovative approaches include use of social media, including Facebook and Twitter, plus new technologies such as quick response (QR) codes, to provide timely public notification and access to complianc e records for individual wells and other affected facilities. Other suggestions included use of a centralized database for industry and public access to compliance information. Further discussion of these approaches is provided in the RTC. While we conside red these suggestions, we did not adopt them in the final rule, for reasons explainedPage 85 of 497

further in the RTC document. S ome of these suggestions , however, may be useful for sources to consider in complying with the rule
. C. What are the requirements for submission of performance test data to the EPA? The EPA must have performance test data to conduct effective reviews of CAA sections 111, 112 and 129 standards, as well as for many other purposes including compliance deter minations, emission factor development, and annual emission rate determinations. In conducting these required reviews, the EPA has found it ineffective and time consuming, not only for us, but also for regulatory agencies and source owners and operators, t o locate, collect, and submit performance test data because of varied locations for data storage and varied data storage methods. In recent years, though, stack testing firms have typically collected performance test data in electronic format, making it po ssible to move to an electronic data submittal system that would increase the ease and efficiency of data submittal and improve data accessibility. In this action, as a step to increase the ease and efficiency of data submittal and improve data accessibility, the EPA is requiring the electronic submittal of select performance test data. Specifically, the EPA is requiring owners and operators of oil an d natural gas production, transmission,Page 86 of 497

distribution, and storage facilities to submit electronic copies of performance test reports required by the rules covered under this action to the EPA’s WebFIRE database. The WebFIRE database was constructed to stor e performance test data for use in developing emission factors. A description of the WebFIRE database is available at
h ttp://cfpub.epa.gov/oarweb/index.cfm?action=fire.main

. As mentioned above, data entry will be through an electronic emissions test report structure called the ERT. The ERT will generate an electronic report which will be submitted using the Compliance and Emissions Data Reporting Interface (CEDRI). The submitt ed report is submitted through the EPA’s Central Data Exchange (CDX) network for storage in the WebFIRE database making submittal of data very straightforward and easy. A description of the ERT can be found at http://www.epa.gov/ttn/chief/ert/index.html an d CEDRI can be accessed through the CDX website ( www.epa.gov/cdx )
. The requirement to submit performance test data electronically to the EPA does not create any additional performance testing and would apply only to those performance tests conducted using test methods that are supported by the ERT. The ERT contains a specific electronic data entry form for most of the commonly used the EPA reference methods. A listing of the pollutants and test methods supported by the ERT isPage 87 of 497

available at http://www.e pa.gov/ttn/chief/ert/index.html . We believe that industry will benefit from this new electronic data submittal requirement. Having these data, the EPA will be able to develop improved emission factors, make fewer information requests, and promulgate better regulations. The information to be reported is already required for the existing test methods and is necessary to evaluate the conformance to the test method. One major advantage of submitting performance test data through the ERT is a standardized metho d to compile and store much of the documentation required to be reported by this rule. Another advantage is that the ERT clearly states what testing information would be required. Another important benefit of submitting these data to the EPA at the time t he source test is conducted is that it should substantially reduce the effort involved in data collection activities in the future. When the EPA has performance test data in hand, there will likely be fewer or less substantial data collection requests in

c onjunction with prospective required residual risk assessments or technology reviews. This results in a reduced burden on both affected facilities (in terms of reduced manpower to respond to data collection requests) and the EPA (in terms of preparing and distributing data collection requests and assessing the results).Page 88 of 497

State, local, and tribal agencies can also benefit from a more streamlined and accurate review of electronic data submitted to them. The ERT allows for an electronic review process rather than a manual data assessment making review and evaluation of the da ta and calculations easier and more efficient. Finally, another benefit of submitting data to WebFIRE electronically is that these data will greatly improve the overall quality of the existing and new emission factors by supplementing the pool of emissions test data for establishing emissions factors and by ensuring that the factors are more representative of current industry operational procedures. A common complaint heard from industry and regulators is that emission factors are outdated or not representa tive of a particular source category. With timely receipt and incorporation of data from most performance tests, the EPA will be able to ensure that emission factors, when updated, represent the most current range of operational practices. In summary, in

a ddition to supporting regulation development, control strategy development, and other air pollution control activities, having an electronic database populated with performance test data will save industry, state, local, tribal agencies, and the EPA signif icant time, money, and effort while improving the quality of emission inventories and, as a result, air quality regulations
.Page 89 of 497

IX . Summary of Significant NSPS Comments and Responses For purposes of this document, the text within the comment summaries was p rovided by the commenter(s) and represents their opinion(s), regardless of whether the summary specifically indicates that the statement is from a commenter(s) ( e.g. , “The commenter states” or “The commenters assert”). The comment summaries do not represen t the EPA’s opinion unless the response to the comment specifically agrees with all or a portion of the
comment. A. Major comments concerning applicability 1. Activities that constitute a modification Comment: Referring to the definition of “modification” in section 111(a)(4) of the CAA , one commenter asserts that a modification occurs only if two things happen: (1) there must be a “physical change or change in the method of operation”; and (2) the change must result in an emissions increase
. The commenter states that i n the context of the New Source Review program, the D.C. Circuit Court has opined that “Congress's use of the word ‘ any ’ in defining a ‘ modification ’ means that all types of ‘ physical changes ’ are covered” ( New York v. EPA , 4 43 F.3d 880, 890 (D.C. Cir. 2006) ) and that the D.C. Circuit Court has determined that “the plain language of the CAA indicates that Congress intended to apply NSR to changes that increase actual emissions instead of potential or allowablePage 90 of 497

emissions.” New York v. EPA , 413 F.3d 3, 40 (D.C. Cir. 2005). However, according to the commenter, the Supreme Court has concluded that the section 111 definition of modification does not have to have the same meaning under the NSPS and NSR
programs ( Environmental Defen se v. Duke Energy Corp. , 127 S. Ct. 1423, 1434 (2007) ), and thus the EPA has latitude within the context of section 111 to implement different rules regarding modifications. The commenter believes i n particular that the EPA’s regulatory definition of “modification” under the NSPS program provides several categories of activities that alone, are not to be considered modifications , including “maintenance, repair, and replacement which the Administrator determines to be routine for a source category,” and “an increase in production rate that can be accomplished without a capital expenditure.” 40 CFR 60.14(e). The commenter believes these provisions reflect the fact that Congress established the NSPS program for “new” sources. According to the commenter, w i thout these exclusions, even the most minor activities would convert an existing source into a “new source.” The commenter state s that t he premise behind characterizing these activities as not being “changes” is that they all contemplate that the plant wil l continue to be operated in a manner consistent with its original design and thus is not a “new” facility.Page 91 of 497

Response: CAA section 111(b) requires that the EPA establish NSPS for new sources in a listed source category. Section 111(a) defines new sources to include sources that undergo modification. As the commenter notes, 111(a)(4) defines modification to include any physical change which increase emissions. We need not address the relevance of the New York v.
EPA , 413 F.3d 3, 40 (D.C. Cir. 2005) or Environmental Defense v. Duke Energy Corp. , 127 S. Ct. 1423, 1434 (2007) in this package or whether those decision compel the position we are taking with respect to recompletions. To be clear, we do not in this package question the general appropriateness of the NSPS general provisions at 40 CFR 60.14(e), including our prior identification of activities that the EPA generally does not consider to be “modification” for purposes of establishing NSPS. As the commenter notes, 60.14(e) is intended to exclude r outine and minor activities , such as routine maintenance and repair or an activity that requires insignificant expenditure. See , e.g. , 40 CFR 60.14(e)(1) and (2)
. However, as the general provisions themselves recognize, the general NSPS definition of mod ification may not be appropriate in all cases. Specifically, the General Provision at 40 CFR 60.14(f) allows the EPA to promulgate special provisions in any specific subpart to supersede any conflictingPage 92 of 4 97

modification provision in 60.14(e). Well completions involving hydraulic fracturing are not the kind of minor or routine activities that the EPA had intended to exclude when it promulgated section 60.14(e), which more appropriately address the minor activities in typical stationary sources, such as a plant o r a facility. As explained in the proposal, recompletion s fit well within the statutory definition of modification (the fracturing results in a physical change which causes flowback and an increase in emissions relative to the emissions level prior to th e refracturing). Given the significant, although short term, increase in emissions and the cost effective nature of the control on such emissions, we have concluded that coverage of refracturing activities is appropriate even if it requires departing from the General Provision definition of modification. We note that the EPA learned from the comment that some hydraulic fracturing operations may be excluded under 60.14(e)(2) because their expenditures do not meet the regulatory definition of “capital expenditure.” Pursuant to 60.14(f) and for the reasons descri b ed above, th e EPA is adding a special provision in NSPS subpart OOOO that modification occurs when a fractured or refractured well undergoes a completion and clarifying that this specific provision supercedes any conflicting modification provisions in 60.14(e)
.Page 93 of 497

We con sider this change to be a logical outgrowth of the proposal as our description and analysis evidenced a clear intent to cover all such activities. 2. Regulation of methane and other pollutants Comment: One commenter believes that under section 111, the EPA must regulate each dangerous pollutant emitted by sources in the oil and gas source category in more than de minimis quantities for which controls are available and asserts that the EPA has failed to do so. In particular, the commenter state s that the EPA must regulate methane, particulate matter, hydrogen sulfide, and nitrogen oxides from oil and gas operations. The commenter
state s that the EPA’s explanation of why it declined to regulate certain pollutants does not discuss particulate matter or hydro gen sulfide, address the most important sources of nitrogen oxides, or offer a legal justification for its failure to regulate methane. The commenter interprets the CAA to mean that the EPA must, every eight years, (1) review its standards (as it has done here), (2) determine whether it is “appropriate” to revise them, including whether it is appropriate to add additional pollutants to the standards, and (3) if so, revise them accordingly. Response: Section 111 of the CAA does not require that the EPA

assess every single pollutant in a listed source category when promulgating NSPS or performing the subsequent 8

- year review.Page 94 of 497

Section 111(a)(1) requires that the standard of performance reflect the application of the best system of emission reductions which , taking into consideration the cost of achieving such emission reductions, any non

- air quality health and environmental impact and energy requirements, the Administrator determines has been adequately demonstrated. It does not require that the standard a ddress every single pollutant. As implemented over many years by the EPA, the NSPS program has established standards that do not necessarily set emission limits for all pollutants or even all regulated pollutants emitted by sources within the relevant sour ce category. Instead, the NSPS generally focus on specific pollutants of concern for a particular source category. For instance, the NSPS promulgated for the oil and gas category regulate VOC and SO 2 emissions at processing plants
. Section 111(b)(1)(B) r equires that the EPA review and, “if appropriate,” revise, NSPS at least every eight years unless the Agency determines that such review is not appropriate in light of readily available information on the efficacy of the standard. Pursuant to this provisio n, the EPA periodically reviews and revises the standards of performance, as appropriate, to reflect improvements in methods for reducing emissions. The EPA also believes that it has discretion under section 111(b)(1)(A) to revise an NSPS to add standard s forPage 95 of 497

pollutants not previously regulated for that source category. However nothing section 111(b)(1)(A) suggests that it imposes such duty on the EPA. Specifically, the definitions of “stationary source” and “modification” do not require that the EPA asses s and regulate every pollutant, as the commenter contended. The definition of “stationary source,” which refers to sources that emit or may emit any pollutant, simply indicates that any source that emits a pollutant may be subject to listing under section 111. Similarly, the definition of modification, which refers to change that results in increase of the amount of any pollutant or emission of pollutant not previously emitted, simply means that such activity could trigger NSPS applicability for an existing source . Neither provision addresses how the EPA should
set or revise a standard under section 111 . We also find commenter’s argument regarding 111(f) equally unpersuasive. Section 111(f) sets forth factors for prioritizing source categories for issuing N SPS; it does not address the content of standards to be set under section 111. Neither has the EPA prescribed criteria for determining when the revision is “appropriate” under section 111(b), as the
commenter contends. The EPA has not stated in the NSPS reviews referenced in the comment or elsewhere that the EPA would only consider these two factors in determining whether revision isPage 96 of 497

“appropriate” under section 111(b) or that the EPA will regulate every pollutant that meets these criteria
. In any e vent, w ith respect to methane emitted from the oil and gas sector, the EPA has not completed its review process. The EPA is continuing to assess methane emissions and evaluate appropriate actions for addressing these concerns. The EPA notes that control me asures for methane are the same as those for VOC, which the EPA has previously regulated and is requiring further reduction in this NSPS review. Although the VOC requirements in this rule would also achieve substantial reduction in methane emissions , the E PA currently does not have sufficient information at this time to assess the extent of methane emissions that would remain even with the expanded VOC controls and whether additional measures are available and appropriate for addressing such emission s . For the reason s stated above, the EPA is continuing its assessment of methane emissions, including gathering and reviewing additional information, to evaluate appropriate actions. 3. Expanded scope of the source category Comment: One commenter states that i n t he preamble, the EPA makes reference to its proposal to significantly expand the scope of oil and gas operations that would be covered by the new NSPS, and states that "[t]o the extent that there are oil and gas operations not covered by the currently list ed Oil andPage 97 of 497

Natural Gas source category, pursuant to CAA section 111(b ) we hereby modify the category list to include all operations in the oil and natural gas sector." 76 Fed. Reg. 52745 , Aug. 23, 2011. The commenter is not aware of any authority pursuant to which the EPA may affect a significant expansion of the category list merely through the language of the preamble in an NSPS rulemaking. The commenter state s that i n a related context, the CAA requires that the EPA engage in consultation with State governors and air pollution control agencies, suggesting that more than a preamble reference is needed in order to expand the category list and thus to impose NSPS requirements on entire categories of sources that had not previously been subjected to such requirements. See 42 U.S.C. §7411( f )(3). Response: As explained in the preamble to the proposed rule, the EPA believes that the currently listed oil and natural gas category covers all operations in this industry. 76 FR at 52745. The EPA has described this listed source category very broadly, to “encompass the operations of exploring for crude oil and natural gas products, drilling for these products, removing them from beneath the earth’s surface, and processing these products from oil and gas fields for d istribution to petroleum refineries and gas pipelines.” 49 FR at 2637. The EPA promulgated the existing NSPS (subparts KKK and LLL) “based on the Administrator’s decision that the crude oil and natural gasPage 98 of 497

production industry causes or contributes signific antly to air pollution that may reasonably be anticipated to endanger public health or welfare” ( Emphasis added ) . 49 FR 2636. For the reasons stated above, we believe that the currently listed oil and natural gas category covers all operations for which we are setting standards. That the original NSPS’s only set standards for a limited set of sources within the category cannot be taken to imply that other units were not within the scope of this original listing. See, e.g., Nat’l Lime Ass’n v. EPA , 627 F.2d at 426 n. 27 (noting that the EPA set standards for only certain kiln types within the source category)
. Even if the original listing was not this broad , section 111(b)(1)(A) provides the EPA authority to revise the list of categories , which we explained in the proposal we believe reasonably includes the ability to modify the scope of existing source categories
. Section 111(b)(1)(A) does not set forth criteria for the EPA’s revision to the list , thus giving the EPA broad discretion. The informat ion that the EPA has reviewed during this rulemaking continues to support the finding that this industry causes or contributes to air pollution which may reasonably be anticipated to endanger public health or welfare. Therefore, to the extent that the orig inal listing of the oil and gas source category had not covered all operations in this industry, the EPA is revising the listed category to includePage 99 of 497

those operations. While the commenter suggests that the EPA cannot amend a source category in a preamble , the commenter points to no directly applicable provision demonstrating why the EPA cannot do so, and does not explain why the EPA’s interpretation is inconsistent with the plain language of the
CAA . Rather, the commenter claims that 111(f)(3)suggests tha t amending a 111(b) listing cannot, or should not, be done in a preamble. By its terms, 111(f)(3)does not apply here. S ection 111(f)(3) requires the EPA to consult with State Governors (1) before promulgating standards for a listed source category for whic h the EPA had not proposed regulations before November 15, 1990 or (2) before listing a category under section 111(f).
Because the EPA listed this source category in 1979 and promulgated regulations in 1984, this rulemaking is not scenario (1) described ab ove. Further, that Congress explicitly requires consultation in certain circumstances but not with respect to the EPA's authority to amend listing under 111(b) supports, rather than undermines, our conclusion that consultation is not a procedural perquisit e to a 111(b) revision. B. Major comments concerning well completions 1. Applicability and exemptions

a . Well exemptionsPage 100 of 497

Comment: One commenter suggests adding “appraisal wells” as a third category of well to be exempt from the REC requirements, and defines these wells as those drilled in an area where the reservoir has not been classified for that area as containing proved reserves of natural gas. According to the commenter, adding this definition and exemption better reflects the universe of wells for which a gas gathering line system will not be available. The commenter adds that it also avoids a potential problem where a shale pl ay appraisal well system is effectively compelled to install a gathering line system before the wells are determined to be economically viable, in order to assure compliance with NSPS subpart OOOO. Response: The EPA recognizes that a gathering line at the well pad is a necessary precondition to capture flowback gas for emissions control so that the REC process has an outlet for the captured gas. However, the EPA does not agree that appraisal wells need to be exempt. Appraisal wells are drilled and then log ged to assess productivity. If well logs indicate that the well is productive, then the cost to fracture, complete and produce the well is incurred. If the well logs indicate the well is not economically productive, then no fracturing occurs. The EPA there fore believes it is reasonable to require appraisal wells that are hydraulically fractured to comply with Subcategory 3 rule requirements.Page 101 of 497

b . Threshold for low pressure (low volume) wells and wells with low or no VOC emissions Comment: One commenter expresse s support for the REC requirements and urge s the EPA to limit the number of well completions exempted from the requirements as much as possible. Several commenters contend that not all well completions can be conducted successfully under a requirem ent to flow back to the gathering line, since the imposition of the gathering line backpressure may reduce the flowback gas velocity sufficiently so that it is not energetic enough to clean up the well of liquid and sand. One commenter recommends that any well whose reservoir pressure (measured at the wellhead immediately after perforation) is less than four times (in absolute units) the line pressure measured at the flow meter would be exempt from any requirement to flow to sales during the flowback period
. According to the commenter, variability in reservoir and line pressures across the United States makes setting a specific pressure threshold difficult. Response: The EPA has established three subcategories of wells in response to comments, as described a bove. One of those categories is comprised of non

- wildcat and non

- delineation low pressure wells. Low pressure wells are defined as wells for which the gathering line pressure at the sales meter (in psia)is greater than 0. 443 times static reservoir pressure (in psia)Page 102 of 497

minus 0. 092 times the vertical well depth (in feet) plus 497 psia
. Thus, wells above this pressure differential must implement REC, while wells below this pressure differential are required to route emissions to a completion combustion device
. The EPA solicited comment in the proposed rule on situations where REC may be infeasible and criteria and thresholds for distinguishing well completion operations in those situations from others where REC is feasible
. As no ted above, several commenters highlighted the technical issue s that prevent an operator from implementing an REC on a low pressure well, which is the inability to attain a gas velocity sufficient to clean up the well when flowing against the gathering line backpressure. Based on this information, the E PA agrees that a
pressure differential threshold is reasonable and addresses the technical limitations of low pressure wells to produce to the gathering line during completion. As noted above, a commenter re commended specific approaches to developing a pressure threshold including specifying that any well whose reservoir pressure is less than four times (in absolute units) the line pressure measured at the flow meter would be exempt from any requirement to fl ow to the sales line during the flowback period. This recommendation is based on a flowing bottom hole to reservoir pressure ratio of 1:2 and a line pressure to flowing bottom hole pressure of 1:2
. The EPAPage 103 of 497

concurs with the commenter that flowing bottom hol e pressure can be represented as half of the reservoir pressure for this rule. The EPA disagrees with the commenter that line pressure can be represented as half of the flowing bottom hole pressure for this rule since this pressure relationship can be more accurately determined using the Turner equation for liquids unloading from a well paired with models relating fluid velocity to pressure drop. Therefore, the EPA has modeled a worst

- case pressure drop factor between the line pressure and flowing bottom hole pressure and has established a pressure threshold using this factor and the 1:2 factor for flowing bottom hole pressure to reservoir pressure. The result of this modeling is the equation discussed above in the definition of low pressure wells. The EPA reviewed potential control options for wells that fall below the pressure threshold and determined that flaring is technically feasible and cost

- effective. Therefore, wells with a pressure drop at or above this differential are required to use
REC . Wells with a pressure drop below this differential are considered low pressure wells in wh ich combustion of the flowback gas is required. Comment: Several commenters address parameters for defining which well completions would be subject to REC requirements. Commenters request that the EPA exempt wells with low VOC concentrations from the REC r equirements and not issue thePage 104 of 497

proposed standards before reconsidering the emissions estimates. One commenter suggests that the EPA exempt hydraulically fractured natural gas horizontal wells with de minimis VOC concentrations because the cost per ton of VOC reductions is extremely high for these wells and the emissions from the combustion of the produced gas could worsen ozone formation in the area. C ommenters also state as examples some wells with low

or no VOC as support for exempting wells with a low VOC content or for exempting certain classes of wells such as coal bed methane. Several commenters contend that coal bed methane wells have low VOC, while several other commenters contend that coal bed methane wells have no VOC. Some commenters provide examples of coal bed methane wells with low VOC or no VOC, and one commenter provides an example of a shale gas well with no VOC. Response: The EPA acknowledges that the VOC concentration in natural gas can vary across wells and reservoir types such coal bed methane ( CBM ) , shale, and tight sands. In response to comments, the EPA assessed the VOC content of coal bed methane (CBM) wells. However, be st available data show that VOC concentrations among CBM wells will vary and are not always low. With respect to the suggestion that the EPA develop a specific threshold for VOC concentrations and exempt wells below such threshold , the EPA determined that the information provided by commenters is not sufficient to warrant a change in the EPA’sPage 105 of 497

VOC emissions estimates or to develop a VOC threshold. In any
event , even if such a threshold can be determined, to ensure compliance with the rule an operator would have to determine with certainly before production whether a particular well was going to be above or below the threshold in order to mobilize the necessary capture equipment and secure a sales line, etc. This would require the operator to determine the re servoir composition, e.g. , the gas composition prior to separation, in advance of the well completion. In addition, the operator would need to certify that the reservoir sample is going to stay consistent and representative of the gas stream throughout the full completion process through multiple gas composition analyses. Taking into account the variability in VOC concentrations across reservoir types, the EPA’s cost analysis illustrate s that on average, these requirements are cost

- effective especially
wh en taking into account the gas savings. Compliance with a VOC concentration threshold based rule for well completions could actually increase the burden to the operator by requiring numerous compositional analyses to demonstrate compliance with the rule. However, in response to comments, we have modified the provisions in the final rule that require REC for all hydraulically fractured gas well completions. As discussedPage 106 of 497

abouve, w e have created three subcategories of hydraulically fractured gas wells: (1) w ildcat (exploratory) and delineation wells, (2) non

- wildcat and non

- delineation low pressure wells (see further discussion below), and (3) all other wells. For each well completion operation at category (3) non - wildcat and

non - delineation wells with hydrau lic fracturing begun on or after [INSERT DATE TWO YEARS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER] , the s tandards require a reduced emission completion (REC) in combination with the use of a completion combustion device to control gas not suitable for entering the gathering line. For w ell completion operations at non

exploratory and non

- delineation wells with hydraulic fracturing begun prior to [INSERT DATE TWO YEARS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER] , the final rule requires the con trol of emissions using REC or a completion combustion device.
For category (1) wells ( exploratory and delineation wells ) and category (2) wells (low pressure wells) , the final rule contains an operational standard that requires the use of a completion c ombustion device. However, the final rule does not prohibit the use of REC for completion of these wells. 2. Rule should not prescribe equipment Comment: Several commenters suggest revising 60.5375(a)(2) equipment requirements to be less prescriptive, especially in cases where use of specified or all listed equipment may not bePage 107 of 497

necessary and to provide flexibility to include newly developing technology. Other commenters assert that language i n sections 60.5375(a)(1) and (2) stating that source owners or operators should “minimize the emissions associated with venting of hydrocarbon fluids and gas” and that “[a]ll salable gas must be routed to the gas gathering line as soon as practicable” is

v ague and recommended a requirement that facility owners follow a Best Management Practice (BMP) plan that the EPA could develop informed by the Natural Gas STAR program. Response: The EPA agrees that prescribing specific equipment to accomplish a reduced e missions completion is not necessary and has revised the rule language to not prescribe specific equipment. The EPA has further clarified Section 60.5375(a)(2) to include the possibility of routing recovered gas and utilizing it as a fuel source. A comment er has suggested that the rule require a best management practice plan to determine when to implement reduced emission completions across a development area. Because completion emissions occur at the well rather than at the area level, the EPA does not bel ieve that use of a BMP is appropriate. 3. Availability of equipment and trained personnel Comment: Commenters state that the supply of REC equipment and personnel is insufficient to meet the requirements of the proposed rule, applied nationally. According to commenters,Page 108 of 497

proper surface equipment, collection infrastructure, and qualified personnel are not readily available; they assert that this equipment is fairly specialized, the shops licensed to make it are limited, and some of the components require a l ong lead time. For these reasons, commenters indicate that compliance by the issuance date of the rule would be unrealistic and that the EPA should provide a longer compliance period. Response: Based on information submitted by commenters, we have reason to believe that currently there is significant demand for REC equipment. For example, Colorado, Wyoming, and the City of Fort Worth, Texas, require RECs under certain conditions. Additionally, pu blic comments, reports to the EPA’s Natural Gas STAR Program, and press statements from companies indicate that some producers implement RECs voluntarily based upon economic and environmental objectives. The NSPS will undoubtedly add additional demands on REC equipment supply and experienced personnel. If the near

- term supply of REC equipment and trained personnel is insufficient to meet the new national demand for equipment and labor, immediate compliance with the REC requirements could be impossible, pot entially causing producers to delay well completions until appropriate equipment and labor

are available. Any resulting delays in well completions while awaiting equipment availability could cause a decrease in thePage 109 of 497

nationwide natural gas supply. It is not the EPA’s intent to set in motion a series of events through this rule that has the potential to affect the natural gas supply. The E PA therefore believes that it is important to consider the availability of REC equipment and personnel is its BSER analysis
. Unfortunately, the EPA is not aware of any quantitative information on the current and future supply of workers trained in REC techniques. Few data are available to quantitatively evaluate the current and future supply of REC equipment. Meanwhile, accor ding to one commenter, about 300 REC units are in use today, with the ability to process about 4,000 wells per year, and 1,300 additional units would be required to perform 20,000 RECs per year. About 1,600 units performing 20,000 RECs/year implies about 1 2.5 RECs/year/unit, or roughly each unit performing one REC per month on average. The 12.5 RECs/year/unit is reasonably consistent with the commenter’s cost analysis, which assumes individual REC units are leased for

one - month periods and perform a single REC within that period. The NSPS proposal estimated 9,300 RECs performed for new natural gas well completions and 12,200 RECs performed for existing natural gas well recompletions. As discussed more below, the EPA has reevaluated the assumption that on a verage each fractured gas well is re

- fractured every 10 years, which equates to approximately 10% of fractured gas wells being re

-Page 110 of 497

fractured each year. In the analysis supporting the final rule, the EPA revised estimates show the NSPS will require approxima tely 10,500 RECs to be performed annually. Assuming a REC unit performs 12.5 RECs/year, about 840 units would be required. This implies a current shortfall of about 540 units, based upon the numbers and assumptions provided by the commenter. The commente r states that industry can deliver about 50 units per quarter, after a one

- year build up period. Under this assumption, it would take about 3.75 years to meet demand. This scenario is depicted in Scenario A in the Table 2 , assuming compliance is initiated at the beginning of the second quarter 2012, and the industry begins delivering 50 units per quarter roughly one year after the compliance date. Surveys conducted by one commenter indicate that nine companies expect to perform more RECs than the current s tock is capable of. Given current demand, it might be reasonable to assume industry can deliver units during the first year of implementation, which would reduce the time required to meet full demand another year to a total about 2.75 years (Scenario B). An additional option to building new REC equipment to meet demand is to increase the productivity of equipment in use. The EPA estimated that flow back periods will typically be 3

- 10 days with 7 being a reasonable average. If the utilization rate ofPage 111 of 497

REC un its is increased gradually from performing 12.5 RECs/year/unit to 14

- 18 RECs/year/unit, the time required to build the supply of REC units decreases (Scenarios C

- F). As the Table 2 shows, each 1 REC/year/unit increase reduces the buildup time by about 1 qu arter. As is shown in Scenario D, increasing the utilization rate of REC from 12.5 to 15 RECs/unit/year with industry supplying new units beginning with the compliance date would provide about two years for full build out of the REC unit supply. Table 2
. REC unit supply analysis Scenario A B C D E RECs Required 10,532 10,532 10,532 10,532 10,532 Productivity (RECs/year/unit) 12.5 12.5 14.0 15.0 16.0 Units Needed 843 843 752 702 658 Stock in Existence (industry can build 50 units/quarter; assuming industry starts with 300 units); compliance begins approximately at the end of the second quarter, 2012.
Scenario A B C D E 2012 (Q1) 300 300 300 300 300 2012 (Q2) 300 300 300 300 300 2012 (Q3) 300 350 350 350 350 2012 (Q4) 300 400 400 400 400 2013 (Q1) 300 450 450 450 450 2013 (Q2) 300 500 500 500 500 2013 (Q3) 350 550 550 550 550 2013 (Q4) 400 600 600 600 600 2014 (Q1) 450 650 650 650 650 2014 (Q2) 500 700 700 700 700 2014 (Q3) 550 750 750 2014 (Q4) 600 800 800 2015 (Q1) 650 850 2015 (Q2) 700 2015 (Q3) 750Page 112 of 497

2015 (Q4) 800 2016 (Q1) 850 2016 (Q2)

Because of uncertainties in the supply of equipment and labor over the near

- term, and based on our analysis described above, the EPA concludes that RECs may not always be available during the first two years after the NSPS becomes effective. Therefore, during the first two years, the BSER for well completions is to combust completion emissions . However, the EPA will allow REC as an alternative to combustion so that facilities that are able to obtain REC equipment may still capture completion emissions using a REC. At the beginning of the third year of implementation, capturing completion emissions using a REC will be considered BSER. This two

- year period will permit the companies producing REC units to increase production to levels sufficient to meet new demand. In addition, because the new rule will require more RECs to be performed, the EPA believes that producers will take advantag e of scale economies and use REC units at a higher rate of productivity than the rate implied by comments received. The EPA believes that the NSPS, as finalized, will minimize the risks of producers slowing well completion

- related activities in order to o btain appropriate equipment and labor, while not losing VOC emissions reductions because completionPage 113 of 497

emissions will be either combusted or captured. This would also minimize the possibility that the price of REC equipment and labor increases over the near

- t erm, enabling producers to better plan efficient use of existing and new capital and labor, and providing additional time for innovation in reduced emission completion technologies. 4. Cost and emissions calculations Comment: Some commenters request the EP A to fully explain or reconsider the 10 percent rate of refracturing of wells
. Response: The EPA has reevaluated the assumption that on average each fractured gas well is re

- fractured every 10 years, which equates to approximately 10 percent of fractured g as wells being

re - fractured each year based on drilling and re

- fracture records from an industry representative. The EPA has received data on the percent of gas wells to be

re - fractured per year, referred to as recompletions. This new information showed that the recompletion frequency can be as low as 0.01 percent and as high as 0.8 percent. The EPA evaluated this new information against the assumptions in the proposed rule analysis, determined that this information represents best available data and conc luded that the impacts analysis needed updating to more accurately reflect the number of wells recompleted in a given year. Based on this information, the EPA has estimated the recompletion frequency to be 1 percent ofPage 114 of 497

fractured gas wells per year. The EPA rounded the figures provided by the companies to reflect the uncertainty in the data. 5. Definition of affected facility Comment: Several commenters assert that a well completion is different from a well workover and should be better defined in the rule. Response: Based on the comments received, the EPA acknowledges
that the term “workover” is a general term that may have a number of different meanings. Based on the various definitions of the term provided by the commenters, we realize that workover
may be interpreted to include activities that we did not intend to cover under the rule. Therefore, in the final rule we have revised the definition of “well completion operation” to exclude the term “workover” and instead include the phrase “with hydraulic fr acturing
. ” C. Major comments concerning pneumatic controllers 1. Definition of affected facility Comment: Some commenters request that the EPA consider excluding or exempting emergency and/or safety system devices (such as a pilot operated pressure relief valve). According to one commenter, safety system devices typically do not emit gas unless there is an emergency, have a near

- zero VOC

- leve l static state, and if regulated, could be replaced by substandard,Page 115 of 497

cheaper technology of spring operated valves which would create much more leakage of gas into the environment. With regard to emergency situations, another commenter argues that the prop osed standards that apply to pneumatic controller affected facilities (§60.5390(b)) could inhibit safe plant operation during an emergency because they require that each pneumatic controller located at a natural gas processing plant have zero natural gas e missions. According to the commenter, a gas

- powered controller is a reliable alternative for safe plant operation during emergencies, and the commenter suggests that the final rule include an exception to allow gas plants to use natural gas

- driven pneumati c controllers for emergency plant shut down and subsequent startup. With regard to high

- bleed pneumatic controllers, several commenters request that the EPA further explain when the use of high

- bleed pneumatic controllers is allowed and provide specific examples of exemptions. The commenters suggest exemptions that address situations such as those where the natural gas includes impurities that could increase the likelihood of fouling a low

bleed pneumatic controller, such as paraffin or salts; where
weat her conditions could degrade pneumatic controller performance; during emergency conditions; where flow is not sufficient for low

- bleed pneumatic controllers; and where electricity is not available; and where engineering judgmentPage 116 of 497

recommends their use to mai ntain safety, reliability, or efficiency. Several commenters request that the EPA provide additional information about how to demonstrate that the use of high

- bleed pneumatic controllers is predicated as stated in proposed §60.5390(a). The commenters sugge st that this exemption is very vague, will allow for excessive emissions, and is not enforceable. Response: The EPA notes that the pneumatic controller standards do not apply if you demonstrate, to the Administrator’s satisfaction, that the use of a high bleed controller is
necessary based on operational requirements of the controller
. As examples, the demonstration may include, but is not limited to, response time, safety, and actuation of valves. These functional exemptions to the requirement address the commenters’ concerns of safety, emergency, and otherwise non

- routine situations. Comment: Several commenters express concerns with the proposed rule’s treatment of various types of pneumatic devices and controllers. One commenter requests that the EPA cla rify in subpart OOOO that intermittent bleed pneumatic devices are not affected sources. Another commenter asserts that continuous low

bleed controllers that replace existing continuous low

- bleed controllers should not be “affected facilities.” According t o this commenter, some designed high bleed devices may be isolatedPage 117 of 497

from the gas pressure with a valve and operated manually on an intermittent basis. The commenter wants clarification in the rule that will allow an operator to use a high

- bleed device if it is operated in a manner that keeps its emission levels less than 6 scfh. One commenter requests that the EPA clarify in the final rule that the distribution sector and self

- contained devices that release gas to a downstream pipeline instead of to the
at mosphere are exempt. Another commenter argues that no

- bleed pneumatic devices have zero emissions and thus should not be included in the proposed rule. One commenter discusses the use of solar

- powered controllers, fuel

- cell powered controllers, and mechan ically

controlled devices in remote locations as an alternative to natural gas where grid electricity is not available. This commenter also recommends that the EPA set a zero emissions standard based upon no

- bleed devices wherever electricity (either from a grid or from field power sources) is available within a reasonable distance from the facility and suggests that the EPA could establish an exemption to no

- bleed devices where low

- bleed devices are necessary because no

- bleed devices cannot be feasibly ins talled. Another commenter states the definition of “pneumatic controller” is unclear and should be revised.Page 118 of 497

Response: The EPA is changing the affected facility definition
to continuous bleed natural gas driven pneumatic controllers to clarify several issues raised by commenters, including the applicability of intermittent bleed devices, applicability of pneumatic devices not related to control, applicability of instrument air , and applicability of no

- bleed controllers. The emission limits in the final rule would effectively eliminate the use of high

- bleed pneumatic controller s for new (including replacement) and modified continuous bleed pneumatic controllers . Also , to ease th e burden on future replacement of or modification to continuous bleed controllers in natural gas service that bleed below the applicable emissions limit , the final rule requires only that these controllers be tagged as such, so that they can be tracked sep arately from devices above the emission limit , which have requirements to ensure compliance . As stated in the proposed rule’s Technical Support Document, it is assumed that a no

- bleed controller meets the definition of a low

- bleed controller for purposes o f the emissions limit. The EPA also confirms that the rule requirements for pneumatic controllers list the industry sectors covered by the regulation (see §60.5430), which addresses a commenter’s request for clarification about distribution sector devices.Page 119 of 497

Regarding the comments related to solar

- powered controllers, fuel

- cell powered controllers, mechanically

controlled devices and no - bleed devices where ver electricity is available , we considered these types of devices in the BSER analysis as discussed in the TSD. Any such controller system would require a backup system (consisting of at least an electrical generator) to operate the controllers when the primary system was inoperable. When considering the cost of the backup system, these options were not cos t effective. Comment: Several commenters request an exemption for all affected facilities handling gas with less than 10 percent VOC content by weight. Some commenters offer suggestions for such exemption, such as requiring recordkeeping of the gas VOC

c ontent in order for a facility to maintain the exemption. One commenter believes that the EPA should delete the pneumatic controller requirements because most of the gas emitted is methane, and there is little VOC emission reduction benefit. Another comme nter suggests limiting applicability to pneumatic controllers at natural gas processing plants or upstream of processing that exceed a defined VOC threshold. Several commenters opine that pneumatic device definitions and applicability should be based on VOC emissions, not natural gas as a surrogate. Commenters assert that the 6 scfh high

bleed/low

- bleed threshold value is unsupported, that natural gasPage 120 of 497

VOC content varies widely, and that in most cases, unconventionally produced coal bed methane and shale g as have little if any measurable VOC. Several commenters also wanted to exclude pneumatic controllers driven by a specified percentage of VOCs. According to the commenters, regulating the use of compressed air or “instrument air” or other gas having litt le or no VOCs would impose a significant burden on the industry without any added benefit. Response: The EPA is using natural gas bleed rate as a surrogate for VOC emissions rate . Measuring the VOC content of a pneumatic controller’s bleed gas adds cost burden to companies, and to the EPA’s knowledge, vendors/manufacturers do not report the VOC emissions from a pneumatic controller primarily because the VOC emissions would depend on the gas composition at the site the pneumatic controller is located. In the Technical Support
Document the EPA has provided cost effectiveness calculations for setting the pneumatic device emission limits. 2. Controllers in the transmission and storage segment Comment: Several commenters requested the EPA reevaluate requirements for pneumatic controller/devices in the natural gas transmission segment of the industry. The commenters argue that the proposed rule’s applicability is too broad and would resul t in an undue recordkeeping and permitting burden.Page 121 of 497

Several commenters recommend that subpart OOOO should limit pneumatic controller applicability to upstream processes. Some commenters suggest that, for natural gas transmission and storage, either pneuma tic controllers should be completely excluded or subpart OOOO should limit applicability to equipment located at “conventional” facilities, e.g. within the fence line at a compressor stations. One commenter recommends limiting the emission limit requiremen t to controllers at natural gas processing plants or locations upstream from gas processing that exceed a defined VOC threshold. The commenter suggests that this exclusion would reduce administrative costs in two ways: mandatory recordkeeping and reporting would be removed and the documentation required to explain why excluded controllers would no longer be necessary would be removed. Another commenter suggests that the EPA state in the final rule that NSPS/NESHAP applicability alone should not trigger mino r source permitting requirements. Response: The EPA is revising the requirements for pneumatic
controllers to apply to production through processing, and the
EPA will collect data under Subpart W of the greenhouse gas reporting rule to inform a decision on potential future action. No VOC threshold will be included in this regulation given the arbitrary nature of defining one using available data. 3 . Cost and emissions calculationsPage 122 of 497

Comment: One commenter asserts that the EPA’s estimate of 14,000 new and repl aced controllers in a given year is grossly underestimated. By the commenter’s data and calculations, approximately 750,000 controllers in Texas alone may need to be replaced (unless an exemption is granted) once a well becomes subject to the new rule.
Re sponse: The commenter incorrectly claim s that the EPA’s estimate of the number of pneumatic controllers installed in a given year is 14,000. In Section 5.3.2 of the Technical Support Document, the EPA explains its methodology for estimating the number of p neumatic controllers in both gas/oil production and gas transmission and storage. Table 5

- 3 gives a breakdown of
snap - acting versus bleed controllers and shows the total number of controllers to be 33,673. The commenter did not provide data to support its claim of 750,000 pneumatic controllers in Texas, and consider that not all would need to be replaced. A bleed rate threshold of 6 scfh is established in the rule for the
p roduction sector. D. Major comments concerning compressors 1. Dry seals versus wet seals Comment: Several commenters address the issue of whether the EPA should permit the use of a system other than dry seal to control emissions from centrifugal compressors. Some c ommenters provide information on situations where dry seal systems for cen trifugalPage 123 of 497

compressors are not technically feasible, such as where gas composition is inadequate, in some processing plants that already have a capture system in place, and in retrofits of some existing compressors due to housing design or operational requir ements. Commenters opine that the rule should allow compliance using either system, depending upon particular circumstances, and should not preclude use of a wet seal

equipped compressor with controls capable of meeting a 95 percent VOC control efficiency or routing captured seal

- oil gas to a fuel gas, recycling, or other processing system. According to another commenter, it would not be feasible to capture gas that escapes from a centrifugal compressor and route it back to a low

- pressure fuel stream for co mbustion as fuel gas; although such a process would capture a minimal amount of VOC emissions, the high cost of equipment to recapture the emissions would make the method described cost

- prohibitive. Commenters generally concurred that a 95 percent reduction in emissions was achievable through installing a capture system on a wet seal compressor. In addition, commenters disagreed with the EPA’s cost estimates and concluded that a wet seal capture syste m is cost

- effective. Response: In the preamble to the proposed rule , the EPA solicited comments on situations where the use of a dry seal is infeasible or otherwise inappropriate and wet seal is the onlyPage 124 of 497

option. 76 FR 52762 . As noted above, several commen ters provided information on situations where dry seals are not technically feasible
. Therefore, the EPA has concluded that dry seal is not the BSER for all new and modified centrifugal compressors. Instead, the EPA separately evaluates the control options for wet seal compressors. The EPA has identified one control option through its review of available information, including comments and other information obtained since proposal. The option is to
route captured seal

- oil gas to the compressor suction, fuel gas system, or flare , all of which can achieve 95 percent control efficiency
. Based on the discrepancy between commenters’ and the EPA’s cost data, the EPA re

- evaluated its cost information for this control opt ion
. The EPA cost estimates in the proposed rule assumed the use of a new flare to combust the captured seal oil gas, and based on commenter information, the EPA is revising this assumption since a new flare or other combustion source is expected to be ava ilable in gas processing facilities. From reviewing comments received, the EPA is aware that the captured gas is not always routed to a flare but in many cases is routed back to the compressor suction or fuel system. Given this information, the EPA has re

- evaluated the costs for the centrifugal compressor wet seal capture system and determined a system of this type, in which the seal oil degassing vents arePage 125 of 497

routed to fuel gas, compressor suction, or an existing flare, would cost $22,000. The estimated cost includes an intermediate pressure degassing drum, new piping, gas demister/filter, and a pressure regulator for the fuel line. With this cost, the estimated VOC control cost

- effectiveness is $161/ton of VOC for the processing sector. If savings are include d, the cost

effectiveness for VOC control is

- $2,134/ton of VOC. In light of the above, we have determined that the control option described above is the BSER for wet seal compressors. Accordingly, the final NSPS would require that wet seal
compressors r educe emission by 95 percent . For dry seal compressors, the only emission control option we have identified is the use of dry seal. Accordingly there is no requirement in the final rule for dry seal compressors , and dry seal compressors are not affected fa cilities under the NSPS
. 2. New source definition Comment: Several commenters oppose the proposal in section 60.5365(b) and (c) that a reciprocating compressor be considered as “commenced construction” on the date of installation at a facility. Commenters argue that the EPA was “arbitrary and capricious” in proposing to apply the concept of “commenced constructio n” in the NSPS context to a relocated compressor, because the Agency had no “reasoned explanation” for making the change and that applying the concept of “commenced construction”Page 126 of 497

to a relocated compressor is contrary to the plain language of the CAA. Resp onse: As provided in the NSPS General Provisions at 40 CFR 60.14(e)(6), relocation of an existing affected facility is not modification. Based on information received from commenters, the EPA acknowledges that each compressor’s manufacture date can be
trac ked, and the EPA is revising the rule defining new source reciprocating compressors based on the equipment manufacture date. E. Major comments concerning storage vessels 1. Applicability threshold metric Comment: Numerous commenters objected to the EPA’s p roposed use of liquid throughput to determine which storage vessels should be subject to the standards, asserting that the high variability in volatility of stored liquids and other parameters affecting emissions makes throughput a poor indicator of VOC em issions. The commenters indicate that, as a result, basing applicability on throughput would bring many storage vessels with low VOC emissions (some less than 1 tpy) under the standard and the required emission controls would not be cost effective. Some

co mmenters point out that certain storage vessels with high emissions might not be subject to the standards based on throughput.Page 127 of 497

Response: The EPA agrees with the commenters that applicability should be based on VOC emissions instead of liquid throughput and that the use of a VOC emissions threshold is more flexible approach, ensuring that controls will be required only on those storage vessels where they can be applied cost

- effectively. This approach also allows for broader coverage across all types of
stora ge vessels, regardless of the fluid that is stored or where the tank may be located. The final rule reflects this change
. Due to the large variability of emission factors from different shale formations, we do not think it is appropriate to use an
average emission factor for all tanks. Instead, the final rule requires each facility to determine its own emission factor and calculate the estimated emissions from each storage vessel. 2 . Definition of affected facility Comment: Numerous commenters commented on the definition of storage vessel in subpart OOOO, calling for greater clarity and consistency, and requesting that certain activities or equipment be included or excluded from the definition. Response: The EPA agrees with the commenters who assert that a

m ore specific and consistent definition of a storage vessel is needed. In the final rule, we have adopted a definition similar to that found in other rules, which excludes pressure vessels, as they are regulated in NESHAP subpart HH. However, we adopted

sev eral differences necessary for the oil and gas sourcePage 128 of 497

category. First, we have chosen not to exclude all tanks permanently attached to motor vehicles. Since there are many tanks in this source category that travel from site to site, we did not feel it was appropriate to exclude all of these tanks from control requirements. Instead we have set a minimum amount of time that the tank must be stationed at the same site before it is considered to be stationary and subject to subpart OOOO. Second, we have not exc luded wastewater tanks, as there are no separate standards for wastewater tanks in subpart OOOO, whereas other rules typically exclude them because they are regulated under different requirements. The final rule applies the storage vessel NSPS to each individual storage vessel (as opposed to a tank farm or some other collection of storage vessels) that emits at le a st 6 tpy of VOC, regardless of the material that the tank is storing or the location of the tank . Since the applicability of the NSPS, as fin alized, is not based on throughput , we believe it is not necessary to specify which types of stored materials are regulated and which are not. If a stored material is emitting at least 6 tpy of VOC, then the storage vessel will need to reduce its VOC emiss ions by 95 percent
. Comment: Some commenters assert that the EPA should limit applicability to storage vessels that are stationary and shouldPage 129 of 497

clarify the meaning of “stationary” to include or exclude certain types of tanks. Additionally, the EPA received comments requesting that the stationary aspect of the “storage vessel” definition should be consistent with other rules, while acknowledging the particular scenarios unique to the oil and gas production sector. The commenter notes that the stationary aspe ct of a storage vessel is typically addressed by the EPA in terms of whether it is reasonably portable, although the EPA sometimes addresses portability based on the size of the vessel. The commenter states that another criterion specified by the EPA in se veral regulations is that “vessels permanently attached to motor vehicles” are not storage vessels, and the EPA has issued a determination that this exemption extends to tanks “equipped with a permanently attached wheel assembly and a truck hitch” (U. S. E nvironmental Protection Agency, letter from George T. Czerniak to Ken Comey, Flint Hills Resources L.P., September 2, 2004.) According to the commenter, this renders most so

- called frac tanks, Baker tanks, ISO tanks, etc. exempt from the storage tank provi sions when this form of definition is used. However, the commenter recognizes that such tanks sometimes become effectively “stationary” in oil and gas production operations, and suggests that storage vessels should be deemed stationary if they remain at a given site for more than 180 consecutive days,Page 130 of 497

consistent with the period of time allowed under §60.14(g) to achieve compliance after a modification. The commenter notes that this 180

- day period is reasonable given that the definition of non

- road engines i n 40 CFR 89.2 allows a period of 12 consecutive months. The commenter also points out that cost effectiveness of the proposed control measures has been evaluated under the assumption that storage vessels remain in place for the useful life of the control equipment, and thus the control costs are amortized over a period of years. Since the cost per ton of emission reductions would be much higher if the controls were applied to a tank that is only on site temporarily, the commenter believes that a cost

- effe ctiveness analysis for permanent storage tanks would not be valid for temporary storage tanks, and thus the control requirements for permanent storage tanks are not justified for temporary storage tanks. The commenter provides recommended language for the definition of “storage vessel” that addresses this and other concerns. Another commenter similarly states that costly control requirements are not appropriate for temporary tanks (on site less than 180 days). Response: NSPS applies only to stationary sourc es. For the reasons stated below, the EPA has revised the definition ofPage 131 of 497

storage vessel to clarify that a storage vessel is considered stationary if it remains on a given site for more than 180 days
. In general, we agree with the commenter’s discussion about the EPA’s past practices related to stationary storage vessels. In particular, we agree that the inherent differences between “mobile” tanks in this source category and other categories indicate that they should be regulated differently. However, we disagree that the mobility aspect of the storage vessel would render it not to be cost effective to control. 3. References to MACT standards Comment: The EPA received comment asserting that the outcome of its BDT analysis for proposed subpart OOOO was calc ulated to achieve the same level of control as subpart HH

– undermining the BDT determination and effectively (and unlawfully) extending subpart HH major source MACT requirements to area source storage tanks. As a result, the commenter asserts that the EPA’s analysis precludes other potentially relevant regulatory alternatives

– such as marginally less effective controls that might be applied to a broader range of storage vessels. The commenter states that the EPA’s failure to consider other control tech niques and other levels of control efficiency that might be achieved by its preferred techniques is arbitrary and capricious. Response: Contrary to the se assertions , the EPA’s proposed BSERPage 132 of 497

determination for storage vessels was not calculated to achieve
t he same level of control as the existing MACT standard for major source storage vessels in 40 CFR part 63, subpart HH. The BSER analysis for storage vessels consists of the same steps as those for other affected sources evaluated in the proposed NSPS. Spec ifically, the EPA evaluated available information to identify VOC control options. The EPA then assessed various aspects of the control options, including their VOC reduction potentials, their cost effectiveness, and secondary air impacts. The commenter did not claim that any part of the EPA’s analysis above was inaccurate or inappropriate. Rather, the commenter notes that the EPA only analyzed two controls and failed to consider other “potentially relevant regulatory alternatives.” However, the commenter did not identify any other control option for the EPA’s consideration. The commenter simply suggests that the EPA should consider some less effective controls. Without more information, it is unclear whether a less effective control would in fact qualify as BSER for controlling VOC emissions from storage vessels considering that there are efficient and cost effective controls. Further, the determination that a 95 percent level of control is BSER for this emission source was determined prior to adopting t he subpart HH requirements. The two control devices we analyzed are known to be commonly used for these emissionPage 133 of 497

sources in this industry. We found both to be cost effective, thus establishing 95 percent control as BSER. We note also that the ref erenced se ction of subpart HH (section 63.766(b) ) requires that the storage vessel be equipped with “a cover that is connected, through a closed

- vent system that meets the conditions specified in §63.771(c), to a control device or combination of control devices that meets any of the conditions specified in §63.771(d).” Subsection 63.771(d) goes on to specify a wide range of control devices th at the source may use to achieve BSER (95 percent control). Other control techniques that the commenter claims are “marginally less effective” would not be BSER precisely because they are less effective, regardless of the cost of those controls. We believe that the wide range of controls allowed under the proposed rule is sufficient to meet the diverse requirements of this industr y. Comment: Two commenters state that the cost of the performance tests, monitoring, recordkeeping, etc. that are required through

cross - references to 40 CFR 63, s ubpart HH were not adequately considered by the EPA in the cost effectiveness determination for s ubpart OOOO, which applies to dispersed locations that do not have electricity or automation, and have limited remote transmitting unit (RTU) space. Response: Based on this and other comments detailed in the RTC for this final rulemaking, the EPA decided to remove fromPage 134 of 497

subpart OOOO the citations to the requirements for performance tests, monitoring, recordkeeping, etc. in subpart HH and instead incorporate the appropriate subpart HH language into subpart
OOOO . This process included an evaluation of whether the subpart HH requirements make sense in the context of subpart OOOO. The requirements that we incorporated into subpart OOOO were those that we believe are necessary to assure regulatory agencies and the public that compliance with the emission limitations is achieved. 4. Availability of control equipment Comment: Some commenters believe that there will be a shortage of control equipment available to meet th e proposed storage vessel requirements , and recommend revisions to the compliance deadline for storage vessels based on a vari e ty of considerations, including the availability of control devices, lead time needed for installation, and the number of affecte d oil and gas wells. Response: The EPA agrees that some lag time may be needed after initial start

- up for the owner or operator to determine the long

- term production level of a well and to procure the appropriate control equipment. For this reason, the EPA has decided to follow the app roach taken in the Wyoming rules for new sources, which allow s from 30 to 90 days for a source to achieve compliance , depending on the area of the state
. WyomingPage 135 of 497

allows only 30 days in ozone nonattainment areas, 60 days for concentrated development areas o r 90 days elsewhere in the
state. However, for replacement storage vessels or additional storage vessels at well sites with one or more wells already in production, we believe the operator already should have information on liquid composition and throughp ut. This information would allow estimation of VOC emissions to determine applicability of control requirements and for acquisition and installation of a control device concurrent with the replacement or additional storage vessel being installed. In the fi nal rule, for storage vessels at well sites with no well already in production, we have provided for a 30

- day period for throughput to stabilize and for the operator to estimate VOC emissions to determine whether a control device will be required. If VOC

e missions are estimated to be at least 6 tpy, the operator is provided an additional 30 days for the control device to become operational. We believe that the Wyoming experience illustrates that this will be sufficient time to size and obtain suitable controls. In addition, we note that the final rule no longer cites to the control requirements of subpart HH as discussed above
. Regarding the number of storage vessels associated with thousands of existing oil and natural gas wells in existence , wePage 136 of 497

note that the final rule app lies only to new, reconstructed and modified storage vessels emitting at least 6 tpy of VOC . In addition, our analysis s hows that at the final applicability threshold of 6 tpy of VOC, the required controls are cost effective. F. Major comments concerning equipment leaks Comment: The EPA received varied opinions regarding use of the optical gas imaging (OGI) detection system s. Certain commenter s state that the use of optical imaging in all areas of the proposed sector rule, not just gas processing facilities, would be beneficial in reducing emissions and simplifying the LDAR program, and some of these commenters support the use of auditory, visual, and olfactory inspections , at a minimum, to minimize the fugitive emissions from equipment leaks. Some commenters assert that Method 21 and existing system s should remain the primary monitoring method for LDAR programs, though OGI and other technical advances are useful and could supplement existing programs. According to these commenters, infrared images cannot provide quantitative measures of the amounts o f leaking gas, infrared optical imaging cameras only detect extremely large leaks, and well

- designed and implemented LDAR programs provide demonstrated emissions reductions. Several commenters state that implementing an OGI

- only alternative work practice (AWP) is consistent with thePage 137 of 497

monitoring requirements for the mandatory GHG reporting under 40 CFR Part 98 subpart W and using such an approach to satisfy both LDAR and GHG monitoring would improve its effectiveness and reduce duplicative and redundant req uirements for facilities. These commenters urge the EPA to return to an OGI AWP without requiring an annual Method 21 survey, on the basis that analytical and field studies demonstrate AWP equivalency, or urge the EPA to evaluate the use of a one

- time, sid e - by

- side survey using OGI and Method 21 as part of initial compliance. The EPA also received requests to restore the 10 percent AWP Sensitivity Test Option, to clarify and modify the video recording requirements, to evaluate how the video data will be

use d and whether a complete video recording is really needed, and to work with stakeholders to develop an OGI Application Protocol for the AWP that is based on OGI techniques for LDAR
programs. Regarding cost effectiveness, some commenters suggest that the EPA use optical imaging as a pilot program to better estimate its cost effectiveness, and others suggest that the EPA base the cost effectiveness of LDAR on all VOC pollutants as well as GHG emissions, such as methane. Response: Optical gas imaging was con sidered in the technology review, but was not determined to be BSER for any of the oil and gas segments. T he cost effectiveness of the OGI LDAR program wasPage 138 of 497

not calculated because the emission reductions from this program could not be quantified. Because th is is a VOC rulemaking, GHG emissions cannot be used to determine the cost effectiveness of OGI monitoring, and therefore the option of OGI could not be considered as BSER for the oil and gas segments. The NSPS requirements do allow the use of OGI as an al ternative work practice under section 60.18(g), which also requires an annual
M ethod 21 survey of all of the components. Currently, the agency is working on a uniform standards rule that would allow the use of OGI as an alternative for the M ethod 21

- based LDAR programs. We intend to provide the use of these uniform standards for equipment leak detection and repair when they become final. The EPA did not receive additional data from commenters to support the statement that an OGI only survey is comparable t o
M ethod 21

- based LDAR program. Therefore, we believe the AWP in section 60.18(g) is appropriate and do not believe that revisions to the requirements are necessary. We urge the commenter to provide their comments related to the video identification of com ponents and the 10% sensitivity test option when the Uniform Standards are proposed.
G . Major comments concerning notification, recordkeeping and reporting requirements 1. 30

- day notification and annual reportsPage 139 of 497

Comment: Multiple commenters state that the 30

- day advance notification of well completions under §60.5420(a) should be removed from the final rule. Commenters assert that this and notification requirements in §60.7(a) are unduly burdensome and costly, not adequate ly explained, not related to verifying compliance with the proposed rule and could conflict with the need to protect proprietary business information. Multiple commenters also note that industry’s estimate of annual completions is several times higher th an the EPA’s estimate of 20,000 completion and recompletion operations annually. The commenters believe that these requirements will likely overwhelm both regulated entities and state regulators alike. Commenters offer suggestions including requiring annua l certifications or maintaining records available for inspection, reducing the proposed advance notification requirement to 5

- 10 days, and considering notification programs such as those in Texas and Wyoming. Different commenters support or oppose requirin g a 30

- day advance notice with follow

- up notification of
1

- 2 days before an impending completion. Several commenters suggest that the EPA should coordinate with state and local agencies to eliminate duplicative recordkeeping and reporting requirements, and that records of interest other than those submitted to the respective Oil andPage 140 of 497

Gas Commissions should only be required to be retained and available upon inspection, similar to other permit requirements. Several commenters do not agree that an annual re port under 60.7(a)(1), 60.7(a)(3), and 60.7(a)(4) adds any value for verifying compliance and the EPA should remove this requirement from the final rule. The commenter s add that the best method for compliance is for an owner or operator to maintain necessa ry records and to have the records available for review during an

on - site inspection. One commenter suggests the annual report should include for each type of affected facility (1) the total number of affected facilities at the site ; (2) the number of faci lities that became affected facilities during the reporting period ; (3) the number of exempted facilities ; and (4) the number of affected facilities with a non

- compliance situation during the reporting period. One c ommenter suggests that it would be easier for facilities to submit an annual report on a set date each year, and multiple affected facilities could be included in a single report. Two commenters propose that all notifications for each year be delivered in a single annual report corresponding to t he reporting period in which the affected facilities become subject to the rule. One commenter suggests that operators should be required to keep records at the nearest manned office, but reports should only be required if they are requested by the EPA.Page 141 of 497

The commenters recommend, where feasible, streamlining the final notification and reporting requirements to eliminate unduly burdensome notification and reporting requirements. Response: The EPA agrees that certain notification, recordkeeping, and reportin g requirements in the general provisions are unduly burdensome. For that reason, well completions , continuous bleed natural gas driven controllers , and storage vessels will be exempt from the notifications required by sections 60.7(a)(1), 60.7(a)(3), and 6 0.7(a)(4). The EPA does not believe that 30

- day notification prior to a well completion conflicts with proprietary business information. The EPA does not believe that 3 days is sufficient time for inspectors to visit and observe a well completion. To lesse n the burden of the 30

- day notification requirement for well completions the EPA will instead require a single bulk 30

- day notification, which will include future estimated dates of well completions plus a n advance notice via email to the EPA or delegated authority no earlier than 3 days or late than 2 days prior to completion
. The EPA is not limiting the 30

- day bulk report to a written format. The rule language is flexible so that electronic communication notification is allowed. To lessen the reporting burden, the EPA is eliminating the requirement to list all affected facilities in the annual report. The EPA will revise the rule to require that only new orPage 142 of 497

modified affected facilities during the reporting period be listed in the annual report. However, the report must include a record of all deviations in cases where well completion operations with hydraulic fracturing were not performed in compliance with the requirements for each gas well affected facility. Comment: One commente r requested that the EPA add a self

certification requirement to the annual report similar to that used in the title V program. The commenter recommended that the final rule require the annual report to include a statement signed by a senior official of th e facility attesting to the truth, accuracy and completeness of the report. The commenter also requested that the EPA require that the annual reports be submitted electronically to facilitate making the reports publicly available. The commenter suggested using social media outlets, smart phone applications, and other electronic means to make the annual reports readily available. Response: The EPA agrees that self

- certification is an important mechanism for assuring the public that the information submitted by each facility is accurate. In addition, the title V program has successfully employed self

- certification since its inception. Therefore, we are requiring self

- certification, based on requirements in the title V program, in the final rule.Page 143 of 497

While we agr ee that having annual reports readily available to the public is a desirable goal, we did not identify any reporting programs or electronic databases that may be used for this purpose without significant modification. Therefore, we are not requiring annual reports to be submitted electronically, but we will continue to evaluate this option in the future. 2. Duplicative recordkeeping and reporting requirements Comment: Multiple commenters state that the notification, recordkeeping, monitoring, and annual reporting requirements in the proposed NSPS are duplicative and extremely burdensome for operators and for state regulators with limited resources. The commenters make both general and specific recommendations to revise the reporting requirements in the fi nal rule to eliminate duplication and reduce burden or better inform the public and regulatory agencies about deviations. Some commenters would eliminate all or some reports, while others argue that reporting is an essential compliance and enforcement mech anism and that additional information should be provided. Some commenters feel that an owner or operator should maintain necessary records and have them available for review. Commenters want the compliance assurance requirements to be appropriate for the oil and gas industry and commensurate to the environmental benefit that will be generated. For example, some commenters feel that the EPA should exempt small sourcesPage 144 of 497

regulated under this rule from the notification and reporting requirements. Response: We have considered these and other related comments presented in the RTC regarding the proposed reporting requirements. The EPA agrees that certain notification, recordkeeping, and reporting requirements are unduly burdensome and believes it is important to m inimize the burden of reporting requirements. The EPA also agrees that states and other enforcement entities are confronting limited resources and that visiting sites is not always practical. For that reason, the EPA believes notifications and reporting re quirements are vital to ensure compliance with our regulations. Therefore, the EPA has evaluated all of the notification, recordkeeping, and reporting requirements in an effort to streamline the requirements and reduce burden on both industry and enforceme nt and has deleted duplicate and unnecessary reports throughout the affected subparts. These changes will streamline the reporting process and reduce the reporting burden on sources. For example , well completions and continuous bleed natural gas controller s are exempt from the notifications required by sections 60.7(a)(1), 60.7(a)(3), and 60.7(a)(4). In addition, the EPA has revised the rule language such that only continuous bleed natural gas controllers installed, modified, or replaced during the reportin g period are reported in the annual report. In addition,Page 145 of 497

the EPA has revised the 30

- day individual notification requirement for well completions , as discussed above
. 3. Electronic reporting of emissions data Comment: Commenters suggest a variety of ways in which electronic reporting could be structured and implemented, with attention to coordination with various CAA requirements and programs to avoid duplicative and potentially burdensome requirements. Several commente rs support electronic reporting of emissions data from all sources to be stored on existing the EPA databases, such as the e

- GGRT or added to the TRI, and available to the public. The se commenters believe that c ommunities must have access to air quality in formation in order to protect public health. One commenter objects to the use of e

- GGRT as a reporting mechanism in place of a state’s own tracking system, where the state has enforcement responsibility for the emissions date and tracking of sources subjec t to the proposed rule. The commenters also suggested a variety of ways in which electronic reporting could be structured and implemented
. Several commenters oppose the implementation of electronic reporting at this time and are concerned that that an ERT will result in numerous complications and undue additional burden. The commenters point out that the EPA ’s experience with e

- GGRT indicates that considerable time and resources are needed to develop and implement efficient systems and to ensure thatPage 146 of 497

electronic reporting enhances efficiency rather than incurring additional burden on affected sources. The commenters state that

a potential disad vantage associated with an ERT is that new and/or alternative test methods would not be in the system. In addition, the commenters believe that an ERT could be complicated and burdensome for smaller companies that lack environmental personnel or experience with electronic reporting under other rules
. The commenters suggest that if the EPA delegates authority to states to implement and enforce the standards, some states may be unable or unwilling to accept electronic reports. The commenters urge the EPA to c onsider other more simplified options to report only the needed information. Response: While the EPA supports and encourages electronic reporting, after further consideration of all the comments, we do not believe the e

- GGRT is the appropriate mechanism fo r electronic reporting under this rule. T he e

- GGRT is not designed to accept all of the types of information required to be reported under the final rule, and significant modification of the system would be required to make it operational for this rule. However, the final rule does include reporting of performance test data via the ERT. The EPA must have performance test data to conduct effective reviews of CAA sections 112 andPage 147 of 497

129 standards, as well as for many other purposes including compliance determi nations, emission factor development, and annual emission rate determinations. In conducting these required reviews, the EPA has found it ineffective and time consuming, not only for us, but also for regulatory agencies and source owners and operators, to locate, collect, and submit performance test data because of varied locations for data storage and varied data storage methods. In recent years, though, stack testing firms have typically collected performance test data in electronic format, making it poss ible to move to an electronic data submittal system that would increase the ease and efficiency of data submittal and improve data accessibility.
In the final rule , as a step to increase the ease and efficiency of data submittal and improve data accessibi lity, the EPA is requiring the electronic submittal of select performance test data. D ata entry will be through an electronic emissions test report structure called the Electronic Reporting Tool (ERT). The ERT will generate an electronic report which will be submitted using the Compliance and Emissions Data Reporting Interface (CEDRI). The submitted report is submitted through the EPA’s Central Data Exchange (CDX) network for storage in the WebFIRE database making submittal of data very straightforward and easy.Page 148 of 497

One major advantage of submitting performance test data through the ERT is a standardized method to compile and store much of the documentation required to be reported by this rule. Another advantage is that the ERT clearly states what testing inf ormation would be required. Another important benefit of submitting these data to the EPA at the time the source test is conducted is that it should substantially reduce the effort involved in data collection activities in the future. State, local, and tr ibal agencies can also benefit from a more streamlined and accurate review of electronic data submitted to them. The ERT allows for an electronic review process rather than a manual data assessment making review and evaluation of the data and calculations easier and more efficient. Finally, another benefit of submitting data to WebFIRE electronically is that these data will greatly improve the overall quality of the existing and new emission factors by supplementing the pool of emissions test data for estab lishing emissions factors and by ensuring that the factors are more representative of current industry operational procedures. A common complaint heard from industry and regulators is that emission factors are outdated or not representative of a particular source category. With timely receipt and incorporation of data from most performance tests, the EPA willPage 149 of 497

be able to ensure that emission factors, when updated, represent the most current range of operational practices.
X . Summary of Significant NESHAP Co mments and Responses For purposes of this document, the text within the comment summaries was provided by the commenter(s) and represents their opinion(s), regardless of whether the summary specifically indicates that the statement is from a commenter(s) ( e.g. , “The commenter states” or “The commenters assert”). The comment summaries do not represent the EPA’s opinion unless the response to the comment specifically agrees with all or a portion of the
comment. A. Major comments concerning applicability 1. P reviously unregulated sources Comment: One commenter supports the EPA’s regulation of previously unregulated sources in the Oil and Natural Gas Sector and the commenter asserts that sections 111, 112(c), and 112(k) (Urban Air Toxics Strategy) support their position regarding this regulation of previously unregulated sources. The commenter asserts that historical regulation of emission sources within the sector leaves a large number of dehydrators, storage vessels and equipment at gas processing plants unreg ulated. Additionally, the commenter states that historical regulation has also not limited emissions from a number of other emission sources ( i.e. , wells, pneumatic devices, compressorPage 150 of 497

seals, valves, or flanges or other production equipment located at oil and gas production facilities or natural gas storage transmission facilities). One commenter supports the EPA’s recognition of the need to control emissions from previously uncontrolled emission points. However, the commenter believes that the EPA has no t satisfied section 112(d)(2)

- (3) of the Clean Air Act and that the EPA needs to calculate the MACT limit based on the best

- performing sources that currently exist. Additionally, according to the commenter, the EPA discovered more uncontrolled emission poi nts than it is planning to control. The commenter recommends that the EPA address all of the uncontrolled HAP emission points of which it is aware. Response: As the commenter notes, historical regulation of HAP emissions from the oil and gas sector has not covered all emission sources in this sector. Congress expressly limits the EPA’s authority to regulate HAP emissions from this sector. For instance, section 112(n)(4)(A) prohibits aggregation o f emissions from any oil and gas exploration or production wells (with their associated equipment) in determining major source status or for any purpose under section 112. Section 112(k) (and the Urban Air Toxic Strategy) noted by the commenter is designed to address area source emissions in urban areas. Section 112(n)(4)(B) limits the EPA’s authority to list and regulatePage 151 of 497

area sources under section 112(k) to only areas that meet certain population threshold and only upon making the requisite adverse effect f inding. In light of the above, it is not clear whether and to what extent emissions from the sources noted in the comment ( e.g. , well completions, pneumatic controllers, or other production equipment) can be effectively controlled under section 112.
Howev er, where appropriate, the Agency continues to take actions to further reduce emissions from this sector. In this final rule, the EPA is promulgating MACT standards for major sources of glycol dehydrators and storage vessels that were left unregulated in t he original NESHAP. In addition, the EPA is promulgating NSPS to address VOC emissions from emission sources noted in the comment. Control of VOC emissions from these sources will likely result in incidental HAP emission reductions as well. B. Major commen ts concerning the risk review Comment: One commenter states that the EPA’s analysis for subpart HH revealed two facilities (Hawkins Gas Plant, Hawkins, TX and Kathleen Tharp 2, Huffman, TX) with a cancer MIR greater than 100

- in

- 1 million based on MACT allowable emissions. Since the EPA determined that these facilities had a cancer MIR greater than 100

- in

- 1 million based on MACT allowable emissions, the EPA determined that the risks are unacceptable for the ONGPage 152 of 497

production MACT category and additional regulation was needed. However, the commenter believes these results are ent irely incorrect due to fundamental errors in the EPA’s calculations of MACT allowable risk for these two facilities. In addition, even if the analysis had been correct, the commenter states there are significant issues associated with the data for both of these facilities, which the commenter discusses in detail, that the commenter believes are sufficient to invalidate the results and the EPA’s conclusion that risks from the ONG production source category are unacceptable. Response: We have reviewed our ri sk results for Oil and Natural Gas Production and agree with the commenter. The NEI facility information for Hawkins Gas Plant was not correct and the multiplier used for the allowable calculation was too high. After correcting the multiplier the MIR for t his facility is 3

- in

- 1 million . For the Kathleen Tharp 2 facility, the actual emissions value was and the allowable multiplier used were too high , resulting in an incorrect MIR . After corrections were made, the MIR for this facility is below 1

- in

- 1 million . After making these changes, and further reviewing our risk results, we determined that the highest remaining cancer risk for ONG is 14

- in

- 1 million for a glycol dehydrator at the Vintage Production facility in Ventura, CA. We find this level of risk acce ptable. We then considered whether this revised standard (existing MACTPage 153 of 497

plus small dehydrator MACT) provides an ample margin of safety. Since this unit is a small dehydrator (this unit has a design throughput of 1 MMSCFD), it will be subject to the small d ehydrator BTEX limit in the final rule. We determined the applicable BTEX limit for this unit under the final MACT provisions and determined that the resulting MIR is less than 1

- in

- 1 million . We conclude that this provides an ample margin of safety.
In addition, w e are including the 0.9 Mg/yr benzene compliance alternative in the final amendments for subpart HH. See additional discussion above in section VII.A. Comment: One commenter states that the EPA bases the decision to eliminate the 0.9 Mg/yr benze ne emission limitation for subpart HHH on two basic factors: (1) it would reduce the cancer MIR from 90

- in

- 1 million to 20

- in

- 1 million, and (2) the cost effectiveness to comply with this option is reasonable. The commenter states that both of these conclu sions are erroneous. First, the commenter states that removal of 0.9 Mg/yr benzene alternative does not reduce risk. The commenter states that the EPA’s own technical analysis indicates that removal of the 0.9 Mg/yr benzene alternative would have no effect on the
MIR. Secondly, the commenter states that the EPA’s cost analysis is severely flawed. The EPA concludes that the costPage 154 of 497

effectiveness of the proposed removal of the 0.9 Mg/yr benzene compliance alternative for natural gas transmission and storage facilities is reasonable. However, the cost estimates used by the EPA in the ample margin of safety determination are inadequate. The EPA did not con duct any analysis using actual data. Rather, the EPA used costs estimated for small dehydrators and made general assumptions to estimate an upper

- end cost effectiveness for removing the 0.9 Mg/yr benzene alternative limit for large dehydrators at natural g as transmission and storage facilities. The commenter believes that, in general, the emission reductions for dehydrators forced to switch from the 0.9 Mg/yr benzene alternative to 95% control would be considerably less than those achieved by small dehydrat ors. The cost effectiveness calculated for small dehydrators is based on a 95% reduction from an uncontrolled baseline level. If a large dehydrator has installed controls to meet the 0.9 Mg/yr alternative benzene limitation, the cost effectiveness must be based on the incremental reduction between the existing controls and 95%. The EPA has provided no evidence that these incremental reductions would be greater than or equal to the 95% reductions that would be achieved for smaller dehydrators. In conclusion, the commenter states that the rationale used by the EPA in the preamble to support the removal of the 0.9 Mg/yr compliance alternative for dehydrators at natural gas transmission andPage 155 of 497

storage facilities under 112(f)(2) of the CAA is not supported by any of the background technical documentation and analyses. The commenter believes that the EPA has no basis under any other CAA authority for this action. Response: In response to comments, we re

- examined our risk
assessment for the Natural Gas Transmission and Storage source category and discovered that the two facilities 8 we identified as the risk drivers are area sources and not part of this major source category that is the subject of this section 112(j)(2) review
. We are including the 0.9 Mg/yr benzene comp liance alternative in the final amendments for subpart HH H . See additional discussion above in section VII.B C. Major comments concerning the previously unregulated sources Comment: T wo commenters do not believe that the dataset used is representative of currently operating small glycol dehydrators. One commenter recommends that the EPA base its MACT floor analyses on emissions data from a representative population of small dehydrators that characterize the population of affected sources within the category or subcategory. The commenter reports that more current data sources may be available, such as dehydrator emissions data reported to state agencies in annual emission reports or in pe rmit applications.

8 Bradley Compressor Station and Danville Compressor Station. Both in West Virginia.Page 156 of 497

One commenter opines that the EPA’s proposal misses the opportunity and fails to fulfill the agency’s responsibility to properly calculate the MACT for all sources in this sector based on current, reliable, and representative emission t est data. The commenter believes that, by relying on an incomplete and outdated dataset to set MACT floors and limits, the EPA has ignored data demonstrating trends in practices, processes and technologies and the resulting improved performance that sectio n 112(d) mandates. The commenter asserts that the EPA ignores the potential HAP emissions that the control devices themselves emit by failing to collect such emissions data from facilities that have installed control devices. The commenter argues that the EPA must collect the appropriate emission test data needed in order to recalculate and set a proper MACT for glycol dehydrators, storage vessels, and equipment leaks. One commenter states that section 112 of the CAA requires the EPA to set a NESHAP for each category or subcategory of “major sources” of HAP emissions. 42 U.S.C. § 7412(d)(1). The commenter asserts that the EPA must set section 112(d) emission standards based on “maximum achievable control technology” or “MACT.” The commenter states that the EPA largely bases its MACT proposal for small glycol dehydrators on emissions data collected from the industry during the development of the original MACT standards. 76 FR 52,768. The commenter contendsPage 157 of 497

that the data were collecte d prior to 1997 and did not adequately represent the emissions profile at that time, and do not reflect the significant changes in the industry and other technological developments that have occurred during the past 13 years. According to the commenter, th e EPA has not provided a reasoned explanation of how those data could be representative of currently operating glycol dehydrators and associated emission reductions, and how proposals based on those data can currently meet the MACT requirements for new and existing sources. The commenter states that the dehydrator technology performance in 1997 was not accurately reflected in the legacy EPA dataset and has advanced significantly in the past thirteen
years. One commenter states that the EPA did not collect recent data regarding emissions of HAPs, including BTEX, from small glycol dehydrators in either source sector in support of this rulemaking. Instead, according to the commenter, the EPA appears to have relied on data collected in the prior MACT rulemakin g, going back to 1998 or prior. The commenter believes that the EPA’s analysis is flawed and questionable because it simply relies on the best

- performing sources that existed a decade ago and fails to identify the best controlled sources today. The
comment er contends that it is unlikely that these MACT standards reflect either the current best controlled similar sourcePage 158 of 497

emissions or the average of the top 12 percent of the currently best controlled sources. The commenter states that while the EPA appropriate ly proposes to set a MACT limit for these sources for the first time, the EPA’s use of out

- dated data fails to demonstrate that its proposed limit is stringent enough in light of significant developments in emission control technologies and practices that have occurred since 1998. Response : The commenters claim that the data the EPA used to set the MACT standards for the small glycol dehydrators subcategory are outdated and that the EPA must collect new data. However, section 112(d)(2) and (3), under which the EPA is setting these standards, do not require that the EPA collect information. Rather, section 112(d)(3) allows the EPA to calculate the MACT floors based on information that the EPA has. Although the information is over a decade old, the available controls for reducing emissions from small glycol dehydrators and their control efficiencies have remained the same during this period and the commenters have not given any indication to the contrary . We therefore believe the data we have are still
represe ntative of the performance of the small dehydrators. The small dehydrators are left uncontrolled under the current NESHAP. Collection and analysis of additional data would inevitably take time and further delay control of these sources. We do not believe such delay is warranted, in light of the factPage 159 of 497

that we think the data we have are still representative of these sources’ performance today. For the reasons stated above, we believe it is reasonable for us to set MACT standards based on these data instead of collecting more current data. We considered using m ore current data (i.e., the 2005 NEI), however, this dataset lacks specific information we believe relevant to identify the best performing units. For glycol dehydrators, t he best performing units were not necessarily represented by those units with the lo west emissions. Low natural gas throughput and low inlet HAP content can be the primary factors in a source’s low emissions. We do not believe sources with inherently low throughput and /or inlet HAP content necessarily comprise the best performing sources
. Therefore, we used the 1997 data which contained that information . We were not able to identify any readily available data source that included inlet gas concentration and throughput, along with other data needed to calculate emissions. As a result we use d the data collected for the 1999 MACT standards. D. Major comments concerning the technology review 1. Representative of current technology and level of emissions Comment: One commenter states that, in conducting an 8

- year review, the EPA must “ look back” at the earlier standard and ascertain whether: 1) the standard was adopted using procedures that comply with the law as it has come to be interpreted by thePage 160 of 497

courts; 2) the EPA had sufficiently accurate and comprehensive data at the time of the initia l standard setting respecting the emissions profile of the category and properly identified the best performing unit(s); and 3) the EPA had properly used the available data. The commenter states the EPA then must “ look around” using currently available da ta and determine whether: 1) the emissions profile of the industry has changed in a way that would substantially affect the MACT floor calculations (the commenter adds that this includes consideration of any increase in the number of good performing units available for use in the existing source MACT floor calculation and in the performance of the best performing unit); 2) data gaps or uncertainties that affected the earlier decision have been resolved in the interim or can be resolved using new information available to the agency; 3) costs or other factors have changed in a way that would substantially affect the “beyond the floor” determination; 4) the use of improved practices, processes or technologies (including improvements in the performance of existi ng technologies) has become more prevalent than at the time of the initial standard setting; or 5) whether newer regulatory requirements, work practices or emission limitations (including state and local jurisdiction air pollution standards and federal enf orcement actions) , which are more stringent than the existingPage 161 of 497

112(d) standard, have shown the achievement or achievability of greater emission reductions than the existing standard requires. Response: We disagree with the commenter’s interpretation of
sect ion 112(d)(6) requirements. While we appreciate the commenter’s ideas on how the 112(d)(6) analysis could be conducted, nowhere does 112(d)(6) require any such “look back” or “look around” analysis as the commenter contends. The commenter appears to argue that 112(d)(6) requires that the EPA recalculate the MACT based on current data and technology. The same argument was posed to the D.C. Circuit, and the Court “[did] that think that the words ‘review, and revise as necessary’ can be construed reasonably a s imposing any such obligation.” NRDC v. EPA , 529 F.3d 1077, 1084 (D.C. Cir. 2008). 2 . Glycol dehydration units and storage vessels Comment: One commenter states that the EPA’s technology review for storage vessel control technologies is limited and makes incorrect assumptions. The commenter contends that without further support, the public cannot understand and the EPA cannot justify its proposed decision; therefore, the E PA’s proposal is arbitrary and capricious. The commenter adds that the EPA must conduct an updated beyond

- the

- floor analysis for both newly controlled emission points , and the EPA must determine a proper beyond

- the

- floor MACT level for storage vessels, by determining the “maximum degree of reduction in emissions” that isPage 162 of 497

achievable, as required under section 112(d)(2). The commenter states that the proposed rule fails to provide any discussion of a beyond

- the

- floor determination for storage vessels.
One co mmenter states that the EPA must examine advances in vapor recovery unit technology and reconsider floating roof technology for tanks containing liquids that do not have the potential for flash emissions. The commenter contends that the EPA improperly reje cted technology advances and developments in pollution prevention systems found in its own RBLC database and employed by its own Natural Gas STAR partners. Specifically, according to the commenter, the EPA failed to evaluate the performance achieved by sys tems that use thermal or catalytic oxidizers, either alone or in combination with condensers. According to the commenter, the EPA’s RBLC review identified a BACT determination for dehydrator efficiency of 98 percent. The commenter also urges the EPA to eva luate the use of combustion devices and vapor recovery units that capture vent steam from the tank and turn it into a saleable product by recompressing the hydrocarbon vapors. The commenter contends that the EPA rejects technology advances by asserting tha t those technologies were considered in the 1999 rulemaking, but fails to provide support for its decision in either the record of the 1999 rulemaking or the current record. The commenter contends that the EPA must provide a basis for its decisions and con clusions.Page 163 of 497

Response: We disagree with the commenter. The EPA has determined that the technology review provisions for NESHAP under section 112(d)(6) must take into account the cost of controls. In the technology review process, we evaluated additional contr ol options for storage vessels and found that none was cost effective. In addition, none of the storage vessels at the major sources used to evaluate the MACT floor used floating roofs. E. Major comments concerning notification, recordkeeping and reporting requirements 1. Annual reports Comment: One commenter requested that the EPA add a self

certification requirement to the annual report similar to that used in the title V program. The commenter recommended that the final rule require the annual report to include a statement signed by a senior official of the facility attesting to the truth, accuracy and completeness of the report. The commenter also requested that the EPA require that the annual reports be submitted electronically to facilitate making the reports publicly available. The commenter suggested using social media outlets, smart phone applications, and other electronic means to make the annual reports readily available. Response: The EPA agrees that self

- certification is an important mechanism f or assuring the public that the information submitted by each facility is accurate. In addition, the title V programPage 164 of 497

has successfully employed self

- certification for since its inception. Therefore, we are requiring self

- certification, based on requirements in the title V program, in the final rule. While we agree that having annual reports readily available to the public is a desirable goal, we did not identify any reporting programs or electronic databases that may be used for this purpose without signifi cant modification. Therefore, we are not requiring annual reports to be submitted electronically, but we will continue to evaluate this option in the future. 2. Electronic reporting of emissions data Comment: Several commenters raised similar issues regard ing reporting of emissions data under the NESAHP as under the NSPS, described supra , and our responses there apply equally here. Please see comments and responses in section IX .G.3.
XI . What are the cost, environmental, and economic impacts of the final NESHAP/NSPS amendments? A. What are the air impacts? For the oil and natural gas sector NESHAP and NSPS, we estimated the emission reductions that will occur due to the implementation of the final emission limits. The EPA estimated emission reductions bas ed on the control technologies selected by the engineering analysis. These emission reductions associated with the final amendments to 40 CFR part 63, subpart HH and 40 CFR part 63, subpart HHH are based on the estimatedPage 165 of 497

population in 2008. Under the final ized limits for glycol dehydration units and storage vessels, we have estimated that the HAP emissions reductions will be 1,300 tpy for existing units subject to the final emissions limits. For the NSPS, we estimated the emission reductions that will occ ur due to the implementation of the final emission limits. The EPA estimated emission reductions based on the control technologies selected by the engineering analysis. These emission reductions are based on the estimated population in 2015. Under the fina l NSPS, we have estimated that the emissions reductions will be 290,000 tpy VOC for affected facilities subject to the NSPS. The control strategies likely adopted to meet the final NESHAP amendments and the final NSPS will result in concurrent control of HAP, methane and VOC emissions. We estimate that direct reductions in HAP, methane and VOC for the final rules combined total about 20,000 tpy, 1.7 million tpy, and 300,000 tpy, respectively. The EPA received several comments regarding the emission factor selected to calculate whole gas emissions (and the associated VOC emissions) from hydraulically fractured well completions. Comments focused on the data behind the emission factor, what the emission factor is intended to represent, and the procedures used to develop the emission factor from thePage 166 of 497

selected data sets. We reviewed all information received and have decided to retain the data set and the analysis conducted to develop the emission factor of 9,000 Mcf per completion. More detailed discussion is pre sented in a technical memorandum on this subject in the docket. B. What are the energy impacts? Energy impacts in this section are those energy requirements associated with the operation of emission control devices. Potential impacts on the national energy economy from the rule are discussed in the economic impacts section. There would be little national energy demand increase from the operation of any of the environmental controls analyzed under the final NESHAP amendments and final NSPS. The final NESHAP amendments and final NSPS encourage the use of emission controls that recover hydrocarbon products, such as methane and condensate that can be used on

- site as fuel or reprocessed within the production process for sale. We estimated that the final standard s will result in net annual costs savings of about $60,000 (in 2008 dollars) due to the recovery of salable natural gas and condensate. Thus, the final standards have a positive impact associated with the recovery of non

renewable energy resources. C. What are the cost impacts?Page 167 of 497

The estimated total capital cost to comply with the final amendments to 40 CFR part 63, subpart HH for major sources in the Oil and Natural Gas Production source category is approximately $47 million. The total capital cost for the final amendments to 40 CFR part 63, subpart HHH for major sources in the Natural Gas Transmission and Storage source category is estimated to be approximately $370 thousand. All costs are in 2008 dollars. The total estimated net annual cost to industry to comply with the final amendments to 40 CFR part 63, subpart HH for major sources in the Oil and Natural Gas Production source category is approximately $18 million. The total net annual cost for final amendments to 40 CFR part 63, subpart HHH for major

so urces in the Natural Gas Transmission and Storage source category is estimated to be approximately $360,000. These estimated annual costs include: (1) The cost of capital, (2) operating and maintenance costs, (3) the cost of monitoring, inspection, recordk eeping and reporting (MIRR) and (4) any associated product recovery credits. All costs are in 2008 dollars. The estimated total capital cost to comply with the final NSPS is approximately $340 million in 2008 dollars. The total estimated net annual cost t o industry to comply with the final NSPS is approximately $340 million in 2008 dollars. This annualPage 168 of 497

cost estimate includes: (1) The cost of capital, (2) operating and maintenance costs and (3) the cost of MIRR. This estimated annual cost does not take into account any producer revenues associated with the recovery of salable natural gas and hydrocarbon condensates. When revenues from additional product recovery are considered, the final NSPS is estimated to result in a net annual engineering cost savings overall. When including the additional natural gas recovery in the engineering cost analysis, we assume that producers are paid $4 per thousand cubic feet (Mcf) for the recovered gas at the wellhead. The engineering analysis cost analysis assumes the value of recovered condensate is $70 per barrel. Based on the engineering analysis, about 82 million Mcf (82 billion cubic feet) of natural gas and 320,000 barrels of condensate are estimated to be recovered by control requirements in 2015. Using the price

assu mptions, the estimated revenues from natural gas product recovery are approximately $350 million in 2008 dollars. Using the engineering cost estimates, estimated natural gas product recovery, and natural gas product price assumptions, the net annual engi neering cost savings is estimated for the final NSPS at about $18 million in 2008 dollars. Totals may not sum due to independent rounding.Page 169 of 497

As the price assumption is very influential on estimated annualized engineering costs, we performed a simple sensiti vity analysis of the influence of the assumed wellhead price paid to natural gas producers on the overall engineering annualized costs estimate of the final NSPS. At $4.22/Mcf, the price forecast reported in the 2011 Annual Energy Outlook in 2008 dollars, the annualized costs are estimated at about

- $36 million, which would approximately double the estimate of net cost savings of the final NSPS. As indicated by this difference, the EPA has chosen a relatively conservative assumption (leading to an estimate of few savings and higher net costs) for the engineering costs analysis. The natural gas price at which the final NSPS breaks

- even from an estimated engineering costs perspective is around $3.79/Mcf. A $1/Mcf change in the wellhead natural gas price leads to a $82 million change in the annualized engineering costs of the final NSPS. Consequently, annualized engineering costs estimates would increase to about $65 million under a $3/Mcf price or decrease to about

- $100 million under a $5/Mcf price. For furthe r details on this sensitivity analysis, please refer the regulatory impact analysis (RIA) for this rulemaking located in the docket. D. What are the economic impacts? The analysis of energy system impacts for the final NSPS estimates that domestic natural gas production is likely toPage 170 of 497

increase slightly (about 60 billion cubic feet or 0.3 percent) and average natural gas prices to decrease slightly ($0.05 per Mcf in 2008 dollars or 1.2 percent at the wellhead for onshore producers in the lower 48 states) for 2015, the year of analysis. This increase in production and decrease in wellhead price is largely a result of the increased natural gas and condensate recovery as a result of complying with the NSPS. Domestic crude oil production is not expected to change, while average crude oil prices are estimated to decrease slightly ($0.01/barrel in 2008 dollars or about 0.01 percent at the wellhead for onshore producers in the lower 48 states) in the year of analysis, 2015. The NEMS

- based analysis estimates in the
yea r of analysis, 2015, that net imports of natural gas will decrease slightly (about 10 bcf or 0.4 percent) and crude will not change significantly. Total CO 2 e emissions from energy

- related sources are expected to increase about 540 thousand metric tons CO 2 e or about 0.01 percent under the final NSPS, according to the NEMS analysis. This increase is attributable largely to natural gas consumption increases, although these increases are estimated to be partially offset by declines in petroleum and coal

consu mption. This estimate does not include CO 2 e reductions from the implementation of the controls; these reductions are discussed in more detail in the benefits section that follows.Page 171 of 497

We did not estimate the energy economy impacts of the final NESHAP amendmen ts using NEMS, as the expected costs of the rule are not likely to have estimable impacts on the national energy
economy. E. What are the benefits of this final rule? The final Oil and Natural Gas NSPS and NESHAP amendments are expected to result in signi ficant reductions in existing emissions and prevent new emissions from expansions of the industry. These final rules combined are anticipated to reduce 20,000 tons of HAP, 300,000 tons of VOC (a precursor to both PM2.5 and ozone formation) and 1.7 million tons of methane (a GHG and a precursor to global ozone formation). These pollutants are associated with substantial health effects, welfare effects and climate effects. With the data available, we are not able to provide credible health benefit estimates for the reduction in exposure to HAP, ozone and PM (2.5 microns and less) (PM 2.5 ) for these rules, due to the differences in the locations of oil and natural gas emission points relative to existing information and the highly localized nature of air quali ty responses associated with HAP and VOC reductions. This is not to imply that there are no benefits of the rules; rather, it is a reflection of the difficulties in modeling the direct and indirect impacts of the reductions in emissions for this industrial sector with the dataPage 172 of 497

currently available. In addition to health improvements, there will be improvements in visibility effects, ecosystem effects and climate effects, as well as additional product recovery. Although we do not have sufficient information or modeling available to provide quantitative estimates for this rulemaking, we include a qualitative assessment of the health effects associated with exposure to HAP, ozone and PM 2.5 in the RIA for this rule. These qualitative effects are briefly summariz ed below, but for more detailed information, please refer to the RIA, which is available in the docket. One of the HAP of concern from the oil and natural gas sector is benzene, which is a known human carcinogen. VOC emissions are precursors to both PM 2.5 and ozone formation. As documented in previous analyses (U.S. EPA, 2006 9 and U.S. EPA, 2010 10 ), exposure to PM 2.5 and ozone is associated with significant public health effects. PM 2.5 is associated with health effects, including premature mortality for adul ts and infants, cardiovascular morbidity such as heart attacks, and respiratory morbidity such as asthma attacks, acute

9 U.S. EPA. RIA. National Ambient Air Quality Standards for Particulate Matter , Chapter 5. Office of Air Quality Planning and Standards, Research Triangle Park, NC. October 2006. Available on the Internet at <http://www.epa.gov/ttn/ecas/regdata/RIAs/Chapter%205

-- Benefits.pdf>.

10 U.S. EPA. RIA. National Ambient Air Quality Standards for Ozone
. Office of Air Quality Planning and Standards, Research Triangle Park, NC. January 2010. Available on the Internet at <http://www.epa.gov/ttn/ecas/regdata/RIAs/s1

- supplemental_analysis_full.pdf>.Page 173 of 497

and chronic bronchitis, hospital admissions and emergency room visits, work loss days, restricted activity days and respiratory symptoms , as well as visibility impairment. 11 Ozone is associated with health effects, including hospital and emergency department visits, school loss days and premature mortality, as well as injury to vegetation and climate effects. 12 In addition to the improvem ents in air quality and resulting benefits to human health and non

- climate welfare effects previously discussed, this rule is expected to result in significant climate co

- benefits due to anticipated methane reductions. Methane is a potent GHG that, once em itted into the atmosphere, absorbs terrestrial infrared radiation, which contributes to increased global warming and continuing climate change. Methane reacts in the atmosphere to form ozone and ozone also impacts global temperatures. According to the
Inte rgovernmental Panel on Climate Change (IPCC) 4 th Assessment Report (2007), methane is the second leading long

- lived climate forcer after CO2 globally. Total methane emissions from the oil and gas industry represent about 40 percent of the total

11 U.S. EPA. Integrated Scien ce Assessment for Particulate Matter (Final Report) . EPA

- 600

- R

- 08

- 139F. National Center for Environmental Assessment

— RTP Division. December 2009. Available at <http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=216546>.

12 U.S. EPA. Air Quality Criteria fo r Ozone and Related Photochemical Oxidants (Final) . EPA/600/R

- 05/004aF

- cF. Washington, DC: U.S. EPA. February 2006. Available on the Internet at http://cfpub.epa.gov/ncea/CFM/recordisplay.cfm?deid=149923.Page 174 of 497

methane emissions from all sources and account for about 5 percent of all CO2 e emissions in the United States, with natural gas systems being the single largest contributor to United States anthropogenic methane emissions. 13 Methane, in addition to other GH G emissions, contributes to warming of the atmosphere, which, over time, leads to increased air and ocean temperatures, changes in precipitation patterns, melting and thawing of global glaciers and ice, increasingly severe weather events, such as hurricane s of greater intensity and sea level rise, among other impacts. This rulemaking requires emission control technologies and regulatory alternatives that will significantly decrease HAP and VOC emissions from the oil and natural gas sector in the United
St ates. As a co

- benefit, the emission control measures the industry will use to reduce HAP and VOC emissions will also decrease methane emissions. The NESHAP Amendments and the NSPS combined are expected to reduce methane emissions annually by about 1.7 mill ion short tons or about 33 million metric tons
CO 2 e. After considering the secondary impacts of this rule previously discussed, such as increased CO 2 emissions from well completion combustion and decreased CO 2 e emissions because of fuel

- switching by consum ers, the methane reductions become about

13 U.S. EPA (2011), 2011 U.S. Greenhouse Gas Invento ry Report Executive Summary available on the internet at http://epa.gov/climatechange/emissions/downloads11/US

- GHG

- Inventory

- 2011

- Executive

- Summary.pdf , accessed 02/13/12

.Page 175 of 497

31 million metric tons CO 2 e. The methane reductions represent about 13 percent of the baseline methane emissions for this sector reported in the EPA’s U.S. Greenhouse Gas Inventory Report for 2009 (251.55 million me tric tons CO 2 e when petroleum refineries and petroleum transportation are excluded because these sources are not examined in this proposal). However, it is important to note that the emission reductions are based upon predicted activities in 2015; the EPA did not forecast sector

level emissions in 2015 for this rulemaking. These emission reductions equate to the climate benefits of taking approximately 6 million typical passenger cars off the road or eliminating electricity use from about 4 million typical homes each year. 14 The EPA recognizes that the methane reductions from this rule will provide for significant economic climate benefits to society just described. However, the 2009

- 2010 Interagency Social Cost of Carbon Work Group did not produce directly modeled estimates of the social cost of methane. In the absence of direct model estimates from the interagency analysis, the EPA has used a “global warming potential (GWP) approach” to estimate the dollar value of this rule’s methane co

- benefits. Specifi cally, the EPA converted methane to CO 2 equivalents using

14 U.S. EPA. Greenhouse Gas Equivalency Calculator available at: http://www.epa.gov/cleanenergy/energy

- resources/calculator.html , accessed 02/13/12.Page 176 of 497

the GWP of methane, then multiplied these CO 2 equivalent emission reductions by the social cost of carbon developed by the Interagency Social Cost of Carbon Work Group. The social cost of carbon is an estimate of the net present value of the flow of monetized damages from a 1

- metric ton increase in CO 2 emissions in a given year (or from the alternative perspective, the benefit to society of reducing CO2 emissions by 1 ton ). For more information about the social cost of carbon, see the Support Document: Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order 12866 15 Applying this approach to the methane reductions estimated for the NESHAP Amendments and NS PS, the 2015 climate co

- benefits vary by discount rate and range from about $190 million to approximately $2.4 billion; the mean social cost of carbon at the 3

- percent discount rate results in an estimate of about $780 million in 2015. 16
These co

- benefits equate to a range of approximately $110 to $1,400 per short ton of methane reduced, depending upon the discount rate assumed with a per ton estimate of $480 at the 3

-

15 Interagency Working Group on Social Cost of Carbon (IWGSC). 2010. Technical Support Document: Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order 12866. Docket ID EPA

- HQ

- OAR

2009

- 0472

- 114577. http://www.epa.gov/otaq/climate/regulations/scc

tsd.pdf , accessed 02/12/12. 16 The ratio of domestic to global benefits of emission reductions varies with key parameter assumptions. See Interagency Working Group on Social Cost of Carbon. 2010. Technical Support Document: Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order 12866.Page 177 of 497

percent discount rate. These social cost of methane benefit estimates are not the same as would be derived from direct computations (using the integrated assessment models employed to develop the Interagency Social Cost of Carbon estimates) for a variety of reasons, including the shorter atmospheric lifetime of methane relative to CO 2 (about 1 2 years compared to CO 2 whose concentrations in the atmosphere decay on timescales of decades to millennia). The climate impacts also differ between the pollutants for reasons other than the radiative forcing profiles and atmospheric lifetimes of these gas es. Methane is a precursor to ozone and ozone is a short

- lived climate forcer that contributes to global warming. The use of the IPCC Second Assessment Report GWP to approximate co

- benefits may underestimate the direct radiative forcing benefits of reduce d ozone levels and does not capture any secondary climate

co - benefits involved with ozone

- ecosystem interactions. In addition, a recent the EPA National Center of Environmental Economics working paper suggests that this quick “GWP approach” to benefits est imation will likely understate the climate benefits of methane reductions in most cases. 17 This conclusion is reached using the 100

- year GWP for methane of 25 as put forth in the IPCC Fourth Assessment Report (AR 4), as opposed to the

17 Marten and Newbold (2011), Estimating the Social Cost of Non

- CO2 GHG Emissions: Methane and Nitrous Oxide , NCEE Working Paper Series #11

- 01. http://yosemite.epa.gov/EE/epa/eed.nsf/WPNumber/2011

- 01?OpenDocument.Page 178 of 497

lower value of 21 used in this analysis. Using the higher GWP estimate of 25 would increase these reported methane climate co

benefit estimates by about 19 percent. Although the IPCC Assessment Report (AR4) suggested a GWP of 25 for methane, the EPA has used GWP of 21 from the IPCC Second Assessment Report to estimate the methane climate co

- benefits for this oil and gas proposal. The EPA uses the 21 GWP in order to provide estimates more consistent with global GHG inventories, which currently use GWP from the IPCC Second Assessm ent Report. Due to the uncertainties involved with the “GWP approach” estimates presented and methane climate co

- benefits estimates available in the literature, the EPA chooses not to compare these co

- benefit estimates to the costs of the rule for this
p roposal. Rather, the EPA presents the “GWP approach” climate

co - benefit estimates as an interim method to produce these estimates until the Interagency Social Cost of Carbon Work Group develops values for non

- CO 2 GHG. For the final NESHAP amendments, a b reak

- even analysis suggests that HAP emissions would need to be valued at $14,000 per ton for the benefits to exceed the costs if the health, ecosystem and climate benefits from the reductions in VOC and methane emissions are assumed to be zero. Even thoug h emission reductions of VOC and methane are co

- benefits for the final NESHAP amendments, they are legitimate components of the totalPage 1 79 of 497

benefit

- cost comparison. If we assume the health benefits from HAP emission reductions are zero, the VOC emissions would n eed to be valued at $1,900 per ton or the methane emissions would need to be valued at $3,700 per ton for the co

- benefits to exceed the costs. All estimates are in 2008 dollars. For the final NSPS, the revenue from additional product recovery exceeds the c osts, which renders a break

- even analysis unnecessary when these revenues are included in the analysis. Based on the methodology from Fann, Fulcher, and Hubbell (2009), 18 ranges of benefit

- per - ton estimates for emissions of VOC indicate that on average in t he United States, VOC emissions are valued from $1,200 to $3,000 per ton as a PM 2.5 precursor, but emission reductions in specific areas are valued from $280 to $7,000 per ton in 2008 dollars. As a result, even if VOC emissions from oil and natural gas ope rations result in monetized benefits that are substantially below the national average, there is a reasonable chance that the benefits of the rule would exceed the costs, especially if we were able to monetize all of the additional benefits associated with ozone formation, visibility, HAP and methane.

18 Fann, N., C.M. Fu lcher, B.J. Hubbell. The influence of location, source, and emission type in estimates of the human health benefits of reducing a ton of air pollution . Air Qual Atmos Health (2009) 2:169

- 176.Page 180 of 497

XII . Statutory and Executive Order Reviews
A. Executive Order 12866, Regulatory Planning and Review and Executive Order 13563, Improving Regulation and Regulatory Review Under section 3(f)(1) of Executive Order 12866 (58 FR 51735, October 4, 1993), this action is an “economically significant regulatory action” because it is likely to have an annual effect on the economy of $100 million or more. Accordingly, the EPA submitted this action to the Office of Man agement and Budget (OMB) for review under Executive Orders 12866 and 13563 (76 FR 3821, January 21, 2011) and any changes made in response to OMB recommendations have been documented in the docket for this action. In addition, the EPA prepared a Regulatory Impact Analysis (RIA) of the potential costs and benefits associated with this action. The RIA available in the docket describes in detail the empirical basis for the EPA’s assumptions and characterizes the various sources of uncertainties affecting the e stimates below. Table 3 shows the results of the cost and benefits analysis for these final rules.
TABLE 3 . SUMMARY OF THE MONETIZED BENEFITS, SOCIAL COSTS, AND NET BENEFITS FOR THE FINAL OIL AND NATURAL GAS NSPS AND NESHAP AMENDMENTS IN 2015 (MILLIONS OF 2008$) 1

Final NSPS Final NESHAP Amendments Final NSPS and NESHAP AmendmentsPage 181 of 497

Combined

Total Monetized Benefits 2 N/A N/A N/A

Total Costs 3 - $18 million $18 million

- $61,000 Net Benefits N/A N/A N/A

Non

monetized Benefits 4 19,000 tons of HAPs 1,300 tons of HAPs 20,000 tons of HAPs 290,000 tons of VOCs 9,000 tons of VOCs 300,000 tons of VOCs 1.7 million tons of methane 4,800 tons of methane 1.7 million tons

of methane Health effects of HAP exposure Health effects of PM2.5 and ozone exposure Visibility impairment Vegetation effects Climate effects 1 All estimates are for the implementation year (2015). 2 While we expect that these avoided emissions will result in improvements in air quality and reductions in health effects associated with HAP, ozone and PM, as well as climate effects associated with methane, we have determined that quantification of those benefits cannot be accomplished for this rule in a defensible way. This is not to imply that there are no benefits of the rules; rat her, it is a reflection of the difficulties in modeling the direct and indirect impacts of the reductions in emissions for this industrial sector with the data currently available. 3 The engineering compliance costs are annualized using a 7

- percent discoun t rate. The negative cost for the final NSPS reflects the inclusion of revenues from additional natural gas and hydrocarbon condensate recovery that are estimated as a result of the NSPS. 4 For the NSPS, reduced exposure to HAP and climate effects are co - b enefits. For the NESHAP, reduced VOC emissions, PM2.5 and ozone exposure, visibility and vegetation effects and climate effects are co

- benefits. 5 The specific control technologies for these final rules are anticipated to have minor secondary disbenefits. The net CO2

- equivalent emission reductions are 90,000 metric tons for the NESHAP and 31 million metric tons for the NSPS. B. Paperwork Reduction ActPage 182 of 497

The information collectio n requirements in this rule have been submitted for approval to OMB under the PRA , 44 U.S.C. 3501, et seq . The ICR document s prepared by the EPA has been assigned EPA ICR number s 2437.01, 2438.01, 2439.01, and 2440.01
. The information collection requirements are not enforceable until OMB approves them. The information requirements are based on notification, recordkeeping, and reporting requirements in the NESHAP General Provisions (40 CFR part 63, subpart A), which

are m andatory for all operators subject to national emission standards. These recordkeeping and reporting requirements are specifically authorized by CAA section 114 (42 U.S.C. 7414). All information submitted to the EPA pursuant to the recordkeeping and report ing requirements for which a claim of confidentiality is made is safeguarded according to Agency policies set forth in 40 CFR part 2, subpart B. This final rule requires maintenance inspections of the control devices but would not require any notifications or reports beyond those required by the General Provisions. The recordkeeping requirements require only the specific information needed to determine compliance. When a malfunction occurs, sources must report them according to the applicable reporting req uirements of 40 CFR part 63, subpart HH or 40 CFR part 63, subpart HHH. An affirmative defense to civil penalties for exceedances ofPage 183 of 497

emission limits that are caused by malfunctions is available to a source if it can demonstrate that certain criteria and

re quirements are satisfied. The criteria ensure that the affirmative defense is available only where the event that causes an exceedance of the emission limit meets the narrow definition of malfunction in 40 CFR 63.2 (sudden, infrequent, not reasonable preve ntable, and not caused by poor maintenance and or careless operation) and where the source took necessary actions to minimize emissions. In addition, the source must meet certain notification and reporting requirements. For example, the source must prepare a written root cause analysis and submit a written report to the Administrator documenting that it has met the conditions and requirements for assertion of the affirmative defense. For this rule, the EPA is adding affirmative defense to the estimate of b urden in the ICR. To provide the public with an estimate of the relative magnitude of the burden associated with an assertion of the affirmative defense position adopted by a source, the EPA has provided administrative adjustments to this ICR that shows wh at the notification, recordkeeping, and reporting requirements associated with the assertion of the affirmative defense might entail. The EPA’s estimate for the required notification, reports, and records, including the root cause analysis, associated with a single incident totalsPage 184 of 497

approximately totals $3,141, and is based on the time and effort required of a source to review relevant data, interview plant employees, and document the events surrounding a malfunction that has caused an exceedance of an emissi on limit. The estimate also includes time to produce and retain the record and reports for submission to the EPA. The EPA provides this illustrative estimate of this burden, because these costs are only incurred if there has been a violation, and a source chooses to take advantage of the affirmative defense. The EPA provides this illustrative estimate of this burden because these costs are only incurred if there has been a violation and a source chooses to take advantage of the affirmative defense. Given t he variety of circumstances under which malfunctions could occur, as well as differences among sources’ operation and maintenance practices, we cannot reliably predict the severity and frequency of malfunction

- related excess emissions events for a particul ar source. It is important to note that the EPA has no basis currently for estimating the number of malfunctions that would qualify for an affirmative defense. Current historical records would be an inappropriate basis, as source owners or operators previo usly operated their facilities in recognition that they were exempt from the requirement to comply with emissions standards during malfunctions. Of the number of excess emissions events reportedPage 185 of 497

by source operators, only a small number would be expected to result from a malfunction (based on the definition above), and only a subset of excess emissions caused by malfunctions would result in the source choosing to assert the affirmative defense. Thus, we believe the number of instances in which source operato rs might be expected to avail themselves of the affirmative defense will be extremely small. For this reason, we estimate 39 such occurrences for all sources subject to 40 CFR part 63, subpart HH and one such occurrence for all sources subject to 40 CFR p art 63, subpart HHH over the 3

- year period covered by this ICR. We expect to gather information on such events in the future, and will revise this estimate as better information becomes available. The annual monitoring, reporting, and record

- keeping burde n for this collection (averaged over the first 3 years after the effective date of the standards) is estimated to be $2.4 million. This includes 61,249 labor hours per year at a total labor cost of $2.1 million per year, and annualized capital costs of $0. 22 million, and annual operating and maintenance costs of $0.08 million. This estimate includes initial and annual performance tests, semiannual excess emission reports, developing a monitoring plan, notifications, and recordkeeping. All burden estimates a re in 2008 dollars and represent the mostPage 186 of 497

cost effective monitoring approach for affected facilities. Burden is defined at 5 CFR 1320.3(b). An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a curre ntly valid OMB control number. The OMB control numbers for the EPA's regulations in 40 CFR are listed in 40 CFR part 9. When these ICRs are approved by OMB, the agency will publish a technical amendment to 40 CFR part 9 in the Federal
R egister to display the OMB control numbers for the approved information collection requirements contained in the final rule.
C. Regulatory Flexibility Act as Amended by the Small Business Regulatory Enforcement Fairness Act (RFA) of 1996 (SBREFA), 5 U.S.C. 601 et seq. The Regulatory Flexibility Act generally requires an agency to prepare a regulatory flexibility analysis of any rule subject to notice and c omment 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 (SISNOSE). Small entities include sm all businesses, small organizations, and small governmental jurisdictions. For purposes of assessing the impact of this rule on small entities, a small entity is defined as: (1) A small business as defined by NAICS codes 211111, 211112, 221210, 486110 and 486210; whosePage 187 of 497

parent company has no more than 500 employees (or revenues of less than $7 million for firms that transport natural gas via pipeline); (2) a small governmental jurisdiction that is a government of a city, county, town, school district, or spe cial district with a population of less than 50,000; and (3) a small organization that is any not

- for

- profit enterprise which is independently owned and operated and is not dominant in its field. For the final NSPS, the EPA performed an analysis for impac ts on a sample of expected affected small entities by comparing compliance costs to entity revenues. Based upon the analysis in the RIA, which is in the Docket, when revenue from additional natural gas product recovered is not included, we estimate that 12 0 of the 127 small firms analyzed (94 percent) are likely to have impacts less than 1 percent in terms of the ratio of annualized compliance costs to revenues. Meanwhile, seven firms (6 percent) are likely to have impacts greater than 1 percent. Three of t hese seven firms are likely to have impacts greater than 3 percent. However, when revenue from additional natural gas product recovery is included, we estimate that none of the analyzed firms will have an impact greater than 1 percent. For the final NESHA P Amendments, we estimate that 54 of the 108 firms (50 percent) that own potentially affected facilitiesPage 188 of 497

are small entities. The EPA performed an analysis for impacts on all expected affected small entities by comparing compliance costs to entity revenues. Among the small firms, 45 of the 54 (83 percent) are likely to have impacts of less than 1 percent in terms of the ratio of annualized compliance costs to revenues. Meanwhile, nine firms (17 percent) are likely to have impacts greater than 1 percent. Thre e of these nine firms are likely to have impacts greater than 3 percent. While these nine firms might receive significant impacts from the final NESHAP amendments, they represent a very small slice of the oil and gas industry in its entirety, less than 0.2 percent of the estimated 6,427 small firms in NAICS 211. After considering the economic impact of the combined NSPS and NESHAP amendments on small entities, I certify this action will not have a SISNOSE. While both the NSPS and NESHAP amendment would in dividually result in a no SISNOSE finding, the EPA performed an additional analysis in order to certify the rule in its entirety. This analysis compared compliance costs to entity revenues for the total of all the entities affected by the NESHAP amendments and the sample of entities analyzed for the NSPS. When revenues from additional natural gas product sales are not included, 153 of the 169 small firms (91 percent) in the sample are likely to have impacts of less than 1 percent in terms of the ratio of an nualized compliance costs toPage 189 of 497

revenues. Meanwhile, 16 firms (9 percent) are likely to have impacts greater than 1 percent. Six of these 16 firms are likely to have impacts greater than 3 percent. When revenues from additional natural gas product sales are i ncluded, 160 small firms (95 percent) in the sample are likely to have impacts of less than 1 percent. Nine firms (5 percent) are likely to have impacts greater than 1 percent, while only three of these nine are likely to have impacts greater than 3 percen t. Our determination is informed by the fact that many affected firms are expected to receive revenues from the additional natural gas and condensate recovery engendered by the implementation of the controls evaluated in this RIA. As much of the addition al natural gas recovery is estimated to arise from completion

- related activities, we expect the impact on well

related compliance costs to be significantly mitigated. This conclusion is enhanced because the returns to REC activities occur without a signifi cant time lag between implementing the control and obtaining the recovered product, unlike many control options where the emissions reductions accumulate over long periods of time; the reduced emission completions and recompletions occur over a short span of time, during which the additional product recovery is also accomplished. Our current baseline for the impacts analysis of our NSPS for gas well completions takes into account reduced emissionPage 190 of 497

completions conducted pursuant to state regulations covering these operations. However, based on public comments and reports
to the EPA's Natural Gas Star program, the EPA acknowledges that some producers conduct well completions using REC techniques voluntarily. However, the EPA normally does not account for voluntary actions in baseline emissions estimates when we analyze potential impacts of our regulatory actions, since there is no assurance that such voluntary emission reduction measures will continue in the future. As such, emissions reductions obtained f rom RECs implemented voluntarily are not reflected in our baseline emissions estimates. Although this final rule will not impact a substantial number of small entities, the EPA, nonetheless, has tried to reduce the impact of this rule on small entities by setting the final emissions limits at the MACT floor, the least stringent level allowed by law.
D. Unfunded Mandates Reform Act of 1995 This final action does not contain a federal mandate under the provisions of Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), 2 U.S.C. 1531

- 1538 for state, local, and tribal governments, in the aggregate, or to the private sector. The action would not result in expenditures of $100 million or mor e for state, local , and tribal governments, in the aggregate, orPage 191 of 497

to the private sector in any 1 year. Thus, this final rule is not subject to the requirements of sections 202 or 205 of UMRA. This final rule is also not subject to the requirements of sectio n 203 of UMRA because it contains no regulatory requirements that might significantly or uniquely affect small governments because it contains no requirements that apply to such governments nor does it impose obligations upon them.
E. Executive Order 13132 : Federalism This action does not have federalism implications. It will not have substantial direct effects on the states, on the relationship between the national government and the states, or on the distribution of power and responsibilities among the various levels of government, as speci fied in Executive Order 13132. These final rules primarily affect private industry, and do not impose significant economic costs on state or local governments. Thus, Executive Order 13132 does not apply to this action
. F. Executive Order 13175: Consultation and Coordination with Indian Tribal Governments Subject to the Executive Order 13175 (65 FR 67249, November 9, 2000) EPA may not issue a regulation that has tribal implications, that imposes substantial direct compliance costs, and that is not required by statute, unless the Federal government provides the funds necessary to pay the directPage 192 of 497

compliance costs incurred by tribal governments, or EPA consults with tribal officials early in the process of developing the proposed regulation and develops a tribal summary impact
statement. EPA has concluded that this action will have tribal implications because of the growth of the oil and gas production industry in Indian country. The EPA consulted with tribal officials early in the process of developing this regulation to permit them to have meaningful and time ly input into its development. Outreach was conducted prior to the proposal in 2010. The EPA met with the Inter Tribal Environmental Council, which include many of the Region VI tribes, The Tribal leadership summit in Region X, and Tribal Energy Conference hosted by Ft. Belknap, and the National Tribal Forum. After the p roposal was published , letters were sent to all tribal leaders offering to consult on the rule. An outreach and consultation call was held on October 12, 2011. Tribes that participated on this call were: Fond du Lac Band of Lake Superior Chippewa, Fort Belknap Indian Community , Forest County Potawatomi Community, Southern Ute Indian Tribe, and Pueblo of Santa Clara. All these tribes counted this as information only, not consultation. There were no issues raised during this call.Page 193 of 497

The tribes were listening to the presentation a nd the call was ended without comment. In this meeting the tribes were presented the information in the proposal the n asked general clarifying questions but did not provide specific comments. Comments on the proposal were received from an affiliate of the Southern Ute Indian Tribe. The commenter expressed concern about the impacts of the rule on natural gas and oil production operations on the Southern Ute Indian reservation and requested additional time to evaluate the impacts. In response to this and o ther requests, the comment period was extended. More specific comments can be found in the docket. As required by section 7(a), the EPA’s Tribal Consultation Official has certified that the requirements of the Executive Order have been met in a meaningfu l and timely manner. A copy of the certification is included in the docket for this action.
G. Executive Order 13045: Protection of Children from Environmental Health Risks and Safety Risks This action is not subject to Executive Order 13045 (62 FR 19885, April 23, 1997) because the Agency does not believe the environmental health risks or safety risks addressed by this action present a disp roportionate risk to children. This action would not relax the control measures on existing regulated

sources. The EPA’s risk assessments (included in the docket forPage 194 of 497

this final rule) demonstrate that the existing regulations are associated with an acceptable level of risk and provide an ample margin of safety to prote ct public health.
H. Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use This action is not a “significant energy action” as defined in Executive Order 13211 (66 FR 28355, ( May 22, 2001 ) ), because it is not likely to have a significant adverse effect on the supply, distribution, or use of energy. These final rules will result in the addition of control equipment and monitoring systems for existing and new sources within the oil and natura l gas industry. The final NESHAP amendments are unlikely to have a significant adverse effect on the supply, distribution, or use of energy. As such, the final NESHAP amendments are not “significant energy actions” as defined in Executive Order 13211, (66 FR 28355, May 22, 2001). The final NSPS is also unlikely to have a significant adverse effect on the supply, distribution, or use of energy. As such, the final NSPS is not a “significant energy action” as defined in Executive Order 13211 (66 FR 28355, M ay 22, 2001). The basis for the determination is as follows. We use the NEMS to estimate the impacts of the final NSPS on the United States energy system. The NEMS is a publically available model of the United States energy economy developedPage 195 of 497

and maintaine d by the Energy Information Administration of the U.S. DOE and is used to produce the Annual Energy Outlook, a reference publication that provides detailed forecasts of the United States energy economy. Emission controls for the NSPS capture VOC emission s that otherwise would be vented to the atmosphere. Since methane is

co - emitted with VOC, a large proportion of the averted methane emissions can be directed into natural gas production streams and sold. One pollution control requirement of the final NSPS also captures saleable condensates. The revenues from additional natural gas and condensate recovery are expected to offset the costs of implementing the final NSPS. The analysis of energy impacts for the final NSPS that includes the additional product recovery shows that domestic natural gas production is estimated to increase (about 60 billion cubic feet or 0.3 percent) and natural gas prices to decrease ($0.05/Mcf or 1.2 percent at the wellhead for producers in the lower 48 states) in 2015, the year o f analysis. Domestic crude oil production is not estimated to change, while crude oil prices are estimated to decrease slightly ($0.01/barrel or less than about 0.01 percent at the wellhead for producers in the lower 48 states) in 2015, the year of analysi s. All prices are in 2008 dollars.Page 196 of 497

Additionally, the NSPS establishes several performance standards that give regulated entities flexibility in determining how to best comply with the regulation. In an industry that is geographically and economically hete rogeneous, this flexibility is an important factor in reducing regulatory burden. For more information on the estimated energy effects, please refer to the economic impact analysis for this final rule. The analysis is available in the RIA, which is in the public docket.
I. National Technology Transfer and Advancement Act Section 12(d) of the NTTAA of 1995, Public Law 104

– 113, 12(d) (15 U.S.C. 272 note) directs the EPA to use VCS in its regulatory activities unless to do so would be inconsistent with appli cable law or ot herwise impractical. Voluntary consensus standards are technical standards ( e.g ., materials specifications, test methods, sampling procedures, and business practices) that are developed or adopted by VCS bodies. The NTTAA directs the EPA to provide Congress, through OMB, explanations when the EPA decides not to use available and applicable VCS. This final action does not involve technical standards. Therefore, the EPA is not considering the use of any VCS.Page 197 of 497

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

- Income Populations Executive Order 12898 (59 FR 7629, February 16, 1994) establishes Federal executive policy on environmental justice
. Its main provision directs Federal agencies, to the greatest extent practicable and permitted by law, to make EJ part of their mission by identifying and addressing, as appropriate, disproportionately high and adverse human health or environmental effects of their programs, policies and activities

on minority populations and low income populations in the United
States. The 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 inc reases the level of environmental protection for all affected populations without having any disproportionately high and adverse human health or environmental effects on any population, including any minority, low

- income, or indigenous populations. To examine the potential for any environmental justice issues that might be associated with each source category, we evaluated the percentages of various social, demographic, and economic groups within the at

- risk population living near thePage 198 of 497

facilities wher e these source categories are located and compared them to national averages. The development of demographic analyses to inform the consideration of environmental justice issues in the EPA rulemakings is an evolving science. The EPA conducted a demograph ic analysis, focusing on populations within 50 km of any facility in each of the source categories that are estimated to have HAP exposures which result in cancer risks of 1

- in

- 1 million or greater or non

- cancer hazard indices of 1 or greater based on esti mates of current HAP emissions. The results of this analysis are documented in the technical report: Risk and Technology Review

– Analysis of Socio

- economic Factors for Populations Living Near Oil & Natural Gas Production Facilities located in the docket for this rulemaking. As described in the preamble, our risk assessments demonstrate that the regulations for the oil and natural gas production and natural gas transmission and storage source categories, are associated with an acceptable level of risk and that the proposed additional requirements will provide an ample margin of safety to protect public health. Our analyses also show that, for these source categories, there is no potential for an adverse environmental effect or human health multi

pathway ef fects, and that acute and chronic noncancer healthPage 199 of 497

impacts are unlikely. The EPA has determined that, although there may be an existing disparity in HAP risks from these sources between some demographic groups, no demographic group is exposed to an unaccep table level of risk. To promote meaningful involvement, the EPA conducted three public hearings on the proposal. The hearings were held in Pittsburgh, PA on September 27, 2011, Denver, CO on September 28, 2011 and Arlington, TX on September 29, 2011. A to tal of 261 people spoke at the three hearings and 735 people attended the hearings. The attendees at the hearings included private citizens, community

- based and environmental organizations, industry representatives, associations representing industry and
l ocal and state government officials.
K. Congressional Review Act The Congressional Review Act, 5 U.S.C. 801, et seq ., as added by the Small Business Regulatory Enforcement Fairness Act of 1996, generally provides that bef ore a rule may take effect, the ag ency 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. The EPA will submit a re port containing this final rule and ot her required informati on to the United S tates Senate, the United
States Ho use of Representatives, and the Co mptroller General of the United States pr ior to publication of the final rule in thePage 200 of 497

Federal Register . A major rule c annot take effect until 60 days after it is published in the Federal Register
. This action is a “major rule” as defined by 5 U.S.C. 804(2). The final rules will be effective on [INSERT DATE 60 DAYS AFTER THE DATE OF
PUBLICATION IN THE FEDERAL REGISTER]
.Page 201 of 497

Oil and Natural Gas Sector: New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants Reviews
List of Subjects in 40 CFR Part 60 Environmental protection, Air pollution control, Reporting and recordkeeping requirements, Volatile organic compounds. List of Subjects in 40 CFR Part 63 Environmental protection, Administrative practice and procedures, Air pollution control, Hazardous substances, Incorporation by reference, Reporting and recordkeeping requirements, Volatile organic compounds.

____________________________ Dated:

____________________________ Lisa P. Jackson, Administrator.Page 202 of 497

For the reasons set out in the preamble, title 40, chapter I of the Code of Federal Regulations is amended as follows: PART 60

— [AMENDED] 1. The authority citation for part 60 continues to read as follows: Authority: 42 U.S.C. 7401, et seq . 2. Section 60.17 is amended by: a. Revising paragraph (a)(7); and b. Revising paragraphs (a)(91) and (a)(92) to read as follows: § 60.17 Incorporations by reference.
* * * * * (a) * * * (7) ASTM D86

– 78, 82, 90, 93, 95, 96, Distillation of Petroleum Products, IBR approved for §§ 60.562

– 2(d), 60.593(d), 60.593a(d), 60.633(h) and 60.5401(h).
* * * * * (91) ASTM E169

– 63, 77, 93, General Techniques of Ultraviolet Quantitative Analysis, IBR approved fo r §§ 60.485a(d)(1), 60.593(b)(2), 60.593a(b)(2), 60.632(f) and 60.5400(f). (92) ASTM E260

– 73, 91, 96, General Gas Chromatography Procedures, IBR approved for §§ 60.485a(d)(1), 60.593(b)(2), 60.593a(b)(2), 60.632(f), 60.5400(f) and 60.5406(b).Page 203 of 497

* * * * *
Su bpart KKK

— Standards of Performance for Equipment Leaks of VOC From Onshore Natural Gas Processing Plants for Which Construction, Reconstruction, or Modification Commenced After January 20, 1984, and on or Before August 23, 2011 3. The heading for Subpart KKK is revised to read as set out above. 4. Section 60.630 is amended by revising paragraph (b) to read as follows: § 60.630 Applicability and designation of affected facility.
* * * * * (b) Any affected facility under paragraph (a) of this section that commences construction, reconstruction, or modification after January 20, 1984, and on or before August 23, 2011, is subject to the requirements of this subpart.
* * * * * Subpart LLL

— Standards of Performance for SO 2 Emissions From Onshore Natural Gas Processing for Which Construction, Reconstruction, or Modification Commenced After January 20, 1984, and on or Before August 23, 2011

5. The heading for Subpart LLL is revised to read as set out above. 6. Section 60.640 is amended by revising paragraph (d) to read as follows: § 60.640 Applicability and designation of affected facilities.
* * * * *Page 204 of 497

(d) The provisions of this subpart apply to each affected facility identified in paragraph (a) of this section which commences construction or modification af ter January 20, 1984, and on or before August 23, 2011.
* * * * * 7. Add subpart OOOO to part 60 to read as follows:
Subpart OOOO

— Standards of Performance for Crude Oil and Natural Gas Production, Transmission, and Distribution
Sec. 60.5360 What is the purpose of this subpart? 60.5365 Am I subject to this subpart? 60.5370 When must I comply with this subpart? 60.5375 What standards apply to gas well affected facilities? 60.5380 What standards apply to centrifugal compressor

affected facilities? 60.5385 What standards apply to reciprocating compressor

affected facilities? 60.5390 What standards apply to pneumatic controller affected

facilities? 60.5395 What standards apply to storage vessel affected

facilities? 60.5400 What VOC standards apply to affected facilities at an

onshore natural gas processing plant? 60.5401 What are the exceptions to the VOC standards for

affected facilities at onshore natural gas processing plants? 60.5402 What are the alternative emission limitations for

equipment leaks from onshore natural gas processing plants? 60.5405 What standards apply to sweetening units at onshore

natural gas processing plants? 60.5406 What test methods and procedures must I use for my

sweetening units affected facilities at onshore natural gas p rocessing plants? 60.5407 What are the requirements for monitoring of emissions

and operations from my sweetening unit affected facilities at onshore natural gas processing plants?Page 205 of 497

60.5408 What is an o ptional procedure for measuring hydrogen

sulfide in aci d gas

— Tutwiler Procedure? 60.5410 How do I demonstrate initial compliance with the

standards for my gas well affected facility, my centrifugal compressor affected facility, my reciprocating compressor affected facility, my pneumatic controller affected facility, my storage vessel affected facility, and my affected facilities at onshore natural gas processing pla nts? 60.5411 What requirements must I meet for closed vent systems

routing emissions from storage vessels or centrifugal compressor wet seal fluid degassing systems ? 60.5412 What requirements must I meet for control devices used

to demonstrate compliance a t my storage vessel or centrifugal compressor affected facility? 60.5413 What are the performance testing procedures for

control devices used to demonstrate compliance at my storage vessel or centrifugal compressor affected facility? 60.5415 How do I demon strate continuous compliance with the

standards for my gas well affected facility, my centrifugal compressor affected facility, my stationary reciprocating compressor affected facility, my pneumatic controller affected facility, my storage vessel affected facility, and my affected facilities at onshore natural gas processing plants? 60.5416 What are the initial and continuous cover and closed

vent system inspection and monitoring requirements for my storage vessel or centrifugal compressor affected facility ? 60.5417 What are the continuous control device monitoring

requirements for my storage vessel or centrifugal compressor affected facility? 60.5420 What are my notification, reporting, and recordkeeping

requirements? 60.5421 What are my additional recordke eping requirements for

my affected facility subject to VOC requirements for onshore natural gas processing plants? 60.5422 What are my additional reporting requirements for my

affected facility subject to VOC requirements for onshore natural gas processing plants? 60.5423 What additional recordkeeping and reporting

requirements apply to my sweetening unit affected facilities at onshore natural gas processing plants? 60.5425 What part s of the General Provisions apply to me? 60.5430 What definitions apply t o this subpart?Page 206 of 497

Table 1 to Subpart OOOO of part 60

– Required Minimum Initial SO2 Emission Reduction Efficiency (Z i ) Table 2 to Subpart OOOO of part 60

– Required Minimum SO2 Emission Reduction Efficiency (Z c ) Table 3 to Subpart OOOO of part 60

– Applicability of General Provisions to Subpart OOOO
Subpart OOOO

— Standards of Performance for Crude Oil and Natural Gas Production, Transmission, and Distribution §60.5360 What is the purpose of this subpart? This subpart establishes emission standards and compliance schedules for the control of volatile organic compounds (VOC) and sulfur dioxide (SO 2 ) emissions from onshore affected facilities that commenced construction, modification or reconstruction after August 23, 2011. §60.5365 Am I subject to th is subpart? If you are the owner or operator of one or more of the affected facilities listed in paragraphs (a) through (g) of this section that commenced construction, modification, or reconstruction after August 23, 2011 your affected facility is subjec t to the applicable provisions of this subpart. (a) A gas well affected facility, which is a single natural gas well. (b) A centrifugal compressor affected facility, which is defined as a single centrifugal compressor using wet seals that is located between the wellhead and the point of custody transfer to a natural gas transmission and storage facility,Page 207 of 497

except that a cen trifugal compressor located at a well site (as defined in §60.5430) is not an affected facility under this subpart. For the purposes of this subpart, your centrifugal compressor is considered to have commenced construction on the date of original manufactu re. (c) A reciprocating compressor affected facility, which is defined as a single reciprocating compressor located between the wellhead and the point of custody transfer to a natural gas transmission and storage facility, except that a reciprocating

com pressor located at a well site (as defined in §60.5430) is not an affected facility under this subpart. For the purposes of this subpart, your reciprocating compressor is considered to have commenced construction on the date of original manufacture. (d) A pneumatic controller affected facility, which is defined as a single natural gas driven pneumatic controller that vents continuously (bleeds) to the atmosphere located between the wellhead and the point of custody transfer to a natural gas transmission an d storage facility. (e) A storage vessel affected facility, which is defined as a single storage vessel. (f) Compressors and equipment (as defined in §60.5430) located at onshore natural gas processing plants. (1) Each compressor in VOC service or in wet gas service is an affected facility.Page 208 of 497

(2) The group of all equipment, except compressors, within a process unit is an affected facility. (3) Addition or replacement of equipment, as defined in §60.5430, for the purpose of process improvement that is

a ccomplished without a capital expenditure shall not by itself be considered a modification under this subpart. (4) Equipment (as defined in §60.5430) associated with a compressor station, dehydration unit, sweetening unit, underground storage tank, f ield gas gathering system, or liquefied natural gas unit is covered by §§60.5400, 60.5401, 60.5402, 60.5421 and 60.5422 of this subpart if it is located at an onshore natural gas processing plant. Equipment (as defined in §60.5430) not located at the onsho re natural gas processing plant site is exempt from the provisions of §§ 60.5400, 60.5401, 60.5402, 60.5421 and 60.5422 of this subpart. (5) Affected facilities located at onshore natural gas processing plants and described in paragraphs (f)(1) and (f)(2) of this section are exempt from this subpart if they are subject to and controlled according to subparts VVa, GGG or GGGa of this part. (g) Sweetening units located at onshore natural gas processing plants that process natural gas produced from either

ons hore or offshore wells.Page 209 of 497

(1) Each sweetening unit that processes natural gas is an affected facility; and (2) Each sweetening unit that processes natural gas followed by a sulfur recovery unit is an affected facility. (3) Facilities that have a design ca pacity less than 2 long tons per day (LT/D) of hydrogen sulfide (H2S) in the acid gas (expressed as sulfur) are required to comply with recordkeeping and reporting requirements specified in §60.5423(c) but are not required to comply with §§60.5405 through 60.5407 and paragraphs 60.5410(g) and 60.5415(g) of this subpart. (4) Sweetening facilities producing acid gas that is completely reinjected into oil

- or - gas - bearing geologic strata or that is otherwise not released to the atmosphere are not subject to §§6 0.5405 through 60.5407, and §§60.5410(g), 60.5415(g), and §60.5423 of this subpart. (h) For the purposes of this subpart, the operations in paragraphs (h)(1) through (h)(4) of this section are modifications, but do not affect the modification status of
ot her equipment, process units, storage vessels, or pneumatic controllers located at the well site. (1) A well completion operation following hydraulic fracturing or refracturing at a gas well facility that commenced construction, modification, or reconstru ction on or before August 23, 2011.Page 210 of 497

(2) A well completion operation following hydraulic fracturing or refracturing at a gas well facility that commenced construction, modification, or reconstruction after August 23, 2011. (3) A well recompletion operati on that occurs after August 23, 2011 at a fractured or refractured gas well facility. (4) A refracturing operation that occurs after August 23, 2011 at a gas well facility. §60.5370 When must I comply with this subpart? (a) You must be in compliance wit h the standards of this subpart no later than [INSERT DATE 60 DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER] or upon startup, whichever is later. (b) The provisions for exemption from compliance during periods of startup, shutdown, and malfuncti ons provided for in 40 CFR 60.8(c) do not apply to this subpart. (c) You are exempt from the obligation to obtain a permit under 40 CFR part 70 or 40 CFR part 71, provided you are not otherwise required by law to obtain a permit under 40 CFR 70.3(a) or 40 CFR 71.3(a). Notwithstanding the previous sentence, you must continue to comply with the provisions of this subpart. §60.5375 What standards apply to gas well affected facilities?Page 211 of 497

If you are the owner or operator of a gas well affected facility, you must comply with paragraphs (a) through (g) of this section. (a) Except as provided in paragraph (f) of this section, for each well completion operation with hydraulic fracturing, as defined in §60.5430, begun prior to [INSERT DAT E TWO YEAR S AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER] , you must comply with the requirements of paragraph (a)(3) of this section unless a more stringent state or local emission control requirement is applicable . For each well completion operation with hydraulic fracturing begun on or after [INSERT DATE TWO YEAR S AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER] , you must comply with the requirements in paragraphs (a)(1) through (a)(3) of this section. (1) For the duration of flowback , route the r ecovered liquids into one or more storage vessels and route the recovered gas into a gas gathering line or collection system. (2) All salable quality gas must be routed to the gas gathering line as soon as practicable. (3) You must capture and direct flowback emissions that cannot be directed to the gathering line to a completion combustion device, except in conditions that may result in a fire hazard or explosion, or where high heat emissions from flaring may negatively impact tundra, permafrost or waterways.Page 212 of 497

Completion combustion devices must be equipped with a reliable continuous ignition source over the duration of flowback. (b) You must maintain a log for each well completion operation at each gas well affected facility. The log must be completed on a daily basis and must contain the records specified in §60.5420(c)(1)(iii). (c) You must demonstrate initial compliance with the standards that apply to gas well affected facilities as required by §60.5410. (d) You must demonstrate continuous compliance with the standards that apply to gas well affected facilities as required by §60.5415. (e) You must perform the required notification, recordkeeping, and reporting as required by §60.5420. (f) (1) For ea ch well completion operation with hydraulic fracturing at a gas well affected facility meeting the criteria for a wildcat or delineation well , you must comply with the requirements of paragraph s (a)(3) and (b)

- (e) of this section. (2) For each well compl etion operation with hydraulic fracturing at a gas well affected facility meeting the criteria for a low pressure non

- wildcat or low pressure non

- delineation well, you must comply with the requirements of paragraph s (a)(3) and (b)

- (e) of this section.Page 213 of 497

(3) You must also maintain records specified in §60.5420(c)(1)(iii) for wildcat or delineation wells and low pressure wells
. §60.5380 What standards apply to centrifugal compressor affected facilities ? You must comply with the standards in paragraphs (a) through (d) of this section, as applicable for each centrifugal compressor affected facility. (a) (1) You must reduce VOC emissions from each centrifugal compressor wet seal fluid degassing system by 95 percent or greater. (2) If you use a control device to reduce emissions, you must equip the wet seal fluid degassing system with a cover that is connected through a closed vent system that meets the requirements of §60.5411 to a control device that meets the conditions specified in §60.5412 (b) You must demonstrate initial compliance with the standards that apply to centrifugal compressor affected facilities as required by §60.5410. (c) You must demonstrate continuous compliance with the standards that apply to centrifugal compressor affected facili ties as required by §60.5415. (d) You must perform the required notification, recordkeeping, and reporting as required by §60.5420.Page 214 of 497

§60.5385 What standards apply to reciprocating compressor affected facilities? You must comply with the standards in para graphs (a) through (d) of this section for each reciprocating compressor affected facility. (a) You must replace the reciprocating compressor rod packing according to either paragraph (a)(1) or (a)(2) of this section. (1) B efore the compressor has operat ed for 26,000 hours. The number of hours of operation must be continuously monitored beginning upon initial startup of your reciprocating compressor affected facility, or [INSERT DATE 60 DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER] , or the date of the previous reciprocating compressor rod packing replacement, whichever is later. (2) Prior to 36 months from the date of the most recent rod packing replacement, or 36 months from the date of installation for a new reciprocating compressor for which the rod packing has not yet been replaced. (b) You must demonstrate initial compliance with standards that apply to reciprocating compressor affected facilities as required by §60.5410.Page 215 of 497

(c) You must demonstrate continuous compliance with standards that a pply to reciprocating compressor affected facilities as required by §60.5415. (d) You must perform the required notification, recordkeeping, and reporting as required by §60.5420. §60.5390 What standards apply to pneumatic controller affected facilities? For each pneumatic controller affected facility you must comply with the VOC standards, based on natural gas as a surrogate for VOC, in either paragraph (b) or (c) of this section, as applicable. Pneumatic controllers meeting the conditions in paragraph (a) are exempt from this requirement. (a) The requirements of paragraph (b) or (c) of this section are not required if you demonstrate, to the Administrator’s satisfaction, that the use of a pneumatic controller affected facility with a bleed rate greater than 6 standard cubic feet per hour is required based on factors such as response time, safety and actuation. (b)(1) Each new, reconstructed or modified pneumatic controller affected facility installed after August 23, 2011, at a natural gas processing plant (as defined in §60.5430 must have a bleed rate of zero. (2) Each new, reconstructed or modified pneumatic controller installed after August 23, 2011, at a natural gasPage 216 of 497

processing plant must be tagged with the month and year of installation, reconstr uction or modification, and identification information that allows traceability to the records for that controlled required in §60.5420(c)(4)(iv). (c)(1) Each new, reconstructed or modified pneumatic controller affected facility installed after August 23, 2011, at a location between the wellhead and a natural gas processing plant must have a bleed rate less than or equal to 6 standard cubic feet per hour. (2) Each new, reconstructed or modified pneumatic controller installed after August 23, 2011, [ at a l ocation between the wellhead and a natural gas processing plant must be tagged with the month and year of installation, reconstruction or modification, and identification information that allows traceability to the records for that controlled required in §60.5420(c)(4)(iii). (d) You must demonstrate initial compliance with standards that apply to pneumatic controller affected facilities as required by §60.5 410. (e) You must demonstrate continuous compliance with standards that apply to pneumatic controller affected facilities as required by §60.5415. (f) You must perform the required notification, recordkeeping, and reporting as required by §60.5420, excep tPage 217 of 497

that you are not required to submit the notifications specified in §60.5420(a). §60.5395 What standards apply to storage vessel affected facilities? You must comply with the standards in this section for each storage vessel affected facility with VOC em issions equal to or greater than 6 tpy as determined in paragraph (a) of this section. (a) (1) Well sites with no other wells in production
. You must determine the VOC emission rate for each storage vessel affected facility within 30 days after installat ion, modification or reconstruction. For each storage vessel affected facility emitting more than 6 tpy VOC you must reduce VOC emissions by 95 percent of greater within 60 days after installation, modification or reconstruction. (2) Well sites with one o r more wells already in production . You must determine the VOC emission rate for each storage vessel affected facility upon installation, modification or reconstruction. For each storage vessel affected facility emitting more than 6 tpy VOC you must reduce VOC emissions by 95 percent or greater upon installation, modification or reconstruction. ( 3 ) If you use a control device to reduce emissions, you must equip the storage vessel with a cover that is connectedPage 218 of 497

through a closed vent system that meets the requirements of §60.5411 to a control device that meets the conditions specified in §60.5412. ( 4 ) If you use a vapor recovery device to reduce emissions, you must meet the requirements of §60. 5411
. (b) This standard does not apply to storage vesse ls already subject to and controlled in accordance with the requirements for storage vessels in 40 CFR part 60, subpart Kb, or 40 CFR part 63, subparts G, CC, HH, WW, or HHH. (c) You must demonstrate initial compliance with standards that apply to storage vessel affected facilities as required by §60.5410. (d) You must demonstrate continuous compliance with standards that apply to storage vessel affected facilities as required by §60.5415. (e) You must perform the required notification, recordkeeping, and reporting as required by §60.5420. §60.5400 What VOC standards apply to affected facilities at an onshore natural gas processing plant? This section applies to each compress or in VOC service or in wet gas service and the group of all equipment (as defined in §60.5430), except compressors, within a process unit.Page 219 of 497

(a) You must comply with the requirements of §60.482

- 1a(a), (b), and (d),§60.482

- 2a, and §60.482

- 4a through 60.4 82

- 11a, except as provided in §60.5401. (b) You may elect to comply with the requirements of §§60.483

- 1a and 60.483

- 2a, as an alternative. (c) You may apply to the Administrator for permission to use an alternative means of emission limitation that achieves a reduction in emissions of VOC at least equivalent to that achieved by the controls required in this subpart according to the requirements of §60.5402 of this subpart. (d) You must comply with the provisions of §60.485a of this part except a s provided in paragraph (f) of this section. (e) You must comply with the provisions of §§60.486a and 60.487a of this part except as provided in §§60.5401, 60.5421, and 60.5422 of this part. (f) You must use the following provision instead of §60.485a(d)(1): Each piece of equipment is presumed to be in VOC service or in wet gas service unless an owner or operator demonstrates that the piece of equipment is not in VOC service or in wet gas service. For a piece of equipment to be considered not in VOC service, it must be determined that the VOC content can be reasonably expected never to exceed 10.0 percent by weight. For a piece of equipment to be considered in wet gas service, it must be de termined that it contains or contacts thePage 220 of 497

field gas before the extraction step in the process. For purposes of determining the percent VOC content of the process fluid that is contained in or contacts a piece of equipment, procedures that conform to the me thods described in ASTM E169

- 63, 77, or 93, E168

- 67, 77, or 92, or E260

- 73, 91, or 96 (incorporated by reference as specified in §60.17) must be used. §60.5401 What are the exceptions to the VOC standards for affected facilities at onshore natural gas proc essing plants? (a) You may comply with the following exceptions to the provisions of subpart VVa of this part. (b)(1) Each pressure relief device in gas/vapor service may be monitored quarterly and within 5 days after each pressure release to detec t leaks by the methods specified in §60.485a(b) except as provided in §60.5400(c) and in paragraph (b)(4) of this section, and §60.482

- 4a(a) through (c) of subpart VVa. (2) If an instrument reading of 5000 ppm or greater is measured, a leak is detected
. (3)(i) When a leak is detected, it must be repaired as soon as practicable, but no later than 15 calendar days after it is detected, except as provided in §60.482

- 9a. (ii) A first attempt at repair must be made no later than 5 calendar days after each leak is detected. (4)(i) Any pressure relief device that is located in a nonfractionating plant that is monitored only by non

- plantPage 221 of 49 7

personnel may be monitored after a pressure release the next time the monitoring personnel are on

- site, instead o f within 5 days as specified in paragraph (b)(1) of this section and §60.482

- 4a(b)(1) of subpart VVa. (ii) No pressure relief device described in paragraph (b)(4)(i) of this section must be allowed to operate for more than 30 days after a pressure rele ase without monitoring. (c) Sampling connection systems are exempt from the requirements of §60.482

- 5a. (d) Pumps in light liquid service, valves in gas/vapor and light liquid service, and pressure relief devices in gas/vapor service that are locat ed at a nonfractionating plant with a design capacity to process 283,200 standard cubic meters per day (scmd) (10 million standard cubic feet per day) or more of field gas are exempt from the routine monitoring requirements of §§60.482

- 2a(a)(1) and 60.482

- 7a(a), and paragraph (b)(1) of this section. (e) Pumps in light liquid service, valves in gas/vapor and light liquid service, and pressure relief devices in gas/vapor service within a process unit that is located in the Alaskan North Slope are exempt f rom the routine monitoring requirements of §§60.482

- 2a(a)(1), 60.482

- 7a(a), and paragraph (b)(1) of this section.Page 222 of 497

(f) Flares used to comply with this subpart must comply with the requirements of §60.18. (g) An owner or operator may use the followin g provisions instead of §60.485a(e): (1) Equipment is in heavy liquid service if the weight percent evaporated is 10 percent or less at 150 o C (302 o F) as determined by ASTM Method D86

- 78, 82, 90, 95, or 96 (incorporated by reference as specified in §60. 17). (2) Equipment is in light liquid service if the weight percent evaporated is greater than 10 percent at 150 o C (302 o F) as determined by ASTM Method D86

- 78, 82, 90, 95, or 96 (incorporated by reference as specified in §60.17). §60.5402 What are the alternative emission limitations for equipment leaks from onshore natural gas processing plants? (a) If, in the Administrator's judgment, an alternative means of emission limitation will achieve a reduction in VOC emissions at least equivalent to the reduction in VOC emissions achieved under any design, equipment, work practice or operational standard, the Administrator will publish, in the Federal Register , a notice permitting the use of that alternative means for the purpose of compliance with that

s tandard. The notice may condition permission on requirements related to the operation and maintenance of the alternative

means.Page 223 of 497

(b) Any notice under paragraph (a) of this section must be published only after notice and an opportunity for a public heari ng. (c) The Administrator will consider applications under this section from either owners or operators of affected facilities, or manufacturers of control equipment. (d) The Administrator will treat applications under this section according to the following criteria, except in cases where the Administrator concludes that other criteria are appropriate: (1) The applicant must collect, verify and submit test data, covering a period of at least 12 months, necessary to support the finding in paragr aph (a) of this section. (2) If the applicant is an owner or operator of an affected facility, the applicant must commit in writing to operate and maintain the alternative means so as to achieve a reduction in VOC emissions at least equivalent to the r eduction in VOC emissions achieved under the design, equipment, work practice or operational standard. §60.5405 What standards apply to sweetening units at onshore natural gas processing plants? (a) During the initial performance test required by §60.8(b) , you must achieve at a minimum, an SO2 emission reduction efficiency (Zi) to be determined from Table 1 of thisPage 224 of 497

subpart based on the sulfur feed rate (X) and the sulfur content of the acid gas (Y) of the affected facility. (b) After demonstrating complia nce with the provisions of paragraph (a) of this section, you must achieve at a minimum, an SO2 emission reduction efficiency (Zc) to be determined from Table 2 of this subpart based on the sulfur feed rate (X) and the sulfur content of the acid gas (Y) of the affected facility. 60.5406 What test methods and procedures must I use for my sweetening units affected facilities at onshore natural gas processing plants? (a) In conducting the performance tests required in §60.8, you must use the test methods in a ppendix A of this part or other methods and procedures as specified in this section, except as provided in paragraph §60.8(b). (b) During a performance test required by §60.8, you must determine the minimum required reduction efficiencies (Z) of SO2 emissions as required in §60.5405(a) and (b) as follows: (1) The average sulfur feed rate (X) must be computed as follows:

Where: X = average sulfur feed rate, Mg/D (LT/D). Qa = average volumetric flow rate of acid gas from sweetening unit, ds cm/day (dscf/day). Y = average H2S concentration in acid gas feed from sweetening unit, percent by volume, expressed as a decimal. K = (32 kg S/kg

- mole)/((24.04 dscm/kg

- mole)(1000 kg S/ Mg))Page 225 of 497

= 1.331 × 10−3Mg/dscm, for metric units = (32 lb S/lb

- mole)/( (385.36 dscf/lb

- mole)(2240 lb S/long ton)) = 3.707 × 10−5long ton/dscf, for English units. (2) You must use the continuous readings from the process flowmeter to determine the average volumetric flow rate (Qa) in dscm/day (dscf/day) of the acid gas from the sweetening unit for each run. (3) You must use the Tutwiler procedure in §60.5408 or a chromatographic procedure following ASTM E

– 260 (incorporated by reference

— see §60.17) to determine the H2S concentration in the acid gas feed from the sweetening u nit (Y). At least one sample per hour (at equally spaced intervals) must be taken during each
4

- hour run. The arithmetic mean of all samples must be the average H2S concentration (Y) on a dry basis for the run. By multiplying the result from the Tutwiler p rocedure by 1.62 × 10−3, the units gr/100 scf are converted to volume percent. (4) Using the information from paragraphs (b)(1) and (b)(3) of this section, Tables 1 and 2 of this subpart must be used to determine the required initial (Zi) and continuous ( Zc) reduction efficiencies of SO2 emissions. (c) You must determine compliance with the SO2 standards in §60.5405(a) or (b) as follows:Page 226 of 497

(1) You must compute the emission reduction efficiency (R) achieved by the sulfur recovery technology for each run usi ng the following equation:

(2) You must use the level indicators or manual soundings to measure the liquid sulfur accumulation rate in the product storage tanks. You must use readings taken at the beginning and end of each run, the tank geometry, sulfur density at the storage temperature, and sample duration to determine the sulfur production rate (S) in kg/hr (lb/hr) for each run. (3) You must compute the emission rate of sulfur for each run as follows:

Where: E = emi ssion rate of sulfur per run, kg/hr. Ce = concentration of sulfur equivalent (SO2+ reduced sulfur), g/dscm (lb/dscf). Qsd = volumetric flow rate of effluent gas, dscm/hr (dscf/hr). K1 = conversion factor, 1000 g/kg (7000 gr/lb). (4) The concentration (Ce) of sulfur equivalent must be the sum of the SO2 and TRS concentrations, after being converted to sulfur equivalents. For each run and each of the test methods specified in this paragraph (c) of this section, you must use a sampling time of at least 4 hour s. You must use Method 1 of appendix A to part 60 of this chapter to select the sampling site. The sampling point in the duct must be at the centroid ofPage 227 of 497

the cross

- section if the area is less than 5 m2 (54 ft2 ) or at a point no closer to the walls than 1 m (39 in) if the cross

sectional area is 5 m2 or more, and the centroid is more than 1 m (39 in.) from the wall. (i) You must use Method 6 of appendix A to part 60 of this chapter to determine the SO2 concentration. You must take eight samples of 20 minute s each at 30

- minute intervals. The arithmetic average must be the concentration for the run. The concentration must be multiplied by 0.5 × 10−3 to convert the results to sulfur equivalent. (ii) You must use Method 15 of appendix A to part 60 of this chapter to determine the TRS concentration from reduction

type devices or where the oxygen content of the effluent gas is less than 1.0 percent by volume. The sampling rate must be at least 3 liters/min (0.1 ft3 /min) to insure minimum residence time in th e sample line. You must take sixteen samples at 15

- minute intervals. The arithmetic average of all the samples must be the concentration for the run. The concentration in ppm reduced sulfur as sulfur must be multiplied by 1.333 × 10−3 to
convert the result s to sulfur equivalent. (iii) You must use Method 16A or Method 15 of appendix A to part 60 of this chapter to determine the reduced sulfur concentration from oxidation

- type devices or where the oxygen content of the effluent gas is greater than 1.0 perce nt byPage 228 of 497

volume. You must take eight samples of 20 minutes each at 30

- minute intervals. The arithmetic average must be the concentration for the run. The concentration in ppm reduced sulfur as sulfur must be multiplied by 1.333 × 10−3 to convert the results t o sulfur equivalent. (iv) You must use Method 2 of appendix A to part 60 of this chapter to determine the volumetric flow rate of the effluent gas. A velocity traverse must be conducted at the beginning and end of each run. The arithmetic average of the t wo measurements must be used to calculate the volumetric flow rate (Qsd) for the run. For the determination of the effluent gas molecular weight, a single integrated sample over the 4

- hour period may be taken and analyzed or grab samples at 1

- hour interval s may be taken, analyzed, and averaged. For the moisture content, you must take two samples of at least 0.10 dscm (3.5 dscf) and 10 minutes at the beginning of the 4

- hour run and near the end of the time period. The arithmetic average of the two runs must be the moisture content for the run. 60.5407 What are the requirements for monitoring of emissions and operations from my sweetening unit affected facilities at onshore natural gas processing plants? (a) If your sweetening unit affected facility is locat ed at an onshore natural gas processing plant and is subject to the provisions of §60.5405(a) or (b) you must install, calibrate,Page 229 of 497

maintain, and operate monitoring devices or perform measurements to determine the following operations information on a daily basis: (1) The accumulation of sulfur product over each 24

- hour period. The monitoring method may incorporate the use of an instrument to measure and record the liquid sulfur production rate, or may be a procedure for measuring and recording the sulfur li quid levels in the storage tanks with a level indicator or by manual soundings, with subsequent calculation of the sulfur production rate based on the tank geometry, stored sulfur density, and elapsed time between readings. The method must be designed to b e accurate within ±2 percent of the 24

- hour sulfur accumulation. (2) The H 2 S concentration in the acid gas from the sweetening unit for each 24

- hour period. At least one sample per 24

- hour period must be collected and analyzed using the equation specified in §60.5406(b)(1). The Administrator may require you to demonstrate that the H2S concentration obtained from one or more samples over a 24

- hour period is within ±20 percent of the average of 12 samples collected at equally spaced intervals during the 24

- h our period. In instances where the H2S concentration of a single sample is not within ±20 percent of the average of the 12 equally spaced samples, the Administrator may require a more frequent sampling schedule.Page 230 of 497

(3) The average acid gas flow rate from the sweetening unit . You must install and operate a monitoring device to continuously measure the flow rate of acid gas. The monitoring device reading must be recorded at least once per hour during each 24

- hour period. The average acid gas flow rate must be

c omputed from the individual readings. (4) The sulfur feed rate (X) . For each 24

- hour period, you must compute X using the equation specified in §60.5406(b)(3). (5) The required sulfur dioxide emission reduction efficiency for the 24

- hour period
. You must use the sulfur feed rate and the H2S concentration in the acid gas for the 24

- hour period, as applicable, to determine the required reduction efficiency in accordance with the provisions of §60.5405(b). (b) Where compliance is achieved through the use of an oxidation control system or a reduction control system followed by a continually operated incineration device, you must install, calibrate, maintain, and operate monitoring devices and continuous emission monitors as follows: (1) A continuous monitori ng system to measure the total sulfur emission rate (E) of SO2 in the gases discharged to the atmosphere . The SO2 emission rate must be expressed in terms of equivalent sulfur mass flow rates (kg/hr (lb/hr)). The span of this monitoring system must be set so that the equivalentPage 231 of 497

emission limit of §60.5405(b) will be between 30 percent and 70 percent of the measurement range of the instrument system. (2) Except as provided in paragraph (b)(3) of this section: A monitoring device to measure the temperature of the gas leaving the combustion zone of the incinerator, if compliance with §60.5405(a) is achieved through the use of an oxidation control system or a reduction control system followed by a continually operated incineration device. The monitoring device

m ust be certified by the manufacturer to be accurate to within ±1 percent of the temperature being measured. (3) When performance tests are conducted under the provision of §60.8 to demonstrate compliance with the standards under §60.5405, the temperature of the gas leaving the incinerator combustion zone must be determined using the monitoring device. If the volumetric ratio of sulfur dioxide to sulfur dioxide plus total reduced sulfur (expressed as SO2) in the gas leaving the incinerator is equal to or le ss than 0.98, then temperature monitoring may be used to demonstrate that sulfur dioxide emission monitoring is sufficient to determine total sulfur emissions. At all times during the operation of the facility, you must maintain the average temperature of the gas leaving the combustion zone of the incinerator at or above the appropriate level determined during the most recent performance test to ensure the sulfur compound oxidation criteria are met.Page 232 of 497

Operation at lower average temperatures may be considered by the Administrator to be unacceptable operation and maintenance of the affected facility. You may request that the minimum incinerator temperature be reestablished by conducting new performance tests under §60.8. (4) Upon promulgation of a performance s pecification of continuous monitoring systems for total reduced sulfur compounds at sulfur recovery plants, you may, as an alternative to paragraph (b)(2) of this section, install, calibrate, maintain, and operate a continuous emission monitoring system fo r total reduced sulfur compounds as required in paragraph (d) of this section in addition to a sulfur dioxide emission monitoring system. The sum of the equivalent sulfur mass emission rates from the two monitoring systems must be used to compute the total sulfur emission rate (E). (c) Where compliance is achieved through the use of a reduction control system not followed by a continually operated incineration device, you must install, calibrate, maintain, and operate a continuous monitoring system to meas ure the emission rate of reduced sulfur compounds as SO2 equivalent in the gases discharged to the atmosphere. The SO2 equivalent compound emission rate must be expressed in terms of equivalent sulfur mass flow rates (kg/hr (lb/hr)). The span of this monit oring system must be set so that the equivalent emission limit ofPage 233 of 497

§60.5405(b) will be between 30 and 70 percent of the measurement range of the system. This requirement becomes effective upon promulgation of a performance specification for continuous monit oring systems for total reduced sulfur compounds at sulfur recovery plants. (d) For those sources required to comply with paragraph (b) or (c) of this section, you must calculate the average sulfur emission reduction efficiency achieved (R) for each 24

- ho ur clock internal. The 24

- hour interval may begin and end at any selected clock time, but must be consistent. You must compute the 24

- hour average reduction efficiency (R) based on the 24

- hour average sulfur production rate (S) and sulfur emission rate (E) , using the equation in §60.5406(c)(1). (1) You must use data obtained from the sulfur production rate monitoring device specified in paragraph (a) of this section to determine S. (2) You must use data obtained from the sulfur emission rate monitoring sy stems specified in paragraphs (b) or (c) of this section to calculate a 24

- hour average for the sulfur emission rate (E). The monitoring system must provide at least one data point in each successive 15

- minute interval. You must use at least two data point s to calculate each 1

- hour average. You must use a minimum of 18 1

- hour averages to compute each 24

- hour average.Page 234 of 497

(e) In lieu of complying with paragraphs (b) or (c) of this section, those sources with a design capacity of less than 152 Mg/D (150 LT/D) of H 2 S expressed as sulfur may calculate the sulfur emission reduction efficiency achieved for each 24

- hour period by:

Where: R = The sulfur dioxide removal efficiency achieved during the 24

- hour period, percent. K2 = Conversion factor, 0.02400 M g/D per kg/hr (0.01071 LT/D per lb/hr). S = The sulfur production rate during the 24

- hour period, kg/hr (lb/hr). X = The sulfur feed rate in the acid gas, Mg/D (LT/D). (f) The monitoring devices required in paragraphs (b)(1), (b)(3) and (c) of this sectio n must be calibrated at least annually according to the manufacturer's specifications, as required by §60.13(b). (g) The continuous emission monitoring systems required in paragraphs (b)(1), (b)(3), and (c) of this section must be subject to the emission monitoring requirements of §60.13 of the General Provisions. For conducting the continuous emission monitoring system performance evaluation required by §60.13(c), Performance Specification 2 of appendix B to part 60 of this chapter must apply, and Method 6 must be used for systems required by paragraph (b) of this section.Page 235 of 497

§60.5408 What is an o ptional procedure for measuring hydrogen sulfide in acid gas — Tutwiler Procedure? 1 (a) When an instantaneous sample is desired and H2S concentration is ten grains p er 1000 cubic foot or more, a 100 ml Tutwiler burette is used. For concentrations less than ten grains, a 500 ml Tutwiler burette and more dilute solutions are used. In principle, this method consists of titrating hydrogen sulfide in a gas sample directly with a standard solution of iodine. (b) Apparatus . (See Figure 1 of this subpart) A 100 or 500 ml capacity Tutwiler burette, with two

- way glass stopcock at bottom and three

- way stopcock at top which connect either with inlet tubulature or glass

- stoppered cylinder, 10 ml capacity, graduated in 0.1 ml subdivision; rubber tubing connecting burette with leveling bottle. (c) Reagents . (1) Iodine stock solution, 0.1N. Weight 12.7 g iodine, and 20 to 25 g cp potassium iodide for each liter of solution. Dissolve KI in as little water as necessary; dissolve iodine in concentrated KI solution, make up to proper volume, and store in glass

- stoppered brown glass bottle. (2) Standard iodine solution, 1 ml=0.001771 g I. Transfer 33.7 ml of above 0.1N stock solution int o a 250 ml volumetric

1 Gas Engineers Handbook, Fuel Gas Engineering practices, The In dustrial Press, 93 Worth Street, New York, NY, 1966, First Edition, Second Printing, page 6/25 (Docket A

- 80

- 20

- A, Entry II

- I

- 67).Page 236 of 497

flask; add water to mark and mix well. Then, for 100 ml sample of gas, 1 ml of standard iodine solution is equivalent to 100 grains H2S per cubic feet of gas. (3) Starch solution. Rub into a thin paste about one teaspoonful of wheat starch with a little water; pour into about a pint of boiling water; stir; let cool and decant off clear solution. Make fresh solution every few days. (d) Procedure
. Fill leveling bulb with starch solution. Raise (L), open cock (G), open (F) to (A), and close (F) when solutions starts to run out of gas inlet. Close (G). Purge gas sampling line and connect with (A). Lower (L) and open (F) and (G). When liquid level is several ml past the 100 ml mark, close (G) and (F), and disconnect sampling tube. Open (G ) and bring starch solution to 100 ml mark by raising (L); then close (G). Open (F) momentarily, to bring gas in burette to atmospheric pressure, and close (F). Open (G), bring liquid level down to 10 ml mark by lowering (L). Close (G), clamp rubber tubing near (E) and disconnect it from burette. Rinse graduated cylinder with a standard iodine solution (0.00171 g I per ml); fill cylinder and record reading. Introduce successive small amounts of iodine thru (F); shake well after each addition; continue until a faint permanent blue color is obtained. Record reading; subtract from previous reading, and call difference D.Page 237 of 497

(e) With every fresh stock of starch solution perform a blank test as follows: Introduce fresh starch solution into burette up to 100 ml mark . Close (F) and (G). Lower (L) and open (G). When liquid level reaches the 10 ml mark, close (G). With air in burette, titrate as during a test and up to same end point. Call ml of iodine used C. Then, Grains H 2 S per 100 cubic foot of gas=100 (D

— C) (f) Gr eater sensitivity can be attained if a 500 ml capacity Tutwiler burette is used with a more dilute (0.001N) iodine solution. Concentrations less than 1.0 grains per 100 cubic foot can be determined in this way. Usually, the starch

iodine end point is much less distinct, and a blank determination of end point, with H2S

- free gas or air, is required.Page 238 of 497

Figure 1 . Tutwiler burette (lettered items mentioned in text).

§ 60.5410 How do I demonstrate initial compliance with the standards for my gas well affected facility, my centrifugal compressor affected facility, my reciprocating compressorPage 239 of 497

affected facility, my pneumatic controller affected facility, my storage vessel affected facility, and my affected facilities at onshore natural gas processing plants? You must determine initial compliance with the standards for each affected facility using the requirements in paragraphs (a) through (g) of this section. The initial compliance period begins on the [INSERT DATE OF PUBLICATION IN THE FED ERAL REGISTER] or upon initial startup, whichever is later, and ends on the date the first annual report is due as specified in §60.5420(b). (a) You have achieved initial compliance with standards for each well completion operation conducted at your gas w ell affected facility if you have complied with paragraphs (a)(1) through (a)(4) of this section. (1) You have notified the Administrator by the first of each month of the anticipated well completion operations during that month, the latitude and longitud e coordinates of the well in decimal degrees to an accuracy and precision of five (5) decimals of a degree using the North American Datum (NAD) of 1983. (2) You have notified the Administrator by email no later than four days prior to each well completion operation the actual date of the well completion operation.Page 240 of 497

(3) You have maintained a log of records as specified in §60.5375(b) or (f) for each well completion operation conducted during the initial compliance period. (4) You have submitted the initial annual report for your well affected facility as required in §60.5420(b). (b) (1) You have demonstrated initial compliance with standards for your centrifugal compressor affected facility if you have reduced VOC emissions from each centrifugal compressor wet seal fluid degassing system by 95 percent or greater as required by §60.5380. (2) If you use a control device to reduce emissions, you have equipped the wet seal fluid degassing system with a cover that is connected through a closed vent system that m eets the requirements of §60.5411 to a control device that meets the conditions specified in §60.5412. ( 3 ) You have conducted an initial performance test as required in §60.5413 within 180 days after initial startup or by [INSERT DATE OF PUBLICATION IN TH E FEDERAL REGISTER] , whichever is later, and have conducted the compliance demonstration in §60.5415(e). ( 4 ) You have conducted the initial inspections required in §60.5416. (5 ) You have installed and operated continuous parameter monitoring systems in a ccordance with §60.5417.Page 241 of 497

(c) You have achieved initial compliance with standards for each reciprocating compressor affected facility if you have complied with paragraphs (c)(1) and (c)(2) of this section. (1) During the initial compliance period, you have continuously monitored the number of hours of operation or tracked the number of months since the last rod packing replacement
. (2) You have included the cumulative number of hours of operation for your reciprocating compressor affected facility du ring the initial compliance period or the number of months since the last rod packing replacement in your initial annual report required in §60.5420(b). (d) You have achieved initial compliance with emission standards for your pneumatic controller affecte d facility if you comply with the requirements specified in paragraphs (d)(1) through (d)(5) of this section. (1) You have demonstrated, to the Administrator’s satisfaction, the use of a pneumatic controller affected facility with a bleed rate greater tha n 6 standard cubic feet of gas per hour is required as specified in §60.5490(a). (2) You own or operate a pneumatic controller affected facility located at a natural gas processing plant and your pneumatic controller is driven other than by use of natural gas and therefore emits zero natural gas.Page 242 of 497

(3) You own or operate a pneumatic controller affected facility located between the wellhead and a natural gas processing plant and the manufacturer’s design specifications indicate that the controller emits les s than or equal to 6 standard cubic feet of gas per hour. (4) You have tagged each new, reconstructed or modified pneumatic controller according to the requirements of §60.5390(c)(2). (5) You have included the information in paragraph (d)(1) of this sect ion and a listing of the pneumatic controller affected facilities specified in paragraphs (d)(2) and (d)(3) of this section in the initial annual report submitted for your pneumatic controller affected facilities installed during the period covered by the annual report according to the requirements of §60.5420(b). (e) You have demonstrated initial compliance with emission standards for your storage vessel affected facility if you have complied with paragraphs (e)(1) through (e)(6) of this section. (1) You have determined the VOC emission rate within 30 days after installation, modification or reconstruction. (2) You have determined the VOC emission rate for storage vessels at well sites one or more wells already in production upon installation, modification or reconstruction.Page 243 of 497

( 3 ) For storage vessel affected facilities emitting more than 6 tpy VOC, you have reduced VOC emissions by 95 percent or
greaer. (4) If you use a control device to reduce emissions, you have equipped the storage vessel wit h a cover that is connected through a closed vent system that meets the requirements of §60.5411 to a control device that meets the conditions specified in §§60.5412. ( 5 ) You have conducted an initial performance test as required in §60.5413 within 180 da ys after initial startup or by [INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER] , whichever is later, and have conducted the compliance demonstration in §60.5415(e). ( 6 ) You have conducted the initial inspections required in §60.5416. ( 7 ) You have ins talled and operated continuous parameter monitoring systems in accordance with §60.5417. ( 8 ) You have submitted the information in paragraphs (e)(1) through (e)( 7 ) of this section in the initial annual report for your storage vessel affected facilities i nstalled, modified or reconstructed during the period covered by the annual report as required in §60.5420(b). (f) For affected facilities at onshore natural gas processing plants, initial compliance with the VOC requirementsPage 244 of 497

is demonstrated if you are in compliance with the requirements of §60.5400. (g) For sweetening unit affected facilities at onshore natural gas processing plants, initial compliance is demonstrated according to paragraphs (g)(1) through (g)(3) of this section. (1) To determine comp liance with the standards for SO2 specified in §60.5405(a), during the initial performance test as required by §60.8, the minimum required sulfur dioxide emission reduction efficiency (Z i ) is compared to the emission reduction efficiency (R) achieved by th e sulfur recovery technology as specified in paragraphs (g)(1)(i) and (g)(1)(ii) of this section. (i) If R ≥ Z i , your affected facility is in compliance. (ii) If R < Z i , your affected facility is not in compliance. (2) The emission reduction efficiency (R) achieved by the sulfur reduction technology must be determined using the procedures in §60.5406(c)(1). (3) You have submitted the results of paragraphs (g)(1) and (g)(2) of this section in the initial annual report submitted for your sweetening unit a ffected facilities at onshore natural gas processing plants.Page 245 of 497

§60.5411 What requirements must I meet for closed vent systems routing materials from storage vessels and centrifugal compressor wet seal degassing systems ? You must meet the applicable require ments of this section for each cover and closed vent system used to demonstrate initial compliance with the emission standards for your storage vessel or centrifugal compressor affected facility. (a) Closed vent system requirements. (1) You must design th e closed vent system to route all gases, vapors, and fumes emitted from the material in the storage tank or wet seal fluid degassing system to a control device that meets the requirements specified in §60.5412. (2) You must design and operate the closed v ent system with no detectable emissions. (3) You must meet the requirements specified in paragraphs (a)(3)(i) and (a)(3)(ii) of this section if the closed vent system contains one or more bypass devices that could be used to divert all or a portion of the gases, vapors, or fumes from entering the control device. (i) Except as provided in paragraph (a)(3)(ii) of this section, you must comply with either paragraph (a)(3)(i)(A) or (a)(3)(i)(B) of this section for each bypass device. (A) You must properly in stall, calibrate, maintain, and operate a flow indicator at the inlet to the bypass device thatPage 246 of 497

could divert the stream away from the control device to the atmosphere that is capable of taking periodic readings and sounding an alarm when the bypass device is open such that the stream is being, or could be, diverted away from the control device to the atmosphere. (B) You must secure the bypass device valve installed at the inlet to the bypass device in the non

- diverting position using a car

- seal or a lock

- a nd

- key type configuration. (ii) Low leg drains, high point bleeds, analyzer vents,
open - ended valves or lines, and safety devices are not subject to the requirements of paragraph (a)(3)(i) of this section. (b) Cover requirements . (1) The cover and all op enings on the cover (e.g., access hatches, sampling ports, and gauge wells) shall be designed to form a continuous barrier over the entire surface area of the liquid in the storage vessel or wet seal fluid degassing system
. (2) Each cover opening shall be secured in a closed, sealed position (e.g., covered by a gasketed lid or cap) whenever material is in the unit on which the cover is installed except during those times when it is necessary to use an opening as follows: (i) To add material to, or remove material from the unit (this includes openings necessary to equalize or balance thePage 247 of 497

internal pressure of the unit following changes in the level of the material in the unit); (ii) To inspect or sample the material in the unit; (iii) To inspect, maintain, repair, or replace equipment located inside the unit; or (iv) To vent liquids, gases, or fumes from the unit through a closed

- vent system to a control device designed and operated in accordance with the requirements of p aragraph (a) of this section. §60.5412 What requirements must I meet for control devices used to demonstrate compliance at my storage vessel or centrifugal
compressor affected facility? You must meet the applicable requirements of this section for each co ntrol device used to demonstrate initial compliance with the emission standards for your storage vessel or centrifugal compressor affected facility. (a) You must use one of the control devices specified in paragraphs (a)(1) through (a)(3) of this sectio n and comply with the emissions reduction performance requirements for the selected control device to reduce VOC emissions in accordance with the standards of this subpart. You must demonstrate that the control device achieves the performance requirements using the performance test methods and procedures specified in §60.5413.Page 248 of 497

(1) You must design and operate an enclosed combustion device (e.g., thermal vapor incinerator, catalytic vapor incinerator, boiler, or process heater) in accordance with one of the performance requirements specified in paragraphs (a)(1)(i) through (a)(1)(iv) of this section. (i) You must reduce the mass content of VOC in the gases vented to the device by 95.0 percent by weight or greater as determined in accordance with the requirem ents of §60.5413. (ii) You must reduce the concentration of TOC in the exhaust gases at the outlet to the device to a level equal to or less than 20 parts per million by volume on a dry basis corrected to 3 percent oxygen as determined in accordance with the requirements of §60.5413. (iii) You must operate at a minimum temperature of 760°C for a control device that can demonstrate a uniform combustion zone temperature during the performance test conducted under §60.5413. (iv) If a boiler or process heate r is used as the control device, then you must introduce the vent stream into the flame zone of the boiler or process heater. (2) You must design and operate a vapor recovery device (e.g., carbon adsorption system or condenser) or other non

destructive co ntrol device to reduce the mass content of VOC in the gases vented to the device by 95.0 percent by weight orPage 249 of 497

greater as determined in accordance with the requirements of §60.5413. (3) You must design and operate a flare, as defined in §60.5430, in accord ance with the requirements of §60.18(b). (b) You must operate each control device in accordance with the requirements specified in paragraphs (b)(1) and (b)(2) of this section. (1) You must operate each control device used to comply with this subpart at all times when gases, vapors, and fumes are vented from the storage vessel or wet seal fluid degassing system affected facility through the closed vent system to the control device, as required under §60.5395. You may vent more than one unit to a control d evice used to comply with this subpart. (2) For each control device monitored in accordance with the requirements of §60.5417, you must demonstrate compliance according to the requirements of §60.5415(e), as applicable. (c) For each carbon adsorption sys tem used as a control device to meet the requirements of paragraph (a) of this section, you must manage the carbon in accordance with the requirements specified in paragraphs (c)(1) or (c)(2) of this section. (1) Following the initial startup of the contr ol device, you must replace all carbon in the control device with freshPage 250 of 497

carbon on a regular, predetermined time interval that is no longer than the carbon service life established for the carbon adsorption system. You must maintain records identifying the schedule for replacement and records of each carbon replacement as required in §63.774(b)(7)(ix). You must submit the schedule for replacement with the Notification of Compliance Status report as specified in §63.775(d)(5)(iv). Each carbon replacement must be reported in the Periodic Reports as specified in §63.772(e)(2)(xii). (2) You must either regenerate, reactivate, or burn the spent carbon removed from the carbon adsorption system in one of the units specified in paragraphs (c)(2)(i) through (c)(2)(vi i) of this section. (i) Regenerate or reactivate the spent carbon in a thermal treatment unit for which you have been issued a final permit under 40 CFR part 270 that implements the requirements of 40 CFR part 264, subpart X. (ii) Regenerate or reactivate the spent carbon in a thermal treatment unit equipped with and operating air emission controls in accordance with this section. (iii) Regenerate or reactivate the spent carbon in a thermal treatment unit equipped with and operating organic air emission controls in accordance with an emissions standard for VOC under another subpart in 40 CFR part 60 or this part.Page 251 of 497

(iv) Burn the spent carbon in a hazardous waste incinerator for which the owner or operator has been issued a final permit under 40 CF R part 270 that implements the requirements of 40 CFR part 264, subpart O. (v) Burn the spent carbon in a hazardous waste incinerator which you have designed and operated in accordance with the requirements of 40 CFR part 265, subpart O. (vi) Burn the sp ent carbon in a boiler or industrial furnace for which you have been issued a final permit under 40 CFR part 270 that implements the requirements of 40 CFR part 266, subpart H. (vii) Burn the spent carbon in a boiler or industrial furnace that you have designed and operated in accordance with the interim status requirements of 40 CFR part 266, subpart H. §60.5413 What are the performance testing procedures for control devices used to demonstrate compliance at my storage vessel or centrifugal compressor a ffected facility? This section applies to the performance testing of control devices used to demonstrate compliance with the emissions standards for your storage vessel or centrifugal compressor affected facility. You must demonstrate that a control devic e achieves the performance requirements of §60.5412(a) using the performance test methods and procedures specified in paragraph (b) of this section. For condensers, you may use a designPage 252 of 497

analysis as specified in paragraph (c) of this section in lieu of comp lying with paragraph (b) of this section. (a) Performance test exemptions . You are exempt from the requirements to conduct performance tests and design analyses if you use any of the control devices described in paragraphs (a)(1) through (7) of this sec tion. (1) A flare, as defined in §60.5430, that is designed and operated in accordance with §60.18(b). You must conduct the compliance determination using Method 22 at 40 CFR part 60, appendix A

- 7, to determine visible emissions. (2) A boiler or process heater with a design heat input capacity of 44 megawatts or greater. (3) A boiler or process heater into which the vent stream is introduced with the primary fuel or is used as the primary fuel. (4) A boiler or process heater burning hazardous waste for which you have either been issued a final permit under 40 CFR part 270 and comply with the requirements of 40 CFR part 266, subpart H; or you have certified compliance with the interim status requirements of 40 CFR part 266, subpart H. (5) A hazardous was te incinerator for which you have been issued a final permit under 40 CFR part 270 and comply with the requirements of 40 CFR part 264, subpart O; or you havePage 253 of 497

certified compliance with the interim status requirements of 40 CFR part 265, subpart O. (6) A c ontrol device for which a performance test was conducted for determining compliance with a regulation promulgated by the EPA and the test was conducted using the same methods specified in this section and either no process changes have been made since the test, or you can demonstrate that the results of the performance test, with or without adjustments, reliably demonstrate compliance despite process changes. (7) A control device that can be demonstrated to meet the performance requirements of §60.5412(a) through a performance test conducted by the manufacturer, as specified in paragraph (d) of this section. (b) Test methods and procedures . You must use the test methods and procedures specified in paragraphs (b)(1) through (b)(5) of this section, as applic able, for each performance test conducted to demonstrate that a control device meets the requirements of §60.5412(a). You must conduct the initial and periodic performance tests according to the schedule specified in paragraph (b)(5) of this section. (1) You must use Method 1 or 1A at 40 CFR part 60, appendix
A

- 1, as appropriate, to select the sampling sites specified in paragraphs (b)(1)(i) and (b)(1)(ii) of this section. AnyPage 254 of 497

references to particulate mentioned in Methods 1 and 1A do not apply to this se ction. (i) Sampling sites must be located at the inlet of the first control device, and at the outlet of the final control device, to determine compliance with the control device percent reduction requirement specified in §60.5412(a)(1)(i) or (a)(2). (ii ) The sampling site must be located at the outlet of the combustion device to determine compliance with the enclosed combustion device total TOC concentration limit specified in §60.5412(a)(1)(ii). (2) You must determine the gas volumetric flowrate using Method 2, 2A, 2C, or 2D at 40 CFR part 60, appendix A

- 2, as appropriate. (3) To determine compliance with the control device percent reduction performance requirement in §60.5412(a)(1)(i) or (a)(2), you must use Method 25A at 40 CFR part 60, appendix A

- 7. You must use the procedures in paragraphs (b)(3)(i) through (b)(3)(iv) of this section to calculate percent reduction efficiency. (i) For each run, you must take either an integrated sample or a minimum of four grab samples per hour. If grab sampling is used, then the samples must be taken at approximately equal intervals in time, such as 15

- minute intervals during the run.Page 255 of 497

(ii) You must compute the mass rate of TOC (minus methane and ethane) using the equations and procedures specified in paragraphs (b) (3)(ii)(A) and (b)(3)(ii)( B ) of this section. ( A ) You must use the following equations:

Where: E i , E o = Mass rate of TOC (minus methane and ethane) at the inlet and outlet of the control device, respectively, dry basis, kilogram per hour. K 2 = Constant, 2.494×10 − 6 (parts per million) (gram

- mole per standard cubic meter) (kilogram/gram) (minute/hour), where s tandard temperature (gram

- mole per standard cubic meter) is 20°C. C ij , C oj = Concentration of sample component j of the gas stream at the inlet and outlet of the control device, respectively, dry basis, parts per million by volume. M ij , M oj = Molecular wei ght of sample component j of the gas stream at the inlet and outlet of the control device, respectively, gram/gram

- mole. Q i , Q o = Flowrate of gas stream at the inlet and outlet of the control device, respectively, dry standard cubic meter per minute. n = N umber of components in sample. ( B ) When calculating the TOC mass rate, you must sum all organic compounds (minus methane and ethane) measured by Method 25A at 40 CFR part 60, appendix A

- 7 using Equations [insert numbers here] in of this section.Page 256 of 497

(iii) You must calculate the percent reduction in TOC (minus methane and ethane) as follows:

Where: R cd = Control efficiency of control device, percent. E i = Mass rate of TOC (minus methane and ethane) at the inlet to the control device as calculated under paragraph (b)(3)(ii) of this section, kilograms TOC per hour or kilograms HAP per hour. E o = Mass rate of TOC (minus methane and ethane) at the outlet of the control device, as calculated under paragraph (b)(3)(ii) of this sectio n, kilograms TOC per hour per hour. (iv) If the vent stream entering a boiler or process heater with a design capacity less than 44 megawatts is introduced with the combustion air or as a secondary fuel, you must determine the weight

- percent reduction of total TOC (minus methane and ethane) across the device by comparing the TOC (minus methane and ethane) in all combusted vent streams and primary and secondary fuels with the TOC (minus methane and ethane) exiting the device, respectively. (4) You must us e Method 25A at 40 CFR part 60, appendix A

- 7 to measure TOC (minus methane and ethane) to determine compliance with the enclosed combustion device total VOC concentration limit specified in §60.5412(a)(1)(ii). You must calculate parts per million by volume concentration and correct to 3 percent oxygen, using the procedures in paragraphs (b)(4)(i) through (b)(4)(iii) of this section.Page 257 of 497

(i) For each run, you must take either an integrated sample or a minimum of four grab samples per hour. If grab sampling is used, then the samples must be taken at approximately equal intervals in time, such as 15

- minute intervals during the run. (ii) You must calculate the TOC concentration for each run as follows:

Where: C TOC = Concentration of total organic compounds minus methane and ethane, dry basis, parts per million by volume. C ji = Concentration of sample component j of sample i, dry basis, parts per million by volume. n = Number of components in the sample. x = Number of samples in the sample run. (iii) You must correct the TOC concentration to 3 percent oxygen as specified in paragraphs (b)(4)(iii)(A) and (b)(4)(iii)(B) of this section. ( A ) You must use the emission rate correction factor for excess air, integrated sampling and analysis procedures of Method 3A or 3B at 40 CFR part 60, appendix A to determine the oxygen concentration. The samples must be taken during the same time that the samples are taken for determining TOC concentration. ( B ) You must correct the TOC concentra tion for percent
oxygen as follows:Page 258 of 497

Where: C c = TOC concentration corrected to 3 percent oxygen, dry basis, parts per million by volume. C m = TOC concentration, dry basis, parts per million by volume. %O 2d = Concentration of o xygen, dry basis, percent by volume. (5) You must conduct performance tests according to the schedule specified in paragraphs (b)(5)(i) and (b)(5)(ii) of this section. (i) You must conduct an initial performance test within 180 days after the compliance date that is specified for each affected source in §63.760(f)(7) through (8), except that the initial performance test for existing combustion control devices at existing major sources must be conducted [INSERT THE DATE NO LATER THAN 3 YEARS AFTER DATE OF PUBLICATION OF THE FINAL RULE
IN THE FEDERAL REGISTER] . If you choose to replace an existing combustion control device at an existing major source with a control device w hose model is tested under paragraph (d) of this section, then the newly installed device must comply with all provisions of this subpart no later than [INSERT THE DATE 3
YEARS AFTER DATE OF PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER ] . You must submit the performance test results in thePage 259 of 497

Notification of Compliance Status Report as required in §63.775(d)(1)(ii). (ii) You must conduct periodic performance tests for all control devices required to conduct initial performance tests except as specifie d in paragraphs (b)(5)(ii)(A) and (b)(5)(ii)(B) of this section. You must conduct the first periodic performance test no later than 60 months after the initial performance test required in paragraph (b)(5)(i) of this section. You must conduct subsequent pe riodic performance tests at intervals no longer than 60 months following the previous periodic performance test or whenever you desire to establish a new operating limit. You must submit the periodic performance test results in the next Periodic Report as specified in §63.775(e)(2)(xi). Combustion control devices meeting the criteria in either paragraph (b)(5)(ii)(A) or (b)(5)(ii)(B) of this section are not required to conduct periodic performance
tests. (A) A control device whose model is tested under, an d meets the criteria of paragraph (d) of this section. (B) A combustion control device tested under paragraph (b) of this section that meets the outlet TOC performance level specified in §60.5412(a)(1)(ii) and that establishes a correlation between firebo x or combustion chamber temperature and the TOC performance level.Page 260 of 497

(c) Condenser design analysis . For a condenser design analysis conducted to meet the requirements of §60.5412(a), you must meet the requirements specified in paragraphs (c)(1) and (c)(2) o f this section. You must submit documentation of the design analysis as a part of the Notification of Compliance Status Report as required in §63.775(d)(1)(i). (1) The condenser design analysis must include an analysis of the vent stream composition, cons tituent concentrations, flowrate, relative humidity, and temperature, and must establish the design outlet organic compound concentration level, design average temperature of the condenser exhaust vent stream, and the design average temperatures of the coo lant fluid at the condenser inlet and outlet . (2) If you and the Administrator do not agree on a demonstration of control device performance using a design analysis, then you must perform a performance test in accordance with the requirements of paragrap h (b) of this section to resolve the disagreement. The Administrator may choose to have an authorized representative observe the performance test. (d) Performance testing for combustion control devices

- manufacturers’ performance test . The manufacturer m ust demonstrate that a specific model of combustion control device achieves the performance requirements in paragraph (d)(1) of this section by conducting a performance test as specified inPage 261 of 497

paragraphs (d)(2) through (d)(8) of this section. You must submit a test report for each combustion control device in accordance with the requirements in paragraphs (d)(9) of this section. (1) The manufacturer must meet the performance test criteria in paragraphs (d)(1)(i) through (d)(1)(iii) of this section. (i) The c ontrol device model tested must meet the emission levels in paragraphs (d)(1)(i)(A) through (d)(1)(i)(C) of this section. (A) Method 22 at 40 CFR part 60, appendix A

- 7, results under paragraph (d)(6)(iv) of this section with no indication of visible emiss ions. (B) Average Method 25A at 40 CFR part 60, appendix A

- 7, results under paragraph (d)(8) of this section equal to or less than 10.0 parts per million by volume

- wet THC as propane corrected to 3.0 percent carbon dioxide, and (C) Average carbon monoxi de emissions determined under paragraph (d)(6)(iii) of this section equal to or less than 10 parts per million by volume

- dry, corrected to 3.0 percent carbon dioxide. (ii) The manufacturer must determine a maximum inlet gas flow rate, which must not be ex ceeded for each control devicePage 262 of 497

model to achieve the criteria in paragraph (d)(1)(i) of this section. (iii) A control device meeting the emission levels in paragraph (d)(1)(i)(A) through (d)(1)(i)(C) of this section must demonstrate a destruction efficienc y of 95.0 percent for VOC regulated under this subpart. (2) Performance testing must consist of three one

- hour (or longer) test runs for each of the four firing rate settings in paragraphs (d)(2)(i) through (d)(2)(iv) of this section, making a total of 12 test runs per test. The manufacturer must use propene (propylene) gas for the testing fuel. An independent third

- party laboratory (not affiliated with the control device manufacturer or fuel supplier) must perform all fuel analyses. (i) 90

- 100 percent of maximum design rate (fixed rate). (ii) 70

- 100

- 70 percent (ramp up, ramp down). Begin the test at 70 percent of the maximum design rate. Within the first 5 minutes, ramp up the firing rate to 100 percent of the maximum design rate. Hold at 100 perce nt for 5 minutes. In the 10

- 15 minute time range, ramp back down to 70 percent of the maximum design rate. Repeat three more times for a total of 60 minutes of sampling. (iii) 30

- 70

- 30 percent (ramp up, ramp down). Begin the test at 30 percent of the maximum design rate. Within the first 5 minutes, ramp up the firing rate to 70 percent of the maximumPage 263 of 497

design rate. Hold at 70 percent for 5 minutes. In the 10

- 15 minute time range, ramp back down to 30 percent of the maximum design rate. Repeat three more times for a total of 60 minutes of sampling. (iv) 0

- 30

- 0 percent (ramp up, ramp down). Begin the test at 0 percent of the maximum design rate. Within the first 5 minutes, ramp up the firing rate to 100 percent of the maximum design rate. Hold at 30 pe rcent for 5 minutes. In the 10

- 15 minute time range, ramp back down to 0 percent of the maximum design rate. Repeat three more times for a total of 60 minutes of sampling. (3) The manufacturer must test all models employing multiple enclosures simultaneou sly and with all burners operational. The manufacturer must report results for each enclosure individually and for the average of the emissions from all interconnected combustion enclosures/chambers. Control device operating data must be collected continuo usly throughout the performance test using an electronic Data Acquisition System and strip chart. The manufacturer must submit data with the test report in accordance with paragraph (d)(9) of this section. (4) The manufacturer must conduct inlet testing as specified in paragraphs (d)(4)(i) through (d)(4)(iii) of this section.Page 264 of 497

(i) The fuel flow metering system must be located in accordance with Method 2A at 40 CFR part 60, appendix A

- 1, (or other approved procedure) to measure fuel flow rate at the
contro l device inlet location. You must position the fitting for filling fuel sample containers a minimum of eight pipe diameters upstream of any inlet fuel flow monitoring meter. (ii) The manufacturer must determine the inlet flow rate using Method 2A at 40 CF R part 60, appendix A

- 1. Record the start and stop reading for each 60

- minute THC test. Record the gas pressure and temperature at 5

- minute intervals throughout each 60

- minute THC test. (iii) The manufacturer must conduct inlet fuel sampling in accordance with the criteria in paragraph (d)(5) of this section. (5) The manufacturer must conduct inlet fuel sampling as specified in paragraphs (d)(5)(i) and (d)(5)(ii) of this section. (i) At the inlet fuel sampling location, the manufacturer must securely con nect a Silonite

- coated stainless steel evacuated canister fitted with a flow controller sufficient to fill the canister over a 1 hour period. Filling must be conducted as specified in paragraphs (d)(5)(i)(A) through (d)(5)(i)(C) of this section.Page 265 of 497

(A) Open the canister sampling valve at the beginning of the total hydrocarbon test, and close the canister at the end of the total hydrocarbon test. (B) Fill one canister for each total hydrocarbon test run. (C) Label the canisters individually and record on a chain of custody form. (ii) The manufacturer must analyze each fuel sample using the methods in paragraphs (d)(5)(ii)(A) through (d)(5)(ii)(D) of this section. You must include the results in the test report in paragraph (d)(9) of this section. (A) Hydro carbon compounds containing between one and five atoms of carbon plus benzene using ASTM D1945

- 03. (B) Hydrogen (H 2 ), carbon monoxide (CO), carbon dioxide (CO 2 ), nitrogen (N 2 ), oxygen (O 2 ) using ASTM D1945

- 03. (C) Carbonyl sulfide, carbon disulfide plus mercaptans using ASTM D5504. (D) Higher heating value using ASTM D3588

- 98 or ASTM D4891

- 89. (6) The manufacturer must conduct outlet testing in accordance with the criteria in paragraphs (d)(6)(i) through (d)(6)(iv) and (d)(7) of this section. (i) The m anufacturer must sample and measure flowrate in accordance with the following:Page 266 of 497

(A) The manufacturer must position the outlet sampling location a minimum of four equivalent stack diameters downstream from the highest peak flame or any other flow disturbanc e, and a minimum of one equivalent stack diameter upstream of the exit or any other flow disturbance. A minimum of two sample ports must be used. (B) The manufacturer must measure flow rate using Method 1 at 40 CFR part 60, appendix A

- 1 for determining f low measurement traverse point location, and Method 2 at 40 CFR part 60, appendix A

- 1 for measuring duct velocity. If low flow conditions are encountered (i.e., velocity pressure differentials less than 0.05 inches of water) during the performance test, a more sensitive manometer must be used to obtain an accurate flow profile. (ii) The manufacturer must determine molecular weight as specified in paragraph (d)(7) of this section. (iii) The manufacturer must determine carbon monoxide using Method 10 at 4 0 CFR part 60, appendix A

- 4. The manufacturer must run the test at the same time and with the sample points used for the Method 25A at 40 CFR part 60, appendix A

- 7, testing. An instrument range of 0

- 10 per million by volume

- dry (ppmvd) must be used. (iv) The manufacturer must determine visible emissions using Method 22 at 40 CFR part 60, appendix A

- 7. The test mustPage 267 of 497

be performed continuously during each test run. A digital color photograph of the exhaust point, taken from the position of the observer and an notated with date and time, will be taken once per test run and the four photos included in the test report. (7) The manufacturer must determine molecular weight as specified in paragraphs (d)(7)(i) and (d)(7)(ii) of this section. (i) The manufacturer mu st collect an integrated bag sample during the Method 4 at 40 CFR part 60, appendix A

- 3, moisture test. The manufacturer must analyze the bag sample using a gas chromatograph

- thermal conductivity detector (GC

- TCD) analysis meeting the criteria in paragraph s (d)(7)(i)(A) through (d)(7)(i)(D) of this section. (A) Collect the integrated sample throughout the entire test, and collect representative volumes from each traverse location. (B) Purge the sampling line with stack gas before opening the valve and beginning to fill the bag. (C) Knead or otherwise vigorously mix the bag contents prior to the gas chromatograph analysis. (D) Modify the gas chromatograph

- thermal conductivity detector calibration procedure in Method 3C at 40 CFR part 60, appendix A

- 2 by using EPA Alt

- 045 as follows: For the initial calibration, triplicate injections of any single concentrationPage 268 of 497

must agree within 5 percent of their mean to be valid. The calibration respon se factor for a single concentration re

- check must be within 10 percent of the original calibration response factor for that concentration. If this criterion is not met, repeat the initial calibration using at least three concentration levels. (ii) The ma nufacturer must report the molecular weight of oxygen, carbon dioxide, methane, and nitrogen and include in the test report submitted under §63.775(d)(iii). The manufacturer must determine moisture using Method 4 at 40 CFR part 60, appendix A

- 3. Traverse b oth ports with the Method 4 at 40 CFR part 60, appendix A

- 3, sampling train during each test run. The manufacturer must not introduce ambient air into the Method 3C at 40 CFR part 60, appendix A

- 2, integrated bag sample during the port change. (8) The man ufacturer must determine total hydrocarbons as specified by the criteria in paragraphs (d)(8)(i) through (d)(8)(vii) of this section. (i) Conduct THC sampling using Method 25A at 40 CFR part 60, appendix A

- 7, except the option for locating the probe in th e center 10 percent of the stack is not allowed. The THC probe must be traversed to 16.7 percent, 50 percent, and 83.3 percent of the stack diameter during the testing.Page 269 of 497

(ii) A valid test must consist of three Method 25A at 40 CFR part 60, appendix A

- 7, te sts, each no less than 60 minutes in duration. (iii) A 0

- 10 parts per million by volume

- wet (ppmvw) (as propane) measurement range is preferred; as an alternative a 0

- 30 ppmvw (as carbon) measurement range may be used. (iv) Calibration gases will be prop ane in air and be certified through EPA Protocol 1

– “EPA Traceability Protocol for Assay and Certification of Gaseous Calibration Standards,” September 1997, as amended August 25, 1999, EPA

– 600/R

– 97/121. (v) THC measurements must be reported in terms of ppmvw as propane. (vi) THC results must be corrected to 3 percent CO2, as measured by Method 3C at 40 CFR part 60, appendix A

- 2. (vii) Subtraction of methane/ethane from the THC data is not allowed in determining results. (9) For each combustion control device model tested by the manufacturer under this section, you must submit the information listed in paragraphs (d)(9)(i) through (d)(9)(vi) of this section in the test report required under §63.775(d)(1)(iii). (i) A full schematic of the control device and dimensions of the device components. (ii) The design net heating value (minimum and maximum) of the device.Page 270 of 497

(iii) The test fuel gas flow range (in both mass and volume). Include the minimum and maximum allowable inlet gas flow rate. (iv) The air/st ream injection/assist ranges, if used. (v) The test parameter ranges listed in paragraphs (d)(9)(v)(A) through (O) of this section, as applicable for the tested model. (A) Fuel gas delivery pressure and temperature. (B) Fuel gas moisture range. (C) Pu rge gas usage range. (D) Condensate (liquid fuel) separation range. (E) Combustion zone temperature range. This is required for all devices that measure this parameter. (F) Excess combustion air range. (G) Flame arrestor(s). (H) Burner manifold pressu re. (I) Pilot flame sensor. (J) Pilot flame design fuel and fuel usage. (K) Tip velocity range. (L) Momentum flux ratio. (M) Exit temperature range. (N) Exit flow rate. (O) Wind velocity and direction.Page 271 of 497

(vi) You must include all calibration quality assurance/quality control data, calibration gas values, gas cylinder certification, and strip charts annotated with test times and calibration values in the test report. §60.5415 How do I demonstrate continuous compliance with the standards for my gas well affected facility, my centrifugal compressor affected facility, my stationary reciprocating compressor affected facility, my pneumatic controller affected facility, my storage vessel affected facility, and my affected facilities at onshore natural gas pro cessing plants? (a) For each gas well affected facility, you must demonstrate continuous compliance by maintaining the records for each completion operation (as defined in §60.5430) specified in §60.5420. (b) For each centrifugal compressor affected fac ility, you have demonstrated continuous compliance according to paragraphs (b)(1) and (b)(2) of this section. (1) C ontinuous compliance is demonstrated if the VOC emissions from the wet seal fluid degassing system are reduced by 95 percent or greater. (2 ) If you use a control device to reduce emissions, you must demonstrate continuous compliance according to paragraphs (e)(2)(i) through (e)(2)(viii) of this section.Page 272 of 497

(c) For each reciprocating compressor affected facility, you have demonstrated continuous compliance according to paragraphs (c)(1) and (2) of this section
. (1) You have continuously monitored the number of hours of operation for each reciprocating compressor affected facility or tracked the number of months since initial startup, or [INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER] , or the date of the previous reciprocating compressor rod packing replacement, whichever is later. The cumulative number of hours of operation or number of months since the previous rod packing replacement
must be included in the annual report as required in §60.5420(b)(4). (2) You have replaced the reciprocating compressor rod packing before the total number of hours of operation reaches 26,000 hours or the number of months since the previous rod packing replac ement reaches 36 months
. (d) For each pneumatic controller affected facility, continuous compliance is demonstrated by maintaining the records demonstrating that you have installed and operated the pneumatic controllers as required in §60.5390(a), (b) or (c). (e) For each storage vessel affected facility for which the VOC emissions are greater than 6 tpy, you have demonstrated continuous compliance according to paragraphs (e)(1) and (e)(2) of this section.Page 273 of 497

(1) Continuous compliance is demonstrated if the VOC emissions from each storage vessel are reduced by 95 percent or greater. (2) If you use a control device to reduce VOC emissions, you must demonstrate continuous compliance with the performance requirements of §60.5412(a)(2) using the procedure speci fied in paragraphs (e)( 2 ) (i) through (e)( 2 ) (viii) of this section. If you use a condenser as the control device to achieve the requirements specified in §60.5412(a)(2), you may demonstrate compliance according to paragraph (e)( 2 ) (viii) of this section.
You may switch between compliance with paragraphs (e)( 2 ) (i) through (e)( 2 ) (vii) of this section and compliance with paragraph (e)( 2 ) (viii) of this section only after at least 1 year of operation in compliance with the selected approach. You must provide notification of such a change in the compliance method in the next Periodic Report, as required in § 60.5420(b) , following the change. ( i ) Y ou must establish a site specific maximum or minimum monitoring parameter value (as appropriate) according to the requirements of §60.5417(f)(1). ( ii ) You must calculate the daily average of the applicable monitored parameter in accordance with §60.5417(e ) except that the inlet gas flow rate to the control device must not be averaged.Page 274 of 497

( iii ) Compliance with the operating parameter limit is achieved when the daily average of the monitoring parameter value calculated under paragraph (e)(2) (ii) of this sectio n is either equal to or greater than the minimum monitoring value or equal to or less than the maximum monitoring value established under paragraph (e)( 2 ) (i) of this section. When performance testing of a combustion control device is conducted by the devic e manufacturer as specified in §60.5413(d), compliance with the operating parameter limit is achieved when the inlet gas flow rate is equal to or less than the value established under §60.5413(d)(1)(ii). ( iv ) You must operate the continuous monitoring sys tem required in §60.5417 at all times the affected source is operating, except for periods of monitoring system malfunctions, repairs associated with monitoring system malfunctions, and required monitoring system quality assurance or quality control activi ties (including, as applicable, system accuracy audits and required zero and span adjustments). A monitoring system malfunction is any sudden, infrequent, not reasonably preventable failure of the monitoring system to provide valid data. Monitoring system failures that are caused in part by poor maintenance or careless operation are not malfunctions. You are required to complete monitoring system repairs in response toPage 275 of 497

monitoring system malfunctions and to return the monitoring system to operation as expedi tiously as practicable. ( v ) You may not use data recorded during monitoring system malfunctions, repairs associated with monitoring system malfunctions, or required monitoring system quality assurance or control activities in calculations used to report e missions or operating levels. You must use all the data collected during all other required data collection periods to assess the operation of the control device and associated control system. ( vi ) Failure to collect required data is a deviation of the monitoring requirements, except for periods of monitoring system malfunctions, repairs associated with monitoring system malfunctions, and required quality monitoring system quality assurance or quality control activities (including, as applicable, system accuracy audits and required zero and span adjustments). ( vii ) If you use a combustion control device to meet the requirements of §60.5412(a), you must demonstrate compliance by installing a device tested under the provisions in §60.5413(d) and complying with the criteria in paragraphs (e)(2)(vii)(A) through (e)(2)(vii)(D) of this section. ( A ) The inlet gas flow rate must meet the range specified by the manufacturer. You must measure the flow rate as specified in §60.5417(d)(1)(viii)(A).Page 276 of 497

( B ) A pilot flam e must be present at all times of operation. You must monitor the pilot flame in accordance with §60.5417(d)(1)(viii)(B). ( C ) You must operate the combustion control device with no visible emissions, except for periods not to exceed a total of 5 minutes during any 2 consecutive hours. You must perform a visible emissions test using Method 22 at 40 CFR part 60, appendix A

- 7 mont hly. The observation period must be 2 hours and must follow Method 22. ( D ) Compliance with the operating parameter limit is achieved when the criteria in paragraphs (e)(2)(vii)(D)( 1 ) through (e)(2)(vii)(D)( 6 ) are met. ( 1 ) The inlet gas flow rate monitored under paragraph (e)(2)(vii)(A) of this section is equal to or below the maximum established by the manufacturer. ( 2 ) The pilot flame is present at all times; and ( 3 ) During the visible emissions test performed under
pa ragraph (e)(2)(vii)(C) of this section, the duration of visible emissions does not exceed a total of 5 minutes during the observation period. Devices failing the visible emissions test must follow the requirements in paragraphs (e)(2)(vii)(D)( 4 ) and (e)(2 )(vii)(D)( 5 ) of this section. ( 4 ) Following the first failure, you must replace the fuel nozzle(s) and burner tubes.Page 277 of 497

( 5 ) If, following replacement of the fuel nozzle(s) and burner tubes as specified in paragraph (e)(2)(vii)(D)( 4 ) of this section, the vi sible emissions test is not passed in the next scheduled test, you must either conduct a performance test as specified in §60.5413, or replace the device with another control device whose model was tested and meets the requirements in §60.5413(d). ( viii ) If you use a condenser as the control device to achieve the percent reduction performance requirements specified in §60.5412(a)(2), you must demonstrate compliance using the procedures in paragraphs (e)(2)(viii)(A) through (e)(2)(viii)(E) of this section. ( A ) You must establish a site

- specific condenser performance curve according to §60.5417(f)(2). ( B ) You must calculate the daily average condenser outlet temperature in accordance with §60.5417(e). ( C ) You must determine the condenser efficiency for the current operating day using the daily average condenser outlet temperature calculated under paragraph (e)(2)(viii)(B) of this section and the condenser performance curve established under paragraph (e)( 2)(viii)(A) of this section. ( D ) Except as provided in paragraphs (e)(2)(viii)( D)( 1 ) and (e)(2)(viii)(D)( 2 ) of this section, at the end of each operating day, you must calculate the 365

- day average TOC emissionPage 278 of 497

reduction, as appropriate, from the condens er efficiencies as determined in paragraph (e)(2)(viii)(C) of this section for the preceding 365 operating days. ( 1 ) After the compliance dates specified in §63.760(f), if you have less than 120 days of data for determining average TOC emission reduction , you must calculate the average TOC emission reduction for the first 120 days of operation after the compliance dates. You have demonstrated compliance with the overall 95.0 percent reduction requirement if the 120

- day average TOC emission reduction is eq ual to or greater than 90.0 percent. ( 2 ) After 120 days and no more than 364 days of operation after the compliance dates specified in §63.760(f), you must calculate the average TOC emission reduction as the TOC emission reduction averaged over the numbe r of days between the current day and the applicable compliance date. You have demonstrated compliance with the overall 95.0 percent reduction requirement, if the average TOC emission reduction is equal to or greater than 90.0 percent. ( E ) If you have d ata for 365 days or more of operation, you have demonstrated compliance with the TOC emission reduction specified in §60.5412(a)(2) if the average TOC emission reduction calculated in paragraph (e)(2)(viii)(D) of this section is equal to or greater than 95 .0 percent.Page 279 of 497

(f) For affected facilities at onshore natural gas processing plants, continuous compliance with VOC requirements is demonstrated if you are in compliance with the requirements of §60.5400. (g) For each sweetening unit affected facility at on shore natural gas processing plants, you must demonstrate continuous compliance with the standards for SO 2 specified in §60.5405(b) according to paragraphs (g)(1) and (g)(2) of this section. (1) The minimum required SO2 emission reduction efficiency (Z c ) is compared to the emission reduction efficiency (R) achieved by the sulfur recovery technology. (i) If R ≥ Z c , your affected facility is in compliance. (ii) If R < Z c , your affected facility is not in compliance. (2) The emission reduction efficiency (R) achieved by the sulfur reduction technology must be determined using the procedures in §60.5406(c)(1). (h) Affirmative defense for exceedance of emission limit during malfunction . In response to an action to enforce the standards set forth in §§60.537 5, 60.5380, 60.5385, 60.5390, 60.5395, 60.5400, and 60.5405, you may assert an affirmative defense to a claim for civil penalties for violations of such standards that are caused by malfunction, as defined at §60.2. Appropriate penalties may be assessed, h owever, if you fail to meet your burden of proving all of the requirements in thePage 280 of 497

affirmative defense. The affirmative defense shall not be available for claims for injunctive relief. (1) To establish the affirmative defense in any action to enforce such a standard , you must timely meet the notification requirements in §60.5420(a), and must prove by a preponderance of evidence that: (i) The violation : (A) Was caused by a sudden, infrequent, and unavoidable failure of air pollution control and monitoring equipment, process equipment, or a process to operate in a normal or usual

manner ; and (B) Could not have been prevented through careful planning, proper design or better operation and maintenance practices; and (C) Did not stem from any activity or ev ent that could have been foreseen and avoided, or planned for; and (D) Were not part of a recurring pattern indicative of inadequate design, operation, or maintenance; and (ii) Repairs were made as expeditiously as possible when a violation occurred
. Off

- shift and overtime labor were used, to the extent practicable to make these repairs; and (iii) The frequency, amount and duration of the violation (including any bypass) were minimized to the maximum extent practicable; andPage 281 of 497

(iv) If the violation resu lted from a bypass of control equipment or a process, then the bypass was unavoidable to prevent loss of life, personal injury, or severe property damage; and (v) All possible steps were taken to minimize the impact of the violation on ambient air quality , the environment and human health; and (vi) All emissions monitoring and control systems were kept in operation if at all possible, consistent with safety and good air pollution control practices; and (vii) All of the actions in response to the violatio n were documented by properly signed, contemporaneous operating logs; and (viii) At all times, the affected source was operated in a manner consistent with good practices for minimizing emissions; and (ix) A written root cause analysis has been prepared, the purpose of which is to determine, correct, and eliminate the primary causes of the malfunction and the violation resulting from the malfunction event at issue. The analysis shall also specify, using best monitoring methods and engineering judgment, th e amount of any emissions that were the result of the malfunction.Page 282 of 497

(2) Report. The owner or operator seeking to assert an affirmative defense shall submit a written report to the Administrator in a semiannual report with all necessary supporting document ation, that it has met the requirements set forth in paragraph (h)(1) of this section. §60.5416 What are the initial and continuous cover and closed vent system inspection and monitoring requirements for my storage vessel and centrifugal compressor affected facility? For each closed vent system or cover at your storage vessel or centrifugal compressor affected facility, you must comply with the requirements of paragraphs (a) through (g) of this section. (a) Inspections . Except as provided in paragr aphs (e) and (f) of this section, you must inspect each closed vent system according to the procedures and schedule specified in paragraphs (a)(1) and (a)(2) of this section, inspect each cover according to the procedures and schedule specified in paragrap h (a)(3) of this section, and inspect each bypass device according to the procedures of paragraph (a)(4) of this section. (1) For each closed vent system joint, seam, or other connection that is permanently or semi

- permanently sealed (e.g., a welded joint between two sections of hard piping or a bolted and gasketed ducting flange), you must meet the requirementsPage 283 of 497

specified in paragraphs (a)(1)(i) and (a)(1)(ii) of this section. (i) Conduct an initial inspection according to the test methods and procedures specified in paragraph (b) of this section to demonstrate that the closed vent system operates with no detectable emissions. You must submit the inspection results with the Notification of Compliance Status Report as specified in §63.775(d)(1) or (2). (ii ) Conduct annual visual inspections for defects that could result in air emissions. Defects include, but are not limited to, visible cracks, holes, or gaps in piping; loose connections; or broken or missing caps or other closure devices. You must monitor a component or connection using the test methods and procedures in paragraph (b) of this section to demonstrate that it operates with no detectable emissions following any time the component is repaired or replaced or the connection is unsealed. You must su bmit the inspection results in the Periodic Report as specified in §63.775(e)(2)(iii). (2) For closed vent system components other than those specified in paragraph (a)(1) of this section, you must meet the requirements of paragraphs (a)(2)(i) through (a) (2)(iii) of this section. (i) Conduct an initial inspection according to the test methods and procedures specified in paragraph (b) of thisPage 284 of 497

section to demonstrate that the closed vent system operates with no detectable emissions. You must submit the inspe ction results with the Notification of Compliance Status Report as specified in §63.775(d)(1) or (2). (ii) Conduct annual inspections according to the test methods and procedures specified in paragraph (b) of this section to demonstrate that the component s or connections operate with no detectable emissions. You must submit the inspection results in the Periodic Report as specified in §63.775(e)(2)(iii). (iii) Conduct annual visual inspections for defects that could result in air emissions. Defects includ e, but are not limited to, visible cracks, holes, or gaps in ductwork; loose connections; or broken or missing caps or other closure devices. You must submit the inspection results in the Periodic Report as specified in §63.775(e)(2)(iii). (3) For each co ver, you must meet the requirements in paragraphs (a)(3)(i) and (a)(3)(ii) of this section. (i) Conduct visual inspections for defects that could result in air emissions. Defects include, but are not limited to, visible cracks, holes, or gaps in the cover , or between the cover and the separator wall; broken, cracked, or otherwise damaged seals or gaskets on closure devices; and broken or missing hatches, access covers, caps, or other closure devices.Page 285 of 497

In the case where the storage vessel is buried partially or entirely underground, you must inspect only those portions of the cover that extend to or above the ground surface, and those connections that are on such portions of the cover (e.g., fill ports, access hatches, gauge wells, etc.) and can be opened to the atmosphere. (ii) You must initially conduct the inspections specified in paragraph (a)(3)(i) of this section following the installation of the cover. You must submit the inspection results with the Notification of Compliance Status Report as specified in §63.775(d)(12). Thereafter, you must perform the inspection at least once every calendar year, except as provided in paragraphs (e) and (f) of this section. You must submit annual inspection results in the Periodic Report as specified in §63.775(e)(2)( iii). (4) For each bypass device, except as provided for in §63.5411, you must meet the requirements of paragraphs (a)(4)(i) or (a)(4)(ii) of this section. (i) Set the flow indicator to take a reading at least once every 15 minutes at the inlet to the by pass device that could divert the steam away from the control device to the atmosphere. (ii) If the bypass device valve installed at the inlet to the bypass device is secured in the non

- diverting position using

a car - seal or a lock

- and

- key type configurat ion, visuallyPage 286 of 497

inspect the seal or closure mechanism at least once every month to verify that the valve is maintained in the non

- diverting position and the vent stream is not diverted through the bypass device. (b) No detectable emissions test methods and procedures . If you are required to conduct an inspection of a closed vent system or cover at your storage vessel or centrifugal compressor affected facility as specified in paragraphs (a)(1), (a)(2), or (a)(3) of this section, you must meet the requirement s of paragraphs (b)(1) through (b)(8) of this section. (1) You must conduct the no detectable emissions test procedure in accordance with Method 21 at 40 CFR part 60, appendix A

- 7. (2) The detection instrument must meet the performance criteria of Method 21 at 40 CFR part 60, appendix A

- 7, except that the instrument response factor criteria in section 3.1.2(a) of Method 21 must be for the average composition of the fluid and not for each individual organic compound in the stream. (3) You must calibrate the detection instrument before use on each day of its use by the procedures specified in Method 21 at 40 CFR part 60, appendix A

- 7. (4) Calibration gases must be as specified in paragraphs (b)(4)(i) and (b)(4)(ii) of this section.Page 287 of 497

(i) Zero air (less tha n 10 parts per million by volume hydrocarbon in air). (ii) A mixture of methane in air at a concentration less than 10,000 parts per million by volume. (5) You may choose to adjust or not adjust the detection instrument readings to account for the backgr ound organic concentration level. If you choose to adjust the instrument readings for the background level, you must determine the background level value according to the procedures in Method 21 at 40 CFR part 60, appendix A

- 7. (6) Your detection instrume nt must meet the performance criteria specified in paragraphs (b)(6)(i) and (b)(6)(ii) of this section. (i) Except as provided in paragraph (b)(6)(ii) of this section, the detection instrument must meet the performance criteria of Method 21 at 40 CFR part 60, appendix A

- 7, except the instrument response factor criteria in section 3.1.2(a) of Method 21 must be for the average composition of the process fluid, not each individual volatile organic compound in the stream. For process streams that contain nitro gen, air, or other inerts that are not organic hazardous air pollutants or volatile organic compounds, you must calculate the average stream response factor on an inert

- free basis.Page 288 of 497

(ii) If no instrument is available that will meet the performance criteria specified in paragraph (b)(6)(i) of this section, you may adjust the instrument readings by multiplying by the average response factor of the process fluid, calculated on an inert

- free basis, as described in paragraph (b)(6)(i) of this section. (7) You m ust determine if a potential leak interface operates with no detectable emissions using the applicable procedure specified in paragraph (b)(7)(i) or (b)(7)(ii) of this section. (i) If you choose not to adjust the detection instrument readings for the back ground organic concentration level, then you must directly compare the maximum organic concentration value measured by the detection instrument to the applicable value for the potential leak interface as specified in paragraph (b)(8) of this section. (ii) If you choose to adjust the detection instrument readings for the background organic concentration level, you must compare the value of the arithmetic difference between the maximum organic concentration value measured by the instrument and the background organic concentration value as determined in paragraph (b)(5) of this section with the applicable value for the potential leak interface as specified in paragraph (b)(8) of this section.Page 289 of 497

(8) A potential leak interface is determined to operate with no det ectable organic emissions if the organic concentration value determined in paragraph (b)(7) of this section is less than 500 parts per million by volume. (c) Repairs . In the event that a leak or defect is detected, you must repair the leak or defect as so on as practicable according to the requirements of paragraphs (c)(1) and (c)(2) of this section, except as provided in paragraph (d) of this section. (1) A first attempt at repair must be made no later than 5 calendar days after the leak is detected. (2) Repair must be completed no later than 15 calendar days after the leak is detected. (d) Delay of repair . Delay of repair of a closed vent system or cover for which leaks or defects have been detected is allowed if the repair is technically infeasible wit hout a shutdown, as defined in §60.5430, or if you determine that emissions resulting from immediate repair would be greater than the fugitive emissions likely to result from delay of repair. You must complete repair of such equipment by the end of the

nex t shutdown. (e) Unsafe to inspect requirements . You may designate any parts of the closed vent system or cover as unsafe to inspect if the requirements in paragraphs (e)(1) and (e)(2) of this sectionPage 290 of 497

are met. Unsafe to inspect parts are exempt from the in spection requirements of paragraphs (a)(1) through (a)(3) of this section. (1) You determine that the equipment is unsafe to inspect because inspecting personnel would be exposed to an imminent or potential danger as a consequence of complying with paragr aphs (a)(1), (a)(2), or (a)(3) of this section. (2) You have a written plan that requires inspection of the equipment as frequently as practicable during safe

- to

- inspect times. (f) Difficult to inspect requirements . You may designate any parts of the clo sed vent system or cover as difficult to inspect, if the requirements in paragraphs (f)(1) and (f)(2) of this section are met. Difficult to inspect parts are exempt from the inspection requirements of paragraphs (a)(1) through (a)(3) of this section.: (1) You determine that the equipment cannot be inspected without elevating the inspecting personnel more than 2 meters above a support surface. (2) You have a written plan that requires inspection of the equipment at least once every 5 years. (g) Records . R ecords shall be maintained as specified in §63.774(b)(5) through (8).Page 291 of 497

§60.5417 What are the continuous control device monitoring requirements for my storage vessel or centrifugal compressor affected facility? You must meet the applicable requirements of this section for each control device used to demonstrate continuous compliance with the emission standards for your storage vessel or centrifugal compressor affected facility. (a) You must install and operate a continuous parameter monitoring system for each control device as specified in paragraphs (c) through (j) of this section, except as provided for in paragraph (b) of this section. If you install and operate a flare in accordance with §60.5412(a)(3), you are exempt from the requirements of paragraphs (e) and (f) of this section. (b) You are exempt from the monitoring requirements specified in paragraphs (c) through (j) of this section for the control devices listed in paragraphs (b)(1) and (b)(2) of this section. (1) A boiler or process heater in which all vent streams are introduced with the primary fuel or is used as the primary fuel. (2) A boiler or process heater with a design heat input capacity equal to or greater than 44 megawatts. (c) You must design and operate the continuous monitoring system so that a determination can be made on whether thePage 292 of 497

control device is achieving the applicable performance requirements of §60.5412. For each continuous parameter monitoring system, you must m eet the specifications and requirements in paragraphs (c)(1) through (c)(4) of this section. (1) Each continuous parameter monitoring system must measure data values at least once every hour and record the parameters in paragraphs (c)(1)(i) or (c)(1)(ii) of this section. (i) Each measured data value. (ii) Each block average value for each 1

- hour period or shorter periods calculated from all measured data values during each period. If values are measured more frequently than once per minute, a single valu e for each minute may be used to calculate the hourly (or shorter period) block average instead of all measured values. (2) You must prepare a site

- specific monitoring plan that addresses the monitoring system design, data collection, and the quality assu rance and quality control elements outlined in paragraphs (c)(2)(i) through (c)(2)(v) of this section and in §63.8(d). You must install, calibrate, operate, and maintain each continuous parameter monitoring system in accordance with the procedures in your approved site

- specific monitoring plan. Using the process described in §63.8(f)(4), you may requestPage 293 of 497

approval of monitoring system quality assurance and quality control procedures alternative to those specified in paragraphs (c)(2)(i) through (v) of this se ction in your site

- specific monitoring plan. (i) The performance criteria and design specifications for the monitoring system equipment, including the sample interface, detector signal analyzer, and data acquisition and calculations. (ii) Sampling interf ace (e.g., thermocouple) location such that the monitoring system will provide representative
measurements. (iii) Equipment performance checks, system accuracy audits, or other audit procedures. (iv) Ongoing operation and maintenance procedures in

accor dance with provisions in §63.8(c)(1) and (c)(3). (v) Ongoing reporting and recordkeeping procedures in accordance with provisions in §63.10(c), (e)(1), and (e)(2)(i). (3) You must conduct the continuous parameter monitoring system equipment performance c hecks, system accuracy audits, or other audit procedures specified in the site

- specific monitoring plan at least once every 12 months. (4) You must conduct a performance evaluation of each continuous parameter monitoring system in accordance with the site

- specific monitoring plan.Page 294 of 497

(d) You must install, calibrate, operate, and maintain a device equipped with a continuous recorder to measure the values of operating parameters appropriate for the control device as specified in either paragraph (d)(1), (d)(2) , or (d)(3) of this section. (1) A continuous monitoring system that measures the operating parameters in paragraphs (d)(1)(i) through (d)(1)(viii) of this section, as applicable. (i) For a thermal vapor incinerator that demonstrates during the performan ce test conducted under §60.5413 that combustion zone temperature is an accurate indicator of performance, a temperature monitoring device equipped with a continuous recorder. The monitoring device must have a minimum accuracy of ±1 percent of the temperat ure being monitored in °C, or ±2.5 °C, whichever value is greater. You must install the temperature sensor at a location representative of the combustion zone temperature. (ii) For a catalytic vapor incinerator, a temperature monitoring device equipped wi th a continuous recorder. The device must be capable of monitoring temperature at two locations and have a minimum accuracy of ±1 percent of the temperature being monitored in °C, or ±2.5 °C, whichever value is greater. You must install one temperature sen sor in the vent stream at the nearest feasible point to the catalyst bed inlet,Page 295 of 497

and you must install a second temperature sensor in the vent stream at the nearest feasible point to the catalyst bed outlet. (iii) For a flare, a heat sensing monitoring devi ce equipped with a continuous recorder that indicates the continuous ignition of the pilot flame. (iv) For a boiler or process heater, a temperature monitoring device equipped with a continuous recorder. The temperature monitoring device must have a minim um accuracy of ±1 percent of the temperature being monitored in °C, or ±2.5 °C, whichever value is greater. You must install the temperature sensor at a location representative of the combustion zone temperature. (v) For a condenser, a temperature monitor ing device equipped with a continuous recorder. The temperature monitoring device must have a minimum accuracy of ±1 percent of the temperature being monitored in °C, or ±2.8 °C, whichever value is greater. You must install the temperature sensor at a loca tion in the exhaust vent stream from the condenser. (vi) For a regenerative

- type carbon adsorption system, a continuous monitoring system that meets the specifications in paragraphs (d)(1)(vi)(A) and (d)(1)(vi)(B) of this section. ( A ) The continuous par ameter monitoring system must measure and record the average total regeneration stream mass flow or volumetric flow during each carbon bed regeneration cycle. ThePage 296 of 497

flow sensor must have a measurement sensitivity of 5 percent of the flow rate or 10 cubic fee t per minute, whichever is greater. You must check the mechanical connections for leakage at least every month, and you must perform a visual inspection at least every 3 months of all components of the flow continuous parameter monitoring system for physic al and operational integrity and all electrical connections for oxidation and galvanic corrosion if your flow continuous parameter monitoring system is not equipped with a redundant flow sensor; and ( B ) The continuous parameter monitoring system must meas ure and record the average carbon bed temperature for the duration of the carbon bed steaming cycle and measure the actual carbon bed temperature after regeneration and within 15 minutes of completing the cooling cycle. The temperature monitoring device

mu st have a minimum accuracy of ±1 percent of the temperature being monitored in °C, or ±2.5 °C, whichever value is greater. (vii) For a nonregenerative

- type carbon adsorption system, you must monitor the design carbon replacement interval established using a performance test performed as specified in §60.5413(b). The design carbon replacement interval must be based on the total carbon working capacity of the control device and source operating schedule. (viii) For a combustion control device whose model is tested under §60.5413(d), a continuous monitoring system meetingPage 297 of 497

the requirements of paragraphs (d)(1)(viii)(A) and (d)(1)(viii)(B) of this section. (A) The continuous monitoring system must measure gas flow rate at the inlet to the control device. The m onitoring instrument must have an accuracy of ±2 percent or better. (B) A heat sensing monitoring device equipped with a continuous recorder that indicates the continuous ignition of the pilot flame. (2) A continuous monitoring system that measures the

c oncentration level of organic compounds in the exhaust vent stream from the control device using an organic monitoring device equipped with a continuous recorder. The monitor must meet the requirements of Performance Specification 8 or 9 of 40 CFR part 60, appendix B. You must install, calibrate, and maintain the monitor according to the manufacturer's specifications. (3) A continuous monitoring system that measures operating parameters other than those specified in paragraph (d)(1) or (d)(2) of this section, upon approval of the Administrator as specified in §63.8(f)(1) through (5). (e) You must calculate the daily average value for each monitored operating parameter for each operating day, using the data recorded by the monitoring system, except for inlet gas flow rate. If the emissions unit operation is continuous, thePage 298 of 497

operating day is a 24

- hour period. If the emissions unit operation is not continuous, the operating day is the total number of hours of control device operation per 24

- hour period.
Va lid data points must be available for 75 percent of the operating hours in an operating day to compute the daily
average. (f) For each operating parameter monitor installed in accordance with the requirements of paragraph (d) of this section, you must comply with paragraph (f)(1) of this section for all control devices. When condensers are installed, you must also comply with paragraph (f)(2) of this section. (1) You must establish a minimum operating parameter value or a maximum operating parameter va lue, as appropriate for the control device, to define the conditions at which the control device must be operated to continuously achieve the applicable performance requirements of §60.5412(a). You must establish each minimum or maximum operating parameter value as specified in paragraphs (f)(1)(i) through (f)(1)(iii) of this section. (i) If you conduct performance tests in accordance with the requirements of §60.5413(b) to demonstrate that the control device achieves the applicable performance requirement s specified in §60.5412(a), then you must establish the minimum operating parameter value or the maximum operating parameter value based on values measured during the performance test andPage 299 of 497

supplemented, as necessary, by a condenser design analysis or
contro l device manufacturer recommendations or a combination of both. (ii) If you use a condenser design analysis in accordance with the requirements of §60.5413(c) to demonstrate that the control device achieves the applicable performance requirements specifie d in §60.5412(a), then you must establish the minimum operating parameter value or the maximum operating parameter value based on the condenser design analysis and supplemented, as necessary, by the condenser manufacturer's recommendations. (iii) If you o perate a control device where the performance test requirement was met under §60.5413(d) to demonstrate that the control device achieves the applicable performance requirements specified in §60.5412(a), then you must establish the maximum inlet gas flow ra te based on the performance test and supplemented, as necessary, by the manufacturer recommendations. (2) If you use a condenser as specified in paragraph (d)(1)(v) of this section, you must establish a condenser performance curve showing the relationship between condenser outlet temperature and condenser control efficiency, according to the requirements of paragraphs (f)(2)(i) and (f)(2)(ii) of this section .Page 300 of 497

(i) If you conduct a performance test in accordance with the requirements of §60.5413(b) to demo nstrate that the condenser achieves the applicable performance requirements in §60.5412(a), then the condenser performance curve must be based on values measured during the performance test and supplemented as necessary by control device design analysis, o r control device manufacturer's recommendations, or a combination or both. (ii) If you use a control device design analysis in accordance with the requirements of §60.5413(c)(1) to demonstrate that the condenser achieves the applicable performance require ments specified in §60.5412(a), then the condenser performance curve must be based on the condenser design analysis and supplemented, as necessary, by the control device manufacturer's recommendations. (g) An excursion for a given control device is determ ined to have occurred when the monitoring data or lack of monitoring data result in any one of the criteria specified in paragraphs (g)(1) through (g)(6) of this section being met. If you monitor multiple operating parameters for the same control device du ring the same operating day and more than one of these operating parameters meets an excursion criterion specified in paragraphs (g)(1) through (g)(6) of this section, then a single excursion is determined to have occurred for the control device for that

o perating day.Page 301 of 497

(1) An excursion occurs when the daily average value of a monitored operating parameter is less than the minimum operating parameter limit (or, if applicable, greater than the maximum operating parameter limit) established in paragraph (f)(1 ) of this section. (2) If you meet §60.5412(a)(2), an excursion occurs when the 365

- day average condenser efficiency calculated according to the requirements specified in §60.5415(e)(8)(iv) is less than 95.0 percent. (3) If you meet §60.5412(a)(2) and y ou have less than 365 days of data, an excursion occurs when the average condenser efficiency calculated according to the procedures specified in §60.5415(e)(8)(iv)(A) or (B) is less than 90.0 percent. (4) An excursion occurs when the monitoring data are not available for at least 75 percent of the operating hours in a day. (5) If the closed vent system contains one or more bypass devices that could be used to divert all or a portion of the gases, vapors, or fumes from entering the control device, an

exc ursion occurs when the requirements of paragraphs (g)(5)(i) and (g)(5)(ii) of this section are met. (i) For each bypass line subject to §60.5411(a)(3)(i)(A), the flow indicator indicates that flow has been detected andPage 302 of 497

that the stream has been diverted aw ay from the control device to the atmosphere. (ii) For each bypass line subject to §60.5411(a)(3)(i)(B), if the seal or closure mechanism has been broken, the bypass line valve position has changed, the key for the lock

- and

- key type lock has been checked out, or the car

- seal has broken. (6) For a combustion control device whose model is tested under §60.5413(d), an excursion occurs when the conditions of paragraphs (g)(6)(i) or (g)(6)(ii) are met. (i) The inlet gas flow rate exceeds the maximum establish ed during the test conducted under §60.5413(d). (ii) Failure of the monthly visible emissions test conducted under §60.5415(e)(7)(iii) occurs. (h) For each excursion, you are deemed to have failed to have applied control in a manner that achieves the re quired operating parameter limits, except as provided for in paragraph (i) of this section. Failure to achieve the required operating parameter limits is a violation of this standard. (i) An excursion is not a violation of the operating parameter limit as specified in paragraphs (i)(1) and (i)(2) of this section. (1) An excursion does not count toward the number of excused excursions allowed under paragraph (i)(2) of this section when the excursion occurs during any one of the periodsPage 303 of 497

identified in paragr aphs (i)(1)(i) and (i)(1)(ii) of this section. (i) During a malfunction when the affected facility is operated during such period in accordance with §63.6(e)(1); or (ii) During periods of non

- operation of the unit or the process that is vented to the con trol device (resulting in cessation of VOC emissions to which the monitoring applies). (2) For each control device, or combinations of control devices installed on the same emissions unit, one excused excursion is allowed per semiannual period for any rea son. The initial semiannual period is the 6

- month reporting period addressed by the first Periodic Report submitted in accordance with §63.775(e) of this subpart. (j) Nothing in paragraphs (a) through (i) of this section is construed to allow or excuse a monitoring parameter excursion caused by any activity that violates other applicable provisions of this subpart. §60.5420 What are my notification, reporting, and recordkeeping requirements? (a) You must submit the notifications required in §60.7(a)(1), (a)(3) and (a)(4), and according to paragraphs (a)(1) and (a)(2) of this section, if you own or operate one or more of the affected facilities specified in §60.5365 that was installed, modified, or replaced during the reporting period
.Page 304 of 497

(1) If you own or operate a gas well , pneumatic controller or storage vessel affected facility you are not required to submit the notifications required in §60.7(a)(1), (a)(3) and (a)(4). (2) If you own or operate a gas well affected facility, you must submit the notificat ions specified in paragraphs (a)(2)(i) and (a)(2)(ii) of this section to the Administrator. (i) By the first of each month in which you anticipate the commencement of one or more well completion operations, you must submit a notification to the Administra tor listing each anticipated well completion operation during that month. The notification shall include the latitude and longitude coordinates of the well in decimal degrees to an accuracy and precision of five (5) decimals of a degree using the North
Ame rican Datum of 1983. You may submit the notification in writing or in electronic format. (ii) No earlier than 3 days or later than 2 days prior to the commencement of each well completion operation, you must send an email notification to the Administrator of the actual commencement date of the well completion operation. (b) Reporting requirements. You must submit annual reports contai ning the information specified in paragraphs (b)(1) through (b)(6) of this section to the Administrator and performance test reports as specified in paragraph (b)(7) ofPage 305 of 497

this section . The initial annual report is due up to 1 year after the initial startup d ate for your affected facility or up to 1 year after [INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER] , whichever is later. Subsequent annual reports are due on the same date each year as the initial annual report. If you own or operate more than one af fected facility, you may submit one report for multiple affected facilities provided the report contains all of the information required as specified in paragraphs (b)(1) through (b)(6) of this section. Annual reports may coincide with title V reports as l ong as all the required elements of the annual report are included. You may arrange with the Administrator a common schedule on which reports required by this part may be submitted as long as the schedule does not extend the reporting period. (1) The gen eral information specified in paragraphs (b)(1)(i) through (b)(1)( iv ) of this section. (i) The company name and address of the affected facility. (ii) An identification of each affected facility being included in the annual report. (iii) Beginning and ending dates of the reporting period. (iv) A certification by a responsible official of truth, accuracy, and completeness. This certification shall state that, based on information and belief formed after reasonable inquiry,Page 306 of 497

the statements and information in the document are true, accurate, and complete. (2) For each gas well affected facility, the information in paragraphs (b)(2)(i) through (b)(2)(iii) of this section. (i) An identification of each well completion operation, as defined in §60.5430, for each gas well affected facility conducted during the reporting period; (ii) R ecord s of deviations specified in paragraph (c)(1)(ii) of this section that occurred during the reporting period
. (iii) Records specified in §60.5375(b) for each well completion operation that occurred during the reporting period. (3) For each centrifugal compressor affected facility , the information specified in paragraphs (b)(3)(i) and (b )(3)(ii) of this section
. (i) An identification of each centrifugal compressor installed, modified or reconstructed during the reporting period. (ii) Records of deviations specified in paragraph (c)(2) of this section that occurred during the reporting p eriod. (4) For each reciprocating compressor affected facility, the information specified in paragraphs (b)(4)(i) through (b)(4)( iii ) of this section.Page 3 07 of 497

(i) The cumulative number of hours or operation or the number of months since initial startup, [INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER] , or since the previous reciprocating compressor rod packing replacement, whichever is later. (ii) Documentation that the reciprocating compressor rod packing was replaced before the cumulative number of hours of operation reached 2 6 ,000 hours or 36 months from the previous rod packing replacement
. (iii) Records of deviations specified in paragraph (c)(3)(iii) of this section that occurred during the reporting period. (5) For each pneumatic controller affected facility, the information specified in paragraphs (b)(5)(i) through (b)(5)( v ) of this section. (i) An identification of each pneumatic controller installed, modified or reconstructed during the reporting period, including the identification information s pecified in §60.5390(c)(2). ( ii ) If applicable, documentation that the use of pneumatic controller affected facilities with a natural gas bleed rate greater than 6 standard cubic feet per hour are required and the reasons why.Page 308 of 497

( iii ) Records of deviations specified in paragraph (c)(4)(v) of this section that occurred during the reporting period. (6) For each sto rage vessel affected facility, the information in paragraphs (b)(6)(i) through (b)(6)( iv ) of this section. (i) An identification of eac h storage vessel with VOC emissions greater than 6 tpy installed, modified or reconstructed during the reporting period. ( ii ) If required to reduce emissions by complying with §60.5395(a)(1), the records specified in §63.774(b)(2) through (b)(8) of this c hapter. ( iii ) Documentation that the VOC emission rate is less than 6 tpy for meeting the requirements in §60.5395(a). (iv) Records of deviations specified in paragraph (c)(5)(iii) of this section that occurred during the reporting period. ( 7 )(i) Within 60 days after the date of completing each performance test(see §60.8 of this part ) as required by this subpart you must submit the results of the performance tests required by this subpart to EPA’s WebFIRE database by using the Compliance and Emissions Da ta Reporting Interface (CEDRI) that is accessed through EPA’s Central Data Exchange (CDX) (www.epa.gov/cdx). Performance test data must be submitted inPage 309 of 497

the file format generated through use of EPA’s Electronic Reporting Tool (ERT) (see http://www.epa.gov/t tn/chief/ert/index.html ). Only data collected using test methods on the ERT website are subject to this requirement for submitting reports electronically to WebFIRE. Owners or operators who claim that some of the information being submitted for performance tests is confidential business information (CBI) must submit a complete ERT file including information claimed to be CBI on a compact disk or other commonly used electronic storage media (including, but not limited to, flash drives) to EPA. The electronic media must be clearly marked as CBI and mailed to U.S. EPA/OAPQS/CORE CBI Office, Attention: WebFIRE Administrator, MD C404

- 02, 4930 Old Page Rd., Durham, NC 27703. The same ERT file with the CBI omitted must be submitted to EPA via CDX as described earl ier in this paragraph. At the discretion of the delegated authority, you must also submit these reports, including the confidential business information, to the delegated authority in the format specified by the delegated authority. (ii) All reports requi red by this subpart not subject to the requirements in paragraphs (1)(i) of this section must be sent to the Administrator at the appropriate address listed in §6 3.13 of this part . The Administrator or the delegated authority may request a report in any fo rm suitable for thePage 310 of 497

specific case (e.g., by commonly used electronic media such as Excel spreadsheet, on CD or hard copy). The Administrator retains the right to require submittal of reports subject to paragraph (1)(i) and (ii) of this section in paper for mat. (c) Recordkeeping requirements
. You must maintain the records identified as specified in §60.7(f) and in paragraphs (c)(1) through (c)(5) of this section (1) The records for each gas well affected facility as specified in paragraphs (c)(1)(i) throug h (c)(1)(iii) of this section
. (i) Records identifying each well completion operation for each gas well affected facility conducted during the reporting period; (ii) Record s of deviations in cases where well completion operations with hydraulic fracturing were not performed in compliance with the requirements specified in §60.5375. (iii) Records required in §60.5375(b) or (f) for each well completion operation conducted for each gas well affected facility that occurred during the reporting period. You must maintain the records specified in paragraphs (c)(1)(iii)(A) and (c)(1)(iii)(B) of this section. (A) For each gas well s affected facility required to comply with the requir ements of §60.5375(a), you must record: The location of the well; the duration of flowback; duration ofPage 311 of 497

recovery to the sales line; duration of combustion; duration of venting; and specific reasons for venting in lieu of capture or combustion. The duration must be specified in hours of time. (B) For each gas well affected facility required to comply with the requirements of §60.5375(f), you must maintain the records specified in paragraph (c)(1)(iii)(A) of this section except that you do not have to record the duration of recovery to the sales line. In addition, you must record the distance, in miles, of the nearest gathering line. (iv) For each gas well facility for which you claim an exception under §60.5375(a)(3), you must record: the location of the we ll; the specific exception claimed; the starting date and ending date for the period the well operated under the exception; and an explanation of why the well meets the claimed exception. (2) For each centrifugal compressor affected facility, you must mai ntain records of deviations in cases where the centrifugal compressor was not operated in compliance with the requirements specified in §60.5380
. (3) For each reciprocating compressors affected facility, you must maintain the records in paragraphs (c)(3)( i) through (c)(3)( iii ) of this section. (i) Records of the cumulative number of hours of operation or number of months since initial startup or [INSERT DATE OFPage 312 of 497

PUBLICATION IN THE FEDERAL REGISTER] , or the previous replacement of the reciprocating compressor rod packing, whichever is later. (ii) Records of the date and time of each reciprocating compressor rod packing replacement. (iii) Records of deviations in cases where the reciprocating compressor was not operated in compliance with the require ments specified in §60.5385. (4) For each pneumatic controller, you must maintain the records identified in paragraphs (c)(4)(i) through (c)(4)( v ) of this section. (i) Records of the date, location and manufacturer specifications for each pneumatic cont roller installed. (ii) Records of the determination that the use of pneumatic controller affected facilities with a natural gas bleed rate greater than 6 standard cubic feet per hour are required and the reasons why. (iii) If the pneumatic controller is not located at a natural gas processing plant, records of the manufacturer’s specifications indicating that the controller is designed such that natural gas bleed rate is less than or equal to 6 standard cubic feet per hour.Page 313 of 497

(iv) If the pneumatic controll er is located at a natural gas processing plant, records of the documentation that the natural gas bleed rate is zero. (v) Records of deviations in cases where the pneumatic controller was not operated in compliance with the requirements specified in §60. 5390. (5) For each storage vessel affected facility, you must maintain the records identified in paragraphs (c)(5)(i) through (c)(5)( iii ) of this section. (i) If required to reduce emissions by complying with § 60.5395 , the records specified in §63.774(b) (2) through (8) of this chapter. (ii) Records of the determination that the VOC emission rate is less than 6 tpy per storage vessel for the exemption under §60.5395(a). (iii) Records of deviations in cases where the storage vessel was not operated in com pliance with the requirements specified in §§60.5395, 60.5411, 60.5412, and 60.5413. §60.5421 What are my additional recordkeeping requirements for my affected facility subject to VOC requirements for onshore natural gas processing plants? (a) You must comply with the requirements of paragraph (b) of this section in addition to the requirements of §60.486a.Page 314 of 497

(b) The following recordkeeping requirements apply to pressure relief devices subject to the requirements of §60.5401(b)(1) of this subpart. (1) When each leak is detected as specified in §60.5401(b)(2), a weatherproof and readily visible identification, marked with the equipment identification number, must be attached to the leaking equipment. The identification on the pressure relief device m ay be removed after it has been repaired. (2) When each leak is detected as specified in §60.5401(b)(2), the following information must be recorded in a log and shall be kept for 2 years in a readily accessible location: (i) The instrument and oper ator identification numbers and the equipment identification number. (ii) The date the leak was detected and the dates of each attempt to repair the leak. (iii) Repair methods applied in each attempt to repair the leak. (iv) ”Above 500 ppm” if the maximum instrument reading measured by the methods specified in paragraph (a) of this section after each repair attempt is 500 ppm or greater.Page 315 of 497

(v) ”Repair delayed” and the reason for the delay if a leak is not repaired within 15 calendar days after discovery of the leak. (vi) The signature of the owner or operator (or designate) whose decision it was that repair could not be effected without a process shutdown. (vii) The expected date of successful repair of the leak if a leak is not repaire d within 15 days. (viii) Dates of process unit shutdowns that occur while the equipment is unrepaired. (ix) The date of successful repair of the leak. (x) A list of identification numbers for equipment that are designated for no detectable emis sions under the provisions of §60.482

- 4a(a). The designation of equipment subject to the provisions of §60.482

- 4a(a) must be signed by the owner or operator. §60.5422 What are my additional reporting requirements for my affected facility subject to VOC req uirements for onshore natural gas processing plants? (a) You must comply with the requirements of paragraphs (b) and (c) of this section in addition to the requirements of §60.487a(a), (b), (c)(2)(i) through (iv), and (c)(2)(vii) through (viii).Page 316 of 497

(b) An o wner or operator must include the following information in the initial semiannual report in addition to the information required in §60.487a(b)(1) through (4): Number of pressure relief devices subject to the requirements of §60.5401(b) except for those pr essure relief devices designated for no detectable emissions under the provisions of §60.482

– 4a(a) and those pressure relief devices complying with §60.482

– 4a(c). (c) An owner or operator must include the following information in all semiannual reports in addition to the information required in §60.487a(c)(2)(i) through (vi): (1) Number of pressure relief devices for which leaks were detected as required in §60.5401(b)(2); and (2) Number of pressure relief devices for which leaks were not repaired as req uired in §60.5401(b)(3). §60.5423 What additional recordkeeping and reporting requirements apply to my sweetening unit affected facilities at onshore natural gas processing plants? (a) You must retain records of the calculations and measurements required in §60.5405(a) and (b) and §60.5407(a) through (g) for at least 2 years following the date of the measurements. This requirement is included under §60.7(d) of the General Provisions.Page 317 of 497

(b) You must submit a report of excess emissions to the Administrator se miannually. For the purpose of these reports, excess emissions are defined as: (1) Any 24

- hour period (at consistent intervals) during which the average sulfur emission reduction efficiency (R) is less than the minimum required efficiency (Z). (2) For an y affected facility electing to comply with the provisions of §60.5407(b)(2), any 24

- hour period during which the average temperature of the gases leaving the combustion zone of an incinerator is less than the appropriate operating temperature as determine d during the most recent performance test in accordance with the provisions of §60.5407(b)(2). Each 24

- hour period must consist of at least 96 temperature measurements equally spaced over the 24 hours. (c) To certify that a facility is exempt from the con trol requirements of these standards, for each facility with a design capacity less that 2 LT/D of H 2 S in the acid gas (expressed as sulfur) you must keep, for the life of the facility, an analysis demonstrating that the facility's design capacity is less than 2 LT/D of H 2 S expressed as sulfur. (d) If you elect to comply with §60.5407(e) you must keep, for the life of the facility, a record demonstrating that the facility's design capacity is less than 150 LT/D of H 2 S expressed as sulfur.Page 318 of 497

(e) The requirem ents of paragraph (b) of this section remain in force until and unless the EPA, in delegating enforcement authority to a state under section 111(c) of the Act, approves reporting requirements or an alternative means of compliance surveillance adopted by su ch state. In that event, affected sources within the state will be relieved of obligation to comply with paragraph (b) of this section, provided that they comply with the requirements established by the state. §60.5425 What part of the General Provisions a pply to me? Table 3 to this subpart shows which parts of the General Provisions in §§60.1 through 60.19 apply to you. §60.5430 What definitions apply to this subpart? As used in this subpart, all terms not defined herein shall have the meaning given them in the Act, in subpart A or subpart VVa of part 60; and the following terms shall have the specific meanings given them. Acid gas means a gas stream of hydrogen sulfide (H 2 S) and carbon dioxide (CO 2 ) that has been separated from sour natural gas by a swe etening unit. Affirmative defense means, in the context of an enforcement proceeding, a response or defense put forward by a defendant, regarding which the defendant has the burden of proof, and the merits of which are independently and objectively evaluated in a judicial or administrativ e proceeding.Page 319 of 497

Alaskan North Slope means the approximately 69,000 square

mile area extending from the Brooks Range to the Arctic Ocean. API Gravity means the weight per unit volume of hydrocarbon liquids as measured by a system recommended by the American Petroleum Institute (API) and is expressed in degrees. Centrifugal compressor means a piece of equipment that compresses a process gas by means of mechanical rotating vanes or impellers. City gate means the delivery point at which natural gas is transfer red from a transmission pipeline to the local gas utility. Completion combustion device means any ignition device, installed horizontally or vertically, used in exploration and production operations to combust otherwise vented emissions from completions. Compressor means a piece of equipment that compresses process gas and is usually a centrifugal compressor or a reciprocating compressor. Compressor station means any permanent combination of compressors that move natural gas at increased pressure from fi elds, in transmission pipelines, or into storage. Condensate means a hydrocarbon liquid separated from natural gas that condenses due to changes in the temperature, pressure, or both, and remains liquid at standard conditions, asPage 320 of 497

specified in §60.2. For t he purposes of this subpart, a hydrocarbon liquid with an API gravity equal to or greater than 40 degrees is considered condensate. Crude oil means crude petroleum oil any other hydrocarbon liquid, which are produced at the well in liquid form by ordinary production methods, and which are not the result of condensation of gas before or after it leaves the reservoir. For the purposes of this subpart, a hydrocarbon liquid with an API gravity less than 40 degrees is considered crude oil. Custody transfer mea ns the transfer of natural gas after processing and/or treatment in the producing operations, or from storage vessels or automatic transfer facilities or other such equipment, including product loading racks, to pipelines or any other forms of transportati on. Dehydrator means a device in which an absorbent directly contacts a natural gas stream and absorbs water in a contact tower or absorption column (absorber). Delineation well means a well drilled in order to determine the boundary of a field or producing reservoir. Equipment means each pump, pressure relief device, open

ended valve or line, valve, compressor, and flange or other connector that is in VOC service or in wet gas service, and any device or system required by this subpart.Page 321 of 497

Field gas means feedstock gas entering the natural gas processing plant. Field gas gathering means the system used transport field gas from a field to the main pipeline in the area. Flare means a thermal oxidation system using an open (without enclosure) flame. Flowback means the process of allowing fluids to flow from the well following a treatment, either in preparation for a subsequent phase of treatment or in preparation for cleanup a nd returning the well to production. Flow line means surface pipe through which oil and/or natural gas travels from the well. Gas processing plant process unit means equipment assembled for the extraction of natural gas liquids from field gas, the fracti onation of the liquids into natural gas products, or other operations associated with the processing of natural gas products. A process unit can operate independently if supplied with sufficient feed or raw materials and sufficient storage facilities for t he products. Gas well or natural gas well means an onshore well drilled principally for production of natural gas. Hydraulic fracturing means process of directing pressurized liquids, containing water, proppant, and any added chemicals, to penetrate ti ght formations, such as sand, shale, or coalPage 322 of 497

formations , that involve high rate, extended back flow to expel fracture fluids and sand during completions. In light liquid service means that the piece of equipment contains a liquid that meets the conditions specified in §60.485a(e) or §60.5401(h)(2) of this part. In wet gas service means that a compressor or piece of equipment contains or contacts the field gas before the extraction step at a gas processing plant process unit. Intermittent/snap

- a ction pneumatic controller means a pneumatic controller that vents non

- continuously. Liquefied natural gas unit means a unit used to cool natural gas to the point at which it is condensed into a liquid which is colorless, odorless, non

- corrosive and non

- t oxic. Low pressure well means a well with reservoir pressure and vertical well depth such that 0.443 times the reservoir pressure (in psia) minus 0.092 times the vertical well depth (in feet) plus 497 psia is less than the sales line pressure at the sale s meter. Modification means any physical change in, or change in the method of operation of, an affected facility which increases the amount of VOC or natural gas emitted into the atmosphere by that facility or which results in the emission of VOC or natu ral gas into the atmosphere not previously emitted.Page 323 of 497

Natural g as - driven pneumatic controller means a pneumatic controller powered by pressurized natural gas. Natural gas liquids means the hydrocarbons, such as ethane, propane, butane, and pentane that are extracted from field gas. Natural gas processing plant (gas plant) means any processing site engaged in the extraction of natural gas liquids from field gas, fractionation of mixed natural gas liquids to natural gas products, or both. Natural gas tra nsmission means the pipelines used for the long distance transport of natural gas (excluding processing). Specific equipment used in natural gas transmission includes the land, mains, valves, meters, boosters, regulators, storage vessels, dehydrators, comp ressors, and their driving units and appurtenances, and equipment used for transporting gas from a production plant, delivery point of purchased gas, gathering system, storage area, or other wholesale source of gas to one or more distribution area(s).
Non fractionating plant means any gas plant that does not fractionate mixed natural gas liquids into natural gas products. Non natural gas

- driven pneumatic controller means an instrument that is actuated using other sources of power than pressurized natural g as; examples include solar, electric, and instrument air.Page 324 of 497

Onshore means all facilities except those that are located in the territorial seas or on the outer continental shelf. Pneumatic controller means an automated instrument used for maintaining a pr ocess condition such as liquid level, pressure, delta

- pressure and temperature. Pressure vessel means a storage vessel that is used to store liquids or gases and is designed not to vent to the atmosphere as a result of compression of the vapor headspace in the pressure vessel during filling of the pressure vessel to its design capacity. Process uni t means components assembled for the extraction of natural gas liquids from field gas, the fractionation of the liquids into natural gas products, or other operations associated with the processing of natural gas products. A process unit can operate indepe ndently if supplied with sufficient feed or raw materials and sufficient storage facilities for the products. Reciprocating compressor means a piece of equipment that increases the pressure of a process gas by positive displacement, employing linear move ment of the driveshaft. Reciprocating compressor rod packing means a series of flexible rings in machined metal cups that fit around the reciprocating compressor piston rod to create a seal limitingPage 325 of 497

the amount of compressed natural gas that escapes to the atmosphere. Reduced emissions completion means a well completion where gas flowback that is otherwise vented is captured, cleaned, and routed to the sales line. Reduced emissions recompletion means a well completion following refracturing of a gas well where gas flowback that is otherwise vented is captured, cleaned, and routed to the sales line. Reduced sulfur compounds means H 2 S, carbonyl sulfide (COS), and carbon disulfide (CS 2 ). Responsible official means one of the following: (1) For a corporation: a president, secretary, treasurer, or vice

- president of the corporation in charge of a principal business function, or any other person who performs similar policy or decision

- making functions for the corporation, or a duly authorized represen tative of such person if the representative is responsible for the overall operation of one or more manufacturing, production, or operating facilities applying for or subject to a permit and either: (i) The facilities employ more than 250 persons or have gross annual sales or expenditures exceeding $25 million (in second quarter 1980 dollars); orPage 326 of 497

(ii) The delegation of authority to such representatives is approved in advance by the permitting authority; (2) For a partnership or sole proprietorship: a gen eral partner or the proprietor, respectively; (3) For a municipality, State, Federal, or other public agency: Either a principal executive officer or ranking elected official. For the purposes of this part, a principal executive officer of a Federal agenc y includes the chief executive officer having responsibility for the overall operations of a principal geographic unit of the agency (e.g., a Regional Administrator of EPA); or (4) For affected facilities : (i) The designated representative in so far as ac tions, standards, requirements, or prohibitions under title IV of the Clean Air Act or the regulations promulgated thereunder are concerned; or (ii) The designated representative for any other purposes under part 6 0. Routed to a process or route to a pro cess means the emissions are conveyed to any enclosed portion of a process unit where the emissions are predominantly recycled and/or consumed in the same manner as a material that fulfills the same function in the process and/or transformed by chemical re action intoPage 327 of 497

materials that are not regulated materials and/or incorporated into a product; and/or recovered. Salable quality gas means natural gas that meets the composition, moisture, or other limits set by the purchaser of the natural gas. Sales line m eans pipeline, generally small in diameter, used to transport oil or gas from the well to a processing facility or a mainline pipeline. Storage vessel means a unit that is constructed primarily of nonearthen materials (such as wood, concrete, steel, fiber glass, or plastic) which provides structural support and is designed to contain an accumulation of liquids or other materials. The following are not considered storage vessels: (1) Vessels that are skid

- mounted or permanently attached to a motor vehicle, such as trucks, railcars, barges or ships, and are located at a site for less than 180 days. ( 2) Process vessels such as surge control vessels, bottoms receivers, or knockout vessels. (3) Pressure vessels designed to operate in excess of 204.9 kilopascal s and without emissions to the atmosphere. Sulfur production rate means the rate of liquid sulfur accumulation from the sulfur recovery unit. Sulfur recovery unit means a process device that recovers element sulfur from acid gas.Page 328 of 497

Surface site means any combination of one or more graded pad sites, gravel pad sites, foundations, platforms, or the immediate physical location upon which equipment is physically affixed. Sweetening unit means a process device that removes hydrogen sulfide and/or carbon dioxi de from the natural gas
stream. Total Reduced Sulfur (TRS) means the sum of the sulfur compounds hydrogen sulfide, methyl mercaptan, dimethyl sulfide, and dimethyl disulfide as measured by Method 16 of appendix A to part 60 of this chapter. Total SO 2 eq uivalents means the sum of volumetric or mass concentrations of the sulfur compounds obtained by adding the quantity existing as SO 2 to the quantity of SO 2 that would be obtained if all reduced sulfur compounds were converted to SO 2 (ppmv or kg/dscm (lb/dscf)). Underground storage tank means a storage tank stored below ground. Well means an oil or gas well, a hole drilled for the purpose of producing oil or gas, or a well into which fluids are injected. Well completion means the p rocess that allows for the flow of petroleum or natural gas from newly drilled wells to expel drilling and reservoir fluids and tests the reservoir flowPage 329 of 497

characteristics, steps which may vent produced gas to the atmosphere via an open pit or tank. Well comp letion also involves connecting the well bore to the reservoir, which may include treating the formation or installing tubing, packer(s), or lifting equipment. Well completion begins with the flowback immediately following hydraulic fracturing or refractur ing and ends when either (1) the well is shut in, or (2) the well is continuously producing to the sales line. Well completion operation means any well completion with hydraulic fracturing or well recompletion with hydraulic fracturing occurring at a gas well affected facility. Well site means the areas that are directly disturbed during the drilling and subsequent operation of, or affected by, production facilities directly associated with any oil well, gas well, or injection well and its associated well pad. Wellhead means the piping, casing, tubing and connected valves protruding above the earth’s surface for an oil and/or natural gas well. The wellhead ends where the flow line connects to a wellhead valve. The wellhead does not include other equipment at the well si te except for any conveyance through which gas is vented to the atmosphere. Wildcat well means a well outside known fields or the first well drilled in an oil or gas field where no other oil and gas production exists.Page 330 of 497

Table 1 to Subpart OOOO of part 60

– Required Minimum Initial SO 2 Emission Reduction Efficiency (Z i )

H 2 S content of acid gas (Y), % Sulfur feed rate (X), LT/D

2.0 < X < 5.0 5.0<X < 15.0 15.0<X < 300.0 X>300.0 Y > 50 79.0 88.51X 0.0101 Y 0.0125 or 99.9, whichever is smaller 20 < Y<50 79.0 88.5X 0.0101 Y 0.0125 or 97.9, whichever is smaller 97.9 10 < Y<20 79.0 88.5X 0.0101 Y 0.0125 or 97.9, whichever is smaller 93.5 93.5

Y<10 79.0 79.0 79.0 79.0

Table 2 to Subpart OOOO of part 60

– Required Minimum SO2 Emission Reduction Efficiency (Z c )

H 2 S content of acid gas (Y), % Sulfur feed rate (X), LT/D

2.0 < X < 5.0 5.0<X < 15.0 15.0<X < 300.0 X>300.0 Y > 50 74.0 85.35X 0.0144 Y 0.0128 or 99.9, whichever is smaller 20 < Y<50 74.0 85.35X 0.0144 Y 0.0128 or 97.9, whichever is smaller 97.5 10 < Y<20 74.0 85.35X 0.0144 Y 0.0128 or 90.8, whichever is smaller 90.8 90.8

Y<10 74.0 74.0 74.0 74.0 E = The sulfur emission rate expressed as elemental sulfur, kilograms per hour (kg/hr) [pounds per hour (lb/hr)], rounded to one decimal place. R = The sulfur emission reduction efficiency achieved in percent, carried to one decimal place. S = The sulfur production rate, kilograms per hour (kg/hr) [pounds per hour (lb/hr)], rounded to one decimal place. X = The sulfur feed rate from the sweetening unit ( i.e. , the H 2 S in the acid gas), expressed as sulfur, Mg/D(LT/D), rounded to one decimal place.Page 331 of 497

Y = The sulfur content of the acid gas from the sweetening unit, expressed as mole percent H 2 S (dry basis) rounded to one decimal place. Z = The minimum required sulfur dioxide (SO2) emission r eduction efficiency, expressed as percent carried to one decimal place. Z i refers to the reduction efficiency required at the initial performance test. Z c refers to the reduction efficiency required on a continuous basis after compliance with Z i has been d emonstrated.

Table 3 to Subpart OOOO of part 60

– Applicability of General Provisions to Subpart OOOO As stated in §60.5425, you must comply with the following applicable General Provisions:

General Provisions Citation Subject of Citation Applies to sub part? Explanation

§60.1 General

applicability of the General Provisions Yes
§60.2 Definitions Yes Additional terms defined in §60.5430 §60.3 Units and

abbreviations Yes §60.4 Address Yes §60.5 Determination of

construction or modification Yes

§60.6 Review of plans Yes §60.7 Notification and

record keeping Yes Except that §60.7 only applies as specified in §60.5420(a). §60.8 Performance tests No Performance testing is required for storage vessels as specified in 40 CFR part 63, subpart HH. §60.9 Availability of

information Yes §60.10 State authority YesPage 332 of 497

§60.11 Compliance with

standards and maintenance requirements No Requirements are specified in subpart OOOO. §60.12 Circumvention Yes §60.13 Monitoring

requirements Yes Continuous monitors are required for storage vessels §60.14 Modification Yes §60.15 Reconstruction Yes §60.16 Priority list Yes §60.17 Incorporations by

reference Yes §60.18 General control

device requirements Yes Except that §60.18 does not apply to flares. §60.19 General

notification and reporting requirement YesPage 333 of 497

PART 63 -- [Amended] 8. The authority citation for part 63 continues to read as follows: Authority: 42 U.S.C. 7401, et seq . 9. Section 63.14 is amended by: a. Adding paragraphs (b)(69), (b)(70), (b)(71) and (b)(72); and b. Revising paragraph (i)(1) to read as follows: §63.14 Incorporations by reference.
* * * * * (b) * * *
* * * * * (69) ASTM D1945

– 03(2010) Standard Test Method for Analysis of Natural Gas by Gas Chromatography, IBR a pproved for §§63.772 and 63.1282. (70) ASTM D5504

- 08 Standard Test Method for Determination of Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography and Chemiluminescence , IBR approved for §§63.772 and 63.1282. (71) ASTM D3588

- 98( 2003) Standard Practice for Calculating Heat Value, Compressibility Factor, and Relative Density of Gaseous Fuels, IBR approved for §§63.772 and 63.1282.Page 334 of 497

(72) ASTM D4891

- 89(2006) Standard Test Method for Heating Value of Gases in Natural Gas Range by St oichiometric Combustion, IBR approved for §§63.772 and 63.1282.
* * * * * (i) * * * (1) ANSI/ASME PTC 19.10

– 1981, Flue and Exhaust Gas Analyses [Part 10, Instruments and Apparatus], issued August 31, 1981 IBR approved for §§63.309(k)(1)(iii), 63.771(e), 63.865(b), 63.1281(d), 63.3166(a)(3), 63.3360(e)(1)(iii), 63.3545(a)(3), 63.3555(a)(3), 63.4166(a)(3), 63.4362(a)(3), 63.4766(a)(3), 63.4965(a)(3), 63.5160(d)(1)(iii), 63.9307(c)(2), 63.9323(a)(3), 63.11148(e)(3)(iii), 63.11155(e)(3), 63.11162(f)(3)(iii) and (f)(4), 63.11163(g)(1)(iii) and (g)(2), 63.11410(j)(1)(iii), 63.11551(a)(2)(i)(C), 63.11646(a)(1)(iii), table 5 to subpart DDDDD of this part, and table 1 to subpart ZZZZZ of this part.
* * * * * Subpart HH - – [Amended] 10. Section 63.760 is amended by: a. Revising paragraph (a)(1) introductory text; b. Revising paragraph (a)(1)(iii); c. Revising paragraph (a)(2); d. Revising paragraph (b)(1)(i); e. Revising paragraph (b)(1)(ii); f. Revising paragraph (f) introductory text;Page 335 of 497

g. Revising paragraph (f)(1); h. Revising paragraph (f)(2); and i. Adding paragraphs (f)(7), (f)(8), and (f)(9) to read as follows: §63.760 Applicability and designation of affected source. (a) * * * (1) Facilities that are major or area sources of hazardous air pollutants (HAP) as defined in §63.761. Emissions for major source determination purposes can be estimated using the maximum natural gas or hydrocarbon liquid throughput, as appropriate, calcul ated in paragraphs (a)(1)(i) through (iii) of this section. As an alternative to calculating the maximum natural gas or hydrocarbon liquid throughput, the owner or operator of a new or existing source may use the facility's design maximum natural gas or hy drocarbon liquid throughput to estimate the maximum potential emissions. Other means to determine the facility's major source status are allowed, provided the information is documented and recorded to the Administrator's satisfaction in accordance with §63 .10(b)(3). A facility that is determined to be an area source, but subsequently increases its emissions or its potential to emit above the major source levels, and becomes a major source, must comply thereafter with all provisions of this subpart applicabl e to a major source starting on the applicable compliance date specified inPage 336 of 497

paragraph (f) of this section. Nothing in this paragraph is intended to preclude a source from limiting its potential to emit through other appropriate mechanisms that may be avail able through the permitting authority.
* * * * * (iii) The owner or operator shall determine the maximum values for other parameters used to calculate emissions as the maximum for the period over which the maximum natural gas or hydrocarbon liquid through put is determined in accordance with paragraph (a)(1)(i)(A) or (B) of this section. Parameters, other than glycol circulation rate, shall be based on either highest measured values or annual average. For estimating maximum potential emissions from glycol d ehydration units, the glycol circulation rate used in the calculation shall be the unit’s maximum rate under its physical and operational design consistent with the definition of potential to emit in §63.2. (2) Facilities that process, upgrade, or store h ydrocarbon liquids.
* * * * * (b) * * * (1) * * * (i) Each glycol dehydration unit as specified in paragraphs (b)(1)(i)(A) through (C) of this section. (A) Each large glycol dehydration unit;Page 337 of 497

(B) Each small glycol dehydration unit for which constructi on commenced before August 23, 2011, is an existing small glycol dehydration unit; and (C) Each small glycol dehydration unit for which construction commenced on or after August 23, 2011, is a new small glycol dehydration unit. (ii) Each storage vessel;
* * * * * (f) The owner or operator of an affected major source shall achieve compliance with the provisions of this subpart by the dates specified in paragraphs (f)(1), (f)(2), and (f)(7) through (f)(9) of this section. The owner or operator of an affect ed area source shall achieve compliance with the provisions of this subpart by the dates specified in paragraphs (f)(3) through (f)(6) of this section. (1) Except as specified in paragraphs (f)(7) through (9) of this section, the owner or operator of an a ffected major source, the construction or reconstruction of which commenced before February 6, 1998, shall achieve compliance with the applicable provisions of this subpart no later than June 17, 2002, except as provided for in §63.6(i). The owner or opera tor of an area source, the construction or reconstruction of which commenced before February 6, 1998, that increases its emissions of (or its potential to emit) HAP such that the source becomes a majorPage 338 of 497

source that is subject to this subpart shall comply wi th this subpart 3 years after becoming a major source. (2) Except as specified in paragraphs (f)(7) through (9) of this section, the owner or operator of an affected major source, the construction or reconstruction of which commences on or after February 6, 1998, shall achieve compliance with the applicable provisions of this subpart immediately upon initial startup or June 17, 1999, whichever date is later. Area sources, other than production field facilities identified in (f)(9) of this section, the cons truction or reconstruction of which commences on or after February 6, 1998, that become major sources shall comply with the provisions of this standard immediately upon becoming a major source.
* * * * * (7) Each affected existing small glycol dehydration unit and each storage vessel that is not a storage vessel with the potential for flash emissions, both as defined in §63.761, located at a major source, that commenced construction before August 23, 2011, must achieve compliance no later than [INSERT
DATE THREE YEARS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER] , except as provided in §63.6(i). (8) Each affected new small glycol dehydration unit and each storage vessel that is not a storage vessel wi th the potential for flash emissions, both as defined in §63.761,Page 339 of 497

located at a major source, that commenced construction on or after August 23, 2011, must achieve compliance immediately upon initial startup or [INSERT DATE 60 DAYS AFTER DATE OF
PUBLICATION IN THE FEDERAL REGISTER], whichever is later. (9) A production field facility, as defined in §63.761, constructed before August 23, 2011, that was previously determined to be an area source but becomes a major source (as defined in paragraph 3 of the maj or source definition in §63.761) on the [INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER] must achieve compliance no later than [INSERT DATE 3 YEARS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER] , except as provided in §63.6(i).
* * * * * 11. Secti on 63.761 is amended by: a. Adding, in alphabetical order, new definitions for the terms “affirmative defense,” “BTEX,” “flare,” “large glycol dehydration units,” “responsible official” and “small glycol dehydration units”; b. Revising the definitions fo r “associated equipment,” “glycol dehydration unit baseline operations,” “storage vessel,” and “temperature monitoring device”; and c. Revising paragraph (3) of the definition for “major source” to read as follows: §63.761 Definitions.Page 340 of 497

* * * * * Affirmative defense means, in the context of an enforcement proceeding, a response or defense put forward by a defendant, regarding which the defendant has the burden of proof, and the merits of which are independently and objectively evaluated in a judici al or administrative proceeding.
* * * * * Associated equipment , as used in this subpart and as referred to in section 112(n)(4) of the Act, means equipment associated with an oil or natural gas exploration or production well, and includes all equipment f rom the wellbore to the point of custody transfer, except glycol dehydration units and storage vessels.
* * * * *
BTEX means benzene, toluene, ethyl benzene and xylene.
* * * * * Flare means a thermal oxidation system using an open flame ( i.e. , without enclosure).
* * * * * Glycol dehydration unit baseline operations means operations representative of the large glycol dehydration unit operations as of June 17, 1999 and the small glycol dehydrator unit operations as of August 23, 2011. For the purposes of this subpart, for determining the percentage of overall HAP emissionPage 341 of 497

reduction attributable to process modifications, baseline operations shall be parameter values (including, but not limited to, glycol circulation rate or glycol

- HAP absorbenc y) that represent actual long

- term conditions ( i.e. , at least 1 year). Glycol dehydration units in operation for less than 1 year shall document that the parameter values represent expected long

- term operating conditions had process modifications not been made.
* * * * * Large glycol dehydration unit means a glycol dehydration unit with an actual annual average natural gas flowrate equal to or greater than 85 thousand standard cubic meters per day and actual annual average benzene emissions equal to or gre ater than 0.90 Mg/yr, determined according to §63.772(b).
* * * * * Major source * * * (3) For facilities that are production field facilities, only HAP emissions from glycol dehydration units and storage vessels shall be aggregated for a major source d etermination. For facilities that are not production field facilities, HAP emissions from all HAP emission units shall be aggregated for a major source determination.
* * * * * Responsible official means one of the following:Page 342 of 497

(1) For a corporation: a pre sident, secretary, treasurer, or vice

- president of the corporation in charge of a principal business function, or any other person who performs similar policy or decision

- making functions for the corporation, or a duly authorized representative of such per son if the representative is responsible for the overall operation of one or more manufacturing, production, or operating facilities applying for or subject to a permit and either: (i) The facilities employ more than 250 persons or have gross annual sales or expenditures exceeding $25 million (in second quarter 1980 dollars); or (ii) The delegation of authority to such representatives is approved in advance by the permitting authority; (2) For a partnership or sole proprietorship: a general partner or th e proprietor, respectively; (3) For a municipality, State, Federal, or other public agency: Either a principal executive officer or ranking elected official. For the purposes of this part, a principal executive officer of a Federal agency includes the chi ef executive officer having responsibility for the overall operations of a principal geographic unit of the agency (e.g., a Regional Administrator of EPA); or (4) For affected sources:Page 343 of 497

(i) The designated representative in so far as actions, standards, re quirements, or prohibitions under title IV of the Act or the regulations promulgated thereunder are concerned; and (ii) The designated representative for any other purposes under part 70.
* * * * * Small glycol dehydration unit means a glycol dehydration unit, located at a major source, with an actual annual average natural gas flowrate less than 85 thousand standard cubic meters per day or actual annual average benzene emissions less than 0.90 Mg/yr, determined according to §63.772(b).
* * * * * Storage vessel means a tank or other vessel that is designed to contain an accumulation of crude oil, condensate, intermediate hydrocarbon liquids, or produced water and that is constructed primarily of non

- earthen materials (e.g., wood, concrete, steel, plastic) that provide structural support. The following process units are not considered storage vessels: surge control vessels and knockout vessels.
* * * * * Temperature monitoring device means an instrument used to monitor temperature and having a minimum accu racy of ±1 percent of the temperature being monitored expressed in degrees C, or ±2.8 degrees C, whichever is greater. The temperature monitoringPage 344 of 497

device may measure temperature in degrees Fahrenheit or degrees Celsius, or both.
* * * * * 12. Section 63.76 2 is revised to read as follows: §63.762 Malfunctions
. (a) The provisions set forth in this subpart shall apply at all times. (b) [Reserved] (c) [Reserved] (d) In response to an action to enforce the standards set forth in this subpart, you may assert an affirmative defense to a claim for civil penalties for exceedances of such standards that are caused by malfunction, as defined in 40 CFR 63.2. Appropriate penalties may be assessed, however, if you fail to meet your burden of proving all the requireme nts in the affirmative defense. The affirmative defense shall not be available for claims for injunctive relief. (1) To establish the affirmative defense in any action to enforce such a limit, you must timely meet the notification requirements in paragrap h (d)(2) of this section, and must prove by a preponderance of evidence that: (i) The excess emissions: (A) Were caused by a sudden, infrequent, and unavoidable failure of air pollution control and monitoring equipment,Page 345 of 497

process equipment, or a process to operate in a normal or usual manner; and (B) Could not have been prevented through careful planning, proper design or better operation and maintenance practices; and (C) Did not stem from any activity or event that could have been foreseen and avoided, or planned for; and (D) Were not part of a recurring pattern indicative of inadequate design, operation, or maintenance; and (ii) Repairs were made as expeditiously as possible when the applicable emission limitations were being exceeded. Off

shift an d overtime labor were used, to the extent practicable to make these repairs; and (iii) The frequency, amount and duration of the excess emissions (including any bypass) were minimized to the maximum extent practicable during periods of such emissions; an d (iv) If the excess emissions resulted from a bypass of control equipment or a process, then the bypass was unavoidable to prevent loss of life, personal injury, or severe property damage; and (v) All possible steps were taken to minimize the impact o f the excess emissions on ambient air quality, the environment, and human health; andPage 346 of 497

(vi) All emissions monitoring and control systems were kept in operation if at all possible, consistent with safety and good air pollution control practices; and (vii ) All of the actions in response to the excess emissions were documented by properly signed, contemporaneous operating logs; and (viii) At all times, the affected source was operated in a manner consistent with good practices for minimizing emissions;

an d (ix) A written root cause analysis has been prepared to determine, correct, and eliminate the primary causes of the malfunction and the excess emissions resulting from the malfunction event at issue. The analysis shall also specify, using best monitori ng methods and engineering judgment, the amount of excess emissions that were the result of the malfunction. (2) Notification . The owner or operator of the affected source experiencing exceedance of its emission limit(s) during a malfunction shall notify the Administrator by telephone or facsimile transmission as soon as possible, but no later than two business days after the initial occurrence of the malfunction, if it wishes to avail itself of an affirmative defense to civil penalties for that malfunctio n. The owner or operator seeking to assert an affirmative defense shall alsoPage 347 of 497

submit a written report to the Administrator within 45 days of the initial occurrence of the exceedance of the standard in this subpart to demonstrate, with all necessary supporti ng documentation, that it has met the requirements set forth in paragraph (d)(1) of this section. The owner or operator may seek an extension of this deadline for up to 30 additional days by submitting a written request to the Administrator before the expi ration of the 45 day period. Until a request for an extension has been approved by the Administrator, the owner or operator is subject to the requirement to submit such report within 45 days of the initial occurrence of the exceedance. 13. Section 63.764 is amended by: a. Revising paragraph (c)(2) introductory text; b. Revising paragraph (e)(1) introductory text; c. Revising paragraph (i); and d. Adding paragraph (j) to read as follows: §63.764 General standards.
* * * * * (c) * * * (2) For each storage vessel subject to this subpart, the owner or operator shall comply with the requirements specified in paragraphs (c)(2)(i) through (iii) of this section.
* * * * *Page 348 of 497

(e) Exemptions
. (1) The owner or operator of an area source is exempt from the requ irements of paragraph (d) of this section if the criteria listed in paragraph (e)(1)(i) or (ii) of this section are met, except that the records of the determination of these criteria must be maintained as required in §63.774(d)(1).
* * * * * (i) In all c ases where the provisions of this subpart require an owner or operator to repair leaks by a specified time after the leak is detected, it is a violation of this standard to fail to take action to repair the leak(s) within the specified time. If action is t aken to repair the leak(s) within the specified time, failure of that action to successfully repair the leak(s) is not a violation of this standard. However, if the repairs are unsuccessful, and a leak is detected, the owner or operator shall take further action as required by the applicable provisions of this subpart. (j) At all times the owner or operator must operate and maintain any affected source, including associated air pollution control equipment and monitoring equipment, in a manner consistent w ith safety and good air pollution control practices for minimizing emissions. Determination of whether such operation and maintenance procedures are being used will be based on information available to the Administrator which may include, but is not limite d to, monitoring results, review ofPage 349 of 49 7

operation and maintenance procedures, review of operation and maintenance records, and inspection of the source.

14. Section 63.765 is amended by: a. Revising paragraph (a); b. Revising paragraph (b)(1); c. Revising paragraph (c)(2); and d. Revising paragraph (c)(3) to read as follows: §63.765 Glycol dehydration unit process vent standards. (a) This section applies to each glycol dehydration unit subject to this subpart that must be controlled for air emissions as specified in either paragraph (c)(1)(i) or paragraph (d)(1)(i) of §63.764. (b) * * * (1) For each glycol dehydration unit process vent, the owner or operator shall control air emissions by either paragraph (b)(1)(i), (ii), or (iii) of this section. (i) The owner or operator of a large glycol dehydration unit, as defined in §63.761, shall connect the process vent to a control device or a combination of control devices through a closed

- vent system. The closed

- vent system shall be designed and operated in a ccordance with the requirements of §63.771(c). The control device(s) shall be designed and operated in accordance with the requirements of §63.771(d).Page 350 of 497

(ii) The owner or operator of a large glycol dehydration unit shall connect the process vent to a contro l device or combination of control devices through a closed

- vent system and the outlet benzene emissions from the control device(s) shall be reduced to a level less than 0.90 megagrams per year. The closed

- vent system shall be designed and operated in acco rdance with the requirements of §63.771(c). The control device(s) shall be designed and operated in accordance with the requirements of §63.771(d), except that the performance levels specified in §63.771(d)(1)(i) and (ii) do not apply. (iii) You must limi t BTEX emissions from each existing small glycol dehydration unit process vent, as defined in §63.761, to the limit determined in Equation 1 of this section. You must limit BTEX emissions from each new small glycol dehydration unit process vent, as defined in §63.761, to the limit determined in Equation 2 of this section. The limits determined using Equation 1 or Equation 2 must be met in accordance with one of the alternatives specified in paragraphs (b)(1)(iii)(A) through (D) of this section. Equation 1

Where: EL BTEX = Unit

- specific BTEX emission limit, megagrams per year; 3.28x10 - 4 = BTEX emission limit, grams BTEX/standard cubic meter

- ppmv; Throughput = Annual average daily natural gas throughput, standard cubic meters per dayPage 351 of 497

C i,BTEX = average annual BTEX concentration of the natural gas at the inlet to the glycol dehydration unit, ppmv.

Equation 2

Where: EL BTEX = Unit

- specific BTEX emission limit, megagrams per year; 4.66x10 - 6 = BTEX emission limit, grams BTEX/standard cubic meter

- ppmv; Throughput = Annual average daily natural gas th roughput, standard cubic meters per day C i,BTEX = average annual BTEX concentration of the natural gas at the inlet to the glycol dehydration unit, ppmv.

(A) Connect the process vent to a control device or combination of control devices through a closed

- vent system. The closed vent system shall be designed and operated in accordance with the requirements of §63.771(c). The control device(s) shall be designed and operated in accordance with the requirements of §63.771(f). (B) Meet the emissions limit thro ugh process modifications in accordance with the requirements specified in §63.771(e). (C) Meet the emissions limit for each small glycol dehydration unit using a combination of process modifications and one or more control devices through the requirement s specified in paragraphs (b)(1)(iii)(A) and (B) of this section. (D) Demonstrate that the emissions limit is met through actual uncontrolled operation of the small glycol dehydration unit. Document operational parameters in accordance with thePage 352 of 497

requiremen ts specified in §63.771(e) and emissions in accordance with the requirements specified in §63.772(b)(2).

* * * * * (c) * * * (2) The owner or operator shall demonstrate, to the Administrator's satisfaction, that the total HAP emissions to the atmosphere from the large glycol dehydration unit process vent are reduced by 95.0 percent through process modifications, or a combination of process modifications and one or more control devices, in accordance with the requirements specified in §63.771(e). (3) Con trol of HAP emissions from a GCG separator (flash tank) vent is not required if the owner or operator demonstrates, to the Administrator's satisfaction, that total emissions to the atmosphere from the glycol dehydration unit process vent are reduced by one of the levels specified in paragraph (c)(3)(i) through (iv) of this section, through the installation and operation of controls as specified in paragraph (b)(1) of this section. (i) For any large glycol dehydration unit, HAP emissions are reduced by 95.0 percent or more.Page 353 of 497

(ii) For any large glycol dehydration unit, benzene emissions are reduced to a level less than 0.90 megagrams per
year. (iii) For each existing small glycol dehydration unit, BTEX emissions are reduced to a level less than the limit cal culated by Equation 1 of paragraph (b)(1)(iii) of this section. (iv) For each new small glycol dehydration unit, BTEX emissions are reduced to a level less than the limit calculated by Equation 2 of paragraph (b)(1)(iii) of this section. 15. Section 63.7 66 is amended by: a. Revising paragraph (a); b. Revising paragraph (b) introductory text; c. Revising paragraph (b)(1); d. Adding paragraph (b)(3); and e. Revising paragraph (d) to read as follows: §63.766 Storage vessel standards. (a) This section applies to each storage vessel (as defined in §63.761) subject to this subpart. (b) The owner or operator of a storage vessel (as defined in §63.761) shall comply with one of the control requirements specified in paragraphs (b)(1) through (3) of this sect ion. (1) The owner or operator shall equip the affected storage vessel with a cover that is connected, through a closed

- vent system that meets the conditions specified in §63.771(c), to aPage 354 of 497

control device or a combination of control devices that meets
any o f the conditions specified in §63.771(d). The cover shall be designed and operated in accordance with the requirements of §63.771(b).
* * * * * (3) The owner or operator shall control air emissions by connecting the cover, through a closed

- vent system tha t meets the conditions specified in §63.771(c), to a process natural gas line.
* * * * * (d) This section does not apply to storage vessels for which the owner or operator is subject to and controlled under the requirements specified in 40 CFR part 60, su bpart Kb or subpart OOOO; or is subject to and controlled under the requirements specified under 40 CFR part 63 subparts G or CC.

16. Section 63.769 is amended by: a. Revising paragraph (b); b. Revising paragraph (c) introductory text; and b. Revisi ng paragraph (c)(8) to read as follows: §63.769 Equipment leak standards.
* * * * * (b) This section does not apply to ancillary equipment and compressors for which the owner or operator is subject to andPage 355 of 497

controlled under the requirements specified in sub part H of this part; or is subject to and controlled under the requirements specified in 40 CFR part 60, subpart KKK or subpart OOOO. (c) For each piece of ancillary equipment and each compressor subject to this section located at an existing or new

sourc e, the owner or operator shall meet the requirements specified in 40 CFR part 61, subpart V, §§61.241 through 61.247, except as specified in paragraphs (c)(1) through (8) of this section, except for valves subject to §61.242

- 7(b) a leak is detected if an i nstrument reading of 500 ppm or greater is measured. When a leak is detected from a valve it shall be repaired in accordance with the schedule in §61.242

- 7(d), or by [INSERT DATE 1 YEAR AFTER THE DATE OF PUBLICATION IN THE FEDERAL REGISTER], whichever is l ater. * * * * * (8) Flares, as defined in §63.761, used to comply with this subpart shall comply with the requirements of §63.11(b). 17. Section 63.771 is amended by: a. Revising paragraph (c)(1) introductory text; b. Revising the heading of paragraph (d); c. Adding paragraph (d) introductory text; d. Revising paragraph (d)(1)(i)(C); e. Revising paragraph (d)(1)(ii); f. Revising paragraph (d)(1)(iii);Page 356 of 497

g. Revising paragraph (d)(4)(i); h. Revising paragraph (d)(5)(i); i. Revising paragraph (e)(2); j. Revising paragraph (e)(3) introductory text; k. Revising paragraph (e)(3)(ii); and l. Adding paragraph (f) to read as follows: §63.771 Control equipment requirements.
* * * * * (c) Closed

- vent system requirements
. (1) The closed

- vent system shall route all gases, vapors, and fumes emitted from the material in an emissions unit to a control device that meets the requirements specified in paragraph (d) of this section.
* * * * * (d) Control device requirements for sources except small glycol dehydra tion units
. Owners and operators of small glycol dehydration units, shall comply with the control device requirements in paragraph (f) of this section. (1) * * * (i) * * * (C) Operates at a minimum temperature of 760 degrees C, provided the control de vice has demonstrated, under §63.772(e), that combustion zone temperature is an indicator of control efficiency.
* * * * *Page 357 of 497

(ii) A vapor recovery device ( e.g. , carbon adsorption system or condenser) or other non

- destructive control device that is designed and operated to reduce the mass content of either TOC or total HAP in the gases vented to the device by 95.0 percent by weight or greater as determined in accordance with the requirements of §63.772(e). (iii) A flare, as defined in §63.761, that is design ed and operated in accordance with the requirements of §63.11(b).
* * * * * (4) * * * (i) Each control device used to comply with this subpart shall be operating at all times when gases, vapors, and fumes are vented from the HAP emissions unit or units t hrough the closed

- vent system to the control device, as required under §63.765, §63.766, and §63.769. An owner or operator may vent more than one unit to a control device used to comply with this subpart.
* * * * * (5) * * * (i) Following the initial sta rtup of the control device, all carbon in the control device shall be replaced with fresh carbon on a regular, predetermined time interval that is no longer than the carbon service life established for the carbon adsorption system. Records identifying the schedule forPage 358 of 497

replacement and records of each carbon replacement shall be maintained as required in §63.774(b)(7)(ix). The schedule for replacement shall be submitted with the Notification of Compliance Status Report as specified in §63.775(d)(5)(iv). Each carbon replacement must be reported in the Periodic Reports as specified in §63.772(e)(2)(xii).
* * * * * (e) * * * (2) The owner or operator shall document, to the Administrator's satisfaction, the conditions for which glycol dehydration unit baseline o perations shall be modified to achieve the 95.0 percent overall HAP emission reduction, or BTEX limit determined in §63.765(b)(1)(iii), as applicable, either through process modifications or through a combination of process modifications and one or more co ntrol devices. If a combination of process modifications and one or more control devices are used, the owner or operator shall also establish the emission reduction to be achieved by the control device to achieve an overall HAP emission reduction of 95.0 p ercent for the glycol dehydration unit process vent or, if applicable, the BTEX limit determined in §63.765(b)(1)(iii) for the small glycol dehydration unit process vent. Only modifications in glycol dehydration unit operations directly related to process changes, including but not limited to changes in glycol circulation ratePage 359 of 497

or glycol

- HAP absorbency, shall be allowed. Changes in the inlet gas characteristics or natural gas throughput rate shall not be considered in determining the overall emission reducti on due to process modifications. (3) The owner or operator that achieves a 95.0 percent HAP emission reduction or meets the BTEX limit determined in §63.765(b)(1)(iii), as applicable, using process modifications alone shall comply with paragraph (e)(3)(i) of this section. The owner or operator that achieves a 95.0 percent HAP emission reduction or meets the BTEX limit determined in §63.765(b)(1)(iii), as applicable, using a combination of process modifications and one or more control devices shall comply w ith paragraphs (e)(3)(i) and (e)(3)(ii) of this section.
* * * * * (ii) The owner or operator shall comply with the control device requirements specified in paragraph (d) or (f) of this section, as applicable, except that the emission reduction or limit a chieved shall be the emission reduction or limit specified for the control device(s) in paragraph (e)(2) of this section. (f) Control device requirements for small glycol dehydration units
. (1) The control device used to meet BTEX the emission limit calc ulated in §63.765(b)(1)(iii) shall be one ofPage 360 of 497

the control devices specified in paragraphs (f)(1)(i) through (iii) of this section. (i) An enclosed combustion device ( e.g. , thermal vapor incinerator, catalytic vapor incinerator, boiler, or process heater) t hat is designed and operated to meet the levels specified in paragraphs (f)(1)(i)(A) or (B) of this section. If a boiler or process heater is used as the control device, then the vent stream shall be introduced into the flame zone of the boiler or process heater. (A) The mass content of BTEX in the gases vented to the device is reduced as determined in accordance with the requirements of §63.772(e). (B) The concentration of either TOC or total HAP in the exhaust gases at the outlet of the device is reduce d to a level equal to or less than 20 parts per million by volume on a dry basis corrected to 3 percent oxygen as determined in accordance with the requirements of §63.772(e). (ii) A vapor recovery device ( e.g. , carbon adsorption system or condenser) or other non

- destructive control device that is designed and operated to reduce the mass content of BTEX in the gases vented to the device as determined in accordance with the requirements of §63.772(e). (iii) A flare, as defined in §63.761, that is designed and operated in accordance with the requirements of §63.11(b).Page 361 of 497

(2) The owner or operator shall operate each control device in accordance with the requirements specified in paragraphs (f)(2)(i) and (ii) of this section. (i) Each control device used to co mply with this subpart shall be operating at all times. An owner or operator may vent more than one unit to a control device used to comply with this subpart. (ii) For each control device monitored in accordance with the requirements of §63.773(d), the ow ner or operator shall demonstrate compliance according to the requirements of either §63.772(f) or (h). (3) For each carbon adsorption system used as a control device to meet the requirements of paragraph (f)(1)(ii) of this section, the owner or operator shall manage the carbon as required under (d)(5)(i) and (ii) of this section. 18. Section 63.772 is amended by: a. Revising paragraph (b) introductory text; b. Revising paragraph (b)(1)(ii); c. Revising paragraph (b)(2); d. Revising paragraph (c)(6)(i ); e. Adding paragraph (d); f. Revising paragraph (e) introductory text; g. Revising paragraphs (e)(1)(i) through (v); h. Revising paragraph (e)(2);Page 362 of 497

i. Revising paragraph (e)(3) introductory text; j. Revising paragraph (e)(3)(i)(B); k. Revising para graph (e)(3)(iv)(C)( 1 ); l. Adding paragraphs (e)(3)(v) and (vi); m. Revising paragraph (e)(4) introductory text; n. Revising paragraph (e)(4)(i); o. Revising paragraph (e)(5); p. Revising paragraph (f) introductory text; q. Revising paragraph (f)(2) and paragraph (f)(3); r. Adding paragraphs (f)(4) through (f)(6); s. Revising paragraph (g) introductory text; t. Revising paragraph (g)(1) and paragraph (g)(2) introductory text; u. Revising paragraph (g)(2)(iii); v. Revising paragraph (g)(3);

w. Adding paragraph (h); and x. Adding paragraph (i) to read as follows: §63.772 Test methods, compliance procedures, and compliance demonstrations.
* * * * * (b) Determination of glycol dehydration unit flowrate, benzene emissions, or BTEX emissions . The procedures of this paragraph shall be used by an owner or operator to determinePage 363 of 497

glycol dehydration unit natural gas flowrate, benzene emissions, or BTEX emissions. (1) * * * (ii) The owner or operator shall document, to the Administrator's satisfaction , the actual annual average natural gas flowrate to the glycol dehydration unit. (2) The determination of actual average benzene or BTEX emissions from a glycol dehydration unit shall be made using the procedures of either paragraph (b)(2)(i) or (b)(2)(ii ) of this section. Emissions shall be determined either uncontrolled, or with federally enforceable controls in place. (i) The owner or operator shall determine actual average benzene or BTEX emissions using the model GRI

- GLYCalc TM , Version 3.0 or higher , and the procedures presented in the associated
GRI

- GLYCalc TM Technical Reference Manual. Inputs to the model shall be representative of actual operating conditions of the glycol dehydration unit and may be determined using the procedures documented in th e Gas Research Institute (GRI) report entitled “Atmospheric Rich/Lean Method for Determining Glycol Dehydrator Emissions” (GRI

– 95/0368.1); or (ii) The owner or operator shall determine an average mass rate of benzene or BTEX emissions in kilograms per hou r through direct measurement using the methods in §63.772(a)(1)(i) or (ii), or an alternative method according to §63.7(f). AnnualPage 364 of 497

emissions in kilograms per year shall be determined by multiplying the mass rate by the number of hours the unit is operated per year. This result shall be converted to megagrams
per year. * * * * * (c) * * * (6) * * * (i) Except as provided in paragraph (c)(6)(ii) of this section, the detection instrument shall meet the performance criteria of Method 21 of 40 CFR part 60, ap pendix A, except the instrument response factor criteria in section 3.1.2(a) of Method 21 shall be for the average composition of the process fluid, not each individual volatile organic compound in the stream. For process streams that contain nitrogen, air , or other inert gases that are not organic hazardous air pollutants or volatile organic compounds, the average stream response factor shall be calculated on an inert

- free basis.
* * * * * (d) Test procedures and compliance demonstrations for small glyco l dehydration units. This paragraph applies to the test procedures for small dehydration units. (1) If the owner or operator is using a control device to comply with the emission limit in §63.765(b)(1)(iii), the requirements of paragraph (e) of this sect ion apply. CompliancePage 365 of 497

is demonstrated using the methods specified in paragraph (f) of this section. (2) If no control device is used to comply with the emission limit in §63.765(b)(1)(iii), the owner or operator must determine the glycol dehydration unit BTEX emissions as specified in paragraphs (d)(2)(i) through (iii) of this section. Compliance is demonstrated if the BTEX emissions determined as specified in paragraphs (d)(2)(i) through (iii) are less than the emission limit calculated using the equation in §63.765(b)(1)(iii). (i) Method 1 or 1A, 40 CFR part 60, appendix A, as appropriate, shall be used for selection of the sampling sites at the outlet of the glycol dehydration unit process vent. Any references to particulate mentioned in Methods 1 and 1 A do not apply to this section. (ii) The gas volumetric flowrate shall be determined using Method 2, 2A, 2C, or 2D, 40 CFR part 60, appendix A, as appropriate. (iii) The BTEX emissions from the outlet of the glycol dehydration unit process vent shall be determined using the procedures specified in paragraph (e)(3)(v) of this section. As an alternative, the mass rate of BTEX at the outlet of the glycol dehydration unit process vent may be calculated using the model GRI

- GLYCalc TM , Version 3.0 or higher, a nd the proceduresPage 366 of 497

presented in the associated GRI

- GLYCalc TM Technical Reference Manual. Inputs to the model shall be representative of actual operating conditions of the glycol dehydration unit and shall be determined using the procedures documented in the Gas Research Institute (GRI) report entitled “Atmospheric Rich/Lean Method for Determining Glycol Dehydrator Emissions” (GRI

– 95/0368.1). When the BTEX mass rate is calculated for glycol dehydration units using the model GRI

- GLYCalc TM , all BTEX measured by Method 18, 40 CFR part 60, appendix A, shall be summed. (e) Control device performance test procedures . This paragraph applies to the performance testing of control devices. The owners or operators shall demonstrate that a control device achieves the performance requirements of §63.771(d)(1), (e)(3)(ii) or (f)( 1) using a performance test as specified in paragraph (e)(3) of this section. Owners or operators using a condenser have the option to use a design analysis as specified in paragraph (e)(4) of this section. The owner or operator may elect to use the altern ative procedures in paragraph (e)(5) of this section for performance testing of a condenser used to control emissions from a glycol dehydration unit process vent. As an alternative to conducting a performance test under this section for combustion control devices, a control device that can be demonstrated to meet the performance requirements of §63.771(d)(1), (e)(3)(ii) or (f)(1) through a performance testPage 367 of 497

conducted by the manufacturer, as specified in paragraph (h) of this section, can be used. (1) * * * (i) Except as specified in paragraph (e)(2) of this section, a flare, as defined in §63.761, that is designed and operated in accordance with §63.11(b); (ii) Except for control devices used for small glycol dehydration units, a boiler or process heater w ith a design heat input capacity of 44 megawatts or greater; (iii) Except for control devices used for small glycol dehydration units, a boiler or process heater into which the vent stream is introduced with the primary fuel or is used as the primary fuel ; (iv) Except for control devices used for small glycol dehydration units, a boiler or process heater burning hazardous waste for which the owner or operator has either been issued a final permit under 40 CFR part 270 and complies with the requirements of 40 CFR part 266, subpart H; or has certified compliance with the interim status requirements of 40 CFR part 266, subpart H; (v) Except for control devices used for small glycol dehydration units, a hazardous waste incinerator for which the
owner or opera tor has been issued a final permit under 40 CFR part 270 and complies with the requirements of 40 CFR part 264,Page 368 of 497

subpart O; or has certified compliance with the interim status requirements of 40 CFR part 265, subpart O.
* * * * * (2) An owner or operator s hall design and operate each flare, as defined in §63.761, in accordance with the requirements specified in §63.11(b) and the compliance determination shall be conducted using Method 22 of 40 CFR part 60, appendix A, to determine visible emissions. (3) F or a performance test conducted to demonstrate that a control device meets the requirements of §63.771(d)(1), (e)(3)(ii) or (f)(1), the owner or operator shall use the test methods and procedures specified in paragraphs (e)(3)(i) through (v) of this sectio n. The initial and periodic performance tests shall be conducted according to the schedule specified in paragraph (e)(3)(vi) of this section. (i) * * * (B) To determine compliance with the enclosed combustion device total HAP concentration limit specifie d in §63.771(d)(1)(i)(B), or the BTEX emission limit specified in §63.765(b)(1)(iii) the sampling site shall be located at the outlet of the combustion device.
* * * * * (iv) * * * (C) * * *Page 369 of 497

( 1 ) The emission rate correction factor for excess air, integr ated sampling and analysis procedures of Method 3A or 3B, 40 CFR part 60, appendix A, shall be used to determine the oxygen concentration. The samples shall be taken during the same time that the samples are taken for determining TOC concentration or total HAP concentration.
* * * * * (v) To determine compliance with the BTEX emission limit specified in §63.765(b)(1)(iii) the owner or operator shall use one of the following methods: Method 18, 40 CFR part 60, appendix A; ASTM D6420

– 99 (2004), as specified in §63.772(a)(1)(ii); or any other method or data that have been validated according to the applicable procedures in Method 301, 40 CFR part 63, appendix A. The following procedures shall be used to calculate BTEX emissions: (A) The minimum sampling time for each run shall be 1 hour in which either an integrated sample or a minimum of four grab samples shall be taken. If grab sampling is used, then the samples shall be taken at approximately equal intervals in time, such as 15

- minute intervals during the run. (B) The mass rate of BTEX (E o ) shall be computed using the equations and procedures specified in paragraphs (e)(3)(v)(B)( 1 ) and ( 2 ) of this section. ( 1 ) The following equation shall be used:Page 370 of 497

Where: E o = Mass rate of BTEX at the outlet of the contr ol device, dry basis, kilogram per hour. C oj = Concentration of sample component j of the gas stream at the outlet of the control device, dry basis, parts per million by volume. M oj = Molecular weight of sample component j of the gas stream at the outlet of the control device, gram/gram

- mole. Q o = Flowrate of gas stream at the outlet of the control device, dry standard cubic meter per minute. K 2 = Constant, 2.494×10 − 6 (parts per million) (gram

- mole per standard cubic meter) (kilogram/gram) (minute/hour), where standard temperature (gram

- mole per standard cubic meter) is 20 degrees C. n = Number of components in sample. ( 2 ) When the BTEX mass rate is calculated, only B TEX compounds measured by Method 18, 40 CFR part 60, appendix A, or ASTM D6420

– 99 (2004) as specified in §63.772(a)(1)(ii), shall be summed using the equations in paragraph (e)(3)(v)(B)( 1 ) of this section. (vi) The owner or operator shall conduct performa nce tests according to the schedule specified in paragraphs (e)(3)(vi)(A) and (B) of this section. (A) An initial performance test shall be conducted within 180 days after the compliance date that is specified for each affected source in §63.760(f)(7) th rough (8), except that the initial performance test for existing combustion control devices at existing major sources shall be conducted no later than [INSERT DATE 3 YEARS AFTER DATE OF PUBLICATION IN THE FEDERALPage 371 of 497

REGISTER] . If the owner or operator of an e xisting combustion control device at an existing major source chooses to replace such device with a control device whose model is tested under §63.772(h), then the newly installed device shall comply with all provisions of this subpart no later than [INSER T DATE 3 YEARS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER] . The performance test results shall be submitted in the Notification of Compliance Status Report as required in §63.775(d)(1)(ii). (B) Periodic performance tests shall be conducted for all control devices required to conduct initial performance tests except as specified in paragraphs (e)(3)(vi)(B)( 1 ) and ( 2 ) of this section. The first periodic performance test shall be conducted no later than 60 months after the initial performance test requ ired in paragraph (e)(3)(vi)(A) of this section. Subsequent periodic performance tests shall be conducted at intervals no longer than 60 months following the previous periodic performance test or whenever a source desires to establish a new operating limit . The periodic performance test results must be submitted in the next Periodic Report as specified in §63.775(e)(2)(xi). Combustion control devices meeting the criteria in either paragraph (e)(3)(vi)(B)( 1 ) or ( 2 ) of this section are not required to conduct periodic performance
tests.Page 372 of 497

( 1 ) A control device whose model is tested under, and meets the criteria of, §63.772(h), or ( 2 ) A combustion control device demonstrating during the performance test under §63.772(e) that combustion zone temperature is an ind icator of destruction efficiency and operates at a minimum temperature of 760 degrees C. (4) For a condenser design analysis conducted to meet the requirements of §63.771(d)(1), (e)(3)(ii), or (f)(1), the owner or operator shall meet the requirements spec ified in paragraphs (e)(4)(i) and (e)(4)(ii) of this section. Documentation of the design analysis shall be submitted as a part of the Notification of Compliance Status Report as required in §63.775(d)(1)(i). (i) The condenser design analysis shall includ e an analysis of the vent stream composition, constituent concentrations, flowrate, relative humidity, and temperature, and shall establish the design outlet organic compound concentration level, design average temperature of the condenser exhaust vent
str eam, and the design average temperatures of the coolant fluid at the condenser inlet and outlet. As an alternative to the condenser design analysis, an owner or operator may elect to use the procedures specified in paragraph (e)(5) of this section.
* * * * * (5) As an alternative to the procedures in paragraph (e)(4)(i) of this section, an owner or operator may elect to usePage 373 of 497

the procedures documented in the GRI report entitled, “Atmospheric Rich/Lean Method for Determining Glycol Dehydrator Emissions” (GRI

– 95/0368.1) as inputs for the model GRI

- GLYCalc TM , Version 3.0 or higher, to generate a condenser performance

curve. (f) Compliance demonstration for control device performance requirements
. This paragraph applies to the demonstration of compliance with t he control device performance requirements specified in §63.771(d)(1)(i), (e)(3) and (f)(1). Compliance shall be demonstrated using the requirements in paragraphs (f)(1) through (3) of this section. As an alternative, an owner or operator that installs a c ondenser as the control device to achieve the requirements specified in §63.771(d)(1)(ii), (e)(3) or (f)(1) may demonstrate compliance according to paragraph (g) of this section. An owner or operator may switch between compliance with paragraph (f) of this section and compliance with paragraph (g) of this section only after at least 1 year of operation in compliance with the selected approach. Notification of such a change in the compliance method shall be reported in the next Periodic Report, as required i n §63.775(e), following the change.
* * * * * (2) The owner or operator shall calculate the daily average of the applicable monitored parameter in accordance withPage 374 of 497

§63.773(d)(4) except that the inlet gas flowrate to the control device shall not be averaged
. (3) Compliance with the operating parameter limit is achieved when the daily average of the monitoring parameter value calculated under paragraph (f)(2) of this section is either equal to or greater than the minimum or equal to or less than the maximum monitoring value established under paragraph (f)(1) of this section. For inlet gas flowrate, compliance with the operating parameter limit is achieved when the value is equal to or less than the value established under §63.772(h). (4) Except for periods o f monitoring system malfunctions, repairs associated with monitoring system malfunctions, and required monitoring system quality assurance or quality control activities (including, as applicable, system accuracy audits and required zero and span adjustment s), the CMS required in §63.773(d) must be operated at all times the affected source is operating. A monitoring system malfunction is any sudden, infrequent, not reasonably preventable failure of the monitoring system to provide valid data. Monitoring syst em failures that are caused in part by poor maintenance or careless operation are not malfunctions. Monitoring system repairs are required to be completed in response to monitoring system malfunctions and to return the monitoring system to operation as exp editiously as practicable.Page 375 of 497

(5) Data recorded during monitoring system malfunctions, repairs associated with monitoring system malfunctions, or required monitoring system quality assurance or control activities may not be used in calculations used to repor t emissions or operating levels. All the data collected during all other required data collection periods must be used in assessing the operation of the control device and associated control system. (6) Except for periods of monitoring system malfunctio ns, repairs associated with monitoring system malfunctions, and required quality monitoring system quality assurance or quality control activities (including, as applicable, system accuracy audits and required zero and span adjustments), failure to collect required data is a deviation of the monitoring requirements. (g) Compliance demonstration with percent reduction or emission limit performance requirements

— condensers
. This paragraph applies to the demonstration of compliance with the performance require ments specified in §63.771(d)(1)(ii),(e)(3) or (f)(1) for condensers. Compliance shall be demonstrated using the procedures in paragraphs (g)(1) through (3) of this section. (1) The owner or operator shall establish a site

- specific condenser performance c urve according to §63.773(d)(5)(ii). For sources required to meet the BTEX limit in accordance withPage 376 of 497

§63.771(e) or (f)(1) the owner or operator shall identify the minimum percent reduction necessary to meet the BTEX limit. (2) Compliance with the requireme nts in §63.771(d)(1)(ii),(e)(3) or (f)(1) shall be demonstrated by the procedures in paragraphs (g)(2)(i) through (iii) of this section.
* * * * * (iii) Except as provided in paragraphs (g)(2)(iii)(A) and (B) of this section, at the end of each operating day, the owner or operator shall calculate the 365

- day average HAP, or BTEX, emission reduction, as appropriate, from the condenser efficiencies as determined in paragraph (g)(2)(ii) of this section for the preceding 365 operating days. If the owner or
ope rator uses a combination of process modifications and a condenser in accordance with the requirements of §63.771(e), the 365

- day average HAP, or BTEX, emission reduction shall be calculated using the emission reduction achieved through process modification s and the condenser efficiency as determined in paragraph (g)(2)(ii) of this section, both for the previous 365 operating days. (A) After the compliance dates specified in §63.760(f), an owner or operator with less than 120 days of data for determining av erage HAP, or BTEX, emission reduction, as appropriate, shall calculate the average HAP, or BTEX emissionPage 377 of 497

reduction, as appropriate, for the first 120 days of operation after the compliance dates. For sources required to meet the overall 95.0 percent reduc tion requirement, compliance is achieved if the 120

- day average HAP emission reduction is equal to or greater than 90.0 percent. For sources required to meet the BTEX limit under §63.765(b)(1)(iii), compliance is achieved if the average BTEX emission reduc tion is at least 95.0 percent of the required 365

- day value identified under paragraph (g)(1) of this section ( i.e. , at least 76.0 percent if the 365

- day design value is 80.0 percent). (B) After 120 days and no more than 364 days of operation after the co mpliance dates specified in §63.760(f), the owner or operator shall calculate the average HAP emission reduction as the HAP emission reduction averaged over the number of days between the current day and the applicable compliance date. For sources required to meet the overall 95.0

- percent reduction requirement, compliance with the performance requirements is achieved if the average HAP emission reduction is equal to or greater than 90.0 percent. For sources required to meet the BTEX limit under §63.765(b)(1 )(iii), compliance is achieved if the average BTEX emission reduction is at least 95.0 percent of the required 365

- day value identified under paragraph (g)(1) of this section ( i.e. , at least 76.0 percent if the 365

- day design value is 80.0 percent).Page 378 of 497

(3) If the owner or operator has data for 365 days or more of operation, compliance is achieved based on the applicable criteria in paragraphs (g)(3)(i) or (ii) of this section. (i) For sources meeting the HAP emission reduction specified in §63.771(d)(1)(ii ) or (e)(3) the average HAP emission reduction calculated in paragraph (g)(2)(iii) of this section is equal to or greater than 95.0 percent. (ii) For sources required to meet the BTEX limit under §63.771(e)(3) or (f)(1), compliance is achieved if the aver age BTEX emission reduction calculated in paragraph (g)(2)(iii) of this section is equal to or greater than the minimum percent reduction identified in paragraph (g)(1) of this section.
* * * * * (h) Performance testing for combustion control devices

-

ma nufacturers’ performance test. (1) This paragraph applies to the performance testing of a combustion control device conducted by the device manufacturer. The manufacturer shall demonstrate that a specific model of control device achieves the performance

re quirements in (h)(7) of this section by conducting a performance test as specified in paragraphs (h)(2) through (6) of this section. (2) Performance testing shall consist of three one

- hour (or longer) test runs for each of the four following firing rate settings making a total of 12 test runs per test. PropenePage 379 of 497

(propylene) gas shall be used for the testing fuel. All fuel analyses shall be performed by an independent third

- party laboratory (not affiliated with the control device manufacturer or fuel supplie r). (i) 90

- 100 percent of maximum design rate (fixed rate). (ii) 70

- 100

- 70 percent (ramp up, ramp down). Begin the test at 70 percent of the maximum design rate. During the first 5 minutes, incrementally ramp the firing rate to 100 percent of the m aximum design rate. Hold at 100 percent for 5 minutes. In the 10

- 15 minute time range, incrementally ramp back down to 70 percent of the maximum design rate. Repeat three more times for a total of 60 minutes of sampling. (iii) 30

- 70

- 30 percent (ramp u p, ramp down). Begin the test at 30 percent of the maximum design rate. During the first 5 minutes, incrementally ramp the firing rate to 70 percent of the maximum design rate. Hold at 70 percent for 5 minutes. In the 10

- 15 minute time range, incrementally ramp back down to 30 percent of the maximum design rate. Repeat three more times for a total of 60 minutes of sampling. (iv) 0

- 30

- 0 percent (ramp up, ramp down). Begin the test at 0 percent of the maximum design rate. During the first 5 minutes, incr ementally ramp the firing rate to 30 percent of the maximum design rate. Hold at 30 percent for 5 minutes. In the 10

- 15 minute time range, incrementally ramp back down to 0Page 380 of 497

percent of the maximum design rate. Repeat three more times for a total of 60 minut es of sampling. (3) All models employing multiple enclosures shall be tested simultaneously and with all burners operational. Results shall be reported for the each enclosure individually and for the average of the emissions from all interconnected combu stion enclosures/chambers. Control device operating data shall be collected continuously throughout the performance test using an electronic Data Acquisition System and strip chart. Data shall be submitted with the test report in accordance with paragraph (h)(8)(iii) of this section. (4) Inlet testing shall be conducted as specified in paragraphs (h)(4)(i) through (iii) of this section. (i) The fuel flow metering system shall be located in accordance with Method 2A, 40 CFR part 60, appendix A

- 1, (or other approved procedure) to measure fuel flowrate at the control device inlet location. The fitting for filling fuel sample containers shall be located a minimum of 8 pipe diameters upstream of any inlet fuel flow monitoring meter. (ii) Inlet flowrate shall b e determined using Method 2A, 40 CFR part 60, appendix A

- 1. Record the start and stop reading for each 60

- minute THC test. Record the gas pressure and temperature at 5

- minute intervals throughout each 60

- minute THC test.Page 381 of 497

(iii) Inlet fuel sampling shall be conducted in accordance with the criteria in paragraphs (h)(4)(iii)(A) and (B) of this section. (A) At the inlet fuel sampling location, securely connect a Silonite

- coated stainless steel evacuated canister fitted with a flow controller sufficient to fil l the canister over a 1 hour period. Filling shall be conducted as specified in the following: ( 1 ) Open the canister sampling valve at the beginning of the total hydrocarbon (THC) test, and close the canister at the end of each THC run. ( 2 ) Fill one ca nister across the three test runs for each THC test such that one composite fuel sample exists for each test condition. ( 3 ) Label the canisters individually and record on a chain of custody form. (B) Each fuel sample shall be analyzed using the following methods. The results shall be included in the test report. ( 1 ) Hydrocarbon compounds containing between one and five atoms of carbon plus benzene using ASTM D1945

- 03. ( 2 ) Hydrogen (H 2 ), carbon monoxide (CO), carbon dioxide (CO 2 ), nitrogen (N 2 ), oxygen (O 2 ) using ASTM D1945

- 03. ( 3 ) Higher heating value using ASTM D3588

- 98 or ASTM D4891

- 89.Page 382 of 497

(5) Outlet testing shall be conducted in accordance with the criteria in paragraphs (h)(5)(i) through (v) of this section. (i) Sampling and flowrate measured in acc ordance with the following: (A) The outlet sampling location shall be a minimum of 4 equivalent stack diameters downstream from the highest peak flame or any other flow disturbance, and a minimum of one equivalent stack diameter upstream of the exit or an y other flow disturbance. A minimum of two sample ports shall be used. (B) Flowrate shall be measured using Method 1, 40 CFR part 60, Appendix 1, for determining flow measurement traverse point location; and Method 2, 40 CFR part 60, Appendix 1, shall be used to measure duct velocity. If low flow conditions are encountered ( i.e. , velocity pressure differentials less than 0.05 inches of water) during the performance test, a more sensitive manometer or other pressure measurement device shall be used to obta in an accurate flow profile. (ii) Molecular weight shall be determined as specified in paragraphs (h)(4)(iii)(B), (h)(5)(ii)(A), and (h)(5)(ii)(B) of this section. (A) An integrated bag sample shall be collected during the Method 4, 40 CFR part 60, Appendix A, moisture test. Analyze thePage 383 of 497

bag sample using a gas chromatograph

- thermal conductivity detector (GC

- TCD) analysis meeting the following criteria: ( 1 ) Collect th e integrated sample throughout the entire test, and collect representative volumes from each traverse location. ( 2 ) The sampling line shall be purged with stack gas before opening the valve and beginning to fill the bag. ( 3 ) The bag contents shall be vig orously mixed prior to the GC analysis. ( 4 ) The GC

- TCD calibration procedure in Method 3C, 40 CFR part 60, Appendix A, shall be modified by using EPAAlt

- 045 as follows: For the initial calibration, triplicate injections of any single concentration must ag ree within 5 percent of their mean to be valid. The calibration response factor for a single concentration re

- check must be within 10 percent of the original calibration response factor for that concentration. If this criterion is not met, the initial cali bration using at least three concentration levels shall be repeated. (B) Report the molecular weight of: O 2 , CO 2 , methane (CH4), and N 2 and include in the test report submitted under §63.775(d)(iii). Moisture shall be determined using Method 4, 40 CFR pa rt 60, Appendix A. Traverse both ports with the Method 4, 40 CFR part 60, Appendix A, sampling train during each test run. Ambient air shall not be introduced into the Method 3C, 40 CFRPage 384 of 497

part 60, Appendix A, integrated bag sample during the port change. (i ii) Carbon monoxide shall be determined using Method 10, 40 CFR part 60, Appendix A. The test shall be run at the same time and with the sample points used for the EPA Method 25A, 40 CFR part 60, Appendix A, testing. An instrument range of 0

- 10 per million by volume

- dry (ppmvd) shall be used. (iv) Visible emissions shall be determined using Method 22, 40 CFR part 60, Appendix A. The test shall be performed continuously during each test run. A digital color photograph of the exhaust point, taken from the po sition of the observer and annotated with date and time, will be taken once per test run and the four photos included in the test report. (v) Excess air shall be determined using resultant data from the EPA Method 3C tests and EPA Method 3B, 40 CFR part 6 0, Appendix A, equation 3B

- 1. (6) Total hydrocarbons (THC) shall be determined as specified by the following criteria: (i) Conduct THC sampling using Method 25A, 40 CFR part 60, Appendix A, except the option for locating the probe in the center 10 percen t of the stack shall not be allowed. The THC probe must be traversed to 16.7 percent, 50 percent, and 83.3 percent of the stack diameter during each test.Page 385 of 497

(ii) A valid test shall consist of three Method 25A, 40 CFR part 60, Appendix A, tests, each no less than 60 minutes in duration. (iii) A 0

- 10 parts per million by volume

- wet (ppmvw) (as propane) measurement range is preferred; as an alternative a 0

- 30 ppmvw (as carbon) measurement range may be used. (iv) Calibration gases will be propane in air and be certified through EPA Protocol 1

– “EPA Traceability Protocol for Assay and Certification of Gaseous Calibration Standards,” September 1997, as amended August 25, 1999, EPA

– 600/R

– 97/121 (or more recent if updated since 1999). (v) THC measurements shall b e reported in terms of ppmvw as
propane. (vi) THC results shall be corrected to 3 percent CO 2 , as measured by Method 3C, 40 CFR part 60, Appendix A. (vii) Subtraction of methane/ethane from the THC data is not allowed in determining results. (7) Performa nce test criteria: (i) The control device model tested must meet the criteria in paragraphs (h)(7)(i)(A) through (C) of this section: (A) Method 22, 40 CFR part 60, Appendix A, results under paragraph (h)(5)(v) of this section with no indication of visib le emissions, andPage 386 of 497

(B) Average Method 25A, 40 CFR part 60, Appendix A, results under paragraph (h)(6) of this section equal to or less than 10.0 ppmvw THC as propane corrected to 3.0 percent CO 2 , and (C) Average CO emissions determined under paragraph ( h)(5)(iv) of this section equal to or less than 10 parts ppmvd, corrected to 3.0 percent CO 2 . (D) Excess combustion air shall be equal to or greater than 150 percent. (ii) The manufacturer shall determine a maximum inlet gas flowrate which shall not be e xceeded for each control device model to achieve the criteria in paragraph (h)(7)(i) of this section. (iii) A control device meeting the criteria in paragraphs (h)(7)(i)(A) through (C) of this section will have demonstrated a destruction efficiency of 95. 0 percent for HAP regulated under this subpart. (8) The owner or operator of a combustion control device model tested under this section shall submit the information listed in paragraphs (h)(8)(i) through (iii) of this section in the test report required under §63.775(d)(1)(iii). (i) Full schematic of the control device and dimensions of the device components. (ii) Design net heating value (minimum and maximum) of the device.Page 387 of 497

(iii) Test fuel gas flow range (in both mass and volume). Include the minimum and maximum allowable inlet gas flowrate. (iv) Air/stream injection/assist ranges, if used. (v) The test parameter ranges listed in paragraphs (h)(8)(v)(A) through (O) of this section, as applicable for the tested model. (A) Fuel gas delivery pressure and temperature. (B) Fuel gas moisture range. (C) Purge gas usage range. (D) Condensate (liquid fuel) separation range. (E) Combustion zone temperature range. This is required for all devices that measure this parameter. (F) Excess combustion air range. ( G) Flame arrestor(s). (H) Burner manifold pressure. (I) Pilot flame sensor. (J) Pilot flame design fuel and fuel usage. (K) Tip velocity range. (L) Momentum flux ratio. (M) Exit temperature range. (N) Exit flowrate. (O) Wind velocity and direction. (v i) The test report shall include all calibration quality assurance/quality control data, calibration gas values, gasPage 388 of 497

cylinder certification, and strip charts annotated with test times and calibration values. (i) Compliance demonstration for combustion co ntrol devices

- manufacturers’ performance test . This paragraph applies to the demonstration of compliance for a combustion control device tested under the provisions in paragraph (h) of this section. Owners or operators shall demonstrate that a control de vice achieves the performance requirements of §63.771(d)(1), (e)(3)(ii) or (f)(1), by installing a device tested under paragraph (h) of this section and complying with the following criteria: (1) The inlet gas flowrate shall meet the range specified by t he manufacturer. Flowrate shall be calculated as specified in §63.773(d)(3)(i)(H)( 1 ). (2) A pilot flame shall be present at all times of operation. The pilot flame shall be monitored in accordance with §63.773(d)(3)(i)(H)( 2 ). (3) Devices shall be operate d with no visible emissions, except for periods not to exceed a total of 2 minutes during any hour. A visible emissions test using Method 22, 40 CFR part 60, Appendix A, shall be performed each calendar quarter. The observation period shall be 1 hour and s hall be conducted according to EPA Method 22, 40 CFR part 60, Appendix A.Page 389 of 497

(4) Compliance with the operating parameter limit is achieved when the following criteria are met: (i) The inlet gas flowrate monitored under paragraph (i)(1) of this section is e qual to or below the maximum established by the manufacturer; and (ii) The pilot flame is present at all times; and (iii) During the visible emissions test performed under paragraph (i)(3) of this section the duration of visible emissions does not exceed a total of 1 minute during the observation period. Devices failing the visible emissions test shall follow manufacturers repair instructions, if available, or best combustion engineering practice as outlined in the unit inspection and maintenance plan, to return the unit to compliant operation. All repairs and maintenance activities for each unit shall be recorded in a maintenance and repair log and shall be available on site for inspection. (iv) Following return to operation from maintenance or repai r activity, each device must pass a Method 22 observation as described in paragraph (i)(3) of this section. 19. Section 63.773 is amended by: a. Adding paragraph (b); b. Revising paragraph (d)(1) introductory text; c. Revising paragraph (d)(1)(ii) and adding paragraphs (d)(1)(iii) and (iv);Page 390 of 497

d. Revising paragraph (d)(2); e. Revising paragraphs (d)(3)(i)(A) and (B); f. Revising paragraphs (d)(3)(i)(D) and (E); g. Revising paragraphs (d)(3)(i)(F)( 1 ) and ( 2 ); h. Revising paragraph (d)(3)(i)(G); i. Adding paragraph (d)(3)(i)(H); j. Revising paragraph (d)(4); k. Revising paragraph (d)(5)(i); l. Revising paragraphs (d)(5)(ii)(A) through (C); m. Revising paragraph (d)(6) introductory text; n. Revising paragraphs (d)(6)(ii) and (iii); o. Adding pa ragraph (d)(6)(vi); p. Revising paragraph (d)(7); and q. Removing paragraphs (d)(8) and (d)(9) to read as follows: §63.773 Inspection and monitoring requirements.
* * * * * (b) The owner or operator of a control device whose model was tested under §63.772(h) shall develop an inspection and maintenance plan for each control device. At a minimum, the plan shall contain the control device manufacturer’s recommendations
for ensur ing proper operation of the device. Semi

- annual inspections shall be conducted for each control device withPage 391 of 497

maintenance and replacement of control device components made in accordance with the plan.
* * * * * (d) Control device monitoring requirements
. (1 ) For each control device, except as provided for in paragraph (d)(2) of this section, the owner or operator shall install and operate a continuous parameter monitoring system in accordance with the requirements of paragraphs (d)(3) through (7) of this sec tion. Owners or operators that install and operate a flare in accordance with §63.771(d)(1)(iii) or (f)(1)(iii) are exempt from the requirements of paragraphs (d)(4) and (5) of this section. The continuous monitoring system shall be designed and operated s o that a determination can be made on whether the control device is achieving the applicable performance requirements of §63.771(d), (e)(3) or (f)(1). Each continuous parameter monitoring system shall meet the following specifications and requirements:
* * * * * (ii) A site

- specific monitoring plan must be prepared that addresses the monitoring system design, data collection, and the quality assurance and quality control elements outlined in paragraph (d) of this section and in §63.8(d). Each CPMS must be installed, calibrated, operated, and maintained in accordance with the procedures in your approved site

- specific monitoringPage 392 of 497

plan. Using the process described in §63.8(f)(4), you may request approval of monitoring system quality assurance and quality contro l procedures alternative to those specified in paragraphs (d)(1)(ii)(A) through (E) of this section in your site

- specific monitoring plan. (A) The performance criteria and design specifications for the monitoring system equipment, including the sample int erface, detector signal analyzer, and data acquisition and calculations; (B) Sampling interface ( e.g. , thermocouple) location such that the monitoring system will provide representative measurements; (C) Equipment performance checks, system accuracy au dits, or other audit procedures; (D) Ongoing operation and maintenance procedures in accordance with provisions in §63.8(c)(1) and (c)(3); and (E) Ongoing reporting and recordkeeping procedures in accordance with provisions in §63.10(c), (e)(1), and (e)(2)(i). (iii) The owner or operator must conduct the CPMS equipment performance checks, system accuracy audits, or other audit procedures specified in the site

- specific monitoring plan at least once every 12 months. (iv) The owner or operator must co nduct a performance evaluation of each CPMS in accordance with the site

- specific monitoring plan.Page 393 of 497

(2) An owner or operator is exempt from the monitoring requirements specified in paragraphs (d)(3) through (7) of this section for the following types of co ntrol devices: (i) Except for control devices for small glycol dehydration units, a boiler or process heater in which all vent streams are introduced with the primary fuel or is used as the primary fuel;

or (ii) Except for control devices for small glyco l dehydration units, a boiler or process heater with a design heat input capacity equal to or greater than 44 megawatts. (3) * * * (i) * * * (A) For a thermal vapor incinerator that demonstrates during the performance test conducted under §63.772(e) tha t the combustion zone temperature is an accurate indicator of performance, a temperature monitoring device equipped with a continuous recorder. The monitoring device shall have a minimum accuracy of ±1 percent of the temperature being monitored in degrees C, or ±2.8 degrees C, whichever value is greater. The temperature sensor shall be installed at a location representative of the combustion zone temperature. (B) For a catalytic vapor incinerator, a temperature monitoring device equipped with a continuous recorder. The device shall be capable of monitoring temperature at twoPage 394 of 497

locations and have a minimum accuracy of ±1 percent of the temperature being monitored in degrees C, or ±2.8 degrees C, whichever value is greater. One temperature sensor shall be insta lled in the vent stream at the nearest feasible point to the catalyst bed inlet and a second temperature sensor shall be installed in the vent stream at the nearest feasible point to the catalyst bed outlet.
* * * * * (D) For a boiler or process heater, a temperature monitoring device equipped with a continuous recorder. The temperature monitoring device shall have a minimum accuracy of ±1 percent of the temperature being monitored in degrees C, or ±2.8 degrees C, whichever value is greater. The temperatur e sensor shall be installed at a location representative of the combustion zone temperature. (E) For a condenser, a temperature monitoring device equipped with a continuous recorder. The temperature monitoring device shall have a minimum accuracy of ±1 pe rcent of the temperature being monitored in degrees C, or ±2.8 degrees C, whichever value is greater. The temperature sensor shall be installed at a location in the exhaust vent stream from the condenser. (F) * * *Page 395 of 497

( 1 ) A continuous parameter monitoring s ystem to measure and record the average total regeneration stream mass flow or volumetric flow during each carbon bed regeneration cycle. The flow sensor must have a measurement sensitivity of 5 percent of the flowrate or 10 cubic feet per minute, whicheve r is greater. The mechanical connections for leakage must be checked at least every month, and a visual inspection must be performed at least every 3 months of all components of the flow CPMS for physical and operational integrity and all electrical connec tions for oxidation and galvanic corrosion if your flow CPMS is not equipped with a redundant flow sensor; and ( 2 ) A continuous parameter monitoring system to measure and record the average carbon bed temperature for the duration of the carbon bed steamin g cycle and to measure the actual carbon bed temperature after regeneration and within 15 minutes of completing the cooling cycle. The temperature monitoring device shall have a minimum accuracy of ±1 percent of the temperature being monitored in degrees C , or ±2.8 degrees C, whichever value is greater. (G) For a nonregenerative

- type carbon adsorption system, the owner or operator shall monitor the design carbon replacement interval established using a performance test performed in accordance with §63.772( e)(3) shall be based on thePage 396 of 497

total carbon working capacity of the control device and source operating schedule. (H) For a control device model whose model is tested under §63.772(h): ( 1 ) The owner or operator shall determine actual average inlet waste gas flowrate using the model GRI

- GLYCalc TM , Version 3.0 or higher, ProMax, or AspenTech HYSYS. Inputs to the models shall be representative of actual operating conditions of the controlled unit. The determination shall be performed to coincide with the visib le emissions test under §63.772(i)(3); ( 2 ) A heat sensing monitoring device equipped with a continuous recorder that indicates the continuous ignition of the pilot flame.
* * * * * (4) Using the data recorded by the monitoring system, except for inlet g as flowrate, the owner or operator must calculate the daily average value for each monitored operating parameter for each operating day. If the emissions unit operation is continuous, the operating day is a 24

- hour period. If the emissions unit operation i s not continuous, the operating day is the total number of hours of control device operation per 24

- hour period. Valid data points must be available for 75 percent of the operating hours in an operating day to compute the daily average.Page 397 of 497

(5) * * *

(i) Th e owner or operator shall establish a minimum operating parameter value or a maximum operating parameter value, as appropriate for the control device, to define the conditions at which the control device must be operated to continuously achieve the applica ble performance requirements of §63.771(d)(1), (e)(3)(ii) or (f)(1). Each minimum or maximum operating parameter value shall be established as follows: (A) If the owner or operator conducts performance tests in accordance with the requirements of §63.772( e)(3) to demonstrate that the control device achieves the applicable performance requirements specified in §63.771(d)(1), (e)(3)(ii) or (f)(1), then the minimum operating parameter value or the maximum operating parameter value shall be established based o n values measured during the performance test and supplemented, as necessary, by a condenser design analysis or control device manufacturer recommendations or a combination of both. (B) If the owner or operator uses a condenser design analysis in accordan ce with the requirements of §63.772(e)(4) to demonstrate that the control device achieves the applicable performance requirements specified in §63.771(d)(1), (e)(3)(ii) or (f)(1), then the minimum operating parameter value or the maximum operating paramete r value shall be established based onPage 398 of 497

the condenser design analysis and may be supplemented by the condenser manufacturer's recommendations. (C) If the owner or operator operates a control device where the performance test requirement was met under §63.772(h) to demonstrate that the control device achieves the applicable performance requirements specified in §63.771(d)(1), (e)(3)(ii) or (f)(1), then the maximum inlet gas flowrate shall be established based on the performance test and supplemented, as necessary, by the manufacturer recommendations. (ii) * * * (A) If the owner or operator conducts a performance test in accordance with the requirements of §63.772(e)(3) to demonstrate that the condenser achieves the applicable performance requirements i n §63.771(d)(1), (e)(3)(ii) or (f)(1), then the condenser performance curve shall be based on values measured during the performance test and supplemented as necessary by control device design analysis, or control device manufacturer's recommendations, or a combination or both. (B) If the owner or operator uses a control device design analysis in accordance with the requirements of §63.772(e)(4)(i) to demonstrate that the condenser achieves the applicable performance requirements specified in §63.771(d)(1) , (e)(3)(ii) or (f)(1), then the condenser performance curve shall be basedPage 399 of 497

on the condenser design analysis and may be supplemented by the control device manufacturer's recommendations. (C) As an alternative to paragraph (d)(5)(ii)(B) of this section, th e owner or operator may elect to use the procedures documented in the GRI report entitled, “Atmospheric Rich/Lean Method for Determining Glycol Dehydrator Emissions” (GRI

– 95/0368.1) as inputs for the model GRI

- GLYCalc TM , Version 3.0 or higher, to generate a condenser performance curve.
* * * * * (6) An excursion for a given control device is determined to have occurred when the monitoring data or lack of monitoring data result in any one of the criteria specified in paragraphs (d)(6)(i) through (d)(6)(vi) of this section being met. When multiple operating parameters are monitored for the same control device and during the same operating day and more than one of these operating parameters meets an excursion criterion specified in paragraphs (d)(6)(i) throu gh (d)(6)(vi) of this section, then a single excursion is determined to have occurred for the control device for that operating day.
* * * * * (ii) For sources meeting §63.771(d)(1)(ii), an excursion occurs when the 365

- day average condenser efficiency ca lculated according to the requirements specified in §63.772(g)(2)(iii) is less than 95.0 percent. For sources meeting §63.771(f)(1), anPage 400 of 497

excursion occurs when the 365

- day average condenser efficiency calculated according to the requirements specified in §63 .772(g)(2)(iii) is less than 95.0 percent of the identified 365

- day required percent reduction. (iii) For sources meeting §63.771(d)(1)(ii), if an owner or operator has less than 365 days of data, an excursion occurs when the average condenser efficiency calculated according to the procedures specified in §63.772(g)(2)(iii)(A) or (B) is less than 90.0 percent. For sources meeting §63.771(f)(1), an excursion occurs when the 365

- day average condenser efficiency calculated according to the requirements specif ied in §63.772(g)(2)(iii) is less than the identified 365

- day required percent reduction.
* * * * * (vi) For control device whose model is tested under §63.772(h) an excursion occurs when: (A) The inlet gas flowrate exceeds the maximum established during the test conducted under §63.772(h). (B) Failure of the quarterly visible emissions test conducted under §63.772(i)(3) occurs. (7) For each excursion, the owner or operator shall be deemed to have failed to have applied control in a manner that achieve s the required operating parameter limits. Failure toPage 401 of 497

achieve the required operating parameter limits is a violation of this standard.
* * * * * 20. Section 63.774 is amended by: a. Revising paragraph (b)(3) introductory text; b. Removing and reserving paragraph (b)(3)(ii); c. Revising paragraph (b)(4)(ii) introductory text; d. Adding paragraph (b)(4)(ii)(C); e. Revising paragraph (b)(4)(iii); f. Adding paragraph (b)(7)(ix); and g. Adding paragraphs (g) through (i) to read as follows: §63.774 Record keeping requirements.
* * * * * (b) * * * (3) Records specified in §63.10(c) for each monitoring system operated by the owner or operator in accordance with the requirements of §63.773(d). Notwithstanding the requirements of §63.10(c), monitoring data re corded during periods identified in paragraphs (b)(3)(i) through (b)(3)(iv) of this section shall not be included in any average or percent leak rate computed under this subpart. Records shall be kept of the times and durations of all such periods and any other periods during process or control device operation when monitors are not operating or failed to collect required data.Page 402 of 497

* * * * * (ii) [Reserved]
* * * * * (4) * * * (ii) Records of the daily average value of each continuously monitored parameter for each operating day determined according to the procedures specified in §63.773(d)(4) of this subpart, except as specified in paragraphs (b)(4)(ii)(A) through (C) of this section.
* * * * * (C) For a control device whose model is tested under §63.772(h ), the records required in paragraph (h) of this section. (iii) Hourly records of the times and durations of all periods when the vent stream is diverted from the control device or the device is not operating.
* * * * * (7) * * * (ix) Records identifyi ng the carbon replacement schedule under §63.771(d)(5) and records of each carbon replacement.
* * * * * (g) The owner or operator of an affected source subject to this subpart shall maintain records of the occurrence and duration of each malfunction of o peration ( i.e. , processPage 403 of 497

equipment) or the air pollution control equipment and monitoring equipment. The owner or operator shall maintain records of actions taken during periods of malfunction to minimize emissions in accordance with §63.764(a), including c orrective actions to restore malfunctioning process and air pollution control and monitoring equipment to its normal or usual manner of operation. (h) Record the following when using a control device whose model is tested under §63.772(h) to comply with § 63.771(d), (e)(3)(ii) and (f)(1): (1) All visible emission readings and flowrate calculations made during the compliance determination required by §63.772(i); and (2) All hourly records and other recorded periods when the pilot flame is absent. (i) The date the semi

- annual maintenance inspection required under §63.773(b) is performed. Include a list of any modifications or repairs made to the control device during the inspection and other maintenance performed such as cleaning of the fuel nozzles. 21. S ection 63.775 is amended by: a. Revising paragraph (b)(1); b. Revising paragraph (b)(6); c. Removing and reserving paragraph (b)(7);Page 404 of 497

d. Revising paragraph (c)(1); e. Revising paragraph (c)(6); f. Revising paragraph (c)(7)(i); g. Revising paragraph ( d)(1)(i); h. Revising paragraph (d)(1)(ii) introductory text; i. Revising paragraph (d)(5)(ii); j. Adding paragraph (d)(5)(iv); k. Revising paragraph (d)(11); l. Adding paragraphs (d)(13) and (d)(14); m. Revising paragraphs (e)(2) introductory text, (e)(2)(ii)(B) and (C); n. Adding paragraphs (e)(2)(ii)(E) and (F); o Adding paragraphs (e)(2)(xi) through (xiii); and p. Adding paragraph (g) to read as follows: §63.775 Reporting requirements.
* * * * * (b) * * * (1) The initial notifications requir ed for existing affected sources under §63.9(b)(2) shall be submitted as provided in paragraphs (b)(1)(i) and (ii) of this section. (i) Except as otherwise provided in paragraph (ii), the initial notifications shall be submitted by 1 year after an affecte d source becomes subject to the provisions of this subpart or by June 17, 2000, whichever is later. AffectedPage 405 of 497

sources that are major sources on or before June 17, 2000, and plan to be area sources by June 17, 2002, shall include in this notification a brief , nonbinding description of a schedule for the action(s) that are planned to achieve area source status. (ii) An affected source identified under §63.760(f)(7) or (9) shall submit an initial notification required for existing affected sources under §63. 9(b)(2) within 1 year after the affected source becomes subject to the provisions of this subpart or by [INSERT DATE ONE YEAR AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER] , whichever is later. An affected source identified under §63.760(f)(7) or (9) t hat plans to be an area source by [INSERT DATE THREE YEARS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER] , shall include in this notification a brief, nonbinding description of a schedule for the action(s) that are planned to achieve area source status
. * * * * * (6) If there was a malfunction during the reporting period, the Periodic Report specified in paragraph (e) of this section shall include the number, duration, and a brief description for each type of malfunction which occurred during the repor ting period and which caused or may have caused any applicable emission limitation to be exceeded. The report must also include a description of actions taken by an owner or operator during a malfunction of an affected source to minimize emissions inPage 406 of 497

accor dance with §63.764(j), including actions taken to correct a malfunction. (7) [Reserved]
* * * * * (c) * * * (1) The initial notifications required under §63.9(b)(2) not later than January 3, 2008. In addition to submitting your initial notification to t he addressees specified under §63.9(a), you must also submit a copy of the initial notification to the EPA's Office of Air Quality Planning and Standards. Send your notification via e

- mail to Oil and Gas Sector@epa.gov or via U.S. mail or other mail delive ry service to U.S. EPA, Sector Policies and Programs Division/Fuels and Incineration Group (E143

– 01), Attn: Oil and Gas Project Leader, Research Triangle Park, NC 27711.
* * * * * (6) If there was a malfunction during the reporting period, the Periodic Re port specified in paragraph (e) of this section shall include the number, duration, and a brief description for each type of malfunction which occurred during the reporting period and which caused or may have caused any applicable emission limitation to be exceeded. The report must also include a description of actions taken by an owner or operator during a malfunction of an affected source to minimize emissions inPage 407 of 497

accordance with §63.764(j), including actions taken to correct a malfunction. (7) * * * (i) Documentation of the source's location relative to the nearest UA plus offset and UC boundaries. This information shall include the latitude and longitude of the affected source; whether the source is located in an urban cluster with 10,000 people or more ; the distance in miles to the nearest urbanized area boundary if the source is not located in an urban cluster with 10,000 people or more; and the name of the nearest urban cluster with 10,000 people or more and nearest urbanized area.
* * * * * (d) * * * (1) * * * (i) The condenser design analysis documentation specified in §63.772(e)(4) of this subpart, if the owner or operator elects to prepare a design analysis. (ii) If the owner or operator is required to conduct a performance test, the performanc e test results including the information specified in paragraphs (d)(1)(ii)(A) and (B) of this section. Results of a performance test conducted prior to the compliance date of this subpart can be used provided that the test was conducted using the methods specified in §63.772(e)(3) and that the test conditions are representative ofPage 408 of 497

current operating conditions. If the owner or operator operates a combustion control device model tested under §63.772(h), an electronic copy of the performance test results shal l be submitted via email to Oil and Gas PT@EPA.GOV unless the test results for that model of combustion control device are posted at the following website: epa.gov/airquality/oilandgas/.
* * * * * (5) * * * (ii) An explanation of the rationale for why the owner or operator selected each of the operating parameter values established in §63.773(d)(5). This explanation shall include any data and calculations used to develop the value and a description of why the chosen value indicates that the control devi ce is operating in accordance with the applicable requirements of §63.771(d)(1), (e)(3)(ii) or (f)(1).
* * * * * (iv) For each carbon adsorber, the predetermined carbon replacement schedule as required in §63.771(d)(5)(i).
* * * * * (11) The owner or ope rator shall submit the analysis prepared under §63.771(e)(2) to demonstrate the conditions by which the facility will be operated to achieve the HAP emission reduction of 95.0 percent, or the BTEX limit in §63.765(b)(1)(iii), through process modifications or aPage 409 of 497

combination of process modifications and one or more control devices.
* * * * * (13) If the owner or operator installs a combustion control device model tested under the procedures in §63.772(h), the data listed under §63.772(h)(8). (14) For each com bustion control device model tested under §63.772(h), the information listed in paragraphs (d)(14)(i) through (vi) of this section. (i) Name, address and telephone number of the control device manufacturer. (ii) Control device model number. (iii) Control d evice serial number. (iv) Date the model of control device was tested by the manufacturer. (v) Manufacturer’s HAP destruction efficiency rating. (vi) Control device operating parameters, maximum allowable inlet gas flowrate. (e) * * * (2) The owner or o perator shall include the information specified in paragraphs (e)(2)(i) through (ix) of this section, as applicable.
* * * * * (ii) * * *Page 410 of 497

* * * * * (B) For each excursion caused when the 365

- day average condenser control efficiency is less than the value specified in §63.773(d)(6)(ii), the report must include the 365

- day average values of the condenser control efficiency, and the date and duration of the period that the excursion occurred. (C) For each excursion caused when condenser control efficiency i s less than the value specified in §63.773(d)(6)(iii), the report must include the average values of the condenser control efficiency, and the date and duration of the period that the excursion occurred.
* * * * * (E) For each excursion caused when the ma ximum inlet gas flowrate identified under §63.772(h) is exceeded, the report must include the values of the inlet gas identified and the date and duration of the period that the excursion occurred. (F) For each excursion caused when visible emissions dete rmined under §63.772(i) exceed the maximum allowable duration, the report must include the date and duration of the period that the excursion occurred, repairs affected to the unit, and date the unit was returned to service.
* * * * * (xi) The results of any periodic test as required in §63.772(e)(3) conducted during the reporting period.Page 411 of 497

(xii) For each carbon adsorber used to meet the control device requirements of §63.771(d)(1), records of each carbon replacement that occurred during the reporting perio d. (xiii) For combustion control device inspections conducted in accordance with §63.773(b) the records specified in §63.774(i). (ix) Certification by a responsible official of truth, accuracy, and completeness. This certification shall state that, based on information and belief formed after reasonable inquiry, the statements and information in the document are true, accurate, and complete.
* * * * * (g) Electronic reporting . (1) Within 60 days after the date of completing each performance test(def ined in §63.2) as required by this subpart you must submit the results of the performance tests required by this subpart to EPA’s WebFIRE database by using the Compliance and Emissions Data Reporting Interface (CEDRI) that is accessed through EPA’s Central Data Exchange (CDX)(www.epa.gov/cdx). Performance test data must be submitted in the file format generated through use of EPA’s Electronic Reporting Tool (ERT) (see http://www.epa.gov/ttn/chief/ert/index.html ). Only data collected using test methods on the ERT website are subject to this requirement for submitting reports electronically toPage 412 of 497

WebFIRE. Owners or operators who claim that some of the information being submi tted for performance tests is confidential business information (CBI) must submit a complete ERT file including information claimed to be CBI on a compact disk or other commonly used electronic storage media (including, but not limited to, flash drives) to EPA. The electronic media must be clearly marked as CBI and mailed to U.S. EPA/OAPQS/CORE CBI Office, Attention: WebFIRE Administrator, MD C404

- 02, 4930 Old Page Rd., Durham, NC 27703. The same ERT file with the CBI omitted must be submitted to EPA via CDX as described earlier in this paragraph. At the discretion of the delegated authority, you must also submit these reports, including the confidential business information, to the delegated authority in the format specified by the delegated authority. (2) All reports required by this subpart not subject to the requirements in paragraph (g)(1) of this section must be sent to the Administrator at the appropriate address listed in §63.13. The Administrator or the delegated authority may request a report in any form suitable for the specific case (e.g., by commonly used electronic media such as Excel spreadsheet, on CD or hard copy). The Administrator retains the right to require submittal of reports subject to paragraph (g)(1) of this section in paper forma t.Page 413 of 497

22. Appendix to subpart HH of part 63 is amended by revising Table 2 to read as follows: Appendix to Subpart HH of Part 63 — Tables
* * * * * Table 2 to Subpart HH of Part 63 — Applicability of 40 CFR Part 63 General Provisions to Subpart HH

General provi sions reference Applicable to subpart HH Explanation §63.1(a)(1) Yes. §63.1(a)(2) Yes. §63.1(a)(3) Yes. §63.1(a)(4) Yes. §63.1(a)(5) No Section reserved. §63.1(a)(6) Yes. §63.1(a)(7) through (a)(9) No Section reserved. §63.1(a)(10) Yes. §63.1(a)(11) Yes. §63.1(a)(12) Yes. §63.1(b)(1) No Subpart HH specifies applicability. §63.1(b)(2) No Section reserved. §63.1(b)(3) Yes. §63.1(c)(1) No Subpart HH specifies applicability. §63.1(c)(2) Yes. Subpart HH exempts area sources from the requirement to obtain a Title V permit unless otherwise required by law as specified in §63.760(h). §63.1(c)(3) and (c)(4) No Section reserved. §63.1(c)(5) Yes. §63.1(d) No Section reserved. §63.1(e) Yes. §63.2 Yes Except definition of major source is unique for this source category and there are additional definitions in subpart HH. §63.3(a) through (c) Yes.Page 414 of 497

§63.4(a)(1) through (a)(2) Yes. §63.4(a)(3) through (a)(5) No Section reserved. §63.4(b) Yes. §63.4(c) Yes. §63.5(a)(1) Yes. §63.5(a)(2) Yes. §63.5(b)(1) Yes. §63.5(b)(2) No Section reserved. §63.5(b)(3) Yes. §63.5(b)(4) Yes. §63.5(b)(5) No Section Reserved. §63.5(b)(6) Yes. §63.5(c) No Section reserved. §63.5(d)(1) Yes. §63.5(d)(2) Yes. §63.5(d)(3) Yes. §63.5(d)(4) Yes. §63.5(e) Yes. §63.5(f)(1) Yes. §63.5(f)(2) Yes. §63.6(a) Yes. §63.6(b)(1) Yes. §63.6(b)(2) Yes. §63.6(b)(3) Yes. §63.6(b)(4) Yes. §63.6(b)(5) Yes. §63.6(b)(6) No Section reserved. §63.6(b)(7) Yes. §63.6(c)(1) Yes. §63.6(c)(2) Yes. §63.6(c)(3) through (c)(4) No Section reserved. §63.6(c)(5) Yes. §63.6(d) No Section reserved. §63.6(e) Yes. §63.6(e)(1)(i) No See §63.764(j) for general duty requirement. §63.6(e)(1)(ii) No. §63.6(e)(1)(iii) Yes. §63.6(e)(2) No Section reserved. §63.6(e)(3) No. §63.6(f)(1) No. §63.6(f)(2) Yes. §63.6(f)(3) Yes.Page 415 of 497

§63.6(g) Yes. §63.6(h) Yes. §63.6(i)(1) through (i)(14) Yes. §63.6(i)(15) No Section reserved. §63.6(i)(16) Yes. §63.6(j) Yes. §63.7(a)(1) Yes. §63.7(a)(2) Yes But the performance test results must be submitted within 180 days after the compliance date. §63.7(a)(3) Yes. §63.7(b) Yes. §63.7(c) Yes. §63.7(d) Yes. §63.7(e)(1) No. §63.7(e)(2) Yes. §63.7(e)(3) Yes. §63.7(e)(4) Yes. §63.7(f) Yes. §63.7(g) Yes. §63.7(h) Yes. §63.8(a)(1) Yes. §63.8(a)(2) Yes. §63.8(a)(3) No Section reserved. §63.8(a)(4) Yes. §63.8(b)(1) Yes. §63.8(b)(2) Yes. §63.8(b)(3) Yes. §63.8(c)(1) No. §63.8(c)(1)(i) §63.8(c)(1)(ii) §63.8(c)(1)(iii) No. Yes. Pending. §63.8(c)(2) Yes. §63.8(c)(3) Yes. §63.8(c)(4) Yes. §63.8(c)(4)(i) No Subpart HH does not require continuous opacity monitors. §63.8(c)(4)(ii) Yes. §63.8(c)(5) through (c)(8) Yes. §63.8(d) Yes. §63.8(d)(3) Yes. Except for last sentence, which refers to an SSM plan. SSM plans are not required. §63.8(e) Yes Subpart HH does notPage 416 of 497
specifically require continuous emissions monitor performance evaluation, however, the Administrator can request that one be conducted. §63.8(f)(1) through (f)(5) Yes. §63.8(f)(6) Yes. §63.8(g) No Subpart HH specifies continuous monitoring system data reduction requirements. §63.9(a) Yes. §63.9(b)(1) Yes. §63.9(b)(2) Yes Existing sources are given 1 year (rather than 120 days) to submit this notification. Major and area sources that meet §63.764(e) do not have to submit initial notifications. §63.9(b)(3) No Section reserved. §63.9(b)(4) Yes. §63.9(b)(5) Yes. §63.9(c) Yes. §63.9(d) Yes. §63.9(e) Yes. §63.9(f) Yes. §63.9(g) Yes. §63.9(h)(1) through (h)(3) Yes Area sources located outside UA plus offset and UC boundaries are not required to submit notifications of compliance status. §63.9(h)(4) No Section reserved. §63.9(h)(5) through (h)(6) Yes. §63.9(i) Yes. §63.9(j) Yes. §63.10(a) Yes. §63.10(b)(1) Yes §63.774(b)(1) requires sources to maintain the most recent 12 months of data on

- site and allows offsite storage for the remaining 4 years of data. §63.10(b)(2) Yes. §63.10(b)(2)(i) No. §63.10(b)(2)(ii) No See §63.774(g) for recordkeeping of occurrence,Page 417 of 497
duration, and actions taken during malfunctions. §63.10(b)(2)(iii) Yes. §63.10(b)(2)(iv) through (b)(2)(v) No. §63.10(b)(2)(vi) through (b)(2)(xiv) Yes. §63.10(b)(3) Yes §63.774(b)(1) requires sources to maintain the most recent 12 months of data on

- site and allows offsite storage for the remaining 4 years of data. §63.10(c)(1) Yes. §63.10(c)(2) through (c)(4) No Sections reserved. §63.10(c)(5) through (8) (c)(8) Yes. §63.10(c)(9) No Section reserved. §63.10(c)(10) through (11) No See §63.774(g) for recordkeeping of malfunctions. §63.10(c)(12) through (14) Yes. §63.10(c)(15) No. §63.10(d)(1) Yes. §63.10(d)(2) Yes Area sources located outside UA plus offset and UC boundaries do not have to submit performance test reports. §63.10(d)(3) Yes. §63.10(d)(4) Yes. §63.10(d)(5) No See §63.775(b)(6) or (c)(6) for reporting of malfunctions. §63.10(e)(1) Yes Area sources located outside UA plus offset and UC boundaries are not required to submit reports. §63.10(e)(2) Yes Area sources located outside UA plus offset and UC boundaries are not required to submit reports. §63.10(e)(3)(i) Yes Subpart HH requires major sources to submit Periodic Reports semi

- annually. Area sources are required to submit Periodic Reports annually. Area sour ces located outside UA plusPage 418 of 497

offset and UC boundaries are not required to submit reports. §63.10(e)(3)(i)(A) Yes. §63.10(e)(3)(i)(B) Yes. §63.10(e)(3)(i)(C) No Section reserved. §63.10(e)(3)(ii) through (viii) Yes. §63.10(f) Yes. §63.11(a) and (b) Yes. §63.11(c), (d), and (e) Yes. §63.12(a) through (c) Yes. §63.13(a) through (c) Yes. §63.14(a) and (b) Yes. §63.15(a) and (b) Yes. §63.16 Yes.Page 419 of 497

Subpart HHH – - [Amended] 23. Section 63.1270 is amended by: a. Revising paragraph (a) introductory text; b. Revising paragraph (a)(4); c. Revising paragraph (b); d. Revising paragraphs (d)(1) and (d)(2); and e. Adding paragraphs (d)(3) and (4) to read as follows: §63.1270 Applicability and designation of affected source. (a) This subpart applies to owners and operators of natural gas transmission and storage facilities that transport or store natural gas prior to entering the pipeline to a local distribution company or to a final end user (if there is no local distribution company ), and that are major sources of hazardous air pollutants (HAP) emissions as defined in §63.1271. Emissions for major source determination purposes can be estimated using the maximum natural gas throughput calculated in either paragraph (a)(1) or (2) of th is section and paragraphs (a)(3) and (4) of this section. As an alternative to calculating the maximum natural gas throughput, the owner or operator of a new or existing source may use the facility design maximum natural gas throughput to estimate the maxi mum potential emissions. Other means to determine the facility's major source status are allowed, provided the information is documented and recorded to the Administrator's satisfaction in accordance withPage 420 of 497

§63.10(b)(3). A compressor station that transports natural gas prior to the point of custody transfer or to a natural gas processing plant (if present) is not considered a part of the natural gas transmission and storage source category. A facility that is determined to be an area source, but subsequently increases its emissions or its potential to emit above the major source levels (without obtaining and complying with other limitations that keep its potential to emit HAP below major source levels), and becomes a major source, must comply thereafter with a ll applicable provisions of this subpart starting on the applicable compliance date specified in paragraph (d) of this section. Nothing in this paragraph is intended to preclude a source from limiting its potential to emit through other appropriate mechani sms that may be available through the permitting authority.
* * * * * (4) The owner or operator shall determine the maximum values for other parameters used to calculate potential emissions as the maximum over the same period for which maximum throughput is determined as specified in paragraph (a)(1) or (a)(2) of this section. These parameters shall be based on an annual average or the highest single measured value. For estimating maximum potential emissions from glycol dehydration units, the glycol circul ation rate used in the calculation shallPage 421 of 497

be the unit’s maximum rate under its physical and operational design consistent with the definition of potential to emit in §63.2. (b) The affected source is each new and existing glycol dehydration unit specified in paragraphs (b)(1) through (3) of this section. (1) Each large glycol dehydration unit; (2) Each small glycol dehydration unit for which construction commenced before August 23, 2011, is an existing small glycol dehydration unit. (3) Each small glycol dehydration unit for which construction commenced on or after August 23, 2011, is a new small glycol dehydration unit.
* * * * * (d) * * * (1) Except as specified in paragraphs (d)(3) through (4) of this section, the owner or operator of an affected sou rce, the construction or reconstruction of which commenced before February 6, 1998, shall achieve compliance with this provisions of the subpart no later than June 17, 2002 except as provided for in §63.6(i). The owner or operator of an area source, the

co nstruction or reconstruction of which commenced before February 6, 1998, that increases its emissions of (or its potential to emit) HAP such that the source becomes a majorPage 422 of 497

source that is subject to this subpart shall comply with this subpart 3 years after becoming a major source. (2) Except as specified in paragraphs (d)(3) through (4) of this section, the owner or operator of an affected source, the construction or reconstruction of which commences on or after February 6, 1998, shall achieve compliance w ith the provisions of this subpart immediately upon initial startup or June 17, 1999, whichever date is later. Area sources, the construction or reconstruction of which commences on or after February 6, 1998, that become major sources shall comply with the provisions of this standard immediately upon becoming a major source. (3) Each affected small glycol dehydration unit, as defined in §63.1271, located at a major source, that commenced construction before August 23, 2011, must achieve compliance no late r than [INSERT DATE 3 YEARS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER] , except as provided in §63.6(i). (4) Each affected small glycol dehydration unit, as defined in §63.1271, located at a major source, that commenced construction on or after Aug ust 23, 2011, must achieve compliance immediately upon initial startup or [INSERT DATE 60 DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER] , whichever is later.
* * * * * 24. Section 63.1271 is amended by:Page 423 of 497

a. Adding, in alphabetical order, new defi nitions for the terms “affirmative defense,” “BTEX,” “flare,” “large glycol dehydration units,” “responsible official” and “small glycol dehydration units”; and b. Revising the definitions for “glycol dehydration unit baseline operations” and “temperatur e monitoring device” to read as follows: §63.1271 Definitions.
* * * * * Affirmative defense means, in the context of an enforcement proceeding, a response or defense put forward by a defendant, regarding which the defendant has the burden of proof, and the merits of which are independently and objectively evaluated in a judicial or administrativ e proceeding.
* * * * *
BTEX means benzene, toluene, ethyl benzene and xylene.
* * * * * Flare means a thermal oxidation system using an open flame ( i.e. , without enclosure).
* * * * * Glycol dehydration unit baseline operations means operations repres entative of the large glycol dehydration unit operations as of June 17, 1999 and the small glycol dehydration unit operations as of August 23, 2011,. For the purposes of thisPage 424 of 497

subpart, for determining the percentage of overall HAP emission reduction attribu table to process modifications, glycol dehydration unit baseline operations shall be parameter values (including, but not limited to, glycol circulation rate or glycol

- HAP absorbency) that represent actual long

- term conditions ( i.e. , at least 1 year). Glyc ol dehydration units in operation for less than 1 year shall document that the parameter values represent expected long

- term operating conditions had process modifications not been made.
* * * * * Large glycol dehydration unit means a glycol dehydration

u nit with an actual annual average natural gas flowrate equal to or greater than 283.0 thousand standard cubic meters per day and actual annual average benzene emissions equal to or greater than 0.90 Mg/yr, determined according to §63.1282(a).
* * * * *
R esponsible official means one of the following: (1) For a corporation: a president, secretary, treasurer, or vice

- president of the corporation in charge of a principal business function, or any other person who performs similar policy or decision

- making f unctions for the corporation, or a duly authorized representative of such person if the representative is responsible for the overall operation of onePage 425 of 497

or more manufacturing, production, or operating facilities applying for or subject to a permit and either : (i) The facilities employ more than 250 persons or have gross annual sales or expenditures exceeding $25 million (in second quarter 1980 dollars); or (ii) The delegation of authority to such representatives is approved in advance by the permitting auth ority; (2) For a partnership or sole proprietorship: a general partner or the proprietor, respectively; (3) For a municipality, State, Federal, or other public agency: Either a principal executive officer or ranking elected official. For the purposes of this part, a principal executive officer of a Federal agency includes the chief executive officer having responsibility for the overall operations of a principal geographic unit of the agency (e.g., a Regional Administrator of EPA); or (4) For affected so urces: (i) The designated representative in so far as actions, standards, requirements, or prohibitions under title IV of the Act or the regulations promulgated thereunder are concerned; and (ii) The designated representative for any other purposes under part 70.
* * * * *Page 426 of 497

Small glycol dehydration unit means a glycol dehydration unit, located at a major source, with an actual annual average natural gas flowrate less than 283.0 thousand standard cubic meters per day or actual annual average benzene emissi ons less than 0.90 Mg/yr, determined according to §63.1282(a). Temperature monitoring device means an instrument used to monitor temperature and having a minimum accuracy of ±1 percent of the temperature being monitored expressed in degrees C, or ±2.8 degrees C, whichever is greater. The temperature monitoring device may measure temperature in degrees Fahrenheit or degrees Celsius, or both.
* * * * * 25. Section 63.1272 is revised to read as follows: §63.1272 Malfunctions
. (a) The provisions set fort h in this subpart shall apply at all times. (b) [Reserved] (c) [Reserved] (d) In response to an action to enforce the standards set forth in this subpart, you may assert an affirmative defense to a claim for civil penalties for exceedances of such standards that are caused by malfunction, as defined in §63.2. Appropriate penalti es may be assessed, however, if you fail to meet your burden of proving all the requirements in the affirmativePage 427 of 497

defense. The affirmative defense shall not be available for claims for injunctive relief. (1) To establish the affirmative defense in any actio n to enforce such a limit, the owner or operator must timely meet the notification requirements in paragraph (d)(2) of this section, and must prove by a preponderance of evidence that: (i) The excess emissions: (A) Were caused by a sudden, infrequent, an d unavoidable failure of air pollution control and monitoring equipment, process equipment, or a process to operate in a normal or usual manner; and (B) Could not have been prevented through careful planning, proper design or better operation and mainten ance practices; and (C) Did not stem from any activity or event that could have been foreseen and avoided, or planned for; and (D) Were not part of a recurring pattern indicative of inadequate design, operation, or maintenance; and (ii) Repairs were m ade as expeditiously as possible when the applicable emission limitations were being exceeded. Off

shift and overtime labor were used, to the extent practicable to make these repairs; and (iii) The frequency, amount and duration of the excess emissions ( including any bypass) were minimized to the maximum extent practicable during periods of such emissions; andPage 428 of 497

(iv) If the excess emissions resulted from a bypass of control equipment or a process, then the bypass was unavoidable to prevent loss of life, p ersonal injury, or severe property damage; and (v) All possible steps were taken to minimize the impact of the excess emissions on ambient air quality, the environment, and human health; and (vi) All emissions monitoring and control systems were kept i n operation if at all possible, consistent with safety and good air pollution control practices; and (vii) All of the actions in response to the excess emissions were documented by properly signed, contemporaneous operating logs; and (viii) At all time s, the affected source was operated in a manner consistent with good practices for minimizing emissions; and (ix) A written root cause analysis has been prepared to determine, correct, and eliminate the primary causes of the malfunction and the excess em issions resulting from the malfunction event at issue. The analysis shall also specify, using best monitoring methods and engineering judgment, the amount of excess emissions that were the result of the malfunction.Page 429 of 497

(2) Notification . The owner or operator of the affected source experiencing an exceedance of its emission limit(s) during a malfunction shall notify the Administrator by telephone or facsimile transmission as soon as possible, but no later than two business days after the initial occurrence of the malfunction, if it wishes to avail itself of an affirmative defense to civil penalties for that malfunction. The owner or operator seeking to assert an affirmative defense shall also submit a written report to the Administrator within 45 days of the in itial occurrence of the exceedance of the standard in this subpart to demonstrate, with all necessary supporting documentation, that it has met the requirements set forth in paragraph (d)(1) of this section. The owner or operator may seek an extension of t his deadline for up to 30 additional days by submitting a written request to the Administrator before the expiration of the 45 day period. Until a request for an extension has been approved by the Administrator, the owner or operator is subject to the requ irement to submit such report within 45 days of the initial occurrence of the exceedance.

26. Section 63.1274 is amended by: a. Revising paragraph (c) introductory text; b. Removing and reserving paragraph (d); c. Revising paragraph (g); andPage 430 of 497

d. Addi ng paragraph (h) to read as follows: §63.1274 General standards.
* * * * * (c) The owner or operator of an affected source ( i.e. , glycol dehydration unit) located at an existing or new major source of HAP emissions shall comply with the requirements in th is subpart as follows:
* * * * * (d) [Reserved]
* * * * * (g) In all cases where the provisions of this subpart require an owner or operator to repair leaks by a specified time after the leak is detected, it is a violation of this standard to fail to take action to repair the leak(s) within the specified time. If action is taken to repair the leak(s) within the specified time, failure of that action to successfully repair the leak(s) is not a violation of this standard. However, if the repairs are unsu ccessful, and a leak is detected, the owner or operator shall take further action as required by the applicable provisions of this subpart. (h) At all times the owner or operator must operate and maintain any affected source, including associated air poll ution control equipment and monitoring equipment, in a manner consistent with safety and good air pollution control practicesPage 431 of 497

for minimizing emissions. Determination of whether such operation and maintenance procedures are being used will be based on infor mation available to the Administrator which may include, but is not limited to, monitoring results, review of operation and maintenance procedures, review of operation and maintenance records, and inspection of the source. 27. Section 63.1275 is amended b y: a. Revising paragraph (a); b. Revising paragraph (b)(1); c. Revising paragraph (c)(2); and d. Revising paragraph (c)(3) to read as follows: §63.1275 Glycol dehydration unit process vent standards. (a) This section applies to each glycol dehydration unit subject to this subpart that must be controlled for air emissions as specified in paragraph (c)(1) of §63.1274. (b) * * * (1) For each glycol dehydration unit process vent, the owner or operator shall control air emissions by either paragraph (b)(1 )(i) or (b)(1)(iii) of this section. (i) The owner or operator of a large glycol dehydration unit, as defined in §63.1271, shall connect the process vent to a control device or a combination of control devices through a closed

- vent system. The closed

- vent system shall be designed and operated in accordance with the requirements of §63.1281(c). ThePage 432 of 497

control device(s) shall be designed and operated in accordance with the requirements of §63.1281(d). (ii) The owner or operator of a large glycol dehydration

un it shall connect the process vent to a control device or a combination of control devices through a closed

- vent system and the outlet benzene emissions from the control device(s) shall be less than 0.90 megagrams per year. The closed

- vent system shall be d esigned and operated in accordance with the requirements of §63.1281(c). The control device(s) shall be designed and operated in accordance with the requirements of §63.1281(d), except that the performance requirements specified in §63.1281(d)(1)(i) and (i i) do not apply. (iii) You must limit BTEX emissions from each existing small glycol dehydration unit, as defined in §63.1271, to the limit determined in Equation 1 of this section. You must limit BTEX emissions from each new small glycol dehydration unit process vent, as defined in §63.1271, to the limit determined in Equation 2 of this section. The limits determined using Equation 1 or Equation 2, of this section, must be met in accordance with one of the alternatives specified in paragraphs (b)(1)(iii)( A) through (D) of this section. Equation 1

Where: EL BTEX = Unit

- specific BTEX emission limit, megagrams per year;Page 433 of 497

3.72x10 - 4 = BTEX emission limit, grams BTEX/standard cubic meter

- ppmv; Throughput = Annual average daily natural gas throughput, standard cubic meters per day C i,BTEX = Annual average BTEX concentration of the natural gas at the inlet to the glycol dehydration unit, ppmv.

Equation 2

Where:
EL BTEX = Unit

- specific BTEX emission limit, megagrams per year; 1.10x10 - 5 = BTEX emission limit, grams BTEX/standard cubic meter

- ppmv; Throughput = Annual average daily natural gas throughput, standard cubic meters per day C i,BTEX = Annual average BTEX concentration of the natural gas at the inlet to the glycol dehydration unit, ppmv. (A) Connect the process vent to a control device or combination of control devices through a closed

- vent system. The closed vent system shall be designed and operated in accordance with the requirements of §63.1281(c). The control device(s) shall be designed and operated in accordance with the requirements of §63.1281(f). (B) Meet the emissions limit through process modifications in accordance with the requirements specified in §63.1281(e). (C) Meet the emission limit for each small glycol dehydration unit using a combination of process modifications and o ne or more control devices through the requirements specified in paragraphs (b)(1)(iii)(A) and (B) of this section. (D) Demonstrate that the emissions limit is met through actual uncontrolled operation of the small glycol dehydrationPage 434 of 497

unit. Document operat ional parameters in accordance with the requirements specified in §63.1281(e) and emissions in accordance with the requirements specified in §63.1282(a)(3).
* * * * * (c) * * * (2) The owner or operator shall demonstrate, to the Administrator's satisfact ion, that the total HAP emissions to the atmosphere from the large glycol dehydration unit process vent are reduced by 95.0 percent through process modifications or a combination of process modifications and one or more control devices, in accordance with the requirements specified in §63.1281(e). (3) Control of HAP emissions from a GCG separator (flash tank) vent is not required if the owner or operator demonstrates, to the Administrator's satisfaction, that total emissions to the atmosphere from the glyc ol dehydration unit process vent are reduced by one of the levels specified in paragraph (c)(3)(i) through (iv) through the installation and operation of controls as specified in paragraph (b)(1) of this section. (i) For any large glycol dehydration unit, HAP emissions are reduced by 95.0 percent or more.Page 4 35 of 497

(ii) For any large glycol dehydration unit, benzene emissions are reduced to a level less than 0.90 megagrams per
year. (iii) For each existing small glycol dehydration unit, BTEX emissions are reduced to a level less than the limit calculated in Equation 1 of paragraph (b)(1)(iii) of this section. (iv) For each new small glycol dehydration unit, BTEX emissions are reduced to a level less than the limit calculated in Equation 2 of paragraph (b)(1)(iii) of this section. 28. Section 63.1281 is amended by: a. Revising paragraph (c)(1); b. Revising the heading of paragraph (d). c. Adding paragraph (d) introductory text; d. Revising paragraph (d)(1)(i)(C); e. Revising paragraphs (d)(1)(ii) and (iii);
f . Revising paragraph (d)(4)(i); g. Revising paragraph (d)(5)(i); h. Revising paragraph (e)(2); i. Revising paragraph (e)(3) introductory text; j. Revising paragraph (e)(3)(ii); and k. Adding paragraph (f) to read as follows: §63.1281 Control equipment requirements.
* * * * * (c) * * *Page 436 of 497

(1) The closed

- vent system shall route all gases, vapors, and fumes emitted from the material in an emissions unit to a control device that meets the requirements specified in paragraph (d) of this section.
* * * * * (d) Control device requirements for sources except small glycol dehydration units . Owners and operators of small glycol dehydration units shall comply with the control requirements in paragraph (f) of this section. (1) * * * (i) * * * (C) Operates at a minimum temperature of 760 degrees C, provided the control device has demonstrated, under §63.1282(d), that combustion zone temperature is an indicator of control efficiency..
* * * * * (ii) A vapor recovery device ( e.g. , carbon adsorption system or conde nser) or other non

- destructive control device that is designed and operated to reduce the mass content of either TOC or total HAP in the gases vented to the device by 95.0 percent by weight or greater as determined in accordance with the requirements of §6 3.1282(d). (iii) A flare, as defined in §63.1271, that is designed and operated in accordance with the requirements of §63.11(b).Page 437 of 497

* * * * * (4) * * * (i) Each control device used to comply with this subpart shall be operating at all times when gases, v apors, and fumes are vented from the emissions unit or units through the closed vent system to the control device as required under §63.1275. An owner or operator may vent more than one unit to a control device used to comply with this subpart.
* * * * * (5) * * * (i) Following the initial startup of the control device, all carbon in the control device shall be replaced with fresh carbon on a regular, predetermined time interval that is no longer than the carbon service life established for the carbon ads orption system. Records identifying the schedule for replacement and records of each carbon replacement shall be maintained as required in §63.1284(b)(7)(ix). The schedule for replacement shall be submitted with the Notification of Compliance Status Report as specified in §63.1285(d)(4)(iv). Each carbon replacement must be reported in the Periodic Reports as specified in §63.1285(e)(2)(xi).
* * * * * (e) * * *Page 438 of 497

(2) The owner or operator shall document, to the Administrator's satisfaction, the conditions fo r which glycol dehydration unit baseline operations shall be modified to achieve the 95.0 percent overall HAP emission reduction, or BTEX limit determined in §63.1275(b)(1)(iii), as applicable, either through process modifications or through a combination of process modifications and one or more control devices. If a combination of process modifications and one or more control devices are used, the owner or operator shall also establish the emission reduction to be achieved by the control device to achieve an overall HAP emission reduction of 95.0 percent for the glycol dehydration unit process vent or, if applicable, the BTEX limit determined in §63.1275(b)(1)(iii) for the small glycol dehydration unit process vent. Only modifications in glycol dehydration unit operations directly related to process changes, including but not limited to changes in glycol circulation rate or glycol

- HAP absorbency, shall be allowed. Changes in the inlet gas characteristics or natural gas throughput rate shall not be considered in determining the overall emission reduction due to process modifications. (3) The owner or operator that achieves a 95.0 percent HAP emission reduction or meets the BTEX limit determined in §63.1275(b)(1)(iii), as applicable, using process modification s alone shall comply with paragraph (e)(3)(i) of this section. ThePage 439 of 497

owner or operator that achieves a 95.0 percent HAP emission reduction or meets the BTEX limit determined in §63.1275(b)(1)(iii), as applicable, using a combination of process modifications and one or more control devices shall comply with paragraphs (e)(3)(i) and (e)(3)(ii) of this section.
* * * * * (ii) The owner or operator shall comply with the control device requirements specified in paragraph (d) or (f) of this section, as applicable, except that the emission reduction or limit achieved shall be the emission reduction or limit specified for the control device(s) in paragraph (e)(2) of this section. (f) Control device requirements for small glycol dehydration units
. (1) The control de vice used to meet BTEX the emission limit calculated in §63.1275(b)(1)(iii) shall be one of the control devices specified in paragraphs (f)(1)(i) through (iii) of this section. (i) An enclosed combustion device ( e.g. , thermal vapor incinerator, catalytic vapor incinerator, boiler, or process heater) that is designed and operated to meet the levels specified in paragraphs (f)(1)(i)(A) or (B) of this section. If a boiler or process heater is used as the control device, then the vent stream shall be introduce d into the flame zone of the boiler or process heater.Page 440 of 497

(A) The mass content of BTEX in the gases vented to the device is reduced as determined in accordance with the requirements of §63.1282(d). (B) The concentration of either TOC or total HAP in the exh aust gases at the outlet of the device is reduced to a level equal to or less than 20 parts per million by volume on a dry basis corrected to 3 percent oxygen as determined in accordance with the requirements of §63.1282(e). (ii) A vapor recovery device ( e.g. , carbon adsorption system or condenser) or other non

- destructive control device that is designed and operated to reduce the mass content of BTEX in the gases vented to the device as determined in accordance with the requirements of §63.1282(d). (iii) A flare, as defined in §63.1271, that is designed and operated in accordance with the requirements of §63.11(b). (2) The owner or operator shall operate each control device in accordance with the requirements specified in paragraphs (f)(2)(i) and (ii) of this section. (i) Each control device used to comply with this subpart shall be operating at all times. An owner or operator ma y vent more than one unit to a control device used to comply with this subpart. (ii) For each control device monitored in accordance with the requirements of §63.1283(d), the owner or operator shallPage 441 of 497

demonstrate compliance according to the requirements of either §63.1282(e) or (h). (3) For each carbon adsorption system used as a control device to meet the requirements of paragraph (f)(1) of this section, the owner or operator shall manage the carbon as required under (d)(5)(i) and (ii) of this section. 29 . Section 63.1282 is amended by: a. Revising paragraph (a) introductory text; b. Revising paragraph (a)(1)(ii); c. Revising paragraph (a)(2); d. Revising paragraph (b)(6)(i); e. Adding paragraph (c); f. Revising paragraph (d) introductory text; g. R evising paragraphs (d)(1)(i) through (v); h. Revising paragraph (d)(2); i. Revising paragraph (d)(3) introductory text; j. Revising paragraph (d)(3)(i)(B); k. Revising paragraph (d)(3)(iv)(C)( 1 ); l. Adding paragraphs (d)(3)(v) and (vi); m. Revising p aragraph (d)(4) introductory text; n. Revising paragraph (d)(4)(i); o. Revising paragraph (d)(5); p. Revising paragraph (e) introductory text; q. Revising paragraphs (e)(2) and (e)(3);Page 442 of 497

r. Adding paragraphs (e)(4) through (e)(6); s. Revising paragrap h (f) introductory text; t. Revising paragraph (f)(1); u. Revising paragraph (f)(2) introductory text; v. Revising paragraph (f)(2)(iii); w. Revising paragraph (f)(3); and x. Adding paragraphs (g) and (h) to read as follows: §63.1282 Test methods, compliance procedures, and compliance demonstrations. (a) Determination of glycol dehydration unit flowrate, benzene emissions, or BTEX emissions
. The procedures of this paragraph shall be used by an owner or operator to determine glycol dehydration unit natural gas flowrate, benzene emissions, or BTEX emissions. (1) * * * (ii) The owner or operator shall document, to the Administrator's satisfaction, the actual annual average natural gas flowrate to the glycol dehydration unit. (2) The determination of actual average benzene or BTEX emissions from a glycol dehydration unit shall be made using the procedures of either paragraph (a)(2)(i) or (a)(2)(ii) of this section. Emissions shall be determined either uncontrolled or with federally enforceable control s in place.Page 443 of 497

(i) The owner or operator shall determine actual average benzene or BTEX emissions using the model GRI

- GLYCalc TM , Version 3.0 or higher, and the procedures presented in the associated
GRI

- GLYCalc TM Technical Reference Manual. Inputs to the model shall be representative of actual operating conditions of the glycol dehydration unit and may be determined using the procedures documented in the Gas Research Institute (GRI) report entitled “Atmospheric Ri ch/Lean Method for Determining Glycol Dehydrator Emissions” (GRI

– 95/0368.1); or (ii) The owner or operator shall determine an average mass rate of benzene or BTEX emissions in kilograms per hour through direct measurement by performing three runs of Metho d 18 in 40 CFR part 60, appendix A (or an equivalent method), and averaging the results of the three runs. Annual emissions in kilograms per year shall be determined by multiplying the mass rate by the number of hours the unit is operated per year. This re sult shall be converted to megagrams per year.
* * * * * (b) * * * (6) * * * (i) Except as provided in paragraph (b)(6)(ii) of this section, the detection instrument shall meet the performance criteria of Method 21 of 40 CFR part 60, appendix A, except the instrument response factor criteria in section 3.1.2(a) ofPage 444 of 497

Method 21 shall be for the average composition of the process fluid not each individual volatile organic compound in the stream. For process streams that contain nitrogen, air, or other inert gases that are not organic HAP or VOC, the average stream response factor shall be calculated on an inert

- free basis.
* * * * * (c) Test procedures and compliance demonstrations for small glycol dehydration units. This paragraph applies to the test proce dures for small dehydration units. (1) If the owner or operator is using a control device to comply with the emission limit in §63.1275(b)(1)(iii), the requirements of paragraph (d) of this section apply. Compliance is demonstrated using the methods spec ified in paragraph (e) of this section. (2) If no control device is used to comply with the emission limit in §63.1275(b)(1)(iii), the owner or operator must determine the glycol dehydration unit BTEX emissions as specified in paragraphs (c)(2)(i) through (iii) of this section. Compliance is demonstrated if the BTEX emissions determined as specified in paragraphs (c)(2)(i) through (iii) are less than the emission limit calculated using the equation in §63.1275(b)(1)(iii). (i) Method 1 or 1A, 40 CFR part 6 0, appendix A, as appropriate, shall be used for selection of the sampling sitesPage 445 of 497

at the outlet of the glycol dehydration unit process vent. Any references to particulate mentioned in Methods 1 and 1A do not apply to this section. (ii) The gas volumetric f lowrate shall be determined using Method 2, 2A, 2C, or 2D, 40 CFR part 60, appendix A, as appropriate. (iii) The BTEX emissions from the outlet of the glycol dehydration unit process vent shall be determined using the procedures specified in paragraph (d )(3)(v) of this section. As an alternative, the mass rate of BTEX at the outlet of the glycol dehydration unit process vent may be calculated using the model GRI

- GLYCalc TM , Version 3.0 or higher, and the procedures presented in the associated GRI

- GLYCalc T M Technical Reference Manual. Inputs to the model shall be representative of actual operating conditions of the glycol dehydration unit and shall be determined using the procedures documented in the Gas Research Institute (GRI) report entitled “Atmospheric Rich/Lean Method for Determining Glycol Dehydrator Emissions” (GRI

– 95/0368.1). When the BTEX mass rate is calculated for glycol dehydration units using the model GRI

- GLYCalc TM , all BTEX measured by Method 18, 40 CFR part 60, appendix A, shall be summed. (d) Control device performance test procedures
. This paragraph applies to the performance testing of control devices. The owners or operators shall demonstrate that a control devicePage 446 of 497

achieves the performance requirements of §63.1281(d)(1), (e)(3)(ii), or (f )(1) using a performance test as specified in paragraph (d)(3) of this section. Owners or operators using a condenser have the option to use a design analysis as specified in paragraph (d)(4) of this section. The owner or operator may elect to use the alte rnative procedures in paragraph (d)(5) of this section for performance testing of a condenser used to control emissions from a glycol dehydration unit process vent. As an alternative to conducting a performance test under this section for combustion contro l devices, a control device that can be demonstrated to meet the performance requirements of §63.1281(d)(1), (e)(3)(ii), or (f)(1) through a performance test conducted by the manufacturer, as specified in paragraph (g) of this section, can be used. (1) * * * (i) Except as specified in paragraph (d)(2) of this section, a flare, as defined in §63.1271, that is designed and operated in accordance with §63.11(b); (ii) Except for control devices used for small glycol dehydration units, a boiler or process hea ter with a design heat input capacity of 44 megawatts or greater; (iii) Except for control devices used for small glycol dehydration units, a boiler or process heater into which thePage 447 of 497

vent stream is introduced with the primary fuel or is used as the primary fuel; (iv) Except for control devices used for small glycol dehydration units, a boiler or process heater burning hazardous waste for which the owner or operator has either been issued a final permit under 40 CFR part 270 and complies with the requiremen ts of 40 CFR part 266, subpart H, or has certified compliance with the interim status requirements of 40 CFR part 266, subpart H; (v) Except for control devices used for small glycol dehydration units, a hazardous waste incinerator for which the

owner or operator has been issued a final permit under 40 CFR part 270 and complies with the requirements of 40 CFR part 264, subpart O, or has certified compliance with the interim status requirements of 40 CFR part 265, subpart O.
* * * * * (2) An owner or operator shall design and operate each flare, as defined in §63.1271, in accordance with the requirements specified in §63.11(b) and the compliance determination shall be conducted using Method 22 of 40 CFR part 60, appendix A, to determine visible emissio ns. (3) For a performance test conducted to demonstrate that a control device meets the requirements of §63.1281(d)(1), (e)(3)(ii), or (f)(1) the owner or operator shall use the testPage 448 of 497

methods and procedures specified in paragraphs (d)(3)(i) through (v) of this section. The initial and periodic performance tests shall be conducted according to the schedule specified in paragraph (d)(3)(vi) of this section. (i) * * * (B) To determine compliance with the enclosed combustion device total HAP concentration lim it specified in §63.1281(d)(1)(i)(B), or the BTEX emission limit specified in §63.1275(b)(1)(iii), the sampling site shall be located at the outlet of the combustion device.
* * * * * (iv) * * * (C) * * * ( 1 ) The emission rate correction factor for exce ss air, integrated sampling and analysis procedures of Method 3A or 3B, 40 CFR part 60, appendix A, shall be used to determine the oxygen concentration (%O 2d ). The samples shall be taken during the same time that the samples are taken for determining TOC

c oncentration or total HAP concentration.
* * * * * (v) To determine compliance with the BTEX emission limit specified in §63.1275(b)(1)(iii) the owner or operator shall use one of the following methods: Method 18, 40 CFR part 60, appendix A; ASTM D6420

– 9 9 (2004), as specified inPage 449 of 497

§63.772(a)(1)(ii); or any other method or data that have been validated according to the applicable procedures in Method 301, 40 CFR part 63, appendix A. The following procedures shall be used to calculate BTEX emissions: (A) The minimum sampling time for each run shall be 1 hour in which either an integrated sample or a minimum of four grab samples shall be taken. If grab sampling is used, then the samples shall be taken at approximately equal intervals in time, such as 15

- minute intervals during the run. (B) The mass rate of BTEX (E o ) shall be computed using the equations and procedures specified in paragraphs (d)(3)(v)(B)( 1 ) and ( 2 ) of this section. ( 1 ) The following equation shall be used:

Where: E o = Mass rate of BTEX at t he outlet of the control device, dry basis, kilogram per hour. C oj = Concentration of sample component j of the gas stream at the outlet of the control device, dry basis, parts per million by volume. M oj = Molecular weight of sample component j of the gas st ream at the outlet of the control device, gram/gram

- mole. Q o = Flowrate of gas stream at the outlet of the control device, dry standard cubic meter per minute. K 2 = Constant, 2.494×10 − 6 (parts per million) (gram

- mole per standard cubic meter) (kilogram/gram) (minute/hour), where standard temperature (gram

- mole per standard cubic meter) is 20 degrees C. n = Number of components in sample.Page 450 of 497

( 2 ) When the BTEX mass rate is calculated, only BTEX compounds measured by Method 18, 40 CFR part 60, appendix A, or
ASTM D6420

– 99 (2004) as specified in §63.772(a)(1)(ii), shall be summed using the equations in paragraph (d)(3)(v)(B)( 1 ) of this section. (vi) The owner or operator shall conduct performance tests according to the schedule specified in paragraphs (d)(3)(vi)(A) and (B) of this section. (A) An initial performance test shall be conducted within 180 days after the compliance date that is specified for each affected source in §63.1270(d)(3) and (4) except that the initial performance test for existing combustion co ntrol devices at existing major sources shall be conducted no later than [INSERT DATE 3 YEARS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER] . If the owner or operator of an existing combustion control device at an existing major source chooses to repla ce such device with a control device whose model is tested under §63.1282(g), then the newly installed device shall comply with all provisions of this subpart no later than [INSERT DATE 3 YEARS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER] . The performance test results shall be submitted in the Notification of Compliance Status Report as required in §63.1285(d)(1)(ii). (B) Periodic performance tests shall be conducted for all control devices required to conduct initial performance testsPage 451 of 497

except a s specified in paragraphs (e)(3)(vi)(B)( 1 ) and ( 2 ) of this section. The first periodic performance test shall be conducted no later than 60 months after the initial performance test required in paragraph (d)(3)(vi)(A) of this section. Subsequent periodic p erformance tests shall be conducted at intervals no longer than 60 months following the previous periodic performance test or whenever a source desires to establish a new operating limit. The periodic performance test results must be submitted in the next Periodic Report as specified in §63.1285(e)(2)(x). Combustion control devices meeting the criteria in either paragraph (e)(3)(vi)(B)( 1 ) or ( 2 ) of this section are not required to conduct periodic performance
tests. ( 1 ) A control device whose model is test ed under, and meets the criteria of, §63.1282(g), or ( 2 ) A combustion control device demonstrating during the performance test under §63.1282(d) that combustion zone temperature is an indicator of destruction efficiency and operates at a minimum temperatu re of 760 degrees C.
* * * * * (4) For a condenser design analysis conducted to meet the requirements of §63.1281(d)(1), (e)(3)(ii), or (f)(1), the owner or operator shall meet the requirements specified in paragraphs (d)(4)(i) and (d)(4)(ii) of this section. Documentation of thePage 452 of 497

design analysis shall be submitted as a part of the Notification of Compliance Status Report as required in §63.1285(d)(1)(i). (i) The condenser design analysis shall include an analysis of the vent stream composition, constituent concentrations, flowrate, rela tive humidity, and temperature, and shall establish the design outlet organic compound concentration level, design average temperature of the condenser exhaust vent stream, and the design average temperatures of the coolant fluid at the condenser inlet and outlet. As an alternative to the condenser design analysis, an owner or operator may elect to use the procedures specified in paragraph (d)(5) of this section.
* * * * * (5) As an alternative to the procedures in paragraph (d)(4)(i) of this section, an o wner or operator may elect to use the procedures documented in the GRI report entitled, “Atmospheric Rich/Lean Method for Determining Glycol Dehydrator Emissions,” (GRI

– 95/0368.1) as inputs for the model GRI

GLYCalc TM , Version 3.0 or higher, to generate a condenser performance curve. (e) Compliance demonstration for control devices performance requirements
. This paragraph applies to the demonstration of compliance with the control device performance requirements specified in §63.1281(d)(1), (e)(3)(ii), and (f)(1). Compliance shall be demonstrated using the requirementsPage 453 of 497

in paragraphs (e)(1) through (3) of this section. As an alternative, an owner or operator that installs a condenser as the control device to achieve the requirements specified in §63.1281(d)( 1)(ii), (e)(3)(ii), or (f)(1) may demonstrate compliance according to paragraph (f) of this section. An owner or operator may switch between compliance with paragraph (e) of this section and compliance with paragraph (f) of this section only after at least 1 year of operation in compliance with the selected approach. Notification of such a change in the compliance method shall be reported in the next Periodic Report, as required in §63.1285(e), following the change.
* * * * * (2) The owner or operator shal l calculate the daily average of the applicable monitored parameter in accordance with §63.1283(d)(4) except that the inlet gas flowrate to the control device shall not be averaged. (3) Compliance is achieved when the daily average of the monitoring param eter value calculated under paragraph (e)(2) of this section is either equal to or greater than the minimum or equal to or less than the maximum monitoring value established under paragraph (e)(1) of this section. For inlet gas flowrate, compliance with th e operating parameter limit is achieved when the value is equal to or less than the value established under §63.1282(g).Page 454 of 497

(4) Except for periods of monitoring system malfunctions, repairs associated with monitoring system malfunctions, and required monitor ing system quality assurance or quality control activities (including, as applicable, system accuracy audits and required zero and span adjustments), the CMS required in §63.1283(d) must be operated at all times the affected source is operating. A monitori ng system malfunction is any sudden, infrequent, not reasonably preventable failure of the monitoring system to provide valid data. Monitoring system failures that are caused in part by poor maintenance or careless operation are not malfunctions. Monitorin g system repairs are required to be completed in response to monitoring system malfunctions and to return the monitoring system to operation as expeditiously as practicable. (5) Data recorded during monitoring system malfunctions, repairs associated with monitoring system malfunctions, or required monitoring system quality assurance or control activities may not be used in calculations used to report emissions or operating levels. All the data collected during all other required data collection periods mus t be used in assessing the operation of the control device and associated control system. (6) Except for periods of monitoring system malfunctions, repairs associated with monitoring system malfunctions, andPage 455 of 497

required quality monitoring system quality a ssurance or quality control activities (including, as applicable, system accuracy audits and required zero and span adjustments), failure to collect required data is a deviation of the monitoring requirements. (f) Compliance demonstration with percent red uction or emission limit performance requirements

— condensers
. This paragraph applies to the demonstration of compliance with the performance requirements specified in §63.1281(d)(1)(ii), (e)(3) or (f)(1) for condensers. Compliance shall be demonstrated usi ng the procedures in paragraphs (f)(1) through (f)(3) of this section. (1) The owner or operator shall establish a site

- specific condenser performance curve according to the procedures specified in §63.1283(d)(5)(ii). For sources required to meet the BTEX limit in accordance with §63.1281(e) or (f)(1) the owner or operator shall identify the minimum percent reduction necessary to meet the BTEX limit. (2) Compliance with the percent reduction requirement in §63.1281(d)(1)(ii), (e)(3), or (f)(1) shall be d emonstrated by the procedures in paragraphs (f)(2)(i) through (iii) of this section.
* * * * *Page 456 of 497

(iii) Except as provided in paragraphs (f)(2)(iii)(A), (B), and (D) of this section, at the end of each operating day the owner or operator shall calculate the 30

- day average HAP, or BTEX, emission reduction, as appropriate, from the condenser efficiencies as determined in paragraph (f)(2)(ii) of this section for the preceding 30 operating days. If the owner or operator uses a combination of process modifications and a condenser in accordance with the requirements of §63.1281(e), the 30

- day average HAP emission, or BTEX, emission reduction, shall be calculated using the emission reduction achieved through process modifications and the condenser efficiency as deter mined in paragraph (f)(2)(ii) of this section, both for the preceding 30 operating days. (A) After the compliance date specified in §63.1270(d), an owner or operator of a facility that stores natural gas that has less than 30 days of data for determining the average HAP, or BTEX, emission reduction, as appropriate, shall calculate the cumulative average at the end of the withdrawal season, each season, until 30 days of condenser operating data are accumulated. For a facility that does not store natural gas , the owner or operator that has less than 30 days of data for determining average HAP, or BTEX, emission reduction, as appropriate, shall calculate the cumulative average at the endPage 457 of 497

of the calendar year, each year, until 30 days of condenser operating dat a are accumulated. (B) After the compliance date specified in §63.1270(d), for an owner or operator that has less than 30 days of data for determining the average HAP, or BTEX, emission reduction, as appropriate, compliance is achieved if the average HAP, or BTEX, emission reduction, as appropriate, calculated in paragraph (f)(2)(iii)(A) of this section is equal to or greater than 95.0 percent or is equal to or greater than the minimum percent reduction necessary to meet the BTEX emission limit as determin ed in paragraph (f)(1) of this section.
* * * * * (3) Compliance is achieved based on the applicable criteria in paragraphs (f)(3)(i) or (ii) of this section. (i) For sources meeting the HAP emission reduction specified in §63.1281(d)(1)(ii) or (e)(3) if the average HAP emission reduction calculated in paragraph (f)(2)(iii) of this section is equal to or greater than 95.0 percent. (ii) For sources required to meet the BTEX limit under §63.1281(e)(3) or (f)(1), compliance is achieved if the average
BTEX e mission reduction calculated in paragraph (f)(2)(iii) of this section is equal to or greater than the minimum percent reduction identified in paragraph (f)(1) of this section.
* * * * *Page 458 of 497

(g) Performance testing for combustion control devices

- manufacturers ’ performance test. (1) This paragraph applies to the performance testing of a combustion control device conducted by the device manufacturer. The manufacturer shall demonstrate that a specific model of control device achieves the performance requirements in (g)(7) of this section by conducting a performance test as specified in paragraphs (g)(2) through (6) of this section. (2) Performance testing shall consist of three one

- hour (or longer) test runs for each of the four following firing rate settings ma king a total of 12 test runs per test. Propene (propylene) gas shall be used for the testing fuel. All fuel analyses shall be performed by an independent third

- party laboratory (not affiliated with the control device manufacturer or fuel supplier). (i) 90

- 100 percent of maximum design rate (fixed rate). (ii) 70

- 100

- 70 percent (ramp up, ramp down). Begin the test at 70 percent of the maximum design rate. During the first 5 minutes, incrementally ramp the firing rate to 100 percent of the maximum desi gn rate. Hold at 100 percent for 5 minutes. In the 10

- 15 minute time range, incrementally ramp back down to 70 percent of the maximum design rate. Repeat three more times for a total of 60 minutes of sampling.Page 459 of 497

(iii) 30

- 70

- 30 percent (ramp up, ramp down). Begin the test at 30 percent of the maximum design rate. During the first 5 minutes, incrementally ramp the firing rate to 70 percent of the maximum design rate. Hold at 70 percent for 5 minutes. In the 10

- 15 minute time range, incrementally ramp ba ck down to 30 percent of the maximum design rate. Repeat three more times for a total of 60 minutes of sampling. (iv) 0

- 30

- 0 percent (ramp up, ramp down). Begin the test at 0 percent of the maximum design rate. During the first 5 minutes, incrementall y ramp the firing rate to 30 percent of the maximum design rate. Hold at 30 percent for 5 minutes. In the 10

- 15 minute time range, incrementally ramp back down to 0 percent of the maximum design rate. Repeat three more times for a total of 60 minutes of sa mpling. (3) All models employing multiple enclosures shall be tested simultaneously and with all burners operational. Results shall be reported for the each enclosure individually and for the average of the emissions from all interconnected combustion

en closures/chambers. Control device operating data shall be collected continuously throughout the performance test using an electronic Data Acquisition System and strip chart. Data shall be submitted with the test report in accordance with paragraph (g)(8)(i ii) of this section.Page 460 of 497

(4) Inlet testing shall be conducted as specified in paragraphs (g)(4)(i) through (iii) of this section. (i) The fuel flow metering system shall be located in accordance with Method 2A, 40 CFR part 60, appendix A

- 1, (or other approve d procedure) to measure fuel flowrate at the control device inlet location. The fitting for filling fuel sample containers shall be located a minimum of 8 pipe diameters upstream of any inlet fuel flow monitoring meter. (ii) Inlet flowrate shall be determ ined using Method 2A, 40 CFR part 60, appendix A

- 1. Record the start and stop reading for each 60

- minute THC test. Record the gas pressure and temperature at 5

- minute intervals throughout each 60

- minute THC test. (iii) Inlet fuel sampling shall be conduct ed in accordance with the criteria in paragraphs (g)(4)(iii)(A) and (B) of this section. (A) At the inlet fuel sampling location, securely connect a Silonite

- coated stainless steel evacuated canister fitted with a flow controller sufficient to fill the ca nister over a 1 hour period. Filling shall be conducted as specified in the following: ( 1 ) Open the canister sampling valve at the beginning of the total hydrocarbon (THC) test, and close the canister at the end of each THC test run.Page 461 of 497

( 2 ) Fill one canis ter across the three test runs for each THC test such that one composite fuel sample exists for each test condition. ( 3 ) Label the canisters individually and record on a chain of custody form. (B) Each fuel sample shall be analyzed using the following

me thods. The results shall be included in the test report. ( 1 ) Hydrocarbon compounds containing between one and five atoms of carbon plus benzene using ASTM D1945

- 03. ( 2 ) Hydrogen (H 2 ), carbon monoxide (CO), carbon dioxide (CO 2 ), nitrogen (N 2 ), oxygen (O 2 ) using ASTM D1945

- 03. ( 3 ) Higher heating value using ASTM D3588

- 98 or ASTM D4891

- 89. (5) Outlet testing shall be conducted in accordance with the criteria in paragraphs (g)(5)(i) through (v) of this section. (i) Sampling and flowrate measured in accorda nce with the following: (A) The outlet sampling location shall be a minimum of 4 equivalent stack diameters downstream from the highest peak flame or any other flow disturbance, and a minimum of one equivalent stack diameter upstream of the exit or any ot her flow disturbance. A minimum of two sample ports shall be used.Page 462 of 497

(B) Flowrate shall be measured using Method 1, 40 CFR part 60, Appendix 1, for determining flow measurement traverse point location; and Method 2, 40 CFR part 60, Appendix 1, shall be

use d to measure duct velocity. If low flow conditions are encountered ( i.e. , velocity pressure differentials less than 0.05 inches of water) during the performance test, a more sensitive manometer or other pressure measurement device shall be used to obtain a n accurate flow profile. (ii) Molecular weight shall be determined as specified in paragraphs (g)(4)(iii)(B), and (g)(5)(ii)(A) and (B) of this section. (A) An integrated bag sample shall be collected during the Method 4, 40 CFR part 60, Appendix A, mois ture test. Analyze the bag sample using a gas chromatograph

- thermal conductivity detector (GC

- TCD) analysis meeting the following criteria: ( 1 ) Collect the integrated sample throughout the entire test, and collect representative volumes from each traverse location. ( 2 ) The sampling line shall be purged with stack gas before opening the valve and beginning to fill the bag. ( 3 ) The bag contents shall be vigorously mixed prior to the GC analysis. ( 4 ) The GC

- TCD calibration procedure in Method 3C, 40 CFR
pa rt 60, Appendix A, shall be modified by using EPAAlt

- 045 asPage 463 of 497

follows: For the initial calibration, triplicate injections of any single concentration must agree within 5 percent of their mean to be valid. The calibration response factor for a single
concent ration re

- check must be within 10 percent of the original calibration response factor for that concentration. If this criterion is not met, the initial calibration using at least three concentration levels shall be repeated. (B) Report the molecular weigh t of: O 2 , CO 2 , methane (CH4), and N 2 and include in the test report submitted under §63.775(d)(iii). Moisture shall be determined using Method 4, 40 CFR part 60, Appendix A. Traverse both ports with the Method 4, 40 CFR part 60, Appendix A, sampling train during each test run. Ambient air shall not be introduced into the Method 3C, 40 CFR part 60, Appendix A, integrated bag sample during the port change. (iii) Carbon monoxide shall be determined using Method 10, 40 CFR part 60, Appendix A. The test shall be run at the same time and with the sample points used for the EPA Method 25A, 40 CFR part 60, Appendix A, testing. An instrument range of 0

- 10 per million by volume

- dry (ppmvd) shall be used. (iv) Visible emissions shall be determined using Method 22,
4 0 CFR part 60, Appendix A. The test shall be performed continuously during each test run. A digital color photograph of the exhaust point, taken from the position of the observer andPage 464 of 497

annotated with date and time, will be taken once per test run and the fou r photos included in the test report. (v) Excess air shall be determined using resultant data from the EPA Method 3C tests and EPA Method 3B, 40 CFR part 60, Appendix A, equation 3B

- 1. (6) Total hydrocarbons (THC) shall be determined as specified by the following criteria: (i) Conduct THC sampling using Method 25A, 40 CFR part 60, Appendix A, except the option for locating the probe in the center 10 percent of the stack shall not be allowed. The THC probe must be traversed to 16.7 percent, 50 percent, an d 83.3 percent of the stack diameter during the test run. (ii) A valid test shall consist of three Method 25A, 40 CFR part 60, Appendix A, tests, each no less than 60 minutes in duration. (iii) A 0

- 10 parts per million by volume

- wet (ppmvw) (as propane) measurement range is preferred; as an alternative a 0

- 30 ppmvw (as carbon) measurement range may be used. (iv) Calibration gases will be propane in air and be certified through EPA Protocol 1

– “EPA Traceability Protocol for Assay and Certification of Gas eous Calibration Standards,” September 1997, as amended August 25, 1999, EPA

– 600/R

– 97/121 (or more recent if updated since 1999).Page 465 of 497

(v) THC measurements shall be reported in terms of ppmvw as
propane. (vi) THC results shall be corrected to 3 percent CO 2 , a s measured by Method 3C, 40 CFR part 60, Appendix A. (vii) Subtraction of methane/ethane from the THC data is not allowed in determining results. (7) Performance test criteria: (i) The control device model tested must meet the criteria in paragraphs (g) (7)(i)(A) through (C) of this section: (A) Method 22, 40 CFR part 60, Appendix A, results under paragraph (g)(5)(v) of this section with no indication of visible emissions, and (B) Average Method 25A, 40 CFR part 60, Appendix A, results under paragraph (g)(6) of this section equal to or less than 10.0 ppmvw THC as propane corrected to 3.0 percent CO 2 , and (C) Average CO emissions determined under paragraph (g)(5)(iv) of this section equal to or less than 10 parts ppmvd, corrected to 3.0 percent CO 2 . ( D) Excess combustion air shall be equal to or greater than 150 percent. (ii) The manufacturer shall determine a maximum inlet gas flowrate which shall not be exceeded for each control device model to achieve the criteria in paragraph (g)(7)(i) of this

se ction.Page 466 of 497

(iii) A control device meeting the criteria in paragraph (g)(7)(i)(A) through (C) of this section will have demonstrated a destruction efficiency of 95.0 percent for HAP regulated under this subpart. (8) The owner or operator of a combustion cont rol device model tested under this section shall submit the information listed in paragraphs (g)(8)(i) through (iii) in the test report required under §63.775(d)(1)(iii). (i) Full schematic of the control device and dimensions of the device components. ( ii) Design net heating value (minimum and maximum) of the device. (iii) Test fuel gas flow range (in both mass and volume). Include the minimum and maximum allowable inlet gas flowrate. (iv) Air/stream injection/assist ranges, if used. (v) The test para meter ranges listed in paragraphs (g)(8)(v)(A) through (O) of this section, as applicable for the tested model. (A) Fuel gas delivery pressure and temperature. (B) Fuel gas moisture range. (C) Purge gas usage range. (D) Condensate (liquid fuel) separati on range. (E) Combustion zone temperature range. This is required for all devices that measure this parameter.Page 467 of 497

(F) Excess combustion air range. (G) Flame arrestor(s). (H) Burner manifold pressure. (I) Pilot flame sensor. (J) Pilot flame design fuel and fuel usage. (K) Tip velocity range. (L) Momentum flux ratio. (M) Exit temperature range. (N) Exit flowrate. (O) Wind velocity and direction. (vi) The test report shall include all calibration quality assurance/quality control data, calibration gas val ues, gas cylinder certification, and strip charts annotated with test times and calibration values. (h) Compliance demonstration for combustion control devices

- manufacturers’ performance test . This paragraph applies to the demonstration of compliance f or a combustion control device tested under the provisions in paragraph (g) of this section. Owners or operators shall demonstrate that a control device achieves the performance requirements of §63.1281(d)(1), (e)(3)(ii) or (f)(1), by installing a device t ested under paragraph (g) of this section and complying with the following criteria:Page 468 of 497

(1) The inlet gas flowrate shall meet the range specified by the manufacturer. Flowrate shall be calculated as specified in §63.1283(d)(3)(i)(H)( 1 ). (2) A pilot flame s hall be present at all times of operation. The pilot flame shall be monitored in accordance with §63.1283(d)(3)(i)(H)( 2 ). (3) Devices shall be operated with no visible emissions, except for periods not to exceed a total of 2 minutes during any hour. A vis ible emissions test using Method 22, 40 CFR part 60, Appendix A, shall be performed each calendar quarter. The observation period shall be 1 hour and shall be used according to EPA Method 22, 40 CFR part 60, Appendix A. (4) Compliance with the operating parameter limit is achieved when the following criteria are met: (i) The inlet gas flowrate monitored under paragraph (h)(1) of this section is equal to or below the maximum established by the manufacturer; and (ii) The pilot flame is present at all time s; and (iii) During the visible emissions test performed under paragraph (h)(3) of this section the duration of visible emissions does not exceed a total of 5 minutes during the observation period. Devices failing the visible emissions test shall follow m anufacturers repair instructions, if available, or best combustion engineering practice as outlined in the unitPage 469 of 497

inspection and maintenance plan, to return the unit to compliant operation. All repairs and maintenance activities for each unit shall be record ed in a maintenance and repair log and shall be available on site for inspection. (iv) Following return to operation from maintenance or repair activity, each device must pass a Method 22 observation as described in paragraph (h)(3) of this section. 30. Section 63.1283 is amended by: a. Adding paragraph (b); b. Revising paragraph (d)(1) introductory text; c. Revising paragraph (d)(1)(ii) and adding paragraphs (d)(1)(iii) and (iv); d. Revising paragraph (d)(2); e. Revising paragraphs (d)(3)(i)(A) and (B); f. Revising paragraphs (d)(3)(i)(D) and (E); g. Revising paragraphs (d)(3)(i)(F)( 1 ) and ( 2 ); h. Revising paragraph (d)(3)(i)(G); i. Adding paragraph (d)(3)(i)(H); j. Revising paragraph (d)(4); k. Revising paragraph (d)(5)(i); l. Revising paragraphs (d)(5)(ii)(A) through (C); m. Revising paragraph (d)(6) introductory text; n. Revising paragraphs (d)(6)(ii); o. Adding paragraph (d)(6)(v);Page 470 of 497

p. Revising paragraph (d)(7)); and q. Removing paragraph (d)(8) to read as follows: §63.1283 Inspec tion and monitoring requirements.
* * * * * (b) The owner or operator of a control device whose model was tested under 63.1282(g) shall develop an inspection and maintenance plan for each control device. At a minimum, the plan shall contain the control device manufacturer’s recommendations for ensuring proper operation of the device. Semi

- annual inspections shall be conducted for each control device with maintenance and replacement of control device components made in accordance with the plan.
* * * * * (d) Control device monitoring requirements
. (1) For each control device except as provided for in paragraph (d)(2) of this section, the owner or operator shall install and operate a continuous parameter monitoring system in accordance with the requirements of paragraphs (d)(3) through (7) of this section. Owners or operators that install and operate a flare in accordance with §63.1281(d)(1)(iii) or (f)(1)(iii) are exempt from the requirements of paragraphs (d)(4) and (5) of this section. The continuous moni toring system shall be designed and operated so that a determination can be made on whether the control device is achieving the applicable performancePage 471 of 497

requirements of §63.1281(d), (e)(3), or (f)(1). Each continuous parameter monitoring system shall meet th e following specifications and requirements:
* * * * * (ii) A site

- specific monitoring plan must be prepared that addresses the monitoring system design, data collection, and the quality assurance and quality control elements outlined in paragraph (d) of this section and in §63.8(d). Each CPMS must be installed, calibrated, operated, and maintained in accordance with the procedures in your approved site

- specific monitoring plan. Using the process described in §63.8(f)(4), you may request approval of monito ring system quality assurance and quality control procedures alternative to those specified in paragraphs (d)(1)(ii)(A) through (E) of this section in your site

- specific monitoring plan. (A) The performance criteria and design specifications for the moni toring system equipment, including the sample interface, detector signal analyzer, and data acquisition and calculations; (B) Sampling interface ( e.g. , thermocouple) location such that the monitoring system will provide representative measurements; (C) Equipment performance checks, system accuracy audits, or other audit procedures;Page 472 of 497

(D) Ongoing operation and maintenance procedures in accordance with provisions in §63.8(c)(1) and (c)(3); and (E) Ongoing reporting and recordkeeping procedures in accordan ce with provisions in §63.10(c), (e)(1), and (e)(2)(i). (iii) The owner or operator must conduct the CPMS equipment performance checks, system accuracy audits, or other audit procedures specified in the site

- specific monitoring plan at least once every 1 2 months. (iv) The owner or operator must conduct a performance evaluation of each CPMS in accordance with the site

- specific monitoring plan. (2) An owner or operator is exempted from the monitoring requirements specified in paragraphs (d)(3) through (7) of this section for the following types of control devices: (i) Except for control devices for small glycol dehydration units, a boiler or process heater in which all vent streams are introduced with the primary fuel or are used as the primary fuel; (ii ) Except for control devices for small glycol dehydration units, a boiler or process heater with a design heat input capacity equal to or greater than 44 megawatts. (3) * * * (i) * * *Page 473 of 497

(A) For a thermal vapor incinerator that demonstrates during the performance test conducted under §63.1282(d) that combustion zone temperature is an accurate indicator of performance, a temperature monitoring device equipped with a continuous recorder. The monitoring device shall have a minimum accuracy of ±1 percent of the temperature being monitored in degrees C, or ±2.8 degrees C, whichever value is greater. The temperature sensor shall be installed at a location representative of the combustion zone temperature. (B) For a catalytic vapor incinerator, a temperature

m onitoring device equipped with a continuous recorder. The device shall be capable of monitoring temperatures at two locations and have a minimum accuracy of ±1 percent of the temperatures being monitored in degrees C, or ±2.8 degrees C, whichever value is greater. One temperature sensor shall be installed in the vent stream at the nearest feasible point to the catalyst bed inlet and a second temperature sensor shall be installed in the vent stream at the nearest feasible point to the catalyst bed outlet.
* * * * * (D) For a boiler or process heater, a temperature monitoring device equipped with a continuous recorder. The temperature monitoring device shall have a minimum accuracy of ±1 percent of the temperature being monitored in degrees C, orPage 474 of 497

±2.8 degrees C, whichever value is greater. The temperature sensor shall be installed at a location representative of the combustion zone temperature. (E) For a condenser, a temperature monitoring device equipped with a continuous recorder. The temperature monitoring device shall have a minimum accuracy of ±1 percent of the temperature being monitored in degrees C, or ±2.8 degrees C, whichever value is greater. The temperature sensor shall be installed at a location in the exhaust vent stream from the condenser. (F) * * * ( 1 ) A continuous parameter monitoring system to measure and record the average total regeneration stream mass flow or volumetric flow during each carbon bed regeneration cycle. The flow sensor must have a measurement sensitivity of 5 percent of the flowrate or 10 cubic feet per minute, whichever is greater. The mechanical connections for leakage must be checked at least every month, and a visual inspection must be performed at least every 3 months of all components of the flow CPMS for physical and o perational integrity and all electrical connections for oxidation and galvanic corrosion if your flow CPMS is not equipped with a redundant flow sensor; and ( 2 ) A continuous parameter monitoring system to measure and record the average carbon bed temperat ure for the duration ofPage 475 of 497

the carbon bed steaming cycle and to measure the actual carbon bed temperature after regeneration and within 15 minutes of completing the cooling cycle. The temperature monitoring device shall have a minimum accuracy of ±1 percent o f the temperature being monitored in degrees C, or ±2.8 degrees C, whichever value is greater. (G) For a nonregenerative

- type carbon adsorption system, the owner or operator shall monitor the design carbon replacement interval established using a performa nce test performed in accordance with §63.1282(d)(3) and shall be based on the total carbon working capacity of the control device and source operating schedule. (H) For a control device whose model is tested under §63.1282(g): ( 1 ) The owner or operator shall determine actual average inlet waste gas flowrate using the model GRI

- GLYCalc TM , Version 3.0 or higher, ProMax, or AspenTech HYSYS. Inputs to the models shall be representative of actual operating conditions of the controlled unit. The determination shall be performed to coincide with the visible emissions test under §63.1282(h)(3); ( 2 ) A heat sensing monitoring device equipped with a continuous recorder that indicates the continuous ignition of the pilot flame.Page 476 of 497

* * * * * (4) Using the data recor ded by the monitoring system, except for inlet gas flowrate, the owner or operator must calculate the daily average value for each monitored operating parameter for each operating day. If the emissions unit operation is continuous, the operating day is a 2 4

- hour period. If the emissions unit operation is not continuous, the operating day is the total number of hours of control device operation per 24

- hour period. Valid data points must be available for 75 percent of the operating hours in an operating day t o compute the daily average. (5) * * * (i) The owner or operator shall establish a minimum operating parameter value or a maximum operating parameter value, as appropriate for the control device, to define the conditions at which the control device must be operated to continuously achieve the applicable performance requirements of §63.1281(d)(1), (e)(3)(ii), or (f)(1). Each minimum or maximum operating parameter value shall be established as follows: (A) If the owner or operator conducts performance test s in accordance with the requirements of §63.1282(d)(3) to demonstrate that the control device achieves the applicable performance requirements specified in §63.1281(d)(1), (e)(3)(ii), or (f)(1), then the minimum operating parameterPage 477 of 49 7

value or the maximum op erating parameter value shall be established based on values measured during the performance test and supplemented, as necessary, by a condenser design analysis or control device manufacturer's recommendations or a combination of both. (B) If the owner or operator uses a condenser design analysis in accordance with the requirements of §63.1282(d)(4) to demonstrate that the control device achieves the applicable performance requirements specified in §63.1281(d)(1), (e)(3)(ii), or (f)(1), then the minimum op erating parameter value or the maximum operating parameter value shall be established based on the condenser design analysis and may be supplemented by the condenser manufacturer's recommendations. (C) If the owner or operator operates a control device
wh ere the performance test requirement was met under §63.1282(g) to demonstrate that the control device achieves the applicable performance requirements specified in §63.1281(d)(1), (e)(3)(ii) or (f)(1), then the maximum inlet gas flowrate shall be establish ed based on the performance test and supplemented, as necessary, by the manufacturer recommendations. (ii) * * * (A) If the owner or operator conducts a performance test in accordance with the requirements of §63.1282(d)(3) to demonstrate that the conden ser achieves the applicablePage 478 of 497

performance requirements in §63.1281(d)(1), (e)(3)(ii), or (f)(1), then the condenser performance curve shall be based on values measured during the performance test and supplemented as necessary by control device design analysi s, or control device manufacturer's recommendations, or a combination or both. (B) If the owner or operator uses a control device design analysis in accordance with the requirements of §63.1282(d)(4)(i) to demonstrate that the condenser achieves the appli cable performance requirements specified in §63.1281(d)(1), (e)(3)(ii), or (f)(1), then the condenser performance curve shall be based on the condenser design analysis and may be supplemented by the control device manufacturer's recommendations. (C) As an alternative to paragraph (d)(5)(ii)(B) of this section, the owner or operator may elect to use the procedures documented in the GRI report entitled, “Atmospheric Rich/Lean Method for Determining Glycol Dehydrator Emissions” (GRI

– 95/0368.1) as inputs for t he model GRI

- GLYCalc TM , Version 3.0 or higher, to generate a condenser performance curve. (6) An excursion for a given control device is determined to have occurred when the monitoring data or lack of monitoring data result in any one of the criteria spec ified in paragraphs (d)(6)(i) through (d)(6)(v) of this section being met. When multiple operating parameters are monitored for the same controlPage 479 of 497

device and during the same operating day, and more than one of these operating parameters meets an excursion cr iterion specified in paragraphs (d)(6)(i) through (d)(6)(v) of this section, then a single excursion is determined to have occurred for the control device for that operating day.
* * * * * (ii) For sources meeting §63.1281(d)(1)(ii), an excursion

occurs when average condenser efficiency calculated according to the requirements specified in §63.1282(f)(2)(iii) is less than 95.0 percent, as specified in §63.1282(f)(3). For sources meeting §63.1281(f)(1), an excursion occurs when the 30

- day average condenser efficiency calculated according to the requirements of §63.1282(f)(2)(iii) is less than the identified 30

- day required percent reduction.
* * * * * (v) For control device whose model is tested under §63.1282(g) an excursion occurs when: (A) The inlet gas flowrate exceeds the maximum established during the test conducted under §63.1282(g). (B) Failure of the quarterly visible emissions test conducted under §63.1282(h)(3) occurs. (7) For each excursion, the owner or operator shall be deemed to have fai led to have applied control in a manner that achieves the required operating parameter limits. Failure toPage 480 of 497

achieve the required operating parameter limits is a violation of this standard.
* * * * * 31. Section 63.1284 is amended by: a. Revising paragraph (b)(3) introductory text; b. Removing and reserving paragraph (b)(3)(ii); c. Revising paragraph (b)(4)(ii); d. Revising paragraph (b)(4)(iii); e. Adding paragraph (b)(7)(ix); and f. Adding paragraph (f), (g) and (h) to read as follows: §63.1284 Record keeping requirements.
* * * * * (b) * * * (3) Records specified in §63.10(c) for each monitoring system operated by the owner or operator in accordance with the requirements of §63.1283(d). Notwithstanding the previous sentence, monitoring data recorded during periods identified in paragraphs (b)(3)(i) through (iv) of this section shall not be included in any average or percent leak rate computed under this subpart. Records shall be kept of the times and durations of all such periods and any other periods during process or control device operation when monitors are not operating or failed to collect required data.
* * * * *Page 481 of 497

(ii) [Reserved]
* * * * * (4) * * * (ii) Records of the daily average value of each continuously monitored parameter for each opera ting day determined according to the procedures specified in §63.1283(d)(4) of this subpart, except as specified in paragraphs (b)(4)(ii)(A) through (C) of this section. (A) For flares, the records required in paragraph (e) of this section. (B)_For conde nsers installed to comply with §63.1275, records of the annual 30

- day rolling average condenser efficiency determined under §63.1282(f) shall be kept in addition to the daily averages. (C) For a control device whose model is tested under §63.1282(g), the records required in paragraph (g) of this section. (iii) Hourly records of the times and durations of all periods when the vent stream is diverted from the control device or the device is not operating.
* * * * * (7) * * * (ix) Records identifying the carbon replacement schedule under §63.1281(d)(5) and records of each carbon replacement.Page 482 of 497

* * * * * (f) The owner or operator of an affected source subject to this subpart shall maintain records of the occurrence and duration of each malfunction of operati on ( i.e. , process equipment) or the air pollution control equipment and monitoring equipment. The owner or operator shall maintain records of actions taken during periods of malfunction to minimize emissions in accordance with §63.1274(a), including correc tive actions to restore malfunctioning process and air pollution control and monitoring equipment to its normal or usual manner of operation. (g) Record the following when using a control device whose model is tested under §63.1282(g) to comply with §63.1 281(d), (e)(3)(ii) and (f)(1): (1) All visible emission readings and flowrate calculations made during the compliance determination required by §63.1282(h); and (2) All hourly records and other recorded periods when the pilot flame is absent. (h) The dat e the semi

- annual maintenance inspection required under §63.1283(b) is performed. Include a list of any modifications or repairs made to the control device during the inspection and other maintenance performed such as cleaning of the fuel nozzles.Page 483 of 497

32. Sec tion 63.1285 is amended by: a. Revising paragraph (b)(1); b. Revising paragraph (b)(6); c. Removing paragraph (b)(7); d. Revising paragraph (d) introductory text; e. Revising paragraph (d)(1) introductory text; f. Revising paragraph (d)(1)(i); g. Re vising paragraph (d)(1)(ii) introductory text; h. Revising paragraph (d)(2) introductory text; i. Revising paragraph (d)(4) introductory text; j. Revising paragraph (d)(4)(ii); k. Adding paragraph (d)(4)(iv); l. Revising paragraph (d)(10); m. Adding paragraphs (d)(11) and (d)(12); n. Revising paragraph (e)(2) introductory text; o. Revising paragraphs (e)(2)(ii)(B); p. Adding paragraphs (e)(2)(ii)(D) and (E); q. Adding paragraphs (e)(2)(x),(xi) and (xii); and r. Adding paragraph (g) to read as fo llows: §63.1285 Reporting requirements.
* * * * * (b) * * *Page 484 of 497

(1) The initial notifications required for existing affected sources under §63.9(b)(2) shall be submitted as provided in paragraphs (b)(1)(i) and (ii) of this section. (i) Except as otherwise provided in paragraph (b)(1)(ii) of this section, the initial notification shall be submitted by 1 year after an affected source becomes subject to the provisions of this subpart or by June 17, 2000, whichever is later. Affected sources that are major sour ces on or before June 17, 2000 and plan to be area sources by June 17, 2002 shall include in this notification a brief, nonbinding description of a schedule for the action(s) that are planned to achieve area
source status. (ii) An affected source identifi ed under §63.1270(d)(3) shall submit an initial notification required for existing affected sources under §63.9(b)(2) within 1 year after the affected source becomes subject to the provisions of this subpart or by [INSERT DATE ONE YEAR AFTER DATE OF PUBLIC ATION IN THE FEDERAL REGISTER] , whichever is later. An affected source identified under §63.1270(d)(3) that plans to be an area source by [INSERT DATE THREE YEARS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER] , shall include in this notification a brie f, nonbinding description of a schedule for the action(s) that are planned to achieve area source status.
* * * * *Page 485 of 497

(6) If there was a malfunction during the reporting period, the Periodic Report specified in paragraph (e) of this section shall include th e number, duration, and a brief description for each type of malfunction which occurred during the reporting period and which caused or may have caused any applicable emission limitation to be exceeded. The report must also include a description of actions taken by an owner or operator during a malfunction of an affected source to minimize emissions in accordance with §63.1274(h), including actions taken to correct a malfunction.
* * * * * (d) Each owner or operator of a source subject to this subpart sha ll submit a Notification of Compliance Status Report as required under §63.9(h) within 180 days after the compliance date specified in §63.1270(d). In addition to the information required under §63.9(h), the Notification of Compliance Status Report shall i nclude the information specified in paragraphs (d)(1) through (12) of this section. This information may be submitted in an operating permit application, in an amendment to an operating permit application, in a separate submittal, or in any combination of the three. If all of the information required under this paragraph have been submitted at any time prior to 180 days after the applicable compliance dates specified in §63.1270(d), a separate Notification of Compliance Status ReportPage 486 of 497

is not required. If an owner or operator submits the information specified in paragraphs (d)(1) through (12) of this section at different times, and/or different submittals, subsequent submittals may refer to previous submittals instead of duplicating and resubmitting the previo usly submitted information. (1) If a closed

- vent system and a control device other than a flare are used to comply with §63.1274, the owner or operator shall submit the information in paragraph (d)(1)(iii) of this section and the information in either par agraph (d)(1)(i) or (ii) of this section. (i) The condenser design analysis documentation specified in §63.1282(d)(4) of this subpart if the owner or operator elects to prepare a design analysis; or (ii) If the owner or operator is required to conduct a performance test, the performance test results including the information specified in paragraphs (d)(1)(ii)(A) and (B) of this section. Results of a performance test conducted prior to the compliance date of this subpart can be used provided that the test was conducted using the methods specified in §63.1282(d)(3), and that the test conditions are representative of current operating conditions. If the owner or operator operates a combustion control device model tested under §63.1282(g), an electronic copy o f the performance test resultsPage 487 of 497

shall be submitted via email to Oil_and_Gas_ PT@EPA.GOV unless the test results for that model of combustion control device are posted at the following website: epa.gov/airquality/oilandgas/

. * * * * * (2) If a closed

- vent system and a flare are used to comply with §63.1274, the owner or operator shall submit performance test results including the information in paragraphs (d)(2)(i) and (ii) of this section. The owner or operator shall also submit the information in paragrap h (d)(2)(iii) of this section.
* * * * * (4) For each control device other than a flare used to meet the requirements of §63.1274, the owner or operator shall submit the information specified in paragraphs (d)(4)(i) through (iv) of this section for each operating parameter required to be monitored in accordance with the requirements of §63.1283(d).* *
* * * (ii) An explanation of the rationale for why the owner or operator selected each of the operating parameter values established in §63.1283(d)(5) of t his subpart. This explanation shall include any data and calculations used to develop the value, and a description of why the chosen value indicates that the control device is operating in accordance with the applicable requirements of §63.1281(d)(1), (e)( 3)(ii), or (f)(1).Page 488 of 497

* * * * * (iv) For each carbon adsorber, the predetermined carbon replacement schedule as required in §63.1281(d)(5)(i).
* * * * * (10) The owner or operator shall submit the analysis prepared under §63.1281(e)(2) to demonstrate that t he conditions by which the facility will be operated to achieve the HAP emission reduction of 95.0 percent, or the BTEX limit in §63.1275(b)(1)(iii) through process modifications or a combination of process modifications and one or more control devices. ( 11) If the owner or operator installs a combustion control device model tested under the procedures in §63.1282(g), the data listed under §63.1282(g)(8). (12) For each combustion control device model tested under §63.1282(g), the information listed in pa ragraphs (d)(12)(i) through (vi) of this section. (i) Name, address and telephone number of the control device manufacturer. (ii) Control device model number. (iii) Control device serial number. (iv) Date the model of control device was tested by the manuf acturer. (v) Manufacturer’s HAP destruction efficiency rating.Page 489 of 497

(vi) Control device operating parameters, maximum allowable inlet gas flowrate.
* * * * * (e) * * * (2) The owner or operator shall include the information specified in paragraphs (e)(2)(i) through (xiii) of this section, as applicable.
* * * * * (ii) * * * (B) For each excursion caused when the 30

- day average condenser control efficiency is less than the value, as specified in §63.1283(d)(6)(ii), the report must include the 30

- day average values of the condenser control efficiency, and the date and duration of the period that the excursion occurred.
* * * * * (D) For each excursion caused when the maximum inlet gas flowrate identified under §63.1282(g) is exceeded, the report must include the values of the inlet gas identified and the date and duration of the period that the excursion occurred. (E) For each excursion caused when visible emissions determined under §63.1282(h) exceed the maximum allowable duration, the report must include th e date and duration of the period that the excursion occurred, repairs affected to the unit, and date the unit was returned to service.Page 490 of 497

* * * * * (x) The results of any periodic test as required in §63.1282(d)(3) conducted during the reporting period. ( xi) For each carbon adsorber used to meet the control device requirements of §63.1281(d)(1), records of each carbon replacement that occurred during the reporting period. (xii) For combustion control device inspections conducted in accordance with §63.128 3(b) the records specified in §63.1284(h). (xiii) Certification by a responsible official of truth, accuracy, and completeness. This certification shall state that, based on information and belief formed after reasonable inquiry, the statements and inform ation in the document are true, accurate, and complete.
* * * * * (g) Electronic reporting . (1) Within 60 days after the date of completing each performance test (defined in §63.2) as required by this subpart you must submit the results of the performance tests required by this subpart to EPA’s WebFIRE database by using the Compliance and Emissions Data Reporting Interface (CEDRI) that is accessed through EPA’s Central Data Exchange (CDX)(www.epa.gov/cdx). Performance test data must be submitted in the fil e format generated through use of EPA’s Electronic Reporting Tool (ERT) (seePage 491 of 497

http://www.epa.gov/ttn/chief/ert/index.html ). Only data collected using test methods on the ERT website are subject to this requirement for submitting reports electronically to
We bFIRE. Owners or operators who claim that some of the information being submitted for performance tests is confidential business information (CBI) must submit a complete ERT file including information claimed to be CBI on a compact disk or other commonly u sed electronic storage media (including, but not limited to, flash drives) to EPA. The electronic media must be clearly marked as CBI and mailed to U.S. EPA/OAPQS/CORE CBI Office, Attention: WebFIRE Administrator, MD C404

- 02, 4930 Old Page Rd., Durham, NC 27703. The same ERT file with the CBI omitted must be submitted to EPA via CDX as described earlier in this paragraph. At the discretion of the delegated authority, you must also submit these reports, including the confidential business information, to t he delegated authority in the format specified by the delegated authority. (2) All reports required by this subpart not subject to the requirements in paragraph (g)(1) of this section must be sent to the Administrator at the appropriate address listed in §63.13. The Administrator or the delegated authority may request a report in any form suitable for the specific case (e.g., by commonly used electronic media such as Excel spreadsheet, on CD or hard copy). The Administrator retains the right to requirePage 492 of 497

sub mittal of reports subject to paragraph (g)(1) of this section in paper format. 33. Section 63.1287 is amended by revising paragraph (a) to read as follows: §63.1287 Alternative means of emission limitation. (a) If, in the judgment of the Administrator, an alternative means of emission limitation will achieve a reduction in HAP emissions at least equivalent to the reduction in HAP emissions from that source achieved under the applicable requirements in §§63.1274 through 63.1281, the Administrator will pu blish a notice in the Federal Register permitting the use of the alternative means for purposes of compliance with that requirement. The notice may condition the permission on requirements related to the operation and maintenance of the alternative means.
* * * * * 34. Appendix to Subpart HHH of Part 63

– Table is amended by revising Table 2 to read as follows: Appendix to Subpart HHH of Part 63 — Tables
* * * * * Table 2 to Subpart HHH of Part 63 — Applicability of 40 CFR Part 63 General Provisions to Subpart HHH General provisions reference Applicable to subpart HHH Explanation

§63.1(a)(1) Yes. §63.1(a)(2) Yes.Page 493 of 497

§63.1(a)(3) Yes. §63.1(a)(4) Yes. §63.1(a)(5) No Section reserved. §63.1(a)(6) through (a)(8) Yes. §63.1(a)(9) No Section reserved. §63.1(a)(10) Yes. §63.1(a)(11) Yes. §63.1(a)(12) through (a)(14) Yes. §63.1(b)(1) No Subpart HHH specifies applicability. §63.1(b)(2) Yes. §63.1(b)(3) No. §63.1(c)(1) No Subpart HHH specifies applicability. §63.1(c)(2) No. §63.1(c)(3) No Section reserved. §63.1(c)(4) Yes. §63.1(c)(5) Yes. §63.1(d) No Section reserved. §63.1(e) Yes. §63.2 Yes Except definition of major source is unique for this source category and there are additional definitions in subpart HHH. §63.3(a) through (c) Yes. §63.4(a)(1) through (a)(3) Yes. §63.4(a)(4) No Section reserved. §63.4(a)(5) Yes. §63.4(b) Yes. §63.4(c) Yes. §63.5(a)(1) Yes. §63.5(a)(2) No Preconstruction review required only for major sources that commence construction after promulgation of the standard. §63.5(b)(1) Yes. §63.5(b)(2) No Section reserved. §63.5(b)(3) Yes. §63.5(b)(4) Yes. §63.5(b)(5) Yes. §63.5(b)(6) Yes. §63.5(c) No Section reserved.Page 494 of 497

§63.5(d)(1) Yes. §63.5(d)(2) Yes. §63.5(d)(3) Yes. §63.5(d)(4) Yes. §63.5(e) Yes. §63.5(f)(1) Yes. §63.5(f)(2) Yes. §63.6(a) Yes. §63.6(b)(1) Yes. §63.6(b)(2) Yes. §63.6(b)(3) Yes. §63.6(b)(4) Yes. §63.6(b)(5) Yes. §63.6(b)(6) No Section reserved. §63.6(b)(7) Yes. §63.6(c)(1) Yes. §63.6(c)(2) Yes. §63.6(c)(3) and (c)(4) No Section reserved. §63.6(c)(5) Yes. §63.6(d) No Section reserved. §63.6(e) Yes. §63.6(e) Yes Except as otherwise specified. §63.6(e)(1)(i) No See §63.1274(h) for general duty requirement. §63.6(e)(1)(ii) No. §63.6(e)(1)(iii) Yes. §63.6(e)(2) Yes. §63.6(e)(3) No. §63.6(f)(1) No. §63.6(f)(2) Yes. §63.6(f)(3) Yes. §63.6(g) Yes. §63.6(h) Yes. §63.6(i)(1) through (i)(14) Yes. §63.6(i)(15) No Section reserved. §63.6(i)(16) Yes. §63.6(j) Yes. §63.7(a)(1) Yes. §63.7(a)(2) Yes But the performance test results must be submitted within 180 days after the compliance date. §63.7(a)(3) Yes. §63.7(b) Yes. §63.7(c) Yes.Page 495 of 497

§63.7(d) Yes. §63.7(e)(1) No. §63.7(e)(2) Yes. §63.7(e)(3) Yes. §63.7(e)(4) Yes. §63.7(f) Yes. §63.7(g) Yes. §63.7(h) Yes. §63.8(a)(1) Yes. §63.8(a)(2) Yes. §63.8(a)(3) No Section reserved. §63.8(a)(4) Yes. §63.8(b)(1) Yes. §63.8(b)(2) Yes. §63.8(b)(3) Yes. §63.8(c)(1) Yes. 63.8(c)(1)(i). §63.8(c)(1)(ii). §63.8(c)(1)(iii) No. Yes. Pending. §63.8(c)(2) Yes. §63.8(c)(3) Yes. §63.8(c)(4) No. §63.8(c)(5) through (c)(8) Yes. §63.8(d) Yes. §63.8(d)(3) Yes Except for last sentence, which refers to an SSM plan. SSM plans are not required. §63.8(e) Yes Subpart HHH does not specifically require continuous emissions monitor performance evaluations, however, the Administrator can request that one be conducted. §63.8(f)(1) through (f)(5) Yes §63.8(f)(6) No Subpart HHH does not require continuous emissions monitoring. §63.8(g) No Subpart HHH specifies continuous monitoring system data reduction requirements. §63.9(a) Yes. §63.9(b)(1) Yes. §63.9(b)(2) Yes Existing sources are given 1 year (rather than 120 days) to submit this notification. §63.9(b)(3) Yes.Page 496 of 497

§63.9(b)(4) Yes. §63.9(b)(5) Yes. §63.9(c) Yes. §63.9(d) Yes. §63.9(e) Yes. §63.9(f) Yes. §63.9(g) Yes. §63.9(h)(1) through (h)(3) Yes. §63.9(h)(4) No Section reserved. §63.9(h)(5) and (h)(6) Yes. §63.9(i) Yes. §63.9(j) Yes. §63.10(a) Yes. §63.10(b)(1) Yes Section 63.1284(b)(1) requires sources to maintain the most recent 12 months of data on

- site and allows offsite storage for the remaining 4 years of data. §63.10(b)(2) Yes. §63.10(b)(2)(i) No. §63.10(b)(2)(ii) No See §63.1284(f) for recordkeeping of occurrence, duration, and actions taken during malfunction §63.10(b)(2)(iii) Yes. §63.10(b)(2)(iv) through (b)(2)(v) No.

§63.10(b)(2)(vi) through (b)(2)(xiv) Yes.

§63.10(b)(3) No. §63.10(c)(1) Yes. §63.10(c)(2) through (c)(4) No Sections reserved. §63.10(c)(5) through (c)(8) Yes. §63.10(c)(9) No Section reserved. §63.10(c)(10) through (c)(11) No See §63.1284(f)for recordkeeping of malfunctions §63.10(c)(12) through (c)(14) Yes. §63.10(c)(15) No.Page 497 of 497

§63.10(d)(1) Yes. §63.10(d)(2) Yes. §63.10(d)(3) Yes. §63.10(d)(4) Yes. §63.10(d)(5) No See §63.1285(b)(6) for reporting of malfunctions. §63.10(e)(1) Yes. §63.10(e)(2) Yes. §63.10(e)(3)(i) Yes Subpart HHH requires major sources to submit Periodic Reports semi

- annually. §63.10(e)(3)(i)(A) Yes. §63.10(e)(3)(i)(B) Yes. §63.10(e)(3)(i)(C) No Subpart HHH does not require quarterly reporting for excess emissions. §63.10(e)(3)(ii) through (e)(3)(viii) Yes.

§63.10(f) Yes. §63.11(a) and (b) Yes. §63.11(c), (d), and (e) Yes. §63.12(a) through (c) Yes. §63.13(a) through (c) Yes. §63.14(a) and (b) Yes. §63.15(a) and (b) Yes.