For more information on the estimated energy effects, please refer to the economic impact analysis for this proposed 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 National Technology Transfer and Advancement Act of 1995 (NTTAA), Public Law No. 104-113 (15 U.S.C. 272 note) directs the EPA to use VCS in its regulatory activities unless to do so would be inconsistent with applicable law or otherwise impractical. Voluntary consensus standards are technical standards (e.g., materials specifications, test methods, sampling procedures, and business practices) that are developed or adopted by VCS. The NTTAA directs the EPA to provide Congress, through OMB, explanations when the Agency decides not to use available and applicable VCS.
	The proposed rule involves technical standards. Therefore, the requirements of the NTTAA apply to this action. We are proposing to revise 40 CFR part 63, subparts HH and HHH to allow ANSI/ASME PTC 19.10 - 1981, Flue and Exhaust Gas Analyses (Part 10, Instruments and Apparatus) to be used in lieu of EPA Methods 3B, 6 and 16A. This standard is available from the American Society of Mechanical Engineers (ASME), Three Park Avenue, New York, NY 10016-5990. Also, we are proposing to revise 40 CFR part 63, subpart HHH, to allow ASTM D6420-99(2004), Test Method for Determination of Gaseous Organic Compounds by Direct Interface Gas Chromatography/Mass Spectrometry, to be used in lieu of EPA Method 18. For a detailed discussion of this VCS, and its appropriateness as a substitute for Method 18, see the final oil and natural gas production NESHAP (Area Sources) (72 FR 36, January 3, 2007).
	As a result, the EPA is proposing ASTM D6420-99 for use in 40 CFR part 63, subpart HHH. The EPA also proposes to allow Method 18 as an option in addition to ASTM D6420-99(2004). This would allow the continued use of GC configurations other than GC/MS.
	The EPA welcomes comments on this aspect of the proposed rulemaking and, specifically, invites the public to identify potentially-applicable VCS and to explain why such standards should be used in this regulation.
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.
      To examine the potential for any EJ issues that might be associated with each source category, we evaluated the distributions of HAP-related cancer and noncancer risks across different social, demographic, and economic groups within the populations living near the facilities where these source categories are located. The methods used to conduct demographic analyses for this rule are described in section VII.D of the preamble for this rule. The development of demographic analyses to inform the consideration of EJ issues in EPA rulemakings is an evolving science. The EPA offers the demographic analyses in this proposed rulemaking as examples of how such analyses might be developed to inform such consideration, and invites public comment on the approaches used and the interpretations made from the results, with the hope that this will support the refinement and improve utility of such analyses for future rulemakings.
      For the demographic analyses, we focused on the populations within 50 km of any facility estimated to have exposures to HAP which result in cancer risks of 1-in-1 million or greater, or noncancer HI of 1 or greater (based on the emissions of the source category or the facility, respectively). We examined the distributions of those risks across various demographic groups, comparing the percentages of particular demographic groups to the total number of people in those demographic groups nationwide. The results, including other risk metrics, such as average risks for the exposed populations, are documented in source category-specific technical reports in the docket for both source categories covered in this proposal.
	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 effects, and that acute and chronic noncancer health 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 unacceptable level of risk.
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, Air pollution control, Reporting and recordkeeping requirements, Volatile organic compounds.

____________________________
Dated:

____________________________
Lisa P. Jackson,
Administrator.
For the reasons set out in the preamble, title 40, chapter I of the Code of Federal Regulations is proposed to be 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 for §§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).
* * * * *
Subpart 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 [INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER].

	3. The heading for Subpart KKK is revised 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 [INSERT DATE OF PUBLICATON IN THE FEDERAL REGISTER], is subject to the requirements of this subpart.
* * * * *
Subpart LLL--Standards of Performance for SO2 Emissions from Onshore Natural Gas Processing for which Construction, Reconstruction, or Modification Commenced After January 20, 1984, and on or Before [INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER].

	5. The heading for Subpart LLL is revised 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.
* * * * *
	(d) The provisions of this subpart apply to each affected facility identified in paragraph (a) of this section which commences construction or modification after January 20, 1984, and on or before [INSERT DATE OF PUBLICATON IN THE FEDERAL REGISTER].
* * * * *
	7. Part 60 is amended by adding subpart OOOO 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 wellhead 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 affected facilities at 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 processing 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?
60.5408	What is an optional procedure for measuring hydrogen sulfide in acid gas-Tutwiler Procedure.
60.5410	How do I demonstrate initial compliance with the standards for my gas wellhead 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 plants?
60.5415	How do I demonstrate continuous compliance with the standards for my gas wellhead 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 plants?
60.5420	What are my notification, reporting, and recordkeeping requirements?
60.5421	What are my additional recordkeeping 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 of the General Provisions apply to me?
60.5430	What definitions apply to this subpart?

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 (SO2) emissions from affected facilities that commenced construction, modification or reconstruction after [INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER].
§60.5365 Am I subject to this 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 [INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER] your affected facility is subject to the applicable provisions of this subpart. For the purposes of this subpart, a well completion operation following hydraulic fracturing or refracturing that occurs at a gas wellhead facility that commenced construction, modification, or reconstruction on or before [INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER] is considered a modification of the gas wellhead facility, but does not affect other equipment, process units, storage vessels, or pneumatic devices located at the well site.
	(a) A gas wellhead affected facility, is a single natural gas well.
	(b) A centrifugal compressor affected facility, which is defined as a single centrifugal compressor located between the wellhead and the city gate (as defined in §60.5430), except that a centrifugal 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 the compressor is installed at the facility.
 	(c) A reciprocating compressor affected facility, which is defined as a single reciprocating compressor located between the wellhead and the city gate (as defined in §60.5430), except that a reciprocating 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 reciprocating compressor is considered to have commenced construction on the date the compressor is installed at the facility.
	(d) A pneumatic controller affected facility, which is defined as a single pneumatic controller.
	(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.
	(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 accomplished 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, field 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 onshore 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 (f)(1) and (f)(2) are exempt from this subpart if they are subject to and controlled according to 40 CFR subparts VVa, GGG or GGGa.
	(g) Sweetening units located onshore that process natural gas produced from either onshore or offshore wells.
	(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 capacity 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 §§60.5405 through 60.5407, and paragraphs 60.5410(g), 60.5415(g), and §60.5423 of this subpart.
§60.5370 When must I comply with this subpart?
	(a) You must be in compliance with the standards of this subpart no later than the date of publication of the final rule in the Federal Register or upon startup, whichever is later.
	(b) The provisions for exemption from compliance during periods of startup, shutdown, and malfunctions 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 wellhead affected facilities?
	If you are the owner or operator of a gas wellhead 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, you must control emissions by the operational procedures found in paragraphs (a)(1) through (a)(3) of this section.
	(1) You must minimize the emissions associated with venting of hydrocarbon fluids and gas over the duration of flowback by routing the recovered liquids into storage vessels and routing the recovered gas into a gas gathering line or collection system.
	(2) You must employ sand traps, surge vessels, separators, and tanks during flowback and cleanout operations to safely maximize resource recovery and minimize releases to the environment. 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. 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 wellhead 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 wellhead affected facilities as required by §60.5410.
     (d) You must demonstrate continuous compliance with the standards that apply to gas wellhead affected facilities as required by §60.5415.
     (e) You must perform the required notification, recordkeeping, and reporting as required by §60.5420.
	(f) For wells meeting the criteria for wildcat or delineation wells, each well completion operation with hydraulic fracturing at a gas wellhead affected facility must reduce emissions by using a completion combustion device meeting the requirements of paragraph (a)(3) of this section. You must also maintain records specified in §60.5420(c)(1)(iii) for wildcat or delineation 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) You must equip each rotating compressor shaft with a dry seal system upon initial startup.
	(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 facilities as required by §60.5415.
	(d) You must perform the required notification, recordkeeping, and reporting as required by §60.5420.
§60.5385 What standards apply to reciprocating compressor affected facilities?
	You must comply with the standards in paragraphs (a) through (d) of this section for each reciprocating compressor affected facility.
	(a) You must replace the reciprocating compressor rod packing before the compressor has operated in the pressurized mode for 24,000 hours. The number of hours of operation in the pressurized mode must be continuously monitored beginning upon initial startup of your reciprocating compressor affected facility, or the date of publication of the final rule in the Federal Register, or the date of the previous reciprocating compressor rod packing replacement, whichever is later.
	(b) You must demonstrate initial compliance with standards that apply to reciprocating compressor affected facilities as required by §60.5410.
	(c) You must demonstrate continuous compliance with standards that apply 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 high bleed device is predicated. The demonstration may include, but is not limited to, response time, safety and actuation.
	(b) Each pneumatic controller affected facility located at a natural gas processing plant (as defined in §60.5430) must have zero emissions of natural gas.
	(c) Each pneumatic controller affected facility not located at a natural gas processing plant (as defined in §60.5430) must have natural gas emissions no greater than 6 standard cubic feet per hour.
	(d) You must demonstrate initial compliance with standards that apply to pneumatic controller affected facilities as required by §60.5410.
	(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, except 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 paragraphs (a) through (e) of this section for each storage vessel affected facility.
	(a) You must comply with the standards for storage vessels specified in 40 CFR part 63, subpart HH, §63.766(b) and (c), except as specified in paragraph (b) of this section. Storage vessels that meet either one or both of the throughput conditions specified in paragraphs (a)(1) or (a)(2) of this section are not subject to the standards of this section.
	(1) The annual average condensate throughput is less than 1 barrel per day per storage vessel.
	(2) The annual average crude oil throughput is less than 21 barrels per day per storage vessel.
	(b) This standard does not apply to storage vessels already subject to and controlled in accordance with the requirements for storage vessels in 40 CFR part 63, subpart HH, §63.766(b)(1) or (2).
	(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 compressor 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.
    (a) You must comply with the requirements of §§60.482-1a(a), (b), and (d) and 60.482-2a through 60.482-10a, 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 as 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 determined that it contains or contacts the 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 methods 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 processing 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 detect leaks by the methods specified in §60.485a(b) except as provided in paragraph (b)(4) of this section, and §60.482-4a(a) through (c) of subpart VVa.
    (2) If an instrument reading of 10,000 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-plant personnel may be monitored after a pressure release the next time the monitoring personnel are on-site, instead of within 5 days as specified in paragraph (b)(1) of this section and §60.482-4a(b)(1) of subpart VV.
    (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 release 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 located 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 from the routine monitoring requirements of §§60.482-2a(a)(1), 60.482-7a(a), and paragraph (b)(1) of this section.
    (f) Reciprocating compressors in wet gas service at onshore natural gas processing plants are exempt from the compressor control requirements of §60.482-3a.
    (g) Flares used to comply with this subpart must comply with the requirements of §60.18.
    (h) An owner or operator may use the following 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 standard. The notice may condition permission on requirements related to the operation and maintenance of the alternative means.
    (b) Any notice under paragraph (a) of this section must be published only after notice and an opportunity for a public hearing.
    (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 paragraph (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 reduction 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 this subpart based on the sulfur feed rate (X) and the sulfur content of the acid gas (Y) of the affected facility.
	(b) After demonstrating compliance 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 appendix 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:
X=KQaY
Where:
X = average sulfur feed rate, Mg/D (LT/D).
Qa = average volumetric flow rate of acid gas from sweetening unit, dscm/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))
  = 1.331 x 10−3Mg/dscm, for metric units
  = (32 lb S/lb-mole)/((385.36 dscf/lb-mole)(2240 lb S/long ton))
  = 3.707 x 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 unit (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 procedure by 1.62 x 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:
	(1) You must compute the emission reduction efficiency (R) achieved by the sulfur recovery technology for each run using the following equation:
R= 100S /S+E
	(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:
E= CeQsd/K1
Where:
E = emission 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 hours. 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 of 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 minutes each at 30-minute intervals. The arithmetic average must be the concentration for the run. The concentration must be multiplied by 0.5 x 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 the 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 x 10−3 to convert the results 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 percent by 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 x 10−3 to convert the results to 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 two 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 intervals 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 located at an onshore natural gas processing plant and is subject to the provisions of §60.5405(a) or (b) you must install, calibrate, 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 liquid 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 be accurate within +-2 percent of the 24-hour sulfur accumulation.
	(2) The H2S 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-hour 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.
	(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 computed 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 monitoring 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 equivalent 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 must 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 less 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. 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.
	(3) Upon promulgation of a performance specification 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 for 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 measure 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 monitoring system must be set so that the equivalent emission limit of §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 monitoring 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-hour 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 systems 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 points to calculate each 1-hour average. You must use a minimum of 18 1-hour averages to compute each 24-hour average.
	(e) In lieu of complying with (b) or (c) of this section, those sources with a design capacity of less than 152 Mg/D (150 LT/D) of H2S expressed as sulfur may calculate the sulfur emission reduction efficiency achieved for each 24-hour period by:
R= K2SX
Where:
R = The sulfur dioxide removal efficiency achieved during the 24-hour period, percent.
K2 = Conversion factor, 0.02400 Mg/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 section 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.
§60.5408  What is an optional procedure for measuring hydrogen sulfide in acid gas -- Tutwiler Procedure.
	(a) When an instantaneous sample is desired and H2S concentration is ten grains per 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 into a 250 ml volumetric 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.
	(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 H2S per 100 cubic foot of gas=100 (D -- C)
	(f) Greater 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.

Figure 1. Tutwiler burette (lettered items mentioned in text).
§60.5410 How do I demonstrate initial compliance with the standards for my gas wellhead 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 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 date of publication of the final rule in the Federal 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 wellhead affected facility if you have complied with paragraphs (a)(1) and (a)(2) of this section.
	(1) You have notified the Administrator within 30 days of the commencement of the well completion operation, the date of the commencement of the well completion operation, 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 American Datum (NAD) of 1983.
	(2) 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.
	(3) You have submitted the initial annual report for your wellhead affected facility as required in §60.5420(b).
	(b) You have achieved initial compliance with standards for your centrifugal compressor affected facility if the centrifugal compressor is fitted with a dry seal system upon initial startup as required by §60.5380.
	(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 in the pressurized mode.
	(2) You have included the cumulative number of hours of operation in the pressurized mode for your reciprocating compressor affected facility during the initial compliance period in your initial annual report required in §60.5420(b).
	(d) You have achieved initial compliance with emission standards for your pneumatic controller affected facility if you comply with the requirements specified in paragraphs (d)(1) through (d)(4) of this section.
	(1) You have demonstrated, to the Administrator's satisfaction, the use of a high bleed device is predicated 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.
	(3) You own or operate a pneumatic controller affected facility not located at a natural gas processing plant and the manufacturer's design specifications guarantee the controller emits less than or equal to 6.0 standard cubic feet of gas per hour.
	(4) You have included the information in paragraphs (d)(1) through (d)(3) of this section in the initial annual report submitted for your pneumatic controller affected facilities 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 are complying with paragraphs (e)(1) through (e)(7) of this section.
	(1) You have equipped the storage vessel with a closed vent system that meets the requirements of §63.771(c) connected to a control device that meets the conditions specified in §63.771(d).
	(2) You have conducted an initial performance test as required in §63.772(e) within 180 days after initial startup or the date of publication of the final rule in the Federal Register and have conducted the compliance demonstration in §63.772(f).
	(3) You have conducted the initial inspections required in §63.773(c).
	(4) You have installed and operated continuous parameter monitoring systems in accordance with §63.773(d).
	(5) If you are exempt from the standards of §60.5395 according to §60.5395(a)(1) or (a)(2), you have determined the condensate or crude oil throughput, as applicable, according to paragraphs (e)(5)(i) or (e)(5)(ii) of this section and demonstrated to the Administrator's satisfaction that your annual average condensate throughput is less than 1 barrel per day per tank and your annual average crude oil throughput is less than 21 barrels per day per tank.
	(i) You have installed and operated a flow meter to measure condensate or crude oil throughput in accordance with the manufacturer's procedures or specifications.
	(ii) You have used any other method approved by the Administrator to determine annual average condensate or crude oil throughput.
	(6) You have submitted the information in paragraphs (e)(1) through (e)(5) of this section in the initial annual report for your storage vessel affected facility as required in §60.5420(b).
	(f)  For affected facilities at onshore natural gas processing plants, initial compliance with the VOC requirements 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 compliance 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 (Zi) is compared to the emission reduction efficiency (R) achieved by the sulfur recovery technology as specified in paragraphs (g)(1)(i) and (g)(1)(ii) of this section.
	(i) If R >= Zi, your affected facility is in compliance.
	(ii) If R < Zi, 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) in the initial annual report submitted for your sweetening unit affected facilities at onshore natural gas processing plants.
§60.5415	How do I demonstrate continuous compliance with the standards for my gas wellhead 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?
	(a) For each gas wellhead 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 facility, continuous compliance is demonstrated if the rotating compressor shaft is equipped with a dry seal.
	(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 in the pressurized mode for each reciprocating compressor affected facility since initial startup, or the date of publication of the final rule 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 in the pressurized mode 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 in the pressurized mode reaches 24,000 hours.
	(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, continuous compliance is demonstrated according 40 CFR part 63, subpart HH, §63.772(f).
	(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 onshore natural gas processing plants, you must demonstrate continuous compliance with the standards for SO2 specified in §60.5405(b) according to paragraphs (g)(1) and (g)(2) of this section.
	(1) The minimum required SO2 emission reduction efficiency (Zc) is compared to the emission reduction efficiency (R) achieved by the sulfur recovery technology.
	(i) If R >= Zc, your affected facility is in compliance.
	(ii) If R < Zc, 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 paragraph §§60.5375, 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 exceedances of such standards that are caused by malfunction, as defined at 40 CFR 60.2. Appropriate penalties may be assessed, however, if you fail to meet your burden of proving all of the requirements 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 §60.5420(a), 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, 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 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; and
	(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 of the excess emissions 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 excess emissions were documented by properly signed, contemporaneous operating logs; and
	(viii) At all times, the facility 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 excess emissions 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.
	(2) The owner or operator of the facility experiencing an exceedance of its emission limit(s) during a malfunction shall notify the Administrator by telephone or facsimile (FAX) transmission as soon as possible, but no later than 2 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 initial occurrence of the exceedance of the standards in §§60.5375, 60.5380, 60.5385, 60.5390, 60.5395, and 60.5400 to demonstrate, with all necessary supporting documentation, that it has met the requirements set forth in paragraph (a) 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 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 requirement to submit such report within 45 days of the initial occurrence of the exceedance.
§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. For the purposes of this subpart, a workover that occurs after [INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER] at each affected facility for which construction, reconstruction, or modification commenced on or before [INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER] is considered a modification for which a notification must be submitted under §60.7(a)(4).
	(1) If you own or operate a pneumatic controller 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 wellhead affected facility, you must submit a notification to the Administrator within 30 days of the commencement of the well completion operation. The notification must include the date of commencement of the well completion operation, 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 American Datum of 1983.
	(b) Reporting requirements. You must submit annual reports containing the information specified in paragraphs (b)(1) through (b)(6) of this section to the Administrator. The initial annual report is due 1 year after the initial startup date for your affected facility or 1 year after the date of publication of the final rule 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 affected 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.
	(1) The general information specified in paragraphs (b)(1)(i) through (b)(1)(iii) 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.
	(2) For each gas wellhead 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 wellhead affected facility conducted during the reporting period;
	(ii)  A record of deviations in cases where well completion operations with hydraulic fracturing were not performed in compliance with the requirements specified in §60.5375 for each gas well affected facility.
	(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 installed during the reporting period, documentation that the centrifugal compressor is equipped with dry seals.
	(4)  For each reciprocating compressor affected facility, the information specified in paragraphs (b)(4)(i) and (b)(4)(ii) of this section.
	(i) The cumulative number of hours or operation in the pressurized mode since initial startup, the date of publication of the final rule 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 in the pressurized mode reached 24,000 hours.
	(5) For each pneumatic controller affected facility, the information specified in paragraphs (b)(5)(i) through (b)(5)(iv) of this section.
	(i) The date, location and manufacturer specifications for each pneumatic controller installed.
	(ii) If applicable, documentation that the use of high bleed pneumatic devices is predicated and the reasons why.
	(iii) For pneumatic controllers not installed at a natural gas processing plant, the manufacturer's guarantee that the device is designed such that natural gas emissions are less than 6 standard cubic feet per hour.
	(iv) For pneumatic controllers installed at a natural gas processing plant, documentation that each controllers has zero natural gas emissions.
	(6) For each storage vessel affected facility, the information in paragraphs (b)(6)(i) and (b)(6)(ii) of this section.
	(i) If required to reduce emissions by complying with paragraph §60.5395(a)(1), the records specified in 40 CFR part 63, subpart §63.774(b)(2) through (b)(8).
	(ii) Documentation that the annual average condensate throughput is less than 1 barrel per day per storage vessel and crude oil throughput is less than 21 barrels per day per storage for meeting the requirements in §60.5395(a)(1) or (a)(2).
	(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 wellhead affected facility as specified in paragraphs (c)(1)(i) through (c)(1)(iii).
	(i) Records identifying each well completion operation for each gas wellhead affected facility conducted during the reporting period;
	(ii) Record 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 wellhead 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 wellheads affected facility required to comply with the requirements of §60.5375(a), you must record: The location of the well; the duration of flowback; duration of 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 wellhead 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.
	(2) For each centrifugal compressor affected facility, you must maintain records on the type of seal system installed.
	(3) For each reciprocating compressors affected facility, you must maintain the records in paragraphs (c)(3)(i) and (c)(3)(ii) of this section.
	(i) Records of the cumulative number of hours of operation in the pressurized mode since initial startup or the date of publication of the final rule 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.

	(4)  For each pneumatic controller affected facility, you must maintain the records identified in paragraphs (c)(4)(i) through (c)(4)(iv) of this section.
	(i) Records of the date, location and manufacturer specifications for each pneumatic controller installed.
	(ii) Records of the determination that the use of high bleed pneumatic devices is predicated and the reasons why.
	(iii) If the pneumatic controller affected facility is not located at a natural gas processing plant, records of the manufacturer's guarantee that the device is designed such that natural gas emissions are less than 6 standard cubic feet per hour.
	(iv) If the pneumatic controller affected facility is located at a natural gas processing plant, records of the documentation that only instrument air controllers are used.
	(5) For each storage vessel affected facility, you must maintain the records identified in paragraphs (c)(5)(i) and (c)(5)(ii) of this section.
	(i) If required to reduce emissions by complying with §63.766, the records specified in 40 CFR part 63, subpart HH, §63.774(b)(2) through (8).
	(ii) Records of the determination that the annual average condensate throughput is less than 1 barrel per day per storage vessel and crude oil throughput is less than 21 barrels per day per storage vessel for the exemption under §60.5395(a)(1) and (a)(2).
§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 paragraphs (b) and (c) of this section in addition to the requirements of §60.486a.
    (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 may 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 operator 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 10,000 ppm" if the maximum instrument reading measured by the methods specified in paragraph (a) of this section after each repair attempt is 10,000 ppm or greater.
    (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 repaired 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 emissions 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.
    (c) An owner or operator must comply with the following requirement in addition to the requirement of §60.486a(j): Information and data used to demonstrate that a reciprocating compressor is in wet gas service to apply for the exemption in §60.5401(f) must be recorded in a log that is kept in a readily accessible location.
§60.5422 What are my additional reporting requirements for my affected facility subject to VOC requirements 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.
	(b) An owner 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 pressure 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 required 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.
	(b) You must submit a written report of excess emissions to the Administrator semiannually. 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 any 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 determined 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 control requirements of these standards, for each facility with a design capacity less that 2 LT/D of H2S 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 H2S 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 H2S expressed as sulfur.
	(e) The requirements 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 such 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 apply 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 (H2S) and carbon dioxide (CO2) that has been separated from sour natural gas by a sweetening unit.
	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 transferred 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 or workovers.
	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 fields, 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, as specified in §60.2. For the 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.
	Delineation well means a well drilled in order to determine the boundary of a field or producing reservoir.
	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).
	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.
	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 and returning the well to production.
	Flow line means surface pipe through which oil and/or natural gas travels from the well.
	Gas-driven pneumatic controller means a pneumatic controller powered by pressurized natural gas.
	Gas processing plant process unit means equipment 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 independently if supplied with sufficient feed or raw materials and sufficient storage facilities for the products.
	Gas well means a well, the principal production of which at the mouth of the well is gas.
	High-Bleed Pneumatic Devices means automated, continuous bleed flow control devices powered by pressurized natural gas and used for maintaining a process condition such as liquid level, pressure, delta-pressure and temperature. Part of the gas power stream which is regulated by the process condition flows to a valve actuator controller where it vents continuously (bleeds) to the atmosphere at a rate in excess of six standard cubic feet per hour.
	Hydraulic fracturing means process of directing pressurized liquids, containing water, proppant, and any added chemicals, to penetrate tight sand, shale, or coal formations that involve high rate, extended back flow to expel fracture fluids and sand during completions and well workovers.
	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.
	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-toxic.
	Low-bleed pneumatic controller means automated flow control devices powered by pressurized natural gas and used for maintaining a process condition such as liquid level, pressure, delta-pressure and temperature. Part of the gas power stream which is regulated by the process condition flows to a valve actuator controller where it vents continuously (bleeds) to the atmosphere at a rate equal to or less than six standard cubic feet per hour.
	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 natural gas into the atmosphere not previously emitted. For the purposes of this subpart, each recompletion of a refractured gas well is considered to be a modification.
	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.
	Nonfractionating plant means any gas plant that does not fractionate mixed natural gas liquids into natural gas products.
	Non gas-driven pneumatic device means an instrument that is actuated using other sources of power than pressurized natural gas; examples include solar, electric, and instrument air.
	Onshore means all facilities except those that are located in the territorial seas or on the outer continental shelf.
	Plunger lift system means an intermittent gas lift that uses gas pressure buildup in the casing-tubing annulus to push a steel plunger, and the column of fluid ahead of it, up the well tubing to the surface.
 	Pneumatic controller means an automated instrument used for maintaining a process condition such as liquid level, pressure, delta-pressure and temperature.
	Pneumatic pump means a pump that uses pressurized natural gas to move a piston or diaphragm, which pumps liquids on the opposite side of the piston or diaphragm.
	Process unit 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 independently 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 movement 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 limiting 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 H2S, carbonyl sulfide (COS), and carbon disulfide (CS2).
	Routed to a process or route to a process 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 reaction into materials that are not regulated materials and/or incorporated into a product; and/or recovered.
	Sales line means pipeline, generally small in diameter, used to transport oil or gas from the well to a processing facility or a mainline pipeline.
	Salable quality gas means natural gas that meets the composition, moisture, or other limits set by the purchaser of the natural gas.
	Storage vessel means a stationary vessel or series of stationary vessels that are either manifolded together or are located at a single well site and that have potential for VOC emissions equal to or greater than 10 tpy.
	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.
	Sweetening unit means a process device that removes hydrogen sulfide and/or carbon dioxide from the natural gas stream.
	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.
	Total SO2 equivalents means the sum of volumetric or mass concentrations of the sulfur compounds obtained by adding the quantity existing as SO2 to the quantity of SO2 that would be obtained if all reduced sulfur compounds were converted to SO2 (ppmv or kg/dscm (lb/dscf)).
	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.
	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 process that allows for the flow of petroleum or natural gas from newly drilled wells to expel drilling and reservoir fluids and tests the reservoir flow characteristics, steps which may vent produced gas to the atmosphere via an open pit or tank. Well completion also involves connecting the well bore to the reservoir, which may include treating the formation or installing tubing, packer(s), or lifting equipment.
	Well completion operation means any well completion or well workover occurring at a gas wellhead 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 site 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.
   Table 1. Required Minimum Initial SO2 Emission Reduction Efficiency (Zi)

                        H2S 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 99.8, 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. Required Minimum SO2 Emission Reduction Efficiency (Zc)

                        H2S 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 99.8, 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 H2S in the acid gas), expressed as sulfur, Mg/D(LT/D), rounded to one decimal place.
Y = The sulfur content of the acid gas from the sweetening unit, expressed as mole percent H2S (dry basis) rounded to one decimal place.
Z = The minimum required sulfur dioxide (SO2) emission reduction efficiency, expressed as percent carried to one decimal place. Zi refers to the reduction efficiency required at the initial performance test. Zc refers to the reduction efficiency required on a continuous basis after compliance with Zi has been demonstrated.

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 subpart?
                                  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
Yes

§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

§60.19
General notification and reporting requirement
Yes

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)(67), (b)(68), (b)(69) and (b)(70); and
	b. Revising paragraph (i)(1) to read as follows:
§63.14 Incorporations by reference.
* * * * *
	(b) * * *
* * * * *
	(67) ASTM D1945  -  03(2010) Standard Test Method for Analysis of Natural Gas by Gas Chromatography, IBR approved for §§63.772 and 63.1282.
	(68) 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.
	(69) 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.
	(70) ASTM D4891 - 89(2006) Standard Test Method for Heating Value of Gases in Natural Gas Range by Stoichiometric 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)(ii);
	e. Revising paragraph (f) introductory text;
	f. Revising paragraph (f)(1);
	g. Revising paragraph (f)(2); and
	h. 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. Existing sources with operating records for each of the 5 years preceding June 15, 1999 can estimate emissions based on these records for major source determination purposes using the maximum natural gas or hydrocarbon liquid throughput, as appropriate, calculated 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 hydrocarbon 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 (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 all provisions of this subpart applicable to a major source starting on the applicable compliance date specified in 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 available 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 throughput 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 dehydration 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 hydrocarbon liquids prior to the point where hydrocarbon liquids enter either the Organic Liquids Distribution (Non-gasoline) or Petroleum Refineries source categories.
* * * * *
	(b) * * *
	(1) * * *
* * * * *
	(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), (f)(7) through (f)(9) of this section. The owner or operator of an affected 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 affected 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 operator 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 major 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 (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 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.
* * * * *
	(7) Each affected small glycol dehydration unit and each storage vessel that is not a storage vessel with the potential for flash emissions located at a major source, that commenced construction before [INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER] must achieve compliance no later than 3 years after the date of publication of the final rule in the Federal Register, except as provided in §63.6(i).
	(8) Each affected 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 on or after [INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER] must achieve compliance immediately upon initial startup or the date of publication of the final rule in the Federal Register, whichever is later.
	(9) A production field facility, as defined in §63.761, constructed before [INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER] that was previously determined to be an area source but becomes a major source (as defined in paragraph 3 of the major source definition in §63.761) on the date of publication of the final rule in the Federal Register must achieve compliance no later than 3 years after the date of publication of the final rule in the Federal Register, except as provided in §63.6(i).
* * * * *
	11. Section 63.761 is amended by:
	a. Adding a definition for "affirmative defense" in alphabetical order;
	b. Revising the definition for "associated equipment";
	c. Adding a definition for "BTEX" in alphabetical order;
	d. Revising the definition for "facility";
	e. Adding a definition for "flare" in alphabetical order;
	f. Revising the definition for "glycol dehydration unit baseline operations";
	g. Adding a definition for "large glycol dehydration units" in alphabetical order;
	h. Revising paragraph (3) of the definition for "major source";
	i. Adding a definition for "small glycol dehydration units" in alphabetical order; and
	j. Revising the definition for "temperature monitoring device" to read as follows:
§63.761 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 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 from the wellbore to the point of custody transfer, except glycol dehydration units and storage vessels.
* * * * *
	BTEX means benzene, toluene, ethyl benzene and xylene.
* * * * *
	Facility means any grouping of equipment where hydrocarbon liquids are processed, upgraded (i.e., remove impurities or other constituents to meet contract specifications), or stored; or where natural gas is processed, upgraded, or stored. For the purpose of a major source determination, facility (including a building, structure, or installation) means oil and natural gas production and processing equipment that is located within the boundaries of an individual surface site as defined in this section. Equipment that is part of a facility will typically be located within close proximity to other equipment located at the same facility. Pieces of production equipment or groupings of equipment located on different oil and gas leases, mineral fee tracts, lease tracts, subsurface or surface unit areas, surface fee tracts, surface lease tracts, or separate surface sites, whether or not connected by a road, waterway, power line or pipeline, shall not be considered part of the same facility. Examples of facilities in the Oil and Natural Gas Production source category include, but are not limited to, well sites, satellite tank batteries, central tank batteries, a compressor station that transports natural gas to a natural gas processing plant, and natural gas processing plants.
* * * * *
	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 [INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER]. For the purposes of this subpart, for determining the percentage of overall HAP emission reduction attributable to process modifications, 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). 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 greater 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 determination. For facilities that are not production field facilities, HAP emissions from all HAP emission units shall be aggregated for a major source determination.
* * * * *
	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).
* * * * *
	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 °C, or +-2.5 °C, whichever is greater. The temperature monitoring device may measure temperature in degrees Fahrenheit or degrees Celsius, or both.
	12. Section 63.762 is amended by:
	a. Revising paragraphs (a) through (d); and
	b. Removing paragraph (e) to read as follows:
§63.762 Startups and shutdowns.
	(a) The provisions set forth in this subpart shall apply at all times.
	(b) The owner or operator shall not shut down items of equipment that are required or utilized for compliance with the provisions of this subpart during times when emissions are being routed to such items of equipment, if the shutdown would contravene requirements of this subpart applicable to such items of equipment. This paragraph does not apply if the owner or operator must shut down the equipment to avoid damage due to a contemporaneous startup or shutdown, of the affected source or a portion thereof.
	(c) During startups and shutdowns, the owner or operator shall implement measures to prevent or minimize excess emissions to the maximum extent practical.
	(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 requirements 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 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, 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 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 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; and
	(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 of the excess emissions 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 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; and
	(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 monitoring 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 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 initial 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 this 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 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) introductory text;
	c. Revising paragraph (i) introductory text; 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.
* * * * *
	(e) Exemptions. (1) The owner or operator of an area source is exempt from the requirements 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 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 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 with 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 limited to, monitoring results, review of 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) introductory text;
	c. Revising paragraphs (b)(1)(i) and (b)(1)(ii);
	d. Adding paragraph (b)(1)(iii);
	e. Revising paragraph (c)(2);
	f. Revising paragraph (c)(3) introductory text;
	g. Revising paragraphs (c)(3)(i) and (c)(3)(ii); and
	h. Adding paragraph (c)(3)(iii) 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 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(d).
	(ii) The owner or operator of a glycol dehydration unit located at an area source, that must be controlled as specified in §63.764(d)(1)(i), shall connect the process vent to a control 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 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(d), except that the performance levels specified in §63.771(d)(1)(i) and (ii) do not apply.
	(iii) You must limit BTEX emissions from each small glycol dehydration unit process vent, as defined in §63.761, to the limit determined in Equation 1 of this section. The limit 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:
ELBTEX = Unit-specific BTEX emission limit, megagrams per year;
1.10x10[-4] = BTEX emission limit, grams BTEX/standard cubic meter -ppmv;
Throughput = Annual average daily natural gas throughput, standard cubic meters per day;
Ci,BTEX = 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 through 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 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 dehydration unit. Document operational parameters in accordance with the requirements 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) 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 glycol dehydration unit process vent are reduced by one of the levels specified in paragraph (c)(3)(i), (ii), or (iii) 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.
	(ii) For area source dehydration units, benzene emissions are reduced to a level less than 0.90 megagrams per year.
	(iii) For each small glycol dehydration unit, BTEX emissions are reduced to a level less than the limit calculated by paragraph (b)(1)(iii) of this section.
	15. Section 63.766 is amended by:
	a. Revising paragraph (a);
	b. Revising paragraph (b) introductory text; and
	c. Revising paragraph (b)(1) 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) and (2) of this section.
	(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 a control device or a combination of control devices that meets any of the conditions specified in §63.771(d). The cover shall be designed and operated in accordance with the requirements of §63.771(b).
* * * * *
	16. Section 63.769 is amended by:
	a. Revising paragraph (b); and
	b. Revising 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 and controlled under the requirements specified in subpart H of this part; or the requirements specified in 40 CFR part 60, subpart KKK.
	(c) * * *
* * * * *
	(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 paragraph (d) introductory text;
	c. Revising paragraph (d)(1)(i)
	d. Revising paragraph (d)(1)(i)(C);
	e. Revising paragraph (d)(1)(ii);
	f. Revising paragraph (d)(1)(iii);
	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 dehydration units. Owners and operators of small glycol dehydration units, shall comply with the control device requirements in paragraph (f) of this section.
	(1) * * *
	(i) An enclosed combustion device (e.g., thermal vapor incinerator, catalytic vapor incinerator, enclosed flare, boiler, or process heater) that is designed and operated in accordance with one of the following performance requirements:
* * * * *
	(C) For a control device that can demonstrate a combustion zone temperature during the performance test conducted under §63.772(e), operates at a minimum temperature of 760 degrees C.
* * * * *
	(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 designed 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. 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 adsorption system. Records identifying the schedule for 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 operations 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 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 §63.765(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 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 §63.765(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 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 device used to meet BTEX the emission limit calculated in §63.765(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, enclosed flare, catalytic vapor incinerator, boiler, or process heater) 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). 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; or
	(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); or
	(iii) A flare, as defined in §63.761, 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 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 owner 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 paragraphs (b)(2)(i) through (ii);
	e. Adding paragraph (d);
	f. Revising paragraph (e) introductory text;
	g. Revising paragraphs (e)(1)(i) through (v);
	h. Revising paragraph (e)(2);
	i. Revising paragraph (e)(3) introductory text;
	j. Revising paragraph (e)(3)(i)(B);
	k. Revising paragraph (e)(3)(iv)(C)(1);
	l. Adding paragraphs (e)(3)(v);
	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. Adding paragraphs (f)(2) through (f)(6);
	r. Revising paragraph (g) introductory text;