This is not to imply that there are no benefits of the rules; rather, it is a reflection of the difficulties in modeling the direct and indirect impacts of the reductions in emissions for this industrial sector with the data currently available. In addition to health improvements, there will be improvements in visibility effects, ecosystem effects and climate effects, as well as additional product recovery.
	Although we do not have sufficient information or modeling available to provide quantitative estimates for this rulemaking, we include a qualitative assessment of the health effects associated with exposure to HAP, ozone and PM2.5 in the RIA for this rule. These qualitative effects are briefly summarized below, but for more detailed information, please refer to the RIA, which is available in the docket. One of the HAP of concern from the oil and natural gas sector is benzene, which is a known human carcinogen, and formaldehyde, which is a probable human carcinogen. VOC emissions are precursors to both PM2.5 and ozone formation. As documented in previous
analyses (U.S. EPA, 2006 and U.S. EPA, 2010), exposure to PM2.5 and ozone is associated with significant public health effects. PM2.5 is associated with health effects such as premature mortality for adults and infants, cardiovascular morbidity, such as heart attacks, hospital admissions and respiratory morbidity such as asthma attacks, acute and chronic bronchitis, hospital and emergency room visits, work loss days, restricted activity days and respiratory symptoms, as well as visibility impairment. Ozone is associated with health effects such as respiratory morbidity such as asthma attacks, hospital and emergency department visits, school loss days and premature mortality, as well as injury to vegetation and climate effects.
	In addition to the improvements in air quality and resulting benefits to human health and non-climate welfare effects previously discussed, this proposed rule is expected to result in significant climate co-benefits due to anticipated methane reductions. Methane is a potent GHG that, once emitted into the atmosphere, absorbs terrestrial infrared radiation, which contributes to increased global warming and continuing climate change. Methane reacts in the atmosphere to form ozone and ozone also impacts global temperatures. According to the Intergovernmental Panel on Climate Change (IPCC) 4[th] Assessment Report (2007), methane is the second leading long-lived climate forcer after CO2 globally. Total methane emissions from the oil and gas industry represent about 40 percent of the total methane emissions from all sources and account for about 5 percent of all CO2e emissions in the United States, with natural gas systems being the single largest contributor to United States anthropogenic methane emissions. Methane, in addition to other GHG emissions, contributes to warming of the atmosphere, which, over time, leads to increased air and ocean temperatures, changes in precipitation patterns, melting and thawing of global glaciers and ice, increasingly severe weather events, such as hurricanes of greater intensity and sea level rise, among other impacts.
	This rulemaking proposes emission control technologies and regulatory alternatives that will significantly decrease methane emissions from the oil and natural gas sector in the United States. The regulatory alternatives proposed for the NESHAP and the NSPS are expected to reduce methane emissions annually by about 3.4 million short tons or 65 million metric tons CO2e. After considering the secondary impacts of this proposal previously discussed, such as increased CO2 emissions from well completion combustion and decreased CO2e emissions because of fuel-switching by consumers, the methane reductions become about 62 million metric tons CO2e. These reductions represent about 26 percent of the baseline methane emissions for this sector reported in the EPA's U.S. Greenhouse Gas Inventory Report for 2009 (251.55 million metric tons CO2e when petroleum refineries and petroleum transportation are excluded because these sources are not examined in this proposal). After considering the secondary impacts of this proposal, such as increased CO2 emissions from well completion combustion and decreased CO2 emissions because of fuel-switching by consumers, the CO2e GHG reductions are reduced to about 62 million metric tons CO2e. However, it is important to note that the emission reductions are based upon predicted activities in 2015; the EPA did not forecast sector-level emissions in 2015 for this rulemaking. These emission reductions equate to the climate benefits of taking approximately 11 million typical passenger cars off the road or eliminating electricity use from about 7 million typical homes each year.
	The EPA recognizes that the methane reductions proposed in this rule will provide for significant economic climate benefits to society just described. However, there is no interagency-accepted methodology to place monetary values on these benefits. A `global warming potential (GWP) approach' of converting methane to CO2e using the GWP of methane provides an approximation method for estimating the monetized value of the methane reductions anticipated from this rule. This calculation uses the GWP of the non-CO2 gas to estimate CO2 equivalents and then multiplies these CO2 equivalent emission reductions by the social cost of carbon developed by the Interagency Social Cost of Carbon Work Group to generate monetized estimates of the benefits.
	The social cost of carbon is an estimate of the net present value of the flow of monetized damages from a 1-metric ton increase in CO2 emissions in a given year (or from the alternative perspective, the benefit to society of reducing CO2 emissions by 1 ton). For more information about the social cost of carbon, see the Support Document: Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order 12866 and RIA for the Light-Duty Vehicle GHG rule. Applying this approach to the methane reductions estimated for the proposed NESHAP and NSPS of the oil and gas rule, the 2015 climate co-benefits vary by discount rate and range from about $370 million to approximately $4.7 billion; the mean social cost of carbon at the 3-percent discount rate results in an estimate of about $1.6 billion in 2015.
	The ratio of domestic to global benefits of emission reductions varies with key parameter assumptions. For example, with a 2.5 or 3 percent discount rate, the U.S. benefit is about 7-10 percent of the global benefit, on average, across the scenarios analyzed. Alternatively, if the fraction of GDP lost due to climate change is assumed to be similar across countries, the domestic benefit would be proportional to the U.S. share of global GDP, which is currently about 23 percent. On the basis of this evidence, values from 7 to 23 percent should be used to adjust the global SCC to calculate domestic effects. It is recognized that these values are approximate, provisional and highly speculative. There is no a priori reason why domestic benefits should be a constant fraction of net global damages over time.
	These co-benefits equate to a range of approximately $110 to $1,400 per short ton of methane reduced, depending upon the discount rate assumed with a per ton estimate of $480 at the 3-percent discount rate. Methane climate co-benefit estimates for additional regulatory alternatives are included in the RIA for this proposed rule. These social cost of methane benefit estimates are not the same as would be derived from direct computations (using the integrated assessment models employed to develop the Interagency Social Cost of Carbon estimates) for a variety of reasons, including the shorter atmospheric lifetime of methane relative to CO2 (about 12 years compared to CO2 whose concentrations in the atmosphere decay on timescales of decades to millennia). The climate impacts also differ between the pollutants for reasons other than the radiative forcing profiles and atmospheric lifetimes of these gases.
	Methane is a precursor to ozone and ozone is a short-lived climate forcer that contributes to global warming. The use of the IPCC Second Assessment Report GWP to approximate co-benefits may underestimate the direct radiative forcing benefits of reduced ozone levels and does not capture any secondary climate co-benefits involved with ozone-ecosystem interactions. In addition, a recent EPA National Center of Environmental Economics working paper suggests that this quick `GWP approach' to benefits estimation will likely understate the climate benefits of methane reductions in most cases. This conclusion is reached using the 100-year GWP for methane of 25 as put forth in the IPCC Fourth Assessment Report (AR 4), as opposed to the lower value of 21 used in this analysis. Using the higher GWP estimate of 25 would increase these reported methane climate co-benefit estimates by about 19 percent. Although the IPCC Assessment Report (AR4) suggested a GWP of 25 for methane, the EPA has used GWP of 21 to estimate the methane climate co-benefits for this oil and gas proposal in order to provide estimates more consistent with global GHG inventories, which currently use GWP from the IPCC Second Assessment Report.
	Due to the uncertainties involved with the `GWP approach' estimates presented and methane climate co-benefits estimates available in the literature, the EPA chooses not to compare these co-benefit estimates to the costs of the rule for this proposal. Rather, the EPA presents the `GWP approach' climate co-benefit estimates as an interim method to produce these estimates until the Interagency Social Cost of Carbon Work Group develops values for non-CO2 GHG. The EPA requests comments from interested parties and the public about this interim approach specifically and more broadly about appropriate methods to monetize the climate benefits of methane reductions. In particular, the EPA seeks public comments to this proposed rulemaking regarding social cost of methane estimates that may be used to value the co-benefits of methane emission reductions anticipated for the oil and gas industry from this rule. Comments specific to whether GWP is an acceptable method for generating a placeholder value for the social cost of methane until interagency-modeled estimates become available are welcome. Public comments may be provided in the official docket for this proposed rulemaking in accordance with the process outlined earlier in this notice. These comments will be considered in developing the final rule for this rulemaking.
	For the proposed NESHAP amendments, a break-even analysis suggests that HAP emissions would need to be valued at $12,000 per ton for the benefits to exceed the costs if the health, ecosystem and climate benefits from the reductions in VOC and methane emissions are assumed to be zero. Even though emission reductions of VOC and methane are co-benefits for the proposed NESHAP amendments, they are legitimate components of the total benefit-cost comparison. If we assume the health benefits from HAP emission reductions are zero, the VOC emissions would need to be valued at $1,700 per ton or the methane emissions would need to be valued at $3,300 per ton for the co-benefits to exceed the costs. All estimates are in 2008 dollars. For the proposed NSPS, the revenue from additional product recovery exceeds the costs, which renders a break-even analysis unnecessary when these revenues are included in the analysis. Based on the methodology from Fann, Fulcher, and Hubbell (2009), ranges of benefit-per-ton estimates for emissions of VOC indicate that on average in the United States, VOC emissions are valued from $1,200 to $3,000 per ton as a PM2.5 precursor, but emission reductions in specific areas are valued from $280 to $7,000 per ton in 2008 dollars. As a result, even if VOC emissions from oil and natural gas operations result in monetized benefits that are substantially below the national average, there is a reasonable chance that the benefits of the rule would exceed the costs, especially if we were able to monetize all of the additional benefits associated with ozone formation, visibility, HAP and methane.
IX. Request for Comments
	We are soliciting comments on all aspects of this proposed action. All comments received during the comment period will be considered. In addition to general comments on the proposed actions, we are also interested in any additional data that may help to reduce the uncertainties inherent in the risk assessments. We are specifically interested in receiving corrections to the datasets used for MACT analyses and risk modeling. Such data should include supporting documentation in sufficient detail to allow characterization of the quality and representativeness of the data or information. Please see the following section for more information on submitting data.
X. Submitting Data Corrections
      The facility-specific data used in the source category risk analyses, facility-wide analyses and demographic analyses for each source category subject to this action are available for download on the RTR Web page at http://www.epa.gov/ttn/atw/rrisk/rtrpg.html. These data files include detailed information for each HAP emissions release point at each facility included in the source category and all other HAP emissions sources at these facilities (facility-wide emissions sources). However, it is important to note that the source category risk analysis included only those emissions tagged with the MACT code associated with the source category subject to the risk analysis.
      If you believe the data are not representative or are inaccurate, please identify the data in question, provide your reason for concern and provide any "improved" data that you have, if available. When you submit data, we request that you provide documentation of the basis for the revised values to support your suggested changes. To submit comments on the data downloaded from the RTR Web page, complete the following steps:
      1. Within this downloaded file, enter suggested revisions to the data fields appropriate for that information. The data fields that may be revised include the following:
                                 Data Element
                                  Definition
Control Measure
Are control measures in place? (yes or no)
Control Measure Comment
Select control measure from list provided and briefly describe the control measure
Delete
Indicate here if the facility or record should be deleted
Delete Comment
Describes the reason for deletion
Emission Calculation Method Code For Revised Emissions
Code description of the method used to derive emissions. For example, CEM, material balance, stack test, etc.
Emission Process Group
Enter the general type of emission process associated with the specified emission point
Fugitive Angle
Enter release angle (clockwise from true North); orientation of the y-dimension relative to true North, measured positive for clockwise starting at 0 degrees (maximum 89 degrees)
Fugitive Length
Enter dimension of the source in the east-west (x-) direction, commonly referred to as length (ft)
Fugitive Width
Enter dimension of the source in the north-south (y-) direction, commonly referred to as width (ft)
Malfunction Emissions
Enter total annual emissions due to malfunctions (TPY)
Malfunction Emissions Max Hourly
Enter maximum hourly malfunction emissions here (lb/hr)
North American Datum
Enter datum for latitude/longitude coordinates (NAD27 or NAD83); if left blank, NAD83 is assumed
Process Comment
Enter general comments about process sources of emissions
REVISED Address
Enter revised physical street address for MACT facility here
REVISED City
Enter revised city name here
REVISED County Name
Enter revised county name here
REVISED Emission Release Point Type
Enter revised Emission Release Point Type here
REVISED End Date
Enter revised End Date here
REVISED Exit Gas Flow Rate
Enter revised Exit Gas Flowrate here (ft3/sec)
REVISED Exit Gas Temperature
Enter revised Exit Gas Temperature here (OF)
REVISED Exit Gas Velocity
Enter revised Exit Gas Velocity here (ft/sec)
REVISED Facility Category Code
Enter revised Facility Category Code here, which indicates whether facility is a major or area source
REVISED Facility Name
Enter revised Facility Name here
REVISED Facility Registry Identifier
Enter revised Facility Registry Identifier here, which is an ID assigned by the EPA Facility Registry System
REVISED HAP Emissions Performance Level Code
Enter revised HAP Emissions Performance Level here
REVISED Latitude
Enter revised Latitude here (decimal degrees)
REVISED Longitude
Enter revised Longitude here (decimal degrees)
REVISED MACT Code
Enter revised MACT Code here
REVISED Pollutant Code
Enter revised Pollutant Code here
REVISED Routine Emissions
Enter revised routine emissions value here (TPY)
REVISED SCC Code
Enter revised SCC Code here
REVISED Stack Diameter
Enter revised Stack Diameter here (ft)
REVISED Stack Height
Enter revised Stack Height here (Ft)
REVISED Start Date
Enter revised Start Date here
REVISED State
Enter revised state here
REVISED Tribal Code
Enter revised Tribal Code here
REVISED Zip Code
Enter revised Zip Code here
Shutdown Emissions
Enter total annual emissions due to shutdown events (TPY)
Shutdown Emissions Max Hourly
Enter maximum hourly shutdown emissions here (lb/hr)
Stack Comment
Enter general comments about emission release points
Startup Emissions
Enter total annual emissions due to startup events (TPY)
Startup Emissions Max Hourly
Enter maximum hourly startup emissions here (lb/hr)
Year Closed
Enter date facility stopped operations

      2. Fill in the commenter information fields for each suggested revision (i.e., commenter name, commenter organization, commenter email address, commenter phone number and revision comments).
      3. Gather documentation for any suggested emissions revisions (e.g., performance test reports, material balance calculations, etc.).
      4. Send the entire downloaded file with suggested revisions in Microsoft(R) Access format and all accompanying documentation to Docket ID Number EPA-HQ-OAR-2010-0505 (through one of the methods described in the ADDRESSES section of this preamble). To expedite review of the revisions, it would also be helpful if you submitted a copy of your revisions to the EPA directly at<EMAIL_ADDRESS>in addition to submitting them to the docket.
      5. If you are providing comments on a facility with multiple source categories, you need only submit one file for that facility, which should contain all suggested changes for all source categories at that facility. We request that all data revision comments be submitted in the form of updated Microsoft(R) Access files, which are provided on the http://www.epa.gov/ttn/atw/rrisk/rtrpg.html Web page.
XI. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and Executive Order 13563: Improving Regulation and Regulatory Review
      Under Executive Order 12866 (58 FR 51735, October 4, 1993), this action is an "economically significant regulatory action" because it is likely to have an annual effect on the economy of $100 million or more. Accordingly, the EPA submitted this action to OMB for review under Executive Order 12866 and Executive Order 13563 (76 FR 3821, January 21, 2011) and any changes made in response to OMB recommendations have been documented in the docket for this action.
      In addition, the EPA prepared a RIA of the potential costs and benefits associated with this action. The RIA available in the docket describes in detail the empirical basis for the EPA's assumptions and characterizes the various sources of uncertainties affecting the estimates below. Table 8 shows the results of the cost and benefits analysis for these proposed rules. For more information on the benefit and cost analysis, as well as details on the regulatory options considered, please refer to the RIA for this rulemaking, which is available in the docket.

Table 8. Summary of the Monetized Benefits, Costs and Net Benefits for the Proposed Oil and Natural Gas NSPS and NEHSAP Amendments in 2015 (millions of 2008$)[1]

                                 Proposed NSPS
                          Proposed NESHAP Amendments
                 Proposed NSPS and NESHAP Amendments Combined
Total Monetized Benefits[2]
                                      N/A
                                      N/A
                                      N/A
Total Costs[3]
                                 -$45 million
                                  $16 million
                                 -$29 million
Net Benefits
                                      N/A
                                      N/A
                                      N/A
                          Non-monetized Benefits[4,5]
                              37,000 tons of HAP
                               1,400 tons of HAP
                              38,000 tons of HAP

                              540,000 tons of VOC
                               9,200 tons of VOC
                              540,000 tons of VOC

                          3.4 million tons of methane
                             4,900 tons of methane
                          3.4 million tons of methane

                        Health effects of HAP exposure

                  Health effects of PM2.5 and ozone exposure

                             Visibility impairment

                              Vegetation effects

                                Climate effects

1 All estimates are for the implementation year (2015).
2 While we expect that these avoided emissions will result in improvements in air quality and reductions in health effects associated with HAP, ozone and PM, as well as climate effects associated with methane, we have determined that quantification of those benefits cannot be accomplished for this rule in a defensible way. This is not to imply that there are no benefits of the rules; rather, it is a reflection of the difficulties in modeling the direct and indirect impacts of the reductions in emissions for this industrial sector with the data currently available.
3 The engineering compliance costs are annualized using a 7-percent discount rate. The negative cost for the proposed NSPS reflects the inclusion of revenues from additional natural gas and hydrocarbon condensate recovery that are estimated as a result of the proposed NSPS.
[4] For the NSPS, reduced exposure to HAP and climate effects are co-benefits. For the NESHAP, reduced VOC emissions, PM2.5 and ozone exposure, visibility and vegetation effects and climate effects are co-benefits.
[5] The specific control technologies for these proposed rules are anticipated to have minor secondary disbenefits. The net CO2-equivalent emission reductions are 93,000 metric tons for the NESHAP and 62 million metric tons for the NSPS.

B. Paperwork Reduction Act
	The information collection requirements in this proposed action have been submitted for approval to OMB under the Paperwork Reduction Act, 44 U.S.C. 3501, et seq. The ICR document prepared by the EPA has been assigned EPA ICR Numbers 1716.07 (40 CFR part 60, subpart OOOO), 1788.10 (40 CFR part 63, subpart HH), 1789.07 (40 CFR part 63, subpart HHH) and 1086.10 (40 CFR part 60, subparts KKK and subpart LLL).
      The information to be collected for the proposed NSPS and the proposed NESHAP amendments are based on notification, recordkeeping and reporting requirements in the NESHAP General Provisions (40 CFR part 63, subpart A), which are mandatory for all operators subject to national emission standards. These recordkeeping and reporting requirements are specifically authorized by section 114 of the CAA (42 U.S.C. 7414). All information submitted to the EPA pursuant to the recordkeeping and reporting requirements for which a claim of confidentiality is made is safeguarded according to Agency policies set forth in 40 CFR part 2, subpart B.
      These proposed rules would require maintenance inspections of the control devices, but would not require any notifications or reports beyond those required by the General Provisions. The recordkeeping requirements require only the specific information needed to determine compliance.
      For sources subject to the proposed NSPS, burden changes associated with these amendments result from the respondents' annual reporting and recordkeeping burden associated with this proposed rule for this collection (averaged over the first 3 years after the effective date of the standards). The burden is estimated to be 560,000 labor hours at a cost of $18 million per year. This includes the burden previously estimated for sources subject to 40 CFR part 60, subpart KKK (which is being incorporated into 40 CFR part 60, subpart OOOO). The average hours and cost per regulated entity subject to the NSPS for oil and natural gas production and natural gas transmissions and distribution facilities would be 110 hours per response and $3,693 per response, based on an average of 1,459 operators responding per year and 16 responses per year.
      The estimated recordkeeping and reporting burden after the effective date of the proposed amendments is estimated for all affected major and area sources subject to the Oil and Natural Gas Production NESHAP to be approximately 63,000 labor hours per year at a cost of $2.1 million per year. For the Natural Gas Transmission and Storage NESHAP, the recordkeeping and reporting burden is estimated to be 2,500 labor hours per year at a cost of $86,800 per year. This estimate includes the cost of reporting, including reading instructions and information gathering. Recordkeeping cost estimates include reading instructions, planning activities and conducting compliance monitoring. The average hours and cost per regulated entity subject to the Oil and Natural Gas Production NESHAP would be 72 hours per year and $2,500 per year, based on an average of 846 facilities per year and three responses per facility. For the Natural Gas Transmission and Storage NESHAP, the average hours and cost per regulated entity would be 50 hours per year and $1,600 per year, based on an average of 53 facilities per year and three responses per facility. Burden is defined at 5 CFR 1320.3(b).
      An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. The OMB control numbers for the EPA's regulations in 40 CFR are listed in 40 CFR part 9.
      To comment on the Agency's need for this information, the accuracy of the provided burden estimates and any suggested methods for minimizing respondent burden, the EPA has established a public docket for this rule, which includes this ICR, under Docket ID Number EPA-HQ-OAR-2010-0505. Submit any comments related to the ICR to the EPA and OMB. See ADDRESSES section at the beginning of this notice for where to submit comments to the EPA. Send comments to OMB at the Office of Information and Regulatory Affairs, Office of Management and Budget, 725 17th Street, NW, Washington, DC 20503, Attention: Desk Office for the EPA. Since OMB is required to make a decision concerning the ICR between 30 and 60 days after [INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER], a comment to OMB is best assured of having its full effect if OMB receives it by [INSERT DATE 30 DAYS FROM DATE OF PUBLICATION IN THE FEDERAL REGISTER]. The final rule will respond to any OMB or public comments on the information collection requirements contained in this proposal.
C. Regulatory Flexibility Act
	The Regulatory Flexibility Act generally requires an agency to prepare a regulatory flexibility analysis of any rule subject to notice and comment rulemaking requirements under the Administrative Procedure Act or any other statute, unless the agency certifies that the rule will not have a significant economic impact on a substantial number of small entities (SISNOSE). Small entities include small businesses, small organizations, and small governmental jurisdictions. For purposes of assessing the impact of this rule on small entities, a small entity is defined as: (1) A small business whose parent company has no more than 500 employees (or revenues of less than $7 million for firms that transport natural gas via pipeline); (2) a small governmental jurisdiction that is a government of a city, county, town, school district, or special district with a population of less than 50,000; and (3) a small organization that is any not-for-profit enterprise which is independently owned and operated and is not dominant in its field.
Proposed NSPS
	After considering the economic impact of the proposed NSPS on small entities, I certify that this action will not have a SISNOSE. The EPA performed a screening analysis for impacts on a sample of expected affected small entities by comparing compliance costs to entity revenues. Based upon the analysis in the RIA, which is in the Docket, EPA concludes the number of impacted small businesses is unlikely to be sufficiently large to declare a SISNOSE.  Our judgment in this determination is informed by the fact that many affected firms are expected to receive revenues from the additional natural gas and condensate recovery engendered by the implementation of the controls evaluated in this RIA. As much of the additional natural gas recovery is estimated to arise from completion-related activities, we expect the impact on well-related compliance costs to be significantly mitigated. This conclusion is enhanced because the returns to REC activities occur without a significant time lag between implementing the control and obtaining the recovered product, unlike many control options where the emissions reductions accumulate over long periods of time; the reduced emission completions and recompletions occur over a short span of time, during which the additional product recovery is also accomplished.
Proposed NESHAP Amendments
	After considering the economic impact of the proposed NESHAP amendments on small entities, I certify that this action will not have a SISNOSE. Based upon the analysis in the RIA, which is in the Docket, we estimate that 62 of the 118 firms (53 percent) that own potentially affected facilities are small entities. The EPA performed a screening analysis for impacts on all expected affected small entities by comparing compliance costs to entity revenues. Among the small firms, 52 of the 62 (84 percent) are likely to have impacts of less than 1 percent in terms of the ratio of annualized compliance costs to revenues. Meanwhile, 10 firms (16 percent) are likely to have impacts greater than 1 percent. Four of these 10 firms are likely to have impacts greater than 3 percent. While these 10 firms might receive significant impacts from the proposed NESHAP amendments, they represent a very small slice of the oil and gas industry in its entirety, less than 0.2 percent of the estimated 6,427 small firms in NAICS 211. Although this final rule will not impact a substantial number of small entities, the EPA, nonetheless, has tried to reduce the impact of this rule on small entities by setting the final emissions limits at the MACT floor, the least stringent level allowed by law.
	We continue to be interested in the potential impacts of the proposed rule on small entities and welcome comments on issues related to such impacts.
D. Unfunded Mandates Reform Act
	This action contains no Federal mandates under the provisions of title II of the Unfunded Mandates Reform Act of 1995 (UMRA), 2 U.S.C. 1531-1538 for state, local or tribal governments or the private sector. This proposed rule does not contain a Federal mandate that may result in expenditures of $100 million or more for state, local and tribal governments, in the aggregate, or to the private sector in any one year. Thus, this proposed rule is not subject to the requirements of sections 202 or 205 of UMRA.
This proposed rule is also not subject to the requirements of section 203 of UMRA because it contains no regulatory requirements that might significantly or uniquely affect small governments. This action contains no requirements that apply to such governments nor does it impose obligations upon them.
E. Executive Order 13132: Federalism
	This proposed rule does not have federalism implications. It will not have substantial direct effects on the states, on the relationship between the national government and the states, or on the distribution of power and responsibilities among the various levels of government, as specified in Executive Order 13132. Thus, Executive Order 13132 does not apply to this proposed rule.
In the spirit of Executive Order 13132 and consistent with the EPA policy to promote communications between the EPA and state and local governments, the EPA specifically solicits comment on this proposed rule from state and local officials.
F. Executive Order 13175: Consultation and Coordination with Indian Tribal Governments
	This action does not have tribal implications, as specified in Executive Order 13175 (65 FR 67249, November 9, 2000). It will not have substantial direct effect on tribal governments, on the relationship between the Federal government and Indian tribes or on the distribution of power and responsibilities between the Federal government and Indian tribes, as specified in Executive Order 13175. Thus, Executive Order 13175 does not apply to this action.
	The EPA specifically solicits additional comment on this proposed action from tribal officials.
G. Executive Order 13045: Protection of Children from Environmental Health Risks and Safety Risks
	This proposed rule is not subject to Executive Order 13045 (62 FR 19885, April 23, 1997) because the Agency does not believe the environmental health risks or safety risks addressed by this action present a disproportionate risk to children. This actions' health and risk assessments are contained in section VII.C of this preamble.
The public is invited to submit comments or identify peer-reviewed studies and data that assess effects of early life exposure to HAP from oil and natural gas sector activities.
H. Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution or Use
	Executive Order 13211, (66 FR 28,355, May 22, 2001), provides that agencies shall prepare and submit to the Administrator of the Office of Information and Regulatory Affairs, OMB, a Statement of Energy Effects for certain actions identified as significant energy actions. Section 4(b) of Executive Order 13211 defines "significant energy actions" as "any action by an agency (normally published in the Federal Register) that promulgates or is expected to lead to the promulgation of a final rule or regulation, including notices of inquiry, advance notices of proposed rulemaking, and notices of proposed rulemaking: (1)(i) That is a significant regulatory action under Executive Order 12866 or any successor order and (ii) is likely to have a significant adverse effect on the supply, distribution, or use of energy; or (2) that is designated by the Administrator of the Office of Information and Regulatory Affairs as a significant energy action."
	The proposed rules will result in the addition of control equipment and monitoring systems for existing and new sources within the oil and natural gas industry. The proposed NESHAP amendments are unlikely to have a significant adverse effect on the supply, distribution or use of energy. As such, the proposed NESHAP amendments are not "significant energy actions" as defined in Executive Order 13211 (66 FR 28355, May 22, 2001).
	The proposed NSPS is also unlikely to have a significant effect on the supply, distribution or use of energy. As such, the proposed NSPS is not a "significant energy action" as defined in Executive Order 13211 (66 FR 28355, May 22, 2001). The basis for the determination is as follows.
	As discussed in the impacts section of the Preamble, we use the NEMS to estimate the impacts of the proposed NSPS on the United States energy system. The NEMS is a publically available model of the United States energy economy developed and maintained by the Energy Information Administration of the United States DOE and is used to produce the Annual Energy Outlook, a reference publication that provides detailed forecasts of the United States energy economy.
	Proposed emission controls for the NSPS capture VOC emissions that otherwise would be vented to the atmosphere. Since methane is co-emitted with VOC, a large proportion of the averted methane emissions can be directed into natural gas production streams and sold. One pollution control requirement of the proposed NSPS also captures saleable condensates. The revenues from additional natural gas and condensate recovery are expected to offset the costs of implementing the proposed NSPS.
	The analysis of energy impacts for the proposed NSPS that includes the additional product recovery shows that domestic natural gas production is estimated to increase (20 billion cubic feet or 0.1 percent) and natural gas prices to decrease ($0.04/Mcf or 0.9 percent at the wellhead for producers in the lower 48 states) in 2015, the year of analysis. Domestic crude oil production is not estimated to change, while crude oil prices are estimated to decrease slightly ($0.02/barrel or less than 0.1 percent at the wellhead for producers in the lower 48 states) in 2015, the year of analysis. All prices are in 2008 dollars.
Additionally, the NSPS establishes several performance standards that give regulated entities flexibility in determining how to best comply with the regulation. In an industry that is geographically and economically heterogeneous, this flexibility is an important factor in reducing regulatory burden.
	For more information on the estimated energy effects, please refer to the economic impact analysis for this 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 voluntary consensus standards (VCS) in its regulatory activities unless to do so would be inconsistent with applicable law or otherwise impractical. VCS are technical standards (e.g., materials specifications, test methods, sampling procedures, and business practices) that are developed or adopted by VCS bodies. 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, subpart HH and 40 CFR part 63, subpart 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 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 (2004) 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 gas chromatography configurations other than gas chromatography/mass spectrometry.
	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 EJ. Its main provision directs Federal agencies, to the greatest extent practicable and permitted by law, to make EJ part of their mission by identifying and addressing, as appropriate, disproportionately high and adverse human health or environmental effects of their programs, policies and activities on minority populations and low-income populations in the United States.
      The EPA has determined that this proposed rule will not have disproportionately high and adverse human health or environmental effects on minority or low-income populations because it increases the level of environmental protection for all affected populations without having any disproportionately high and adverse human health or environmental effects on any population, including any minority or low-income population.
	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.C 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 H2S 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 for 26,000 hours. The number of hours of operation must be continuously monitored beginning upon initial startup of your reciprocating compressor affected facility, or 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 20 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),§60.482-2a, and §60.482-4a through 60.482-11a, except as provided in §60.5401.
    (b) You may elect to comply with the requirements of §§60.483-1a and 60.483-2a, as an alternative.
    (c) You may apply to the Administrator for permission to use an alternative means of emission limitation that achieves a reduction in emissions of VOC at least equivalent to that achieved by the controls required in this subpart according to the requirements of §60.5402 of this subpart.
    (d) You must comply with the provisions of §60.485a of this part except 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 §60.5400(c) and in paragraph (b)(4) of this section, and §60.482-4a(a) through (c) of subpart VVa.
    (2) If an instrument reading of 5000 ppm or greater is measured, a leak is detected.
    (3)(i) When a leak is detected, it must be repaired as soon as practicable, but no later than 15 calendar days after it is detected, except as provided in §60.482-9a.
    (ii) A first attempt at repair must be made no later than 5 calendar days after each leak is detected.
    (4)(i) Any pressure relief device that is located in a  nonfractionating plant that is monitored only by non-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 VVa.
    (ii) No pressure relief device described in paragraph (b)(4)(i) of this section must be allowed to operate for more than 30 days after a pressure 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) Flares used to comply with this subpart must comply with the requirements of §60.18.
    (g) 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.
	(2) You have included the cumulative number of hours of operation 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 20 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 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 must be included in the annual report as required in §60.5420(b)(4).
	(2) You have replaced the reciprocating compressor rod packing before the total number of hours of operation reaches 26,000 hours.
	(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 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 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 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 paragraph (b)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 500 ppm" if the maximum instrument reading measured by the methods specified in paragraph (a) of this section after each repair attempt is 500 ppm or greater.
    (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.
§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(a), (b), (c)(i) through (iv), and (c)(vii) through (viii).
	(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 fractured or refractured existing 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 99.9, whichever is smaller
                                 20<Y<50
                                     79.0
	88.5X[0.0101]Y[0.0125]
                         or 97.9, whichever is smaller
                                     97.9
                                 10<Y<20
                                     79.0
                            88.5X[0.0101]Y[0.0125]
                         or 97.9, whichever is smaller
                                     93.5
                                     93.5
                                    Y<10
                                     79.0
                                     79.0
                                     79.0
                                     79.0

       Table 2. 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 99.9, whichever is smaller
                                 20<Y<50
                                     74.0
	85.35X[0.0144]Y[0.0128]
                         or 97.9, whichever is smaller
                                     97.5
                                 10<Y<20
                                     74.0
                            85.35X[0.0144]Y[0.0128]