In the proposed rule, we had defined "well site," for purposes of the fugitive emissions standards at §60.5397a, to include separately located, centralized tank batteries. We received comments that the definition was unclear and that there was concern that the affected facility status of centralized tank batteries could inadvertently pull into affected facility status those well sites that only contain one or more wellheads, which were proposed to be excluded from affected facility status. We agree that the proposed definition of well site was somewhat unclear, and we have revised the definition in the final rule. With regard to the affected facility status of centralized tank batteries and its effect on well sites that only contain one or more wellheads, our intent is not to have well sites that only contain one or more wellheads subject to fugitive emissions standards. To make this intent more explicit, we have added language to §60.5365a(i)(2) to this effect.
2. Fugitive Emissions from Compressor Stations
      Based on our consideration of the comments received and other relevant information, we have made several changes to the proposed fugitive emissions standards for the compressor stations in this final rule. The finalized fugitive emissions monitoring and repair requirements for compressor stations are similar to the requirements for well sites, so we streamlined this section by referencing our well site discussion, where appropriate. Below we provide the significant changes since proposal and our rationales for these changes.
a. Monitoring Frequency
       In conjunction with semiannual monitoring, the EPA co-proposed annual monitoring, solicited comment on conducting monitoring surveys on a quarterly basis, and solicited comment on the availability of trained OGI contractors and OGI instrumentation. 80 FR at 56639.
      Some commenters supported quarterly monitoring on the belief that it is more accurate and cost-effective than the monitoring frequencies proposed by the EPA. Other commenters opposed quarterly monitoring, alleging that it is not cost-effective and may be infeasible due to weather or shortages associated with OGI, necessary for the surveys. Also citing factors such as cost-effectiveness and questioning data underlying the EPA's analysis, some commenters supported annual monitoring or generally opposed semiannual monitoring.
      Based on the comments received, the EPA reviewed the type of equipment and the associated components that were included in the model plant used to determine emission reductions and costs for compressor stations at proposal. The storage and transmission model plants developed for the proposed rule had inadvertently included site blowdown open-ended lines, which are not sources of fugitive emissions but are vents. Therefore, the transmission and storage model plants were revised for the final rule to remove these components from the total component count.
      The EPA used information provided by commenters to re-evaluate the control options for annual, semiannual and quarterly monitoring. As shown in the TSD, the control costs for quarterly, semiannual, and annual monitoring remain cost-effective for reducing GHG (in the form of methane) and VOC emissions. Semiannual and quarterly monitoring would provide greater emissions reductions than would annual monitoring. However, as explained in the proposed rule, we were concerned with compliance burden, in particular for small businesses, associated with quarterly monitoring even though it was cost effective. 80 FR at 56641. Specifically, we were concerned that the limited supplies of trained personnel for performing surveys might lead to disadvantages for small businesses, which are more likely to hire trained personnel. Id. However, certain changes we have made in the final rule will help alleviate the concern. For example, the final rule requires that the initial monitoring survey must take place by [insert date 1 year after publication of the final rule in the Federal Register] or within 60 days of the startup of production, whichever is later. This allows additional time for owners and operators to establish the requirement program's infrastructure at the initial stage. Another example, in light of comments urging EPA to allow Method 21 as an alternative, and the fact that we know many companies already own Method 21 instruments, offering Method 21 at a repair threshold of 500 ppm, as an alternative to conduct the monitoring surveys, will alleviate some of the demand for OGI instruments and personnel. Therefore, the EPA is finalizing quarterly monitoring frequency for the collection of fugitive emissions components at compressor stations to ensure the maximum amount of emission reductions. Please see the RTC document in the public docket for further discussion.
      Some commenters requested that fugitive emissions monitoring exemptions be given to well sites and compressor stations that are located in areas of the country that routinely experience extreme weather. The commenters noted that these areas experience several months of average temperatures below 0°Fahrenheit and long periods of snow cover. The commenter also provided information from one of the OGI instrument manufacturers which indicates that the instrument cannot operate at temperatures below -4°Fahrenheit. The commenter also expressed concerns about monitoring survey personnel's safety if they were to attempt to conduct surveys in these weather conditions.
      We agree that there are areas within the United States that regularly have extreme weather conditions such as three or more consecutive months of average temperatures below 0°Fahrenheit. We also obtained information from two OGI instrument manufacturers that confirm that the minimum operating temperature of the OGI instruments is -4°Fahrenheit. As such, these prolonged subzero temperature conditions would make performing fugitive emissions monitoring surveys impossible during several months of the year. Additionally, while we believe that company personnel may be accessing these sites for maintenance activities, it may be difficult to transport OGI contractors to unmanned sites within these areas during these periods, as outside access for OGI contractors usually requires air travel to access these production sites.
      Based on these considerations, we are waiving quarterly fugitive emissions monitoring surveys at compressor stations if, based on three years of historical climatic data, two of the three consecutive months within the quarter has an average temperature below 0°Fahrenheit. The average temperatures must be determined by historical climatic data from the National Oceanic and Atmospheric Administration or a source approved by the EPA Administrator. This waiver may not be used for two consecutive quarters and is not extended to well sites because we do not believe that there will be any locations that have average monthly temperatures below 0°Fahrenheit for six consecutive months. Owners and operators will have to keep records of the waiver period, including the three months within the quarterly monitoring period, the average monthly temperatures and the source of the temperature information. Owners and operators will also have to report this information in their annual report.
b. Monitoring Using Method 21
      In performing analysis for the proposed rule, the EPA found OGI to be more cost-effective than Method 21 and, therefore, identified OGI as the BSER for monitoring fugitive emissions at compressor stations. See 80 FR 56641, September 18, 2015. As with well sites, discussed previously in section VI.F.1.c, the EPA solicited comment on whether to allow Method 21 as an alternative fugitive emissions monitoring method to OGI and solicited comment on the repair threshold for components that are found to have fugitive emissions using Method 21.
      The EPA received the same types of comments regarding allowing Method 21 as an alternative to OGI for monitoring fugitive emissions at compressor stations as for well sites, as discussed in section VI.F.1.c. Likewise, for the same reasons as discussed earlier, we are finalizing Method 21 as an alternative to OGI for monitoring fugitive emissions components at compressor stations at a repair threshold of an instrument reading of 500 ppm or greater. We are also finalizing specific recordkeeping and reporting requirements when Method 21 is used to perform a monitoring survey. See section V.J for more details on the recordkeeping and reporting requirements.
c. Shifting of Monitoring Frequency Based on Performance
      The EPA proposed shifting monitoring frequencies (ranging from annual to quarterly monitoring) based on the percentage of components that are found to have fugitive emissions during a monitoring survey. We solicited comment on the proposed monitoring scheme, including the proposed metrics of one percent and three percent to determine monitoring frequency or whether the monitoring frequency thresholds should be based on a specific number of components that are found to have fugitive emissions. In addition, the EPA solicited comment on whether a performance-based frequency or a fixed-frequency was more appropriate.
      The EPA received the same comments regarding frequency of monitoring for compressor stations as for well sites, discussed in section VI.F.1.d. Likewise, for the same reasons as discussed earlier, the EPA is finalizing a fixed monitoring frequency instead of performance based monitoring.
d. Fugitive Emissions Components Repair and Resurvey
      The EPA proposed that a source of fugitive emissions at compressor stations must be repaired or replaced as soon as practicable, and, in any case, no later than 15 calendar days after detection of the fugitive emissions. The EPA solicited comment on whether 15 days is the appropriate amount of time for repair of sources of fugitive emissions from compressor stations. We also solicited comment on whether 15 days is the appropriate amount of time needed to resurvey a component after it has been repaired.
      The EPA received the same comments regarding the timeframe for repairs, delay of repair, and resurveys for compressor stations as for well sites, discussed in section VI.F.1.e. Likewise, for the same reasons as discussed earlier, we are finalizing 30 days for the repair of fugitive emissions sources and an additional 30 days for resurvey of the repaired fugitive emissions components. We also are finalizing revisions to the delay of repair requirements. If a repair cannot be made due to a technical infeasibility that would require a blowdown or shutdown of the compressor station, or would be unsafe to repair by exposing personnel to immediate danger, the repair can be delayed until the next scheduled or emergency blowdown or station shutdown or within 2 years of finding the fugitive source of emissions, whichever is earlier. We believe that the likelihood of an emergency blowdown or a compressor station shutdown occurring within six months of finding fugitive emissions from a component may be low; however, it would be feasible to repair the component within a two-year timeframe, since one of above described events is likely to occur within that two-year timeframe. The owner or operator will also have to record the number and types of components that are placed on delay of repair and record an explanation for each delay of repair.
      Similarly with respect to well sites, and as discussed in section VI.F.1.e, we are finalizing the use of the alternative screening procedures specified in Section 8.3.3 of Method 21 for resurveying repaired fugitive emissions components. Please see the RTC document in the public docket for further discussion.
e. Definition of "Fugitive Emission Component"
      As discussed earlier, we proposed monitoring, repair and resurvey of "fugitive emission components," that apply to both well sites and compressor stations because the type of components are identical. We solicited comment on the proposed definition. The EPA received the same comments regarding the fugitive emissions component definition for compressor stations as for well sites, discussed in section VI.F.1.f. Likewise, for the same reasons as discussed earlier, we are finalizing changes to the definition to identify specific components, such as valves and flanges, that have the potential to be sources of fugitive emissions and that, when surveyed and repaired, would significantly reduce GHG and VOC emissions. This targeted list will remove the ambiguity of the proposed definition and will allow owners and operators to consistently identify fugitive emissions at compressor stations.
f. Timing of the Initial Monitoring Survey
      The EPA proposed that the initial monitoring be conducted within 30 days after the initial startup of a new compressor station or modification of an existing compressor station. The EPA solicited comment on whether 30 days is an appropriate amount of time to begin conducting fugitive emissions monitoring.
      Many commenters supported a longer timeframe for commencing monitoring, citing time needed to complete well ties into a compressor station that collects field gas, safety, and the relationship with other regulations, while some commenters supported the timeframe proposed. The EPA recognizes that at the time of startup of a compressor station, additional gathering lines or well tie-ins may be required. However, we also believe that, at the time of startup, the associated collection of fugitive emissions components is operational and initial monitoring can begin, even if the gathering lines or well tie-ins are incomplete, which could take several months or longer. Sources of fugitive emissions could go undetected for months if we were to allow monitoring to begin after all of the gathering lines and tie-ins were completed. Therefore, we are finalizing the proposed requirement that initial monitoring will begin after the initial startup of a compressor station instead of allowing all of the gathering lines or tie-ins to be completed before monitoring begins.
      However, based on the comments received, we are concerned that the tasks required prior to conducting an initial survey would take more than the 30 days we had proposed. Because each new or modified compressor station must be covered by a monitoring plan for a company-defined area, owners and operators must visit and assess each new or modified compressor station in order to incorporate it into a newly developed or modified monitoring plan for that area. They also need to secure certified monitoring survey contractors or monitoring instruments. In addition, they need to ensure that other compliance requirements will be met, such as recordkeeping and reporting. In light of the activities described above, the EPA is requiring in the final rule that the initial survey be conducted within 60 days from startup or modification of a compressor station.
      While 60 days from startup or modification of a compressor station is sufficient time to conduct the initial survey once the underlying program infrastructure is established, we recognize that the initial establishment of the required program's infrastructure and the initial round of monitoring surveys will require additional time. Most importantly, additional time is needed to secure the necessary equipment or trained personnel according to one OGI instrument manufacturer, which commented that they would need to increase production of key components for the OGI instrument to meet demand. The OGI manufacturer also indicated that they would need to scale up the number of personnel needed to provide OGI training and service of the equipment. We are concerned that currently there is not sufficient equipment and trained personnel to meet the demand imposed by this final rule in the near term. Accordingly, it will be necessary to have a window of time for trained personnel to work through this backlog. Furthermore, as previously mentioned, an owner or operator will need to develop a monitoring plan that would apply to each compressor station located within the company-defined area, which requires an assessment of each compressor station. Therefore, before a plan can be developed or modified, the owner or operator would need time to visit each compressor station within the company-defined area. In light of the above, the initial site visits and development of the monitoring plan would require a significant amount of time. Time is also needed to secure certified monitoring survey contractors or monitoring instruments. In addition, owners and operators will need to plan the logistics of the initial activities in order to comply with the requirements. This includes time to set up recordkeeping systems and to train personnel to manage the fugitive emissions monitoring program. These corporate systems are critical for submitting the notification of initial and subsequent annual compliance status.
      As noted above, once programs are established and equipment supplies have caught up, well owners will be able to add additional affected facilities to existing programs and, thus, this longer timeline will not be needed. Therefore, in order to provide time for owners and operators to establish the initial groundwork of their fugitives program, we are requiring that the initial monitoring survey must take place by [insert date 1 year after publication of the final rule in the Federal Register] or within 60 days of the startup or modification of a compressor station, whichever is later. We anticipate that sources will begin to phase in these requirements as additional devices and trained personnel become available. For additional discussion, please refer to the materials in the docket.
g. Monitoring Plan
      The EPA proposed that owners or operators develop a corporate-wide emissions monitoring plan that specifies the measures for locating sources and the detection technology to be used. The EPA also proposed that owners or operators develop a separate site-specific fugitive emissions monitoring plan that specifies information, such as the number of fugitive emission components for that site and for each affected facility. The EPA solicited comment on the required elements of the proposed corporate-wide monitoring plan and specifically asked for comment regarding whether the monitoring plan should include other techniques, such as visual inspections to help identify indicators of potential leaks.
      As with this topic in the context of well sites, and as discussed in section VI.F.1.h, some commenters agreed with the EPA's proposal to require a corporate fugitive monitoring plan, but expressed concerns about the elements of the plan, while others objected that the proposed plan is overly prescriptive and costly, with particular concerns about including requirements for a walking path and for digital photographs. Other commenters suggested changing the scope of monitoring plans to accommodate variations in locations of contractors and equipment.
      Based on the comments that we received, we are revising the fugitive emissions monitoring plan for compressor stations. We acknowledge that developing and implementing a corporate-wide monitoring plan that would be applicable to all compressor stations within a company could be problematic because compressor station configurations may differ across areas (i.e., basins, fields, or districts) and what may be applicable in one area may not be relevant in another area. This would mean that a company could have to design and implement a site-specific plan for each compressor station.
      We also agree that developing a site-specific plan may be overly burdensome because several gathering and boosting or transmission compressor stations may exist in a specific geographic area and have similar equipment. Using information from the Interstate Natural Gas Association of America (INGAA) and the Energy Information Administration (EIA), we estimated that, on average, compressor stations are located 70 miles apart. We also assumed that a company could monitor emissions from gathering and boosting or transmission compressor stations within a 210-mile radius of a central location. Using these assumptions, we estimated that a company could monitor seven gathering and boosting or transmission compressor stations within that company's specific geographic region. In such cases, companies would benefit from having a plan to cover all of the compressor stations within that area, as the monitoring will likely require use of the same contractors, the same company-owned monitoring instruments, or the same company personnel to perform the monitoring surveys. Allowing companies to develop one fugitive emissions monitoring plan for all of the compressors within a company-defined area would alleviate burden and provide efficiency for owners and operators.
      Therefore, we are replacing the proposed corporate-wide and site-specific monitoring plan requirements with a requirement for owners or operators to develop a corporate monitoring plan for each of the company-defined areas that would cover the collection of fugitive emissions components at the compressor stations located within that company-defined area. This will allow owners and operators flexibility in developing monitoring plans for compressor stations by allowing owners and operators to determine which company-defined area can be covered under the specifications outlined in one monitoring plan, for ease of implementation and compliance. See section VI.F.1.h of this preamble for further discussion.
h. Modifications for Compressor Stations
      The EPA proposed that, for the purposes of the collection of fugitive emissions monitoring and repair requirements, a compressor station is modified when a new compressor is constructed at an existing compressor station or when a physical change is made that causes an increase in the compression capacity of an existing compressor station. We received numerous comments on the compressor modification definition.
      Several commenters stated that the compressor station modification definition is too vague and broad because anytime a physical modification occurred, a regulatory modification would be triggered regardless of whether there were additional emissions. Commenters also stated if a compressor station is not operating at full capacity, addition of a compressor may not necessarily increase the compressor station capacity, nor would addition of a compressor with greater horsepower (thus adding capacity) necessarily increase emissions.
      At proposal, we attempted to identify distinct actions that we were confident would result in an emissions increase and would clearly mark for operators and regulators when a modification occurs. However, upon reviewing the comments, we agree that certain triggering events identified in the proposal may not result in an increase in emissions. Specifically, EPA agrees that an addition of a compressor does not result in an increase in emissions in all instances. For example, there is no emission increase when a new compressor is being installed as a replacement to an existing one. We have, therefore, made changes in the final rule to clarify when an addition of a new compressor would increase emission and therefore trigger the fugitive emission standards (i.e., when it is installed as an additional compressor or if it is a replacement that is of greater horsepower than the compressor or compressors that it is replacing).
       The EPA agrees that an increase in the compression capacity that is not due to the addition of a compressor that would result in an increase of the overall design capacity of the compressor station is not a modification. For example, a compressor station may have to increase the operating throughput by bringing existing compressors on-line to meet demand during peak seasons. In such a case, the compressors' capacities are already accounted for in the overall design capacity for the compressor station, and bringing them on-line would not increase the overall design capacity nor would it increase the potential emissions of the compressor station. Therefore, we are not finalizing that an increase in compression capacity is a modification.
       Commenters also indicated that the addition of a new compressor at an existing compressor station should not trigger a fugitive emissions monitoring program for the entire compressor station but, should only apply to the new compressor and its associated components. We disagree that the addition of a compressor at an existing compressor station should not trigger a fugitive emissions monitoring program for the entire compressor station. We have clarified that the installation of a compressor will only trigger the fugitive monitoring requirements if it is installed as an additional compressor or if it is a replacement that is of greater horsepower than the compressor or compressors that it is replacing. In this case, the design capacity and potential emissions of the compressor station would increase. Unlike the affected facilities for purposes of standards for centrifugal and reciprocating compressors themselves, the affected facility for purposes of the fugitive emission requirements is the collection of fugitive emissions components at a compressor station, not the fugitive emissions components associated with a single compressor. Therefore, if a compressor is added to an existing compressor station, the entire compressor station is subject to the fugitive emissions monitoring program.
      Therefore, we are finalizing a definition that we are confident identifies actions that increase emissions and achieves our original goal of having clearly identifiable criteria that can be easily recognized by operators and regulators. We are finalizing that a modification to a compressor station occurs when a compressor is added to a compressor station or if one or more compressors is replaced with one or more compressors with a greater total horsepower.
i. Provision for Emerging Technology
      Pursuant to CAA section 111(h)(3), we are establishing in the final rule a process for the Agency to permit the use of innovative technology for reducing fugitive emissions at well sites and/or compressor stations. For a detailed discussion, please see section VI.F.1.i.
 G. Equipment Leaks at Natural Gas Processing Plants
       For equipment leaks at natural gas processing plants, the EPA received a total of seven comments addressing issues such as the definition of natural gas processing plant and whether OGI may be used in place of Method 21. We reviewed the comments received and determined to finalize the standard for equipment leaks at natural gas processing plants as proposed. Specifically, the final rule requires NSPS part 60, subpart VVa level of control, including a detection limitation of 500 ppm for certain pieces of equipment. Please see the TSD and RTC documents in the public docket for further discussion.
 H. Reconsideration Issues Being Addressed
      To address numerous items on which we granted reconsideration, we proposed amendments to subpart OOOO and solicited comment on certain topics that would also impact the new NSPS requirements. With some revisions based on our consideration of public comment, the EPA is finalizing certain reconsideration amendments. These amendments address: storage vessel control device monitoring and testing provisions; initial compliance requirements for bypass devices; recordkeeping requirements for repair logs for control devices failing a visible emissions test; clarification of the due date for the initial annual report under the 2012 NSPS; flare design and operation standards; LDAR for open-ended valves or lines; compliance period for LDAR for newly affected units; exemption to notification requirement for reconstruction; disposal of carbon from control devices; the definition of capital expenditure; and continuous control device monitoring requirements for storage vessels and centrifugal compressor affected facilities. This section identifies specifically what the EPA proposed, identifies the regulatory text changes from proposal, and states how the EPA is finalizing these provisions. Please see the TSD and RTC documents in the public docket for further discussion.
1. Storage Vessel Control Device Monitoring and Testing Provisions
      The EPA proposed regulatory text changes to address performance testing and monitoring of control devices used for new storage vessel installations and centrifugal compressor emissions, specifically relating to in-field performance testing of enclosed combustors. The EPA specifically proposed to revise the limit for total organic carbon (TOC) concentration in the exhaust gases at the outlet of the control device from 20 ppmv to 600 ppmv as propane on a dry basis corrected to 3 percent oxygen, a value that more appropriately reflects 95 percent control of VOC inflow to control devices. The EPA also proposed initial and ongoing performance testing for any enclosed combustors used to comply with the emissions standard for an affected facility and whose make and model are not listed on the EPA Oil and Natural Gas Web site (http://www.epa.gov/airquality/oilandgas/implement.html) as those having already met a manufacturer's performance test demonstration. The proposal stated that performance testing of combustors not listed at the above Web site would be conducted on an ongoing basis, every 60 months of service, and monthly monitoring of visible emissions from each unit would also be required.
      Additionally, the EPA proposed amendments to make the requirements for monitoring visible emissions consistent for all enclosed combustion units. Specifically, the EPA proposed to amend 40 CFR 60.5413(e)(3) to require monthly 15-minute period observations using EPA Method 22.
      Based on information submitted through the public comment process, the EPA has identified four necessary revisions for the final storage vessel provisions. First, commenters provided information to the EPA concerning the use of 600 ppmv as propane as appropriately reflecting 95 percent control of VOC inflow to control devices. After an evaluation of the comments, we agreed that the EPA's assumption about the ratio of fuel to combustion air was incorrect, making the proposed 600 ppmv as propane value incorrect. The 600 ppmv as propane value was derived in the memorandum dated June 2, 2015, which discusses the background for the §60.5412(a)(1)(ii) TOC exhaust gas standard for combustion control devices to control VOC emissions from oil and gas affected facilities. While this analysis reflects the destruction of hydrocarbons compared to the concentration of hydrocarbon in the inlet fuel, our analysis did not take into account any in-stack dilution represented by the introduction of combustion air or the correction of that air to 3 percent oxygen. Since hydrocarbon combustion requires approximately a ratio of 12:1 input of combustion air to hydrocarbon, the outlet concentration of TOC would be adjusted downward to 275 parts per million by volume on a wet basis (ppmvw), as propane, at 3 percent O2. The final rule corrects this concentration at §60.5412(a)(1)(ii), and the EPA has appended the memo in the public docket with this adjustment.
      Second, the EPA is finalizing amendments to make the requirements for monitoring of visible emissions consistent for all enclosed combustion units. Prior to the proposal, enclosed combustors that met the manufacturer's performance test requirement were to conduct quarterly observations for visible smoke emissions employing section 11 of EPA Method 22 for a 60-minute period. Petitioners suggested it would ease implementation to adjust the frequency and duration to monthly 15-minute EPA Method 22 tests, which is currently required for continuous monitoring of enclosed combustors that are not manufacturer tested. The EPA agrees with the petitioners. This revision will result in consistent requirements to all enclosed combustors, which will make compliance easier for owners and operators. Because both monitoring requirements ensure compliance of the enclosed combustors, and having the same requirement would ease implementation burden, we are finalizing amendments to §§60.5413(e)(3) and 60.5415(b)(2)(vii)(B) to require monthly 15-minute period observations using EPA Method 22 Test, as suggested by the petitioner.
      The EPA proposed requirements for determining applicability for new storage tanks that replace existing tanks. Commenters provided alternative text indicating how the meaning of the regulation was difficult to discern. The EPA considered the suggested text and agrees that amending this section will make the requirements for compliance easier to understand. The amended language has been finalized in §60.5365(e)(4).
      Fourth, the EPA received comments requesting removal of the requirement that certain devices that route emissions to processes must reduce emissions by 95 percent and instead be written to be consistent with §60.5411a(c), which requires that process devices must operate 95 percent of the year or greater. Upon further reflection, the EPA determined that, because §60.5395a(a) clearly requires that affected sources (except those with uncontrolled emissions below 4 tons per year (tpy)) must reduce VOC emission by 95 percent, it is not necessary to further prescribe the level of reduction to be achieved when emissions are routed to a process. The EPA has therefore removed such specification in §60.5395a(b)(1) in the final rule. As finalized, this specific provision relative to control requirements is the same for centrifugal compressors, pneumatic pumps, and storage vessel affected facilities routing to a process.
2. Initial Compliance Requirements for Bypass Devices
	The EPA proposed to amend §60.5416(c)(3)(i) to include notification via remote alarm to the nearest field office in order to maintain consistency with previous amendments. The EPA proposed to require both an alarm at the bypass device and a remote alarm. The EPA proposed similar amendments to parallel requirements at §60.5411(a)(3)(i)(A) for closed vent systems used with reciprocating compressors and centrifugal compressor wet seal degassing systems. At proposal to amend subpart OOOO, EPA changed "or" to "and" under subpart OOOO at §§60.5411(a)(3)(i)(A) and 60.5411(c)(3)(i)(A), which would have required that both an audible and remote alarm be installed on a bypass device with the potential to vent to the atmosphere. One commenter pointed out that the requirements would be applied retroactively, as the EPA changed the requirements in subpart OOOO as well as subpart OOOOa. The EPA agrees with the commenter that our intent was not to create a retroactive requirement by revising subpart OOOO. The EPA is therefore not finalizing the changes to subpart OOOO, §60.5411 (a)(3)(i)(A), or §60.5411 (c)(3)(i)(A).
      Although we are not finalizing both audible and remote alarm requirements in subpart OOOO, the EPA disagrees that the requirement for remote notification is unreasonable and is therefore preserving the option as an alternative to an audible alarm. The EPA notes that either requirement is restricted to those bypass devices that vent to the atmosphere, not bypass devices (such as some pressure relief devices) that are required to be routed through closed vent systems to control devices. The EPA proposed to require both types of notification in subpart OOOOa because of the diverse nature of facilities that will use them. While an audible alarm may be sufficient at facilities that have personnel present on a continuous basis, not all affected facilities are at continuously-manned locations. An audible alarm on a bypass at a remote location that is visited only on a schedule by maintenance personnel would likely alert no one authorized to take action on the audible alarm until such time as the maintenance personnel arrive, which according to industry, may be a considerable time. The EPA agrees that the logistical requirements may need to be resolved in some instances, and is therefore finalizing the requirements in subpart OOOOa to be the same in substance as the requirements in subpart OOOO, which allow for the operator to choose one form of alarm or the other. Section 60.5416a(c)(3)(i) was revised to match the promulgated regulatory language in §60.5416 (c)(3)(i) of OOOO for consistency.
3. Recordkeeping Requirements for Repair Logs for Control Devices Failing a Visible Emissions Test
	The EPA proposed that the recordkeeping requirements include the repair logs for control devices failing a visible emissions test as required by the rule. Petitioners noted that the recordkeeping requirements of §60.5420(c) do not include the repair logs for control devices failing a visible emissions test required by §60.5413(c). We agree that these recordkeeping requirements should be listed and are finalizing them at §60.5420(c)(14).
4. Due Date for Initial Annual Report
The EPA did not propose regulatory text to amend the rule; rather, the EPA stated in the preamble to the proposed rule that we will consider any initial annual report submitted no later than January 15, 2014 to be a timely submission. All subsequent annual reports must be submitted by the correct date of January 13 of the year.
5. Flare Design and Operation Standards
The EPA proposed to remove the provision of Table 3 in subpart OOOO that exempts flares from complying with the requirements for the design and operation of flares under 40 CFR 60.18 of the General Provisions. By removing the exemption from the General Provisions of subpart OOOO, this clarifies that flares used to comply with subpart OOOO are subject to the design and operation requirements in the general provisions.
Comments on our proposal focused on support for the use of pressure-assisted flares. Pressure-assisted flares are designed to operate with high velocities up to sonic velocity conditions (e.g., 700 to 1,400 feet per second for common hydrocarbon gases). In order to evaluate the use of pressure-assisted flares by the oil and natural gas industry and determine whether to develop operating parameters for pressure-assisted flares for purposes of subparts OOOO and subpart OOOOa, the EPA solicited comment on where in the source category, under what conditions (e.g., maintenance), and how frequently pressure-assisted flares are used to control emissions from an affected facility, as defined within this subpart. From comments to our proposal, the EPA understands that there may be affected facilities that use pressure-assisted flares (e.g., sonic flares) to control emissions from certain activities; however, the EPA now understands that an affected facility storage vessel, pneumatic pump, or centrifugal or reciprocating compressor would not use a pressure-assisted flare for control. The affected facility could be routed by closed vent system to a low pressure flare, which can comply with the velocity requirements of 40 CFR 60.18. The EPA received information showing that certain configurations have separate flare tips that accommodate high pressure and low pressure. The EPA understands that a flare configured this way would be able to meet §60.18 on the low pressure side, which would be appropriate for compliance with these standards. Given these facts, the EPA is finalizing the rule as proposed, because no regulatory amendment appears necessary for such flares to comply with the proposed requirements.
6. Leak Detection and Repair (LDAR) for Open-ended Valves or Lines
In the preamble to the final 2012 rule, the EPA stated that subpart VVa lowered the concentration limit defining a leak from 10,000 ppm to 500 ppm. The EPA's action did not revise subpart VVa, but rather changed the application of leak detection and repair provisions by making the LDAR standards of subpart VVa applicable to affected units subject to LDAR under subpart OOOO if the concentration emanating from a leak is 500 ppm or greater. The EPA further stated that monitoring requirements from subpart VVa applied to pumps, pressure relief devices, and open-ended valves or lines at units affected by LDAR under subpart OOOO. Although the preamble may have obscured the issue, we clarify here that the monitoring provisions of subpart VVa applicable to affected units of subpart OOOO do not extend to open-ended valves or lines. Given this clarification of preamble language, the EPA can identify no need to modify the regulatory language in response to this petition.
7. Compliance Period for LDAR for Newly Affected Units
An issue was raised in an administrative petition that the EPA did not adequately respond to a comment on the 2011 proposed NSPS regarding the compliance period for the LDAR requirements for on-shore natural gas processing plants. The commenter requested that the EPA include in subpart OOOO a provision similar to subpart KKK, 40 CFR 60.632(a), which allows a compliance period of up to 180 days after initial start-up. The commenter was concerned that a modification at an existing facility or a subpart KKK regulated facility could subject the facility to subpart OOOO LDAR requirements without adequate time to bring the whole process unit into compliance with the new regulation. We clarify that subpart OOOO, as promulgated in 2012, already includes a provision similar to subpart KKK, §60.632(a), as requested in the comment. Therefore, the EPA has determined there is no need to modify the current regulations.
8. Exemption to Notification Requirement for Reconstruction
The EPA received an administrative petition that raised the issue that notification of reconstruction requirements under §60.15(d) is unnecessary for some affected facilities. After consideration, the EPA agrees that some notifications are unnecessary because the EPA specifies notification of reconstruction for affected unit pneumatic controllers, centrifugal compressors, reciprocating compressors, and storage vessels under §60.5410a and §60.5420a, in lieu of the general notification requirement in §60.15(d). To make this change effective, the EPA has noted this change in the explanatory comments in Table 3 reflecting that §60.15(d) does not apply to affected facility pneumatic controllers, centrifugal compressors, reciprocating compressors and storage vessels in subpart OOOO. The EPA has determined to finalize these amendments as proposed.
9. Disposal of Carbon from Control Devices
      The EPA re-proposed provisions for management of waste from spent carbon canisters that were finalized in §60.5412(c)(2) of the 2012 NSPS to allow for comment. The EPA received no comment to the re-proposal. The EPA has determined to finalize these amendments as proposed.
10. The Definition of Capital Expenditure
      The EPA proposed to specifically define the term "capital expenditure" in subpart OOOO. In this proposed definition, the EPA updated the formula to reflect the calendar year that subpart OOOO was proposed, as well as specified that the B value for subpart OOOO is 4.5. These updates are necessary for proper calculation of capital expenditure under subpart OOOO. The EPA has determined to finalize these amendments as proposed. Please refer to the RTC document in the public docket for this rulemaking for further discussion.
11. Tanks Associated with Water Recycling Operations
      The EPA solicited comment in the proposed rule to remove tanks that are used for water recycling from potential NSPS applicability and on approaches that could be taken to amend the definition of "storage vessel." Commenters requested that the EPA remove water tanks that are primarily used for water recycling from subpart OOOOa applicability. Commenters discussed that large storage tanks encourage large scale water recycling and are expected to reduce fresh water usage primarily in the Permian Basin. After reviewing the public comments, the EPA agrees that certain large water recycling vessels should be exempt from affected facility status for storage vessels because EPA did not intend such vessels to be affected facility storage vessels under OOOO or OOOOa. By exempting such vessels, EPA will not create a disincentive for recycling of water for hydraulic fracturing. Therefore, the final rule exempts water recycling vessels that receive water that has been through separation, and are much larger than the storage vessels generally intended to be regulated by subparts OOOO and OOOOa for VOC emissions. The EPA has included the exemption language at §60.5365(e)(5) and §60.5365a(e)(5) in the final rule.
12. Continuous Control Device Monitoring
      The EPA proposed under §60.5417 to add continuous control device monitoring requirements for storage vessels and centrifugal compressor affected facilities. The EPA received comments indicating that to impose this requirement on affected facilities under subpart OOOO may make such requirements retroactive, given the time between the original proposal for subpart OOOO and the proposal of the additional requirements. To avoid this possibility, the EPA will not finalize the change proposed to subpart OOOO §60.5417(h)(4).
 I. Technical Corrections and Clarifications
      The EPA is finalizing technical corrections and clarifications intended to provide clarity, improve implementation, and update procedures. This section identifies each correction and the rationale for these changes. Please see the TSD and RTC documents in the public docket for further discussion.
 1. The EPA discovered drafting errors in §60.5412a(d)(1)(iv)(A), §60.5412a(d)(2) and §60.5415a(e)(3) that required control of methane from storage vessels. As discussed in the preamble and the TSD for the proposed rule, the EPA did not consider reduction of methane emissions from storage vessels. Therefore, the reference to controlling storage vessel methane emissions in the proposed regulatory text in the above provisions was a drafting error. In correction, the EPA is removing "methane and" from these three provisions because methane control is not required for storage vessels under subpart OOOOa.
 2. A commenter noted that EPA had omitted a clear deadline by which newly constructed, reconstructed, or modified storage vessels that receive liquids from sources other than hydraulically fractured wells must make their potential to emit determination, in §60.5365a(e)(1). The commenter presumed, correctly, that the omission was inadvertent, stating that "Presumably, EPA intends that such tanks with potential VOC emissions greater than 6 tons per year would be subject to the rule." We have more clearly specified the deadline.
 3. We removed the requirement in §60.5375a(a)(2) that all salable gas recovered from a well completion be routed as soon as practicable to a gathering line. This requirement was duplicative of the provisions of paragraph (1) of the same section.
 4. We revised §60.5420a(b)(4)(i) to include the provision that gas recovered from reciprocating compressors could also be routed to a process as an alternative to replacing rod packing no later than on or before 26,000 hours of operation or 36 months. We additionally corrected an error that identified a wrong initial startup period. This correction consists of removing "since [insert date 60 days after publication of final rule in the Federal Register]." This correction was also made in §60.5420a(c)(3)(i) and §60.5415a(c)(1).
 5. We revised the requirements in §60.5417a for heat sensing monitoring devices on pilot flames to clarify that these devices are not subject to calibration, quality assurance and quality control requirements. While we intended for these devices to monitor continuously, we did not intend to place all of the requirements for continuous parameter monitoring systems on these devices. We also revised the language in §60.5417a(e) and §60.5417a(g) to indicate that heat sensing is not a daily average and that a deviation occurs when the device fails to indicate the presence of a pilot flame.
 6. We revised the language in §60.5417a(f)(1)(iii) for monitoring inlet gas flow rate on control devices tested by the manufacturer. We did not intend for owners or operators to have to continuously achieve a minimum inlet gas flow rate. We have revised the requirement to indicate that there is only a limit on the maximum gas inlet flow rate to the device. We also revised the language in §60.5417a(d)(1)(viii)(A) to indicate that the accuracy requirement is at the maximum flow rate.
 7. We revised the language in §60.5413a(d)(11)(iii) to indicate that manufacturers must demonstrate a destruction efficiency of 95 percent for total hydrocarbons (THC), as propane. This requirement previously stated that the manufacturer must demonstrate a destruction efficiency of 95 percent for VOC and methane. The revised language aligns more accurately with the testing requirements in the rule. Additionally, as these units are burning propene during the test, it would be impossible to demonstrate a destruction efficiency of methane. As methane is a one-carbon, single-bonded compound, it is more easily destructed than propene, a double-bonded compound, and thus, the destruction efficiency should be just as high or higher for methane than for the THC measured during the performance test.
8. We revised the testing language in §60.5413a(b) in order to make it clearer for compliance purposes. The proposed language failed to clearly identify the number of runs or the length of runs expected for each performance test. Additionally, the calculations did not properly align with the specified methods.  Section 60.5412a(d)(1)(i) has no subsections. The reference to "percent reduction performance requirement" in the referring section 60.5413a(b)(3) indicates that the cross reference should refer to section 60.5412a(d)(1)(iv)(A), which contains the percent reduction required.
9. We revised the language in §60.5395a(a) to clarify that owners and operators must comply with the requirements of §60.5395a(a)(1). The proposed language could have been interpreted to mean that compliance with §60.5395a(a)(1) was not required if owners or operators complied with §60.5395a(a)(3); however, it would be impossible to comply with §60.5395a(a)(3) without first determining the potential for VOC emissions, as required by §60.5395a(a)(1). We also further clarified when owners and operators must comply with the requirements of §60.5395a(a)(2) and when they may comply with the requirements of §60.5395a(a)(3).
10. We revised the language in §60.5420a(b)(9)(i), §60.5420a(b)(11), §60.5422a(a), and 60.5423a(b) to update the Web site address for the Electronic Reporting Tool (ERT). We have also clarified that if the CEDRI form is not available at the time that a report is due, we do not intend for owners or operators to submit forms electronically through CEDRI until the form has been available for 90 days. We are also clarifying that this only applies to subsequent reports; owners or operators would not be required to enter previous reports into CEDRI once the form is available. While similar language was proposed, we realize that the previous language did not fully capture our intent.
11. We revised the language in §60.5412a(c)(2)(iii) to correct a drafting error. The proposed language lists the types of units in which owners or operators must regenerate or reactivate spent carbon. The proposed language stated the unit must be operating emission controls in accordance with an emissions standard for VOC under another subpart in 40 CFR part 60 or this part, which is redundant. The language has been revised to state part 63 or this part. We also removed §60.5412a(c)(2)(ii), as we do not believe that owners or operators would be able to regenerate or reactivate spent carbon in accordance with this section, as there are no requirements in this section for that activity. Finally, we removed the phrase "thermal treatment" in front of unit in §60.5412a(c)(2)(i) and (iii) as the phrase "thermal treatment unit" is not defined.
12. We revised the language in §60.5412a(c)(2)(iv) through (vii) and §60.5413a(a)(4) and (5) to reconcile the fact that most hazardous waste combustion units are subject to the requirements of 40 CFR part 63 subpart EEE. While our intent was to encompass all hazardous waste incinerators, boilers and industrial furnaces in these requirements, referencing only 40 CFR parts 264, 265, 266 and 270 may have inadvertently excluded units.
13. We revised the language in §60.5413a(b)(5)(ii)(B) to more clearly identify the continuing compliance obligations for units exempt from periodic testing.
14. We revised the TOC emission rate limit in §60.5412a(a)(1)(ii) and §60.5412a(d)(1)(iv)(B) to be consistent with the changes to the limit in 40 CFR part 60 subpart OOOO. For more explanation on this topic, see the discussion on reconsideration issues in section VI.H of this preamble. We also revised the TOC limit to be on a wet basis, as these units will be tested with Method 25A, which provides measurement data on a wet basis. While we note that compressors must control both VOCs and methane to at least 95 percent, the calculated limit reflects 95 percent control of VOC inflow to control devices. Because methane is the simplest carbon compound, it is very easy to destroy through combustion. Ensuring 95 percent destruction of VOCs will guarantee greater than 95 percent destruction of methane.
15. We revised the wording of §60.5365(e)(4) and 60.5365a(e)(4) at the request of commenters seeking clearer direction on the applicability of standards to storage vessels returning to service. Since the re-wording does not change the meaning or requirements of the section, the revisions have been made to both subparts OOOO and OOOOa for consistency.
16. We corrected the cross reference in section 60.5415(c)(4) from §60.5411(a) to section 60.5416(a) and (b), and in §60.5415a paragraph (c)(4) from section 60.5411a(a) to §60.5416a(a) and (b).
17. We corrected language in in §60.5420(c)(6) to include reciprocating compressors.
18. We adjusted the language in §60.5412(d)(1)(iv)(C), §60.5412a(a)(1)(iii) and §60.5412a(d)(1)(iv)(C). This language allowed operation of the control device at a minimum temperature of 760°Celsius, if the control device was able to demonstrate a uniform combustion temperature during the performance test. In our response to comments on the August 23, 2011 proposed rule, we agreed with commenters that uniform combustion profiles are difficult to obtain due to flame zone mixing and heat transfer. In response to that comment, we revised the language in 40 CFR part 63 subpart HH. We have now revised the language in 40 CFR part 60 subparts OOOO and OOOOa to mimic the language in 40 CFR part 63 subpart HH. We believe that this change is necessary as we do not believe that owners or operators will be able to demonstrate a uniform combustion zone temperature, nor have we defined what it means to have a uniform combustion zone temperature (e.g., the number of measurement points necessary, the agreement between points, etc.). Additionally, §60.5412(d)(1)(iv)(C), §60.5412a(a)(1)(iii) and §60.5412a(d)(1)(iv)(C) previously referenced performance testing in accordance with §60.5413 and §60.5413a, but it was unclear what the performance testing obligations were. We believe the revised language will allow owners and operators to more easily comply with this requirement.
19. We added language to §60.5412(d) and §60.5412a(d) to make our intent clear that flares are acceptable control devices for storage vessels and to identify the design requirements for flares. We also revised language in §60.5415a(b)(2)(vii) to clearly identify the continuing compliance requirements for flares.
20. We adjusted the language in §60.5413a(b)(5)(ii)(A) and §60.5417a(d)(1)(viii) to add a second compliance option for control device models tested under §60.5413a(d). We are allowing owners and operators an option to retest these units every five years in lieu of continuously monitoring the gas flow rate. Owners and operators must still ensure they are not overwhelming the control device by using a control device that can handle the maximum flow rate at the site.
21. We added language to §60.5417a(a) to identify the continuing compliance requirements for enclosed combustion devices that are not specifically identified in §60.5417a(d).
22. In preparation of the final rule, EPA discovered an error in both subpart OOOO and the proposed subpart OOOOa. Specifically, they fail to include a general duty to minimize emissions. As the EPA clarified during the 2012 NSPS rulemaking, "[t]he general duty is applicable to a source at all times." Therefore, the absence of this provision in subpart OOOO and the proposed subpart OOOOa was an error, which is being corrected in these final rules at §60.5370 and §60.5370a.
J. Final Standards Reflecting Next Generation Compliance and Rule Effectiveness
      We are finalizing certain standards that are reflecting EPA's Next Generation Compliance and rule effectiveness strategies. Based on our consideration of the comments received, we are finalizing some aspects as proposed while, for others, we have made a number of changes to the proposed standards. We have the opportunity to expand transparency by making the information we have more accessible and by making new information, obtained from advanced emissions monitoring and electronic reporting, publicly available. We are finalizing an electronic reporting requirement, via the EPA's CDX.
      Other aspects of the final rule will maximize regulatory compliance, such as clear applicability of the final rule (e.g., in revisions to modification criteria) and provide incentives for inherently low-emitting equipment (e.g., solar pumps at gas plants are not affected facilities). Advances in technology additionally promote compliance by enhancing a "visibility" factor; this rule builds on such Next Generation strategies, by including measures involving the use of digital picture reporting and OGI technology. In lieu of independent third party verification for closed vent system design, we are finalizing a qualified professional engineer certification for certain issues. For example, as discussed in section VIII of this preamble, in response to comment, we are providing that a pneumatic pump that cannot be connected to an existing control device due to technical infeasibility does not have to meet this requirement. However, we will require that the source make this determination through use of a professional engineer certification. We are finalizing the use of OGI technology as a method for detecting fugitive emissions at well sites and compressor station sites. With the exception of "clear applicability", "incentives for inherently low-emitting equipment" and "OGI technology for monitoring fugitive emissions", which are discussed elsewhere in this preamble, this section identifies the rationale to the regulatory text changes from proposal and states how the EPA is finalizing these provisions. For additional details, please refer to section VIII, the TSD, and the RTC supporting documentation in the public docket.
 1. Electronic Reporting
        Through electronic reporting, or e-reporting, paper reporting is replaced by standardized, Internet-based, electronic reporting to a central repository using specifically developed forms, templates, and tools. E-reporting is not simply a regulated entity emailing an electronic copy of a document to the government but, also a means to make collected information easily accessible to the public and other stakeholders.
      On March 20, 2015, the EPA proposed the "Electronic Reporting and Recordkeeping Requirements for New Source Performance Standards" (80 FR 15099, March 20, 2015). If adopted, the rule would revise the part 60 General Provisions and various NSPS subparts in part 60 of title 40 of the Code of Federal Regulations (CFR) to require affected facilities to submit specified air emissions data reports to the EPA electronically and to allow affected facilities to maintain electronic records of these reports. This proposed rule focuses on the submission of electronic reports to the EPA that provide direct measures of air emissions data such as performance test reports, performance evaluation reports, summary and excess emission reports and subpart specific reports that are similar in nature to these reports.
      Subpart OOOO is one of the rules potentially affected by this rulemaking. When promulgated, in addition to electronically reporting the results of performance tests, which is already a requirement, a requirement to report the annual reports required in §60.5420(b), the semiannual reports required in §60.5422 and the excess emissions reports required in §60.5423(b) would be added to subpart OOOO. The owner or operator would be required to use the appropriate electronic form in CEDRI for the subpart or an alternate electronic file format consistent with the form's extensible markup language (XML) schema. If the reporting form specific to the subpart is not available at the time that the report is due, the owner or operator would submit the report to the Administrator at the appropriate address listed in §60.4 of the General Provisions. The owner or operator would begin submitting reports electronically with the next report that is due once the electronic form has been available for at least 90 days. The EPA is currently working to develop the form for subpart OOOO.
      In the proposal for subpart OOOOa, the EPA included the same electronic reporting requirements for subpart OOOOa that were included for subpart OOOO in the March 2015 proposal. The EPA is finalizing the requirement to report certain performance test reports, excess emission reports, annual reports and semiannual reports electronically through the EPA's CDX using the CEDRI. The EPA believes that the electronic submittal of the reports addressed in this rulemaking will increase the usefulness of the data contained in those reports, is in keeping with current trends in data availability, will further assist in the protection of public health and the environment, and will ultimately result in less burden on the regulated community. Electronic reporting can also eliminate paper-based, manual processes, thereby saving time and resources, simplifying data entry, eliminating redundancies, minimizing data reporting errors, and providing data quickly and accurately to the affected facilities, air agencies, the EPA and the public.
The EPA Web site that stores the submitted electronic data, WebFIRE, will be easily accessible to everyone and will provide a user-friendly interface that any stakeholder can access. By making the records, data and reports addressed in this rulemaking readily available, the EPA, the regulated community and the public will benefit when the EPA conducts its CAA-required reviews. As a result of having reports readily accessible, our ability to carry out comprehensive reviews will be increased and achieved within a shorter period of time.
The EPA anticipates fewer or less substantial information collection requests (ICRs) in conjunction with prospective CAA-required reviews may be needed, resulting in a decrease in time spent by industry to respond to data collection requests. The EPA also expects the ICRs to contain less extensive stack testing provisions, as we will already have stack test data electronically. Reduced testing requirements would be a cost savings to industry. The EPA should also be able to conduct these required reviews more quickly. While the regulated community may benefit from a reduced burden of ICRs, the general public benefits from the Agency's ability to provide these required reviews more quickly, resulting in increased public health and environmental protection.
Air agencies will benefit from more streamlined and automated review of the electronically submitted data. Having reports and associated data in electronic format will facilitate review through the use of software "search" options, as well as the downloading and analyzing of data in spreadsheet format. The ability to access and review air emission report information electronically will assist air agencies to more quickly and accurately determine compliance with the applicable regulations, potentially allowing a faster response to violations that could minimize harmful air emissions. This benefits both air agencies and the general public.
       For a more thorough discussion of electronic reporting, see the discussion in the preamble of the March 2015 proposal. In summary, in addition to supporting regulation development, control strategy development, and other air pollution control activities, having an electronic database populated with performance test data will save industry, air agencies, and the EPA significant time, money, and effort while improving the quality of emission inventories, air quality regulations, and enhancing the public's access to this important information.
 2. Digital Picture Reporting as an Alternative for Well Completions ("REC PIX") and Manufacturer Installed Control Devices
       The EPA is finalizing digital picture reporting as an alternative for well completions and manufacturer installed control devices as proposed. Specifically, the final rule allows digital picture reporting as an alternative for well completions ("REC PIX") and manufacturer installed control devices. These alternative reporting options provide flexibility for owners and operators, provide enhanced "visibility" for regulators, and take advantage of the advances of the digital age with the ability to capture geospatial accuracy at any location.
       Digital picture reporting as an alternative for well completions ("REC PIX") reflects the 2012 NSPS. As with the 2012 NSPS, we continue to promote an optional mechanism by which owners and operators could streamline annual reporting of well completions by using a digital camera to document that a well completion was performed in compliance with subpart OOOOa. Although we understand that commenters have concerns about the amount of electronic storage capability necessary to store digital pictures, we believe that by allowing either the REC PIX or the elements required under the recordkeeping requirements for well completions, the owner or operator may determine what is most advantageous for their company. Should an owner or operator choose to submit the REC PIX, the REC PIX must consist of a digital photograph of the REC equipment in use, with the date and geospatial coordinates shown on the photographs. These photographs must be submitted with the next annual report, along with a list of well completions performed with identifying information for each well completed.
       Digital picture reporting as an alternative for manufacturer installed control devices provides further opportunity and flexibility to owners and operators to advance data capture to ensure that compliance practices are in effect. This alternative recordkeeping and reporting option is allowed specifically for centrifugal compressors and storage vessels routed to control devices, where the control device used is one tested in accordance with the manufacturer testing procedures in the rule and is posted to the EPA Oil and Gas page. In lieu of a written record with the location of the centrifugal compressor or storage vessel and its associated control device in latitude and longitude, the digital picture alternative must have the date the photograph was taken and the latitude and longitude of the centrifugal compressor and control device or storage vessel and control device imbedded within or stored with the digital file. As an alternative to imbedded latitude and longitude within the digital picture, the digital picture may consist of a photograph of the centrifugal compressor and control device with a photograph of a separately operating GPS device within the same digital picture, provided the latitude and longitude output of the GPS unit can be clearly read in the digital photograph. Furthermore, as discussed in section VI.F of this preamble, digital pictures and frame captures will help ensure that OGI for fugitive emissions is being performed properly.
 3. Certification of Technical Infeasibility of Connecting a Pneumatic Pump to an Existing Control Device
 	In response to comment, the final rule requires that a new, modified, or reconstructed pneumatic pump be routed to an existing control device or process onsite, unless the owner or operator obtains a certification that it is technically infeasible to do so. The EPA understands that some factors such as capacity of the existing control device and back pressure on the exhaust of the pneumatic pump imposed by the closed vent system and control device can contribute to infeasibility of routing a pneumatic pump to an existing control device onsite. Due to the various scenarios that could make routing a pneumatic pump to an onsite control device or process technically infeasible, we do not think we could prescribe a specific set of criteria or factors that must be considered for making such determination that could capture all such circumstances. However, we want to ensure that the owner or operator has effectively assessed these factors before making a claim of infeasibility. To that end, we have included provisions in the final rule to require certification by a qualified professional engineer of such technical infeasibility. In addition, we are requiring that the owner or operator maintain records of that certification for a period of five years.
 4. Professional Engineer Design of Closed Vent Systems.
 	It is the EPA's experience, through site inspections and interaction with the states, that closed vent systems and control devices for storage vessels and other emission sources often suffer from improper design or inadequate capacity that results in emissions not reaching the control device and/or the control device being overwhelmed by the volume of emissions. Either of these conditions can seriously compromise emissions control and can render the system ineffective. We also discussed the issue in the September 2015 Compliance Alert "EPA Observes Air Emissions from Controlled Storage Vessels at Onshore Oil and Natural Gas Production Facilities" (See https://www.epa.gov/sites/production/files/2015-09/documents/oilgascompliancealert.pdf).
       We believe it is important that owners and operators make real efforts to provide for proper design of these systems to ensure that all the emissions routed to the control device reach the control device and that the control device is sized and operated to result in proper control. As a result, we have included in the final rule provisions for certification by a qualified professional engineer that the closed vent system is properly designed to ensure that all emissions from the unit being controlled in fact reach the control device and allow for proper control.
 	Although the final rule does not include requirements for specific criteria for proper design, the EPA believes there are certain minimum design criteria that should be considered to ensure that the closed vent and control device system are designed to meet the requirements of the rule; i.e., the closed vent system must be capable of routing all gases, vapors, and fumes emitted from the affected facility to a control device or to a process that meets the requirements of the rule.
       Furthermore, because other emissions may be collected into the closed vent system and routed to the control device, these design criteria include consideration of the contribution of these additional emissions to ensure proper sizing and operation. The minimum design elements include, but are not limited to, based on site-specific considerations:
 Review of the Control Technologies to be Used to Comply with §§60.5380a and 60.5395a.
 Closed Vent System Considerations:
 Piping --
 Size (include all emissions, not just affected facility);
 Back pressure, including low points which collect liquids;
 Pressure losses; and
 Bypasses and pressure release points.
 Affected Facility Considerations:
 Peak Flow from affected facility, including flash emissions, if applicable; and
 Bypasses, pressure release points.
 Control Device Considerations:
 Maximum volumetric flow rate based on peak flow, and
 Ability to handle future gas flow.
K. Provision for Equivalency Determinations
      In recent years, certain states have developed programs to control various oil and gas emission sources in their own states. Due to the differences in the sources covered and the requirements, determining equivalency through direct comparison of the various state programs with the NSPS has proven to be difficult. We also did not find that any state program as a whole would reflect what we have identified as the BSERs for all emissions sources covered by the NSPS. In any event, federal standards are necessary to ensure that emissions from the oil and natural gas industry are controlled nationwide.
      However, depending on the applicable state requirements, certain owners and operators may achieve equivalent or more emission reduction from their affected source(s) than the required reduction under the NSPS by complying with their state requirements. States may adopt and enforce standards or limitations that are more stringent than the NSPS. See CAA section 116 and the EPA's regulations at 40 CFR § 60.10(a). For states that are being proactive in addressing emissions from the oil and natural gas industry, it is important that the NSPS complement such effort. Therefore, in the final rule, through the process described in section VI.F.1.i for emerging technology, owners and operators may also submit an application requesting that the EPA approve certain state requirement as "alternative means of emission limitations" under the NSPS for their affected facilities. The application would include a demonstration that emission reduction achieved under the state requirement(s) is at least equivalent to the emission reduction achieved under the NSPS standards for a given affected facility. Consistent with section 111(h)(3), any application will be publicly noticed, which the EPA intends to provide within six months after receiving a complete application, including all required information for evaluation. The EPA will provide an opportunity for public hearing on the application and on intended action the EPA might take. The EPA intends to make a final determination within six months after the close of the public comment period. The EPA will also publish its determination in the Federal Register.
 VII. Prevention of Significant Deterioration and Title V Permitting
 A. Overview
      This final rule will regulate GHGs under CAA section 111. In this section, the EPA is addressing how regulation of GHGs under CAA section 111 could have implications for other EPA rules and for permits written under the CAA Prevention of Significant Deterioration (PSD) preconstruction permit program and the CAA Title V operating permit program. The EPA is adopting provisions in the regulations that explicitly address some of these potential implications based on our review of the proposed regulatory text and comments received on the proposal.
       For purposes of the PSD program, the EPA is finalizing provisions in part 60 of its regulations and explaining in this preamble that the current threshold for determining whether a PSD source must satisfy the best available control technology (BACT) requirement for GHGs continues to apply after promulgation of this rule. This rule does not require any additional revisions to state implementation plans (SIPs). With respect to the Title V operating permits program, we are finalizing provisions in part 60 and explaining in this preamble that this rule does not affect whether sources are subject to the requirement to obtain a Title V operating permit based solely on emitting or having the potential to emit GHGs above major source thresholds.
B. Applicability of Tailoring Rule Thresholds under the PSD Program
      EPA received several comments asking for clarification or changes to make clear that this rule did not directly regulate methane as a separate pollutant from GHG and that it would not cause sources to trigger PSD or Title V permitting requirements based solely on methane emissions. This section discusses changes made in response to these comments as well as clarification as to what, if any, impact this rule has on PSD permitting. Section VII.C below addresses Title V-specific issues.
      Under the PSD program in part C of title I of the CAA, in areas that are classified as attainment or unclassifiable for NAAQS pollutants, a new or modified source that emits any air pollutant subject to regulation at or above specified thresholds is required to obtain a preconstruction permit. This permit ensures that the source meets specific requirements, including application of BACT to each pollutant subject to regulation under the CAA. Many states (and local districts) are authorized by the EPA to administer the PSD program and to issue PSD permits. If a state is not authorized, then the EPA issues the PSD permits for facilities in that state.
      To identify the pollutants subject to the PSD permitting program, EPA regulations contain a definition of the term "regulated NSR pollutant." 40 CFR 52.21(b)(50); 40 CFR 51.166(b)(49). This definition contains four subparts, which cover pollutants regulated under various parts of the CAA. The second subpart covers pollutants regulated under section 111 of the CAA. The fourth subpart is a catch-all provision that applies to "[a]ny pollutant that is otherwise subject to regulation under the Act."
      This definition and the associated PSD permitting requirements applied to GHGs for the first time on January 2, 2011, by virtue of the EPA's regulation of GHG emissions from motor vehicles, which first took effect on that same date. 75 FR 17004 (Apr. 2, 2010). GHGs became subject to regulation under the CAA and the fourth subpart of the "regulated NSR pollutant" definition became applicable to GHGs.
      On June 3, 2010, the EPA issued a final rule, known as the Tailoring Rule, which phased in permitting requirements for GHG emissions from stationary sources under the CAA PSD and Title V permitting programs (75 FR 31514). Under its understanding of the CAA at the time, the EPA believed the Tailoring Rule was necessary to avoid a sudden and unmanageable increase in the number of sources that would be required to obtain PSD and Title V permits under the CAA because the sources emitted GHGs in amounts over applicable major source and major modification thresholds. In Step 1 of the Tailoring Rule, which began on January 2, 2011, the EPA limited application of PSD or Title V requirements to sources of GHG emissions only if the sources were subject to PSD or Title V "anyway" due to their emissions of non-GHG pollutants. These sources are referred to as "anyway sources." In Step 2 of the Tailoring Rule, which began on July 1, 2011, the EPA applied the PSD and Title V permitting requirements under the CAA to sources that were classified as major and, thus, required to obtain a permit based solely on their potential GHG emissions and to modifications of otherwise major sources that required a PSD permit because they increased only GHG emissions above applicable levels in the EPA regulations.
     In the PSD program, the EPA implemented the steps of the Tailoring Rule by adopting a definition of the term "subject to regulation." The limitations in Step 1 of the Tailoring Rule are reflected in 40 CFR 52.21(b)(49)(iv) and 40 CFR 51.166(b)(48)(iv). With respect to "anyway sources" covered by PSD during Step 1, this provision established that GHGs would not be subject to PSD requirements unless the source emitted GHGs in the amount of 75,000 tons per year (tpy) of CO2 Eq. or more. The primary practical effect of this paragraph is that the PSD BACT requirement does not apply to GHG emissions from an "anyway source" unless the source emits GHGs at or above this threshold. The Tailoring Rule Step 2 limitations are reflected in 40 CFR 52.21(b)(49)(v) and 51.166(b)(48)(v). These provisions contain thresholds that, when applied through the definition of "regulated NSR pollutant," function to limit the scope of the terms "major stationary source" and "major modification" that determine whether a source is required to obtain a PSD permit. See e.g., 40 CFR 51.166(a)(7)(i) and (iii); 40 CFR 51.166(b)(1); 40 CFR 51.166(b)(2).
     On June 23, 2014, the United States Supreme Court, in Utility Air Regulatory Group v. Environmental Protection Agency, issued a decision addressing the application of PSD permitting requirements to GHG emissions. The Supreme Court held that the EPA may not treat GHGs as an air pollutant for purposes of determining whether a source is a major source (or modification thereof) for the purpose of PSD applicability. The Court also said that the EPA could continue to require that PSD permits, otherwise required based on emissions of pollutants other than GHGs, contain limitations on GHG emissions based on the application of BACT. The Supreme Court decision effectively upheld PSD permitting requirements for GHG emissions under Step 1 of the Tailoring Rule for "anyway sources" and invalidated application of PSD permitting requirements to Step 2 sources based on GHG emissions. The Court also recognized that, although the EPA had not yet done so, it could "establish an appropriate de minimis threshold below which BACT is not required for a source's greenhouse gas emissions." 134 S. Ct. at 2449.
     In accordance with the Supreme Court decision, on April 10, 2015, the United States Court of Appeals for the District of Columbia Circuit (the D.C. Circuit) issued an amended judgment vacating the regulations that implemented Step 2 of the Tailoring Rule but not the regulations that implement Step 1 of the Tailoring Rule. The court specifically vacated 40 CFR 51.166(b)(48)(v) and 40 CFR 52.21(b)(49)(v) of the EPA's regulations, but did not vacate 40 CFR 51.166(b)(48)(iv) or 40 CFR 52.21(b)(48)(iv). The court also directed the EPA to consider whether any further revisions to its regulations are appropriate in light of UARG v. EPA and, if so, to undertake such revisions.
     The practical effect of the Supreme Court's clarification of the reach of the CAA is that it eliminates the need for Step 2 of the Tailoring Rule and subsequent steps of the GHG permitting phase-in that the EPA had planned to consider under the Tailoring Rule. This also eliminates the possibility that the promulgation of GHG standards under section 111 could result in additional sources becoming subject to PSD based solely on GHGs, notwithstanding the limitations the EPA adopted in the Tailoring Rule. However, for an interim period, the EPA and the states will need to continue applying parts of the PSD definition of "subject to regulation" to ensure that sources obtain PSD permits meeting the requirements of the CAA.
     The CAA continues to require that PSD permits issued to "anyway sources" satisfy the BACT requirement for GHGs. Based on the language that remains applicable under 40 CFR 51.166(b)(48)(iv) and 40 CFR 52.21(b)(49)(iv), the EPA and states may continue to limit the application of BACT to GHG emissions in those circumstances where a source emits GHGs in the amount of at least 75,000 tpy on a CO2 Eq. basis. The EPA's intention is for this to serve as an interim approach while the EPA moves forward to propose a GHG significant emission rate (SER) that would establish a de minimis threshold level for permitting GHG emissions under PSD. Under this forthcoming rule, the EPA intends to propose restructuring the GHG provisions in its PSD regulations so that the de minimis threshold for GHGs will not reside within the definition of "subject to regulation." This restructuring will be designed to make the PSD regulatory provisions on GHGs universally applicable, without regard to the particular subparts of the definition of "regulated NSR pollutant" that may cover GHGs. Upon promulgation of this PSD rule, it will then provide a framework that states may use when updating their SIPs consistent with the Supreme Court decision.
	While the PSD rulemaking described above is pending, the EPA and approved state, local, and tribal permitting authorities will still need to implement the BACT requirement for GHGs. In order to enable permitting authorities to continue applying the 75,000 tpy CO2 Eq. threshold to determine whether BACT applies to GHG emissions from an "anyway source" after GHGs are subject to regulation under CAA section 111, the EPA has concluded that it is appropriate to adopt language in 40 CFR 60.5360a, language that is substantially similar to language found in 40 CFR 60.5515 (subpart TTTT).
      While most of the Tailoring Rule limitations are no longer needed to avoid triggering the requirement to obtain a PSD permit based on GHGs alone, the limitation in 40 CFR 51.166(b)(48)(iv) and 40 CFR 52.21(b)(49)(iv) will remain important to provide an interim applicability level for the GHG BACT requirement in "anyway source" PSD permits. Thus, there continues to be a need to ensure that the regulation of GHGs under CAA section 111 does not make this BACT applicability level for "anyway sources" effectively inoperable. The language in 40 CFR 60.5360a is necessary to avoid this result in light of the judicial actions described above.                                                          C. Implications for Title V Program
      Under the Title V program, certain stationary sources, including "major sources" are required to obtain an operating permit. This permit includes all of the CAA requirements applicable to the source, including adequate monitoring, recordkeeping, and reporting requirements to ensure sources' compliance. These permits are generally issued through EPA-approved state Title V programs.
      In the proposal for this rulemaking, the EPA indicated that "the air pollutant that it propose[d] to regulate [was] the pollutant GHGs (which consist of the six well-mixed gases), consistent with other actions the EPA has taken under the CAA, although only methane will be reduced directly by the proposed standards." 80 FR 56600-56601 (Sept. 18, 2015).
      Similar to the comments received on PSD permitting, the EPA received several comments asking for clarification to make clear that this rule did not directly regulate methane as a separate pollutant from GHG and that it would not cause sources to be considered a major source under the Title V permitting program based solely on having methane emissions above the major source threshold. Several of these comments suggested that this issue could be addressed by adding provisions similar to those that appear in 40 CFR 60.5515 (subpart TTTT).
      The immediately preceding section provides some general background about the application of the PSD and Title V permitting programs to GHG emissions. With respect to Title V, the definition of major source includes, in relevant part, a stationary source that "directly emits or has the potential to emit, 100 tpy or more of any air pollutant subject to regulation." 40 CFR 70.2, 71.2 (definition of "major source"). In the Tailoring Rule, a GHG threshold was incorporated into the definition of "subject to regulation" under 40 CFR 70.2 and 71.2, such that those definitions specify that GHGs are not subject to regulation, unless, as of July 1, 2011, the emissions of GHGs are from a source emitting or having the potential to emit 100,000 tpy of GHGs on a CO2 Eq. basis. 40 CFR 70.2, 71.2 (definition of "subject to regulation"); see also 75 FR 31583, June 3, 2010. However, there is not a similar threshold for methane as a separately regulated air pollutant. Some comments reflected a concern that if methane were to be subject to regulation as a separate air pollutant, sources that emitted or had the potential to emit 100 tpy or more of methane would trigger major source status under Title V and any related requirements under the Title V permitting program.
       In consideration of these comments and for purposes of clarity, the EPA has concluded that it is appropriate to adopt language in 40 CFR 60.5360a that is substantially similar to language found in 40 CFR 60.5515 (subpart TTTT). Consistent with the statement quoted above from the proposal, that provision along with the explanation in this preamble clarifies that the GHG standard established in this rulemaking regulates the air pollutant GHGs, although the standard is expressed in the form of a limitation on emission of methane. Accordingly, the air pollutant that is subject to regulation under this standard for Title V purposes is GHGs.
       As noted above, on June 23, 2014, the United States Supreme Court issued its opinion in UARG v EPA, 134 S.Ct. 2427 (June 23, 2014) and, in accordance with that decision, the D.C. Circuit subsequently issued an amended judgment in Coalition for Responsible Regulation, Inc. v. Environmental Protection Agency, Nos. 09-1322, 10-073, 10-1092 and 10-1167 (D.C. Cir., April 10, 2015). With respect to Title V, the Supreme Court said in UARG v. EPA that the EPA may not treat GHGs as an air pollutant for purposes of determining whether a source is a major source required to obtain a Title V operating permit. In accordance with that decision, the D.C. Circuit's amended judgment in Coalition for Responsible Regulation, Inc. v. Environmental Protection Agency, vacated the Title V regulations under review in that case to the extent that they require a stationary source to obtain a Title V permit solely because the source emits or has the potential to emit GHGs above the applicable major source thresholds. The D.C. Circuit also directed the EPA to consider whether any further revisions to its regulations are appropriate in light of UARG v. EPA, and, if so, to undertake to make such revisions. These court decisions make clear that promulgation of CAA section 111 requirements for GHGs will not result in the EPA imposing a requirement that stationary sources obtain a Title V permit solely because such sources emit or have the potential to emit GHGs above the applicable major source thresholds.
      To be clear, however, unless exempted by the Administrator through regulation under CAA section 502(a), any source, including an area source (a "non-major source"), subject to an NSPS is required to apply for, and operate pursuant to, a Title V permit that ensures compliance with all applicable CAA requirements for the source, including any GHG-related applicable requirements. This aspect of the Title V program is not affected by UARG v. EPA, as the EPA does not read that decision to affect either the grounds other than those described above on which a Title V permit may be required or the applicable requirements that must be addressed in Title V permits. For the source category in this rule, there is an exemption in 40 CFR 60.5370a from the obligation to obtain a Title V permit for sources that are not otherwise required by law to obtain a permit under 40 CFR 70.3(a) or 40 CFR 71.3(a). However, sources that are subject to the CAA section 111 standards promulgated in this rule and that are otherwise required to obtain a Title V permit under 40 CFR 70.3(a) or 40 CFR 71.3(a) will be required to apply for, and operate pursuant to, a Title V permit that ensures compliance with all applicable CAA requirements, including any GHG-related applicable requirements.
 VIII. Summary of Significant Comments and Responses
      This section summarizes the significant comments on our proposed amendments and our response to those comments.
A. Major Comments Concerning Listing of the Oil and Natural Gas Source Category
      As previously explained, the EPA interprets the 1979 listing of this source category to cover the oil and natural gas industry broadly. To the extent there is any uncertainty, EPA proposed, as an alternative in the 2015 proposal, to revise the listing of this source category to include oil production and natural gas production, processing, and transmission and storage. We received several comments regarding the EPA's interpretation of the 1979 category listing and its alternative proposal to revise that listing. Provided below is one such comment and the EPA's response. Other comments on this subject and the EPA's responses thereto can be found in the RTC.
Comment: One commenter argues that, in the proposed rule, the EPA seeks to unlawfully expand the scope of the oil and natural gas sector source category, even beyond the expansion that the EPA undertook in 2012 with subpart OOOO, which the commenter had also opposed as unlawful. The commenter asserts that the EPA's attempt here to expand even further the types of emissions sources that would be subject to the NSPS is likewise unlawful. The commenter notes that, in this proposal, several types of never before  - regulated emissions sources would be regulated under NSPS, specifically, hydraulically fractured oil well completions, pneumatic pumps and fugitive emissions from well sites and compressor stations, and that some source types would also be regulated more generally for methane and VOC emissions, as only a small subset are currently regulated for VOC: pneumatic controllers, centrifugal compressors and reciprocating compressors (except for compressors at well sites).
      The commenter notes that the EPA's proposed NSPS would cover an even greater number of very small source types in the EPA's broadly defined "oil and natural gas source category," which, according to the EPA, includes production, processing, transmission and storage. The commenter notes that the EPA again maintains, as it did in the original subpart OOOO rulemaking, that all emissions sources proposed for regulation are covered by its 1979 listing of the oil and natural gas category.
      The commenter claims that the EPA is incorrect that the 1979 original source category determination can be read to include the numerous smaller emissions points covered by this proposal. According to the commenter, the 1979 listing was focused on major emitting operations and cannot be reasonably construed as encompassing small, discrete sources that exist separate and apart from a large facility, like a processing plant.
      The commenter claims that the EPA made clear in the 1979 listing notice that the category was listed to satisfy section 111(f) of the Clean Air Act. According to the commenter, that section required the EPA to create a list of "categories of major stationary sources" that had not been listed as of August 7, 1977, under section 111(b)(1)(A) of the Act, and to promulgate NSPS for the listed categories according to a set schedule. The commenter asserts that the EPA explained in the listing rule that its list included "major source categories," which the EPA defined to include "those categories for which an average size plant has the potential to emit 100 tons or more per year of any one pollutant."
      Although the commenter notes that the EPA provided no further explanation in its original 1979 listing decision as to what facilities it intended to regulate under the "crude oil and natural gas production" source category, the commenter claims that "there can be no doubt that the category originally included `stationary sources' (i.e., `plants') that typically have a potential to emit at least 100 tons per year of a regulated pollutant." The commenter argues that this communicates two important limitations on the original listing decision: first, the EPA was focused on discrete "plants" or "stationary sources"; and second, the EPA was focused on large emitting plants or stationary sources. The commenter argues that, as a result, the original listing decision cannot reasonably be interpreted to extend to the types of sources the EPA seeks to regulate in the proposal and that the additional source types that the EPA seeks to regulate in this proposal could not plausibly be considered part and parcel of major emitting plants.
      The commenter notes that the EPA interpreted the 1979 listing to be broader than the "production source segment" because the EPA evaluated equipment that is used in various segments of the natural gas industry, such as stationary pipeline compressor engines. 80 FR 56600, September 18, 2015. The commenter argues that this does not evince an intent to regulate non-major source types, but only that the Agency evaluated equipment located at what it perceived to be major facilities.
      The commenter further notes that, in the preamble to the proposed NSPS for natural gas processing plants, the EPA described the major emission points of this source category to include process, storage and equipment leaks. However, the commenter argues that this does not support what the commenter claims as "broad regulation of even the smallest sources in the oil and natural gas industry." The commenter notes that the emissions points regulated in that rulemaking -- process units and compressors -- were located at gas processing plants. The commenter argues that it is telling that the Agency decided to regulate only natural gas processing plants -- the closest thing to a major emitting plant that can be found in this sector -- in that NSPS.
Response: In 1979, the EPA published a list of source categories, including "oil and natural gas production," pursuant to a new section 111(f) in the Clean Air Act amendment of 1977, which directed the EPA to list under 111(b)(1)(A) "categories of major stationary sources" and establish standards of performance for the listed source categories. As explained in the September 2015 proposal preamble and earlier in section IV.A of this notice, the EPA interprets the 1979 listing to broadly cover the oil and natural gas industry. The commenter claims that the EPA's interpretation is incorrect because the 1979 listing included only large emitting plants or stationary sources. However, the commenter's interpretation fails for the following reasons.
      The commenter's claim relies in large part on the EPA's definition of a "major source category" in the 1979 listing action, which was defined as "an average size plant that has the potential to emit 100 tons or more per year of any one pollutant," 44 FR 49222 (August 21, 1979). However, despite the definition above, the EPA provided notice in the listing action that "certain new sources of smaller than average size within these categories may have less than a 100 ton per year emission potential." 43 FR 38872, 38873 (August 31, 1978). The EPA thus made clear that the 1979 listing did not include only those meeting the major source threshold. The EPA's contemporaneous explanation indicates that, while the 1979 action focused on large emitting sources, the EPA recognized at the time that there are smaller sources that may warrant regulation.
      The commenter next argues that the 1979 listing included only large plants because it included only "stationary sources." However, "stationary sources," as defined in section 111(a)(2), include not only buildings, structures and facilities (e.g., plants) but also installations, such as equipment, that emit or may emit any pollutant. Moreover, this definition contains no size limitation.
      The commenter cites to the EPA's initial NSPS promulgation in 1985, which regulated only natural gas processing plants, as evidence that the 1979 listing included only large emitting stationary sources and, in the case of the oil and natural gas source category, only natural gas processing plants. However, the fact that the EPA regulated only natural gas processing plants in the 1985 NSPS does not establish that the listed oil and natural gas source category consists of only large natural gas processing plants. On the contrary, this argument ignores that the category, as listed, also includes crude oil production. Further, such narrow view is inconsistent with the EPA's clarification of the 1979 listing and the statutory definition of "stationary sources," neither of which limits a listed category of stationary sources under section 111 only to large plants such as natural gas processing plants, as explained above.
      The commenter's assertion is also refuted by the EPA's statements during the development of the 1985 NSPS. Specifically, in the preamble to the proposed rule for equipment leaks at natural gas processing plants, the EPA described the major emission points of this source category to include process, storage and equipment leaks, which can be found in various segments of the oil and natural gas industry. Further, as mentioned earlier, the EPA described the listed oil and natural gas source category to include emission points that the EPA did not regulate at that time, such as "well systems field oil and gas separators, wash tanks, settling tanks and other sources." 49 FR at 2637. The EPA explained in that action that it could not address these emission at that time because "best demonstrated control technology has not been identified."
      In light of the above, EPA reasonably interprets the 1979 listing to include the sources regulated under the 2012 oil and gas NSPS as well as those subject to today's action. The EPA established well completion performances standards for hydraulically fractured gas wells in the 2012 NSPS and for oil wells in today's action. These standards address some of the above mentioned well system emissions that the EPA could not regulate previously due to the lack of data. In addition, as mentioned above, the EPA had previously identified equipment leaks as a major emission point from this listed source category and established leaks standards for natural gas processing plants. Today's action further reduces emissions from equipment leaks by establishing work practice standards to detect and repair fugitive emissions at well sites and compressor stations. Emissions from equipment do not result only from leaks but also from normal operations that, if uncontrolled, are vented into the atmosphere. Therefore, both the 2012 NSPS and today's rule include performance standards for certain equipment used throughout the oil and natural gas industry, such as storage vessels, pneumatic controllers, pneumatic pumps, and compressors. Because these equipment are widely used across this industry, they contribute significant amount of emissions even if emissions from an individual piece of equipment may not be big.
      The commenter's main concern appears to be with the EPA regulating what the commenter claims to be "very small emission sources" and, therefore, unreasonable. However, section 111(b)(1)(A) requires that the EPA list source categories, not emission sources. In listing a source category, the EPA is not required to identify specific emission points within that source category. However, having listed a source category, the EPA is then required under section 111(b)(1)(B) to establish through rulemaking performance standards that reflect the best system of emission reductions, which would entail evaluation of emissions, control options, and other considerations (including their costs) for the sources to be regulated. Therefore, specific concerns with regulation of certain emission sources can be addressed during the rulemaking to establish such performance standards, where a commenter can argue that controlling a specific type of source is unreasonable under 111(b)(1)(B).
      For the reasons stated above, the commenter fails to support its claim that the EPA's interpretation of the 1979 listing is unlawful. The commenter also fails to support its interpretation of the 1979 listing. The EPA's interpretation of the 1979 listing therefore remains unchanged.
Comment: The commenter claims that the EPA fails to make the required statutory findings under section 111(b)(1)(A) to support its proposed revision to the 1979 listing. The commenter asserts that, under section 111(b)(1)(A), the EPA is authorized to regulate additional source types if and only if it: (1) defines a discrete "category" of stationary sources; and (2) determines that emissions from the source category cause or significantly contribute to endangerment to health or the environment.
      The commenter claims that the EPA makes no effort whatsoever to demonstrate that emissions from the particular additionally-regulated sources in subpart OOOOa cause or contribute to endangerment to health or the environment. Instead, the Agency simply asserts general public health effects associated with GHGs, VOC, and SO2 and then evaluates emissions from oil and natural gas sources generally. See 80 FR 56601-08, September 18, 2015. For methane, the EPA merely breaks down emissions into four general "segments" (natural gas production, natural gas processing, natural gas transmission and storage, and petroleum production), but does not evaluate particular source type emissions within those segments. The EPA does nothing to break down its evaluation of emissions even by sector segment for SO2 and VOC. This failure to investigate the key statutory listing criteria is patently arbitrary and plainly violates the requirement in section 307(d)(3) of the Clean Air Act to clearly set forth the basis and purpose of the proposal.
      The commenter claims that under the EPA's logic, as long as certain types of stationary sources in a category, or segment of a category, cause or significantly contribute to endangerment to health or the environment, the Agency can lump together in the defined source category (or segment of a source category) all manner of ancillary equipment and operations, even if those ancillary equipment and operations do not in and of themselves significantly contribute to the previously identified endangerment. See 80 FR 56601, September 18, 2015. This is not a reasonable interpretation of section 111(b)(1)(A) because such an interpretation would bestow virtually unlimited regulatory authority upon the EPA, allowing the EPA to evade the express listing criteria by creating loose associations of nominally related sources in a sector.
Response: The commenter claims that the EPA must separately list and make the required findings under CAA section 111(b)(1)(A) for the "additional source types" from the oil and natural gas industry that were not covered by the 1979 listing. First of all, the EPA disagrees that there are such "additional source types" because, for the reasons stated in section IV.A of this notice and the response to comment immediately above, the EPA interprets the 1979 listing to broadly cover the oil and natural gas industry. To the extent there is any uncertainty, the EPA rejects the commenter's claim that the 1979 listing covers only natural gas processing plants. But, more importantly, the EPA rejects this comment because it is contrary to the law.
      CAA section 111(b)(1)(A) requires that the EPA list a category of sources "if in [the Administrator's] judgment it causes, or contributes significantly to, air pollution which may reasonably be anticipated to endanger public health and welfare." The provision is clear that the listing and endangerment findings requirements are to be made for source categories, not specific emission sources within the source category. The provision also does not require that the EPA identify all emission points within a source category when listing that category.
      The commenter's claim that the EPA must separately list and make findings for particular emission source types within individual segments of the natural gas industry clearly contradicts with the plain language of section 111(b)(1)(A) which, as discussed above, is stated in terms of source category, not emission source types. Regardless, the EPA has satisfied the two criteria the commenter has identified as required by section 111(b)(1)(A): (1) define a discrete category of stationary sources; and (2) determine that emissions from the source category cause or significantly contribute to endangerment to health or the environment. Although the EPA does not believe that revision to the 1979 category listing to be necessary for today's action, the EPA is finalizing as an alternative its proposed revision of the category listing to broadly include the oil and natural gas industry. In support of the revision, the final rule includes the Administrator's determination under section 111(b)(1)(A) that, in her judgment, this source category, as defined in this revision, contributes significantly to air pollution which may reasonably be anticipated to endanger public health or welfare.
      The commenter also appears to claim that the EPA cannot revise the scope of a listed source category, but must instead separately list and make findings for what the commenter considers as "additional source types" within an already listed source category. The commenter offers no legal basis to support its claim because there is none. On the contrary, as explained below, the commenter claim impermissibly restricts the EPA's authority under section 111(b)(1)(A).
      Section 111(b)(1)(A) requires that the EPA revise the category listing from time to time; it does not limit such revision to simply adding new source categories. The only criteria that section 111(b)(1)(A) states for the EPA to apply to category listing revision are the same as those for the initial category listing: that the category "causes, or contributes significantly to, air pollution which may reasonably be anticipated to endanger public health and welfare." Thus, the statute leaves the EPA with the discretion to determine how to carry out such task, and that gives the EPA the flexibility to list and revise the list, including redefining the scope of a previously listed category, as long as long as the EPA meets the above criteria with the requisite endangerment findings for the source category as a whole. It allows the EPA to revise a category listing to include sources that, though not included in the initial listing (e.g., the EPA might now have known about it at the time), reasonably belong in a listed source category. The commenter provides no compelling reason that such emission sources need a separate category listing and endangerment finding. In light of the above, the commenter's claim for a separate category listing and endangerment finding is not only unsupported by the statute, it unreasonably curtails the discretion section 111(b)(1)(A) provides the EPA in executing its category listing and revision authority under that provision. For the reasons stated above, the EPA disagrees with this comment.
B. Major Comments Concerning EPA's Authority to Establish GHG Standards in the Form of Limitations on Methane Emissions
      As previously explained in section IV.D, the EPA's authority for regulating GHGs in this rule is CAA section 111. The standards in this rule that are specific to GHGs are expressed in the form of limitations on emissions of methane, and not the other constituent gases of the air pollutant GHGs. We received several comments regarding the EPA's interpretation of CAA section 111. Provided below is a summary of such comments and the EPA's response. Other comments on this subject and the EPA's responses thereto can be found in the RTC document.
Comment: Several commenters argued that the EPA cannot rely on the 2009 Endangerment Finding for GHG to justify the limitations of methane in this rule. The commenters made several arguments.
      First, some commenters asserted that the EPA cannot regulate methane alone or specifically without a new Endangerment and Cause or Contribute Finding for the individual gas, because the original 2009 Finding defined the pollutant as the six well-mixed greenhouse gases. One commenter further stated that it is unlawful for the EPA to regulate only methane based on an endangerment finding that is largely attributable to other pollutants and that, of the six greenhouse gases, carbon dioxide is emitted in vastly greater quantities (even on a carbon dioxide equivalent basis) than methane.
      Second, some commenters argue that a new endangerment finding is necessary for each pollutant regulated in a given source category. One commenter claims that section 111(b)(1)(A) of the CAA requires the EPA to list a category of stationary sources if, in the Administrator's judgment, the category causes, or contributes significantly to, air pollution which may reasonably be anticipated to endanger public health or welfare. The commenter further argues that this CAA section unambiguously requires the EPA to list and regulate according to endangerment and significant contribution findings for particular pollutants. The commenter goes to state that it is unreasonable for the EPA to use a cause-or-contribute finding made for one pollutant thirty years ago in order to justify controlling a different pollutant today. The commenter asserts that a "rational basis test" is insufficient justification, and that the term "rational basis" is not found in section 111.
      Third, some commenters argue that methane does not endanger human health or welfare. One commenter states that methane is naturally occurring and is non-toxic, that it does not accumulate in the body, that the only real risks that it poses are that it is flammable when present in high concentrations, and that inhaling high levels can cause oxygen deprivation. Another commenter claims that recent science supports a weakening of the case for human-caused global warming.
      Finally, some commenters state that the impacts of the rule will be very small. One commenter argues that "the oil and gas sector do [sic] not significantly cause or contribute to climate change" because methane emissions from that sector "account for only 3 percent of total United States domestic GHG emissions, just over 2 percent of the total United States GHG Inventory, and 0.3 percent of Global GHG emissions" and transmission and storage is only a third of that total.
Response: As a general matter, commenters on this issue consistently mischaracterize the EPA's actions. The standards in this rule that are specific to GHGs are expressed in the form of limitations on emissions of methane. For these standards, GHG is the regulated pollutant. An endangerment finding is only required when the EPA lists a source category under section 111(b)(1)(A). Nothing in section 111 requires that the EPA make further endangerment findings with respect to each pollutant that it regulates under section 111(b)(1)(B). By considering whether there is a rational basis to regulate a given pollutant from a listed source category, the EPA ensures that it regulates pollutants that warrant regulation.
      For purposes of this final rule, the EPA's rational basis is supported, in part, by the analysis that supported the 2009 Endangerment Finding. If, as commenters argue, the EPA is required to make additional findings of endangerment and cause-or-contribute for this final rule, then the analysis that supported the 2009 Endangerment Finding, along with other facts presented herein, including the information in sections IV.B and C, would be sufficient to make these findings.
      While the 2009 Endangerment Finding defined the pollutant as the "aggregate group of the well-mixed greenhouse gases" the finding was also clear that a given source category does not have to emit every single one of these gases in order to contribute to the pollution in question. See 74 FR 66496-99 and 66541 (December 15, 2009). Specifically, as we explained in the 2009 Endangerment Finding, two of the six pollutants (PFCs and SF6) are not emitted by motor vehicles, the source category in question in the 2009 Endangerment Finding. Moreover, while motor vehicles contribute to emissions of HFC-134a, there are many other HFCs which are not emitted by that source. Just as the GHG emissions from motor vehicles do not need to contain all six gases in order to be regulated, the GHG emissions from the oil and gas sector do not need to contain all six gases. Therefore, the EPA does not need to make an endangerment finding for methane alone: the 2009 Endangerment Finding that defines the aggregate group of six well-mixed gases as the air pollution addresses emissions of any individual component of that aggregate group and, therefore, supports the rational basis for this final rule.
      Next, the assertion that methane has no risks beyond flammability is false. While methane is indeed produced from natural sources, the health and welfare risks of elevated concentrations of greenhouse gases (including methane) was detailed in the 2009 Endangerment Finding. Moreover, methane is a precursor to tropospheric ozone formation, which also impacts human health. As further context, according to the IPCC, historical methane emissions contribute the second most warming today of all the greenhouse gases, after carbon dioxide. This makes methane emission reductions an important contribution to reducing the atmospheric concentrations of the six well-mixed greenhouse gases.
      Lastly, the climate benefits anticipated from the implementation of this rule are consequential in terms of the quantity of methane reduced, particularly in light of the potency of methane as a GHG. The reductions are additionally important as the United States oil and natural gas sector emits about 32 percent of United States methane emissions and about 3.4 percent of all United States GHGs. The final standards are expected to reduce methane emissions annually by about 6.9 million metric tons CO2 Eq. in 2020 and by about 11 million metric tons CO2 Eq. in 2025. To gives a sense of the magnitude of these reductions, the methane reductions expected in 2020 are equivalent to about 2.8 percent of the methane emissions for this sector reported in the United States GHG Inventory for 2014. Expected reductions in 2025 are equivalent to around 4.7 percent of 2014 emissions. As discussed in section IX.E, the estimated monetized benefits of methane emission reductions resulting from this rule are $160 million to approximately $950 million for reduced emissions in 2020, and $320 million to $1.8 billion for reduced emissions in 2025, depending on the discount rate used. The magnitude of these benefits estimates demonstrates that the methane reductions are consequential from an economic perspective, as well as physical perspective.
 C. Major Comments Concerning Compressors
1. Wet Seal Centrifugal Compressors with Emission Rates Equal to or Lower than Dry Seal Centrifugal Compressors
Comment: The EPA received several comments asserting that there are many wet seal centrifugal compressors that have emissions that are equal to, or lower than, dry seal compressors. One commenter notes that the EPA cites 6 standard cubic feet per minute (scfm) as the emission rate for dry seals and that a wide variety of wet seal systems are in use with varying rates of de-gas emissions and that if wet seal system can meet an emissions performance specification on par with dry seals (i.e., 6 scfm), they should be exempt from the 95 percent reduction requirement. One commenter states that data indicate that a well-maintained wet seal will have a methane emission rate comparable to or lesser than dry seals and that the emission rate for commenter's compressors is significantly lower than the average rate identified in the EPA's National Emissions Inventory for this kind of source.
Response: The emissions factor used in our BSER analysis is an average factor calculated from available emissions information. As such, there are some wet seal centrifugal compressors that have a lower emission rate than the average emission rate. However, we have not been provided, nor do we have, any data indicating that there is a specific type or significant population of wet seal centrifugal compressors that have emission rates that are equal to or lower than dry seal compressors. We acknowledge that a well-maintained wet seal compressor may have lower emissions; however, as noted, the rule is based on an average emission factor derived from the best available information on a population of wet seal compressors. We have no data on which to base an exemption or different requirement for a subcategory of merely presumed low-emitting wet seal centrifugal compressors.
2. Regulation of Centrifugal and Reciprocating Compressors at Well Sites
Comment: The EPA received several comments opposing the exemption of centrifugal and reciprocating compressors located at well heads from the requirements of the rule. The commenters state that there are thousands of well head reciprocating compressors across the nation as well as some centrifugal compressors at well heads, and they pose a significant source of emissions unless properly controlled. The commenters contend that the reason the EPA claims to exclude these compressors is based on EPA data that show no centrifugal compressors located at well heads and on the determination that it is not cost effective to regulate these reciprocating compressors. Commenters state that the GHGRP data shows that there are centrifugal compressors located at well heads and that they should be regulated under the rule. Further, commenters assert that the EPA's cost effectiveness determination for reciprocating compressors is arbitrary because it was based on outdated emission factors and that if updated, the revised emissions would render the control for the well head compressors as cost-effective. Commenters suggest that the EPA should have relied on updated emission factors to estimate emissions from well-site compressors as it did to estimate emissions from gathering sector compressors, or at least explained why it failed to rely on updated emissions data to estimate emissions from well-site compressors.
Response: The emissions estimates presented in the proposal were based on the most robust data available at the time of their development. The EPA began collecting data through GHGRP on centrifugal compressors in the onshore petroleum and natural gas production segment in 2011. However, reporting of input data for compressors, including the count of centrifugal compressors at a facility, in onshore production was deferred until 2015 and published for the first time in October 2015. As a result, data on the number of centrifugal compressors were not available through GHGRP at the time of the development of the NSPS OOOOa proposal.
	The EPA agrees with the commenter that the newly available data from GHGRP show the presence of centrifugal compressors in the onshore production segment, but the EPA disagrees with the commenter that it should cover these sources under the final rule. Although GHGRP data shows that 15 reporters indicated 69 centrifugal compressors at production facilities, the data do not provide a method to determine the number of centrifugal compressors with wet seals in onshore production. The GHGRP does not collect data on seal type (wet seal and dry seal) for onshore production. The EPA is not aware of other data sets on wet seals in the onshore production segment. Based on available data on the number of centrifugal compressors in onshore production, it is unlikely that there is a large population of centrifugal compressors with wet seals in onshore production.
      With respect to emission factors for reciprocating compressors at well sites, the EPA proposed to exempt these compressors from the standards because we found that the cost of control for reciprocating compressors at well sites is not reasonable. Commenters on the 2014 Oil and Gas White Papers and on the subpart OOOOa proposal did not provide new data available for development of emission factors for reciprocating compressors at well sites. The EPA has not identified additional data sources for development of emission factors for reciprocating compressors at well sites and, therefore, has not updated its emissions estimate for this source. We continue to believe the cost of control for reciprocating compressors at well sites remains unreasonable. The final rule exempts centrifugal and reciprocating compressors at well sites.
3. Condition-Based Maintenance
Comment: The EPA solicited comment on an alternative to the proposed requirements which consists of monitoring of rod packing leakage to identify when the rate of rod packing leakage indicates that packing replacement is needed. Under such a condition-based maintenance provision, rod packing would be inspected or monitored based on a prescribed method and frequency and rod packing replacement, or repair would be required once a prescribed leak rate was observed. We requested additional information on the technical details of this condition-based concept.
      Several commenters state that the rule should include an alternative maintenance program and allow operators flexibility to use a condition-based maintenance approach to reduce emissions rather than a prescribed maintenance schedule as currently included in the rule. In addition to controlling emissions, commenters assert that a condition-based maintenance may extend the operation of functional rod packing, eliminate premature and wasteful rod packing maintenance/replacement and, possibly, where rod packing leakage increases quicker than is typical, condition-based maintenance can result in earlier maintenance than EPA's proposed prescribed maintenance schedule. Commenters note that condition-based maintenance has been a proven successful technique for reducing methane emissions through the Natural Gas STAR program, where rod packing leaks were periodically monitored and the value of the incremental leaked gas (relative to leak rates for "new" packing) was compared to the rod packing maintenance cost. When the incremental lost gas value exceeded the maintenance/replacement cost, the rod packing maintenance was determined to be cost-effective.
      Other commenters noted that because operators in transmission and storage segment do not own the gas, a different performance metric could be used and recommended a metric based on a defined leak rate or change in leak rate over time. Commenters recommended possibly setting a threshold at a leak rate above 2 scfm, combined with annual monitoring, which would require rod packing maintenance/replacement within nine months or during the next unit shutdown, whichever is sooner and which is consistent with a draft California Air Resources Board (CARB) regulation for oil and gas operations.