We then examined the recordkeeping costs associated with the fugitive emissions requirements. As stated above, we were unable to locate clearly defined estimates for recordkeeping costs for the 2016 NSPS OOOOa, therefore, all costs are new in our baseline estimate of the actual cost of the existing standards and are based on information received from commenters and previous information collected by the Agency for similar programs. There are extensive records required for each survey that is performed, regardless of the frequency; therefore, we recognize that appropriate data management is critical to ensuring compliance with the standards. As explained in the TSD for this final rule, we evaluated costs for the set-up for a database system, which ranged from commercially available options to customized systems. Because there are commercial systems currently available that allow owners and operators to maintain records in compliance with the standards, we did not find it appropriate to apply customized system costs to determine an average or range of costs. Therefore, our initial database set-up fee is estimated as $18,607 for 22 well sites and 7 gathering and boosting compressor stations. In addition to this initial set-up fee, we recognize that there are annual licensing fees that include technical support and updates to software. Therefore, we have incorporated an ongoing annual fee of approximately $470. Finally, there is recordkeeping associated with tracking observed fugitive emissions and repairs, such as scheduling repairs and quality control of the data. Based on information provided by commenters we estimate additional recordkeeping costs at $430 for well sites and $860 for gathering and boosting compressor stations.
	Finally, we evaluated the current estimate for reporting costs associated with the 2016 NSPS OOOOa. One commenter asserted they spent over 500 hours reporting information through CEDRI for their sources. We examined the information reported to CEDRI for this commenter and concluded they have reported information for approximately 100 well sites, which would equate to 5 hours per site. This is comparable to our estimate of 4 hours per well site; therefore we did not update the cost estimate for reporting associated with the 2016 NSPS OOOOa.
	In summary, we updated the cost burden estimates for recordkeeping based on the 2016 NSPS OOOOa. As updated, the annualized recordkeeping and reporting costs for the existing rule, on a per site basis, are approximately $1,500 per well site and $2,500 per gathering and boosting compressor station. These costs represent the baseline from which any changes to the cost burden for reporting and recordkeeping requirements in this final rule are compared. It is important to note that while these costs represent the costs for each individual site, the EPA estimates that currently there are over 40,000 well sites and 1,250 compressor stations currently subject to the fugitive emissions requirements in the 2016 NSPS OOOOa. When multiplied, the total annualized costs to the industry is estimated to exceed $60 million per year.
	After updating the recordkeeping and reporting costs for the existing requirements, we evaluated requests by commenters recommending specific changes to those requirements. Several commenters requested removal of or amendments to specific line items. These included items such as the site map and observation path requirement in the monitoring plan, records related to the date and repair method for each repair attempt, and name of the operator performing the survey. After further review of the specific requirements, for the reasons explained below, we agree with the commenters that some of the items are not critical or are redundant for demonstrating compliance and, therefore, are an unnecessary burden.
	We are amending the monitoring plan by removing the requirement for a site map and observation path when OGI is used to perform fugitive emissions surveys. This requirement was in place to ensure that all fugitive emissions components could and would be imaged during each survey. As explained in the TSD, we agree with the commenters that a site map and observation path are only one way to ensure all components are imaged. We are replacing the specified site map and observation path with a requirement to include procedures to ensure that all fugitive emissions components are monitored during each survey in the monitoring plan. These procedures may include a site map and observation path, an inventory, or narrative of the location of each fugitive emissions component, but may also include other procedures not listed here. These company-defined procedures are consistent with other requirements for procedures in the monitoring plan, such as the requirement for procedures for determining the maximum viewing distance and maintaining this viewing distance during a survey. As previously stated, we had not accurately accounted for the ongoing cost of updating the site map and observation path as changes occur at the site. Based on information provided by one commenter, we estimate this amendment will save each site $580 with the semiannual monitoring frequency. These cost reductions are based on an initial cost of $400 to develop the site map and observation path, plus $180 to update the site map or observation path each year, based on a semiannual monitoring frequency.
	We are not finalizing the proposed recordkeeping requirement to keep records of each repair attempt. Instead, the final rule requires maintaining a record only for the first attempt at repair and the completion of repair. Other interim repair attempts are not necessary for demonstrating compliance with the repair requirements. Additionally, we are removing the requirement to maintain records of the number and type of components not repaired during the monitoring survey. The 2016 NSPS OOOOa required maintaining a record of the number and type of components found with fugitive emissions that were not repaired during the monitoring survey. After further review, this information can be derived from, and is therefore redundant to, other records of the survey date and repair dates required for all fugitive emissions components. While it is difficult to quantify the reduction in cost burden of the removal of these records, we have estimated a reduction in cost of 25%, or $107 per site per year as discussed in the TSD.
	We are also amending the reporting requirements to streamline reporting based on comments received and further reconsideration of what information is essential to demonstrate compliance with the standards. First, as we are finalizing the electronic reporting form for the annual report required by 40 CFR 60.5420a(b) concurrently with this action, we are updating the CEDRI reporting template to reflect the streamlined reporting requirements in this final action and ease review of the information contained within the form. Specifically, for reporting compliance with the fugitive emissions requirements, we have created dropdown menus for the operator to select the type of site for which they are reporting (i.e., well site or compressor station), to indicate whether the well site changed status to a wellhead-only well site during the reporting period, and identify any approved alternative fugitive emissions standard that was used during the reporting period for the site. Second, we are removing specific items from the annual report as listed in section IV.I.3 of this preamble. We are removing the requirement to report the name or unique ID of the operator performing the survey; however, this information must be maintained in the record, similar to the LDAR requirements for onshore natural gas processing plants. We are removing the requirement to report the number and type of difficult-to-monitor and unsafe-to-monitor components that were monitored during the specified survey. This information is required to be kept in the record, and the type and number of these components would already be included in the reported number and type of components found with fugitive emissions during the survey. The date of successful repair is being removed from the report because we already require owners and operators to report the number and type of fugitive emissions not repaired on time. The date of successful repair will be maintained in the record. Finally, the type of instrument used for the resurvey is being removed from the report because the rule allows either OGI or Method 21 (analyzer or a soap bubbles test). The information is required to be kept in the record. Similar to the recordkeeping changes identified in the previous paragraph, it is difficult to estimate the reduced cost burden of each of these individual items. That said, as shown in the TSD, we have estimated a burden reduction of 25%, or $61 per site per annual report.
	In summary, the amendments to the recordkeeping and reporting requirements in this final rule will reduce the recordkeeping and reporting burden for NSPS OOOOa. The estimated annualized recordkeeping and reporting costs for this final rule, on a per site basis, are approximately $1,100 per well site and $1,750 per gathering and boosting compressor station. This results in an annualized burden reduction of approximately 27% for well sites and 30% for gathering and boosting compressor stations.
3. Additional Updates to the Model Plants.
      We also received information from commenters that suggested additional updates beyond those already discussed above. These included the major equipment counts and survey costs. A detailed discussion of these updates, which we agree are necessary, is provided in the TSD. A summary of these updates is provided below.
      Well sites. In the October 15,2018 proposal, we maintained the assumed flat contractor fee of $600 per survey. However, information from commenters suggested this may be an overestimate of survey costs if an hourly rate were used. To examine this comment, we analyzed the CEDRI reports, and evaluated the survey times that were reported. Based on this information, we estimated it takes operators 3.4 hours to complete a survey at a well site, including the travel time to and from the well site. This is based on an average survey time of approximately 1.4 hours. The travel time considers travel between sites and the shared travel of mobilizing a monitoring operator. We applied an hourly rate of $134 based on the Regulatory Analysis performed by the Colorado Department of Public Health and Environment in support of Colorado's Regulation 7. We believe this more accurately reflects the costs of performing the survey than the previously assumed flat rate of $600.
	Low production well sites. The low production well site model plants (i.e., well sites with total production at or below 15 boe per day) were updated after further review of the FW Study, updates to the Greenhouse Gas Inventory (GHGI), and based on comments received. First, the counts of wellheads, separators, meters/piping, and dehydrators were recalculated after removing well sites that listed no production on the day prior to emissions measurements during the FW Study. This resulted in a decrease in the number of separators and meters/piping for the low production gas well pad. The scaling factors were also updated based on these revisions and applied to low production oil well pads and low production associated gas well pads. Further discussion on these changes are in the TSD. Like the well sites discussed above, we maintained the estimate of one controlled storage vessel per low production well site. One commenter provided some preliminary information regarding component counts, specific to valves and storage vessels, but also stated in their comments that the information was not representative. Therefore, as discussed in the TSD, it was not appropriate to revise the model plants using information this commenter provided. We also performed an analysis of the survey time and found that on average, the surveys for low production well sites were approximately 30 minutes. After accounting for travel time, we estimate that each survey of a low production well site takes 2.4 hours. We applied the same hourly rate of $134 to estimate the total cost of each survey.
	Gathering and boosting compressor stations. Information of average equipment counts were provided by GPA Midstream for gathering and boosting compressor stations. We updated the model plant estimate to use this information. Specifically, we revised the estimated number of separators from 11 to 5, meter/piping from 7 to 6, gathering compressors from 5 to 3, in-line heaters from 7 to 1, and dehydrators from 5 to 1, which reduces the baseline emissions estimated for the compressor station. We maintained the cost for the survey of $2,300 because the commenter indicated this was appropriate based on implementation of the rule.
4. Cost-Effectiveness of Fugitive Emissions Requirements
	With the revisions discussed in sections V.B.1 through 3 incorporated in the model plants, we reexamined the costs and emission reductions for various monitoring frequencies to determine the updated costs of control. In evaluating the costs for this final rule, we also reexamined the decisions made in the 2016 NSPS OOOOa for comparison. In the 2016 NSPS OOOOa, we evaluated the controls under different approaches, namely a single pollutant approach and multipollutant approach. Further, we stated that a frequency is considered cost-effective if the cost of control for any one scenario of methane (without consideration of VOC), VOC (without consideration of methane), or the combination of both pollutants is cost-effective. That is, if the cost of control for reducing VOCs, where all costs are attributed to VOC control and zero to methane control, is cost-effective, then that frequency is cost-effective regardless of the methane-only or multipollutant costs.
	In the Review Rule, also finalized today, we are rescinding the methane standards for NSPS OOOOa. Therefore, in this final rule we examined the cost-effectiveness for the control of VOC emissions only. For each frequency evaluated in this final rule, we examined the total cost-effectiveness of each monitoring frequency (i.e., the cost of control for each frequency from a baseline of no monitoring). This is consistent with how costs were examined in the 2016 NSPS OOOOa. For the reason explained in the preamble to the October 15, 2018 proposal, in addition to evaluating the total cost-effectiveness of the different monitoring frequencies, this final rule also considers incremental cost (i.e., the additional cost to achieve the next increment of emission reduction) to be an appropriate tool for assessing the effects of different stringency levels of control costs.  83 FR 52070. It is important to note that the 2016 NSPS OOOOa analysis did not present the incremental costs between each of the monitoring frequencies evaluated. The TSD supporting this final rule presents the cost of control for annual, semiannual, and quarterly monitoring frequencies for well sites producing greater than 15 boe per day and compressor stations, and biennial, annual, and semiannual monitoring frequencies for low production well sites.
	When examining the costs of each monitoring frequency, we recognized that a significant percentage of the costs are independent of the monitoring frequency. That is, when annualized, the recordkeeping and reporting costs remain unchanged as monitoring frequencies increase. For example, the annualized cost of semiannual monitoring is approximately 20 percent higher than the annualized cost of annual monitoring at well sites. However, the cost-effectiveness of the annual monitoring is a higher $/ton reduced because semiannual monitoring results in approximately 50 percent more emissions reductions than annual monitoring. Therefore, while more frequent monitoring does increase the costs of surveys for the year, the bulk of the costs are realized regardless of monitoring frequency. In other words, whereas we assumed during the proposal that reduced monitoring frequencies would lead to large cost savings, the analyses we performed for this final rule demonstrate that monitoring frequency is not the most significant factor in the overall cost of the fugitive emissions requirements. Below we present the costs of control for the monitoring frequencies at the model plants for well sites, low production well sites, and compressor stations.
	Table 3 presents the costs of control for VOC emissions at the monitoring frequencies evaluated in this final rule and compares those costs to the costs presented for the 2016 NSPS OOOOa. With the updates to the model plants discussed in Section V.B.1 through 3 of this preamble, the EPA estimates that the semiannual monitoring currently required by the 2016 NSPS OOOOa for well sites has a cost-effectiveness value of $4,324/ton of VOC emissions reduced. This value is $1,135/ton less than was estimated for semiannual monitoring in 2016, after adjusting for inflation. Therefore, we have determined that semiannual monitoring remains cost-effective for well sites producing greater than 15 boe per day. We also considered the incremental cost-effectiveness of semiannual monitoring compared to annual monitoring. This analysis showed that it cost $2,666/ton of additional VOC emissions reduced between the annual and semiannual monitoring frequencies. This cost is very reasonable and, therefore, further supports retaining semiannual monitoring. Finally, the EPA notes that, while we did not propose or take comment on quarterly monitoring for well sites, this monitoring frequency results in a total cost of control of $4,725/ton of VOC emissions reduced, which is also less than the inflation-adjusted cost-effectiveness value for quarterly monitoring that was calculated in 2016. However, the incremental cost to reduce additional emissions by going from semiannual monitoring to quarterly monitoring is $5,927/ton, which is a value that is higher than the EPA has previously found to be cost-effective in the past.
TABLE 3. Costs of Control for Well Sites Subject to Fugitive Emissions Standards Under Subpart OOOOa of 40 CFR Part 60
Monitoring Frequency
                        Cost-effectiveness ($/ton VOC)

                     2016 TSD Total Cost-effectiveness[1]
                       2020 TSD Total Cost-effectiveness
                    2020 TSD Incremental Cost-effectiveness
Annual
                                    $4,723
                                    $5,153

Semiannual
                                    $5,459
                                    $4,324
                                    $2,666
Quarterly
                                    $7,559
                                    $4,725
                                    $5,927
 1 Values from the 2016 TSD have been adjusted for inflation for comparison purposes.
	As shown in the EPA's revised model plant analysis in the TSD for this final rule, and consistent with the October 15, 2018 proposal, there is sufficient evidence that low production well sites are different than well sites with higher production and, therefore, warrant a separate evaluation of the cost of control. The EPA did not include a separate analysis of low production well sites in the 2016 NSPS OOOOa. Therefore, all costs presented above for well sites from the 2016 analysis also would apply to low production well sites. The EPA proposed biennial monitoring of low production well sites (i.e., well sites with total production less than 15 boe per day). Based on the revised cost analysis, the EPA estimates that the proposed biennial monitoring frequency has a cost-effectiveness of $6,061/ton of VOC emissions reduced. In addition, we estimate that annual monitoring would cost $7,577/ton VOC, and semiannual monitoring currently required by the 2016 NSPS OOOOa has a cost of $6,116/ton of VOC emissions reduced. All of these values are higher than the inflation-adjusted value of $5,459/ton VOC that was estimated for semiannual monitoring at well sites in 2016. Further, all of these costs are higher than a value the EPA has previously stated is not cost-effective.   Therefore, we have determined that none of the monitoring frequencies are cost-effective for low production well sites. Table 4 provides a summary of the costs of control for low production well sites.
TABLE 4. Costs of Control for Low Production Well Sites Subject to Fugitive Emissions Standards Under Subpart OOOOa of 40 CFR Part 60
Monitoring Frequency
                        Cost-effectiveness ($/ton VOC)

                     2016 TSD Total Cost-effectiveness[1]
                       2020 TSD Total Cost-effectiveness
                    2020 TSD Incremental Cost-effectiveness
Biennial
                                    $4,723
                                    $6,061

Annual
                                    $5,459
                                    $7,577
                                    $12,125
Semiannual
                                    $7,559
                                    $6,116
                                    $3,192
 1 Values from the 2016 TSD have been adjusted for inflation for comparison purposes.
	Further, while this final rule does not have to consider the costs of controlling methane emissions, the EPA did evaluate those costs. The costs for all of the monitoring frequencies evaluated for low production well sites are greater than the highest value for methane that the EPA determined to be reasonable in the 2016 NSPS OOOOa for both methane only and under the multipollutant approach. In the 2015 proposal for NSPS OOOOa, the EPA stated that a cost of control of $738 per ton of methane reduced did not appear excessive when all costs are assigned to methane reduction and zero to VOC reduction. 80 FR 56624. Based on the revised analysis, the costs of control of methane emissions under the single pollutant approach for low production well sites are more than double this value of $738 per ton at all of the monitoring frequencies evaluated. This value is also exceeded under a multipollutant approach where methane reduction only assumes half the cost, as explained in the TSD. Therefore, even if had we had not rescinded the methane standards in the Review Rule, we would still conclude that fugitive emissions monitoring, at any of the frequencies evaluated, is not cost-effective for low production well sites.
	While we are concluding that fugitive emissions monitoring is not cost-effective for low production well sites, production at these well sites could potentially increase to greater than 15 boe per day, rendering monitoring to be cost-effective. For example, a new well may be drilled at a well site, or the existing wells may be refractured to increase the production levels. When these actions occur, the final rule requires a new 30-day calculation of the total well site production. If the total production remains at or below 15 boe per day, no monitoring is required as long as the owner or operator continues to maintain the production at these low levels. However, if the total production following one of these actions has increased to greater than 15 boe per day, the owner or operator must begin monitoring for fugitive emissions within 90 days of the startup of production following such action, the same as the requirement for a modified well site. Therefore, under the final rule, low production well sites remain affected facilities; however, they have the option of maintaining production at or below 15 boe per day on a continuous basis instead of implementing the fugitive monitoring requirement.
	There are three timeframes in which we are requiring sources to calculate the total production from the well site. First, there are well sites that have not yet triggered the requirements in NSPS OOOOa, which are those constructed, reconstructed, or modified after this final rule becomes effective. The owner or operator of such a well site has the option to calculate the total well site production based on the first 30 days of production. If the total production from all of the wells at the well site is at or below 15 boe per day (combined for both oil and natural gas produced at the site), then the owner or operator of the well site may either maintain production at or below this threshold on a rolling 12-month average or begin the fugitive emissions program. The owner or operator must comply with one of these two requirements at any and all times. If the total production of the well site is above 15 boe per day as determined in the first 30 days of production, then the site must begin the fugitive emissions program, including completing the initial monitoring within 90 days of startup of production. Recognizing that there are some well sites that have triggered the fugitive emissions requirements that may not have 12-months' worth of production data yet but are already be able to demonstrate they are low production, the final rule contains a provision to allow the owner or operator to use production records based on the first 30 days of production after becoming subject to the NSPS to determine if the well site is low production. This determination must be made by [INSERT DATE 90 DAYS AFTER THE DATE OF PUBLICATION IN THE FEDERAL REGISTER]. After that date, the owner or operator may use the rolling 12-month average, as described next, for demonstrating the well site is low production.
	Next, recognizing that production declines over time, we are also allowing an option for owners or operators subject to the monitoring requirement to determine whether the total production for the well site declines to 15 boe per day or below when calculated on a rolling 12-month average. If the total well site production is at or below this threshold on a rolling 12-month average, then the owner or operator has the option to stop fugitive monitoring and instead maintain total well site production below this threshold. The owner or operator must comply with either the fugitive monitoring requirement or maintain total well site production below this threshold at any and all times.
	Finally, the EPA is aware that a low production well site could later increase production due to subsequent activities, as discussed above. For example, owners or operators commonly take actions to increase production as production declines or continue to drill new wells after the initial startup of production of the well site. If production subsequently increases to greater than 15 boe per day, it would be cost effective to implement the fugitive emissions monitoring requirement. In light of the above, the final rule requires that any well site that is not conducting fugitive emissions monitoring because total well site production is at or below the threshold must redetermine the total well site production following any of the following actions: a new well is drilled, a well is hydraulically fractured or re-fractured, a well is stimulated in any manner for the purpose of increasing production (including well workovers), or a well at the well site is shut-in for the purposes of increasing production from the well site. These well sites must recalculate the total well site production based on the first 30 days of production following the completion of that action. It is inappropriate to continue to utilize a rolling 12-month average because the production in the 11 months prior to the action that increased production would bias the average low. Like well sites constructed, reconstructed, or modified after this final rule, these well sites must recalculate the total well site production based on the first 30 days of production following the completion of that action to increase production.
	We have not calculated the impacts of the production calculation because owners and operators are already required to track production for other purposes, regardless of environmental regulation, and we do not anticipate any additional burden associated with these records for purposes of this rule.
	The final rule also requires quarterly monitoring of gathering and boosting compressor stations.  As with fugitive monitoring of well sites, based on the revised cost analysis in the TSD for the final rule, the EPA reexamined the costs and emission reductions, including incremental cost and emission reductions, for various monitoring frequencies. In the October 15, 2018 proposed rule, the EPA co-proposed annual and semiannual monitoring of fugitive emissions at all compressor stations. As previously discussed, the 2016 NSPS OOOOa requires quarterly monitoring for compressor stations, including gathering and boosting stations, transmission stations, and storage stations. Therefore, the 2016 determination that quarterly monitoring was cost-effective was based on the weighted average of the cost-effectiveness values for all of those station types. In the Review Rule that is separately finalized today, the EPA has removed the transmission and storage segments from the crude oil and natural gas production source category and rescinded the standards for those sources. As a consequence, only gathering and boosting compressor stations remain subject to the standards of NSPS OOOOa.
	After updating the compressor station model plants, the EPA estimates that the quarterly monitoring currently required by the 2016 NSPS OOOOa has a cost-effectiveness of $3,221/ton of VOC emissions reduced at gathering and boosting compressor stations. After adjusting for inflation, this value is $1,785/ton VOC less than we estimated quarterly monitoring would cost for the weighted average of all compressor stations in 2016, and $170/ton VOC less than we estimated for gathering and boosting stations alone in 2016. Therefore, we have determined that quarterly monitoring remains cost-effective for gathering and boosting compressor stations. To further support this conclusion, the EPA also considered the incremental cost-effectiveness of going from semiannual monitoring to quarterly monitoring. This analysis showed that it cost $4,988/ton of additional VOC emissions reduced between the annual and semiannual monitoring frequencies. This cost is also reasonable. Table 5 provides a summary and comparison of these costs.
TABLE 5. Costs of Control for Compressor Stations Subject to Fugitive Emissions Standards Under Subpart OOOOa of 40 CFR Part 60
Monitoring Frequency
                        Cost-effectiveness ($/ton VOC)

                        Gathering and Boosting Stations
                      Compressor Station Weighted-Average

                     2016 TSD Total Cost-effectiveness[1]
                       2020 TSD Total Cost-effectiveness
                    2020 TSD Incremental Cost-effectiveness
                     2016 TSD Total Cost-effectiveness[1]
                       2020 TSD Total Cost-effectiveness
                    2020 TSD Incremental Cost-effectiveness
Annual
                                    $2,105
                                    $2,698

                                    $3,278
                                    $3,606

Semiannual
                                    $2,443
                                    $2,632
                                    $2,501
                                    $3,682
                                    $3,341
                                    $2,811
Quarterly
                                    $3,391
                                    $3,221
                                    $4,988
                                    $5,006
                                    $3,908
                                    $5,607
 1 Values from the 2016 TSD have been adjusted for inflation for comparison purposes.
C. AMEL
	The 2016 NSPS OOOOa contains provisions for requesting an AMEL for specific work practice standards covering well completions, reciprocating compressors, and the collection of fugitive emissions components at well sites and compressor stations. While written with emerging technologies as the focus, the provisions in the 2016 NSPS OOOOa could also be used for state programs, though the application requirements were unclear on certain points. Therefore, the EPA proposed amendments to the application requirements as they relate to emerging technologies in order to streamline the application process, and proposed a new section to address state programs, including proposed alternative fugitive emissions standards based on our review of existing state programs. This section describes changes, based on information provided in public comments, to the AMEL provisions.
1. Emerging Technologies
	The EPA continues to recognize that new technologies are expected to enter the market soon that could locate sources of fugitive emissions sooner and at lower costs than the current technologies required by the 2016 NSPS OOOOa. While the EPA established a foundation for approving the use of these emerging technologies in the 2016 NSPS OOOOa, we proposed specific revisions in the October 15, 2018 proposal to help streamline the application requirements and process. Specifically, we proposed to allow owners and operators to apply for an AMEL on their own, or in conjunction with manufacturers or vendors and trade associations. We also proposed to allow the use of test data, modeling analyses, and other documentation to support field test data, provided seasonal variations are accounted for in the analyses. While we received many supportive comments on these specific proposed amendments, we also received comments asserting that the application process is too still restrictive and burdensome to promote innovation.
	First, the commenters stated that applications seeking approval of an alternative should be accepted by the EPA from manufacturers and vendors independently of owners and operators. We have reviewed the information provided by the commenters and agree that it is appropriate in the context of the revisions to 40 CFR 60.5398a to remove language that previously indicated from whom the Administrator would consider applications under that section because Section 111(h)(3) of the CAA states "any person" can request an AMEL, and if they establish to the satisfaction of the Administrator that the AMEL will achieve emission reductions that are at least equivalent with the requirements of the rule then the Administrator will allow the alternative. While the final rule allows any person to submit an application for an AMEL under this provision, the final rule still includes the minimum information that must be included in each application in order for the EPA to make a determination of equivalency and thus be able to approve an alternative. This final rule requires applications for these AMEL to include site-specific information to demonstrate equivalent emissions reductions, as well as site-specific procedures for ensuring continuous compliance.
	Next, the commenters generally supported the proposal to allow the use of test data, modeling analyses, and other documentation to support field test data. In addition to their support of these supplemental data, commenters also requested that the final rule allow the use of information collected during testing at controlled testing facilities to be considered in lieu of site-specific field testing. The EPA considered whether it would be appropriate to allow this information and has concerns related to the representativeness of the information when compared to actual operating sites. For example, we are aware of one controlled testing facility located in the U.S., the Methane Emissions Technology Evaluation Center (METEC) located in Fort Collins, Colorado. That facility is equipped with several different configurations of well pads using equipment that was donated from the oil and natural gas industry. The test well pads do not produce or process field gas; in fact, none of the equipment that is onsite is in contact with field gas. Instead, METEC utilizes compressed natural gas that is transported from offsite in order to create controlled leaks. In establishing controlled leaks, METEC uses tubing with leak points near typical leak interfaces to simulate a leak; however, these releases are not operated at pressures or temperatures that are typically encountered at an operating well site in the field. While we agree that testing at a controlled testing facility such as the METEC site can be helpful to understanding how a technology may perform, and the information gathered from such controlled test sites can be useful in supplementing other data, it is inappropriate to rely solely on the information collected at these types of facilities as being representative of how the technology would perform at an operating well site or compressor station. At this time, the EPA does not believe that it can determine the efficacy of a monitoring or detection technology where demonstrations take place only under controlled conditions. By extension, the EPA would be unable to determine the validity of whether an alternative indeed achieves equivalent emissions reductions if only presented with data from testing at a controlled testing facility. Therefore, we are finalizing amendments that require field test data, but that allow the use of test data, modeling analyses, data collected at controlled testing facilities, and other documentation to support and supplement field test data.
	Next, we solicited comment on whether groups of sites within a specific area that are operated by the same operator could be grouped under a single AMEL. We received comments that discussed this broad application of alternatives in two distinct ways: (1) allowing the aggregation of emission sources beyond the individual site in order to demonstrate equivalent emission reductions, and (2) allowing the use of approved AMELs at future sites that are designed and operated under the conditions specified in the approved AMEL. We evaluated both types of broad approval options raised in the comments by considering the definitions in the existing rule and the AMEL provisions of section 111(h)(3) of the CAA.
	In the first instance, we evaluated whether it would be appropriate to allow the aggregation of emission sources beyond the individual site when evaluating the equivalency of an alternative. Specifically, we considered whether an applicant for an AMEL related to fugitive emissions monitoring could aggregate the total fugitive emissions across multiple sites within a specific geographic area, such as a basin, in order to demonstrate the requested AMEL would achieve at least equivalent emission reductions as the NSPS requirements for fugitive emissions monitoring and repair at an individual site. The work practice standards for the collection of fugitive emissions components at a well site or at a compressor station were established pursuant to section 111(h) of the CAA, which allows an opportunity for an AMEL. In accordance with section 111(h)(3) of the CAA, a source may use an approved AMEL for purposes of compliance with the established work practice. The commenters stated that the generic use of the word "source" allows aggregation of fugitive emissions components amongst multiple sites and is not limited to single sites. The EPA does not agree that aggregating fugitive emissions across multiple sites is a viable method to determine equivalency with the NSPS provided the definitions of affected facility in NSPS OOOOa related to the collection of fugitive emissions components. NSPS OOOOa defines the "source" that is subject to the work practice standards for fugitive emissions as the "collection of fugitive emissions components at a well site" and the "collection of fugitive emissions components at a compressor station" in 40 CFR 60.5365a(i) and (j). These terms specify single-site applicability for the work practice standard. Because the rule does not define an affected facility or a source to be a geographic area, such as a basin, it is the EPA's determination that a demonstration of equivalent emission reductions for purposes of evaluating alternatives to the BSER ought to be based on the fugitive emissions at a single site, and not an aggregation of emissions across multiple well sites, compressor stations, or a combination of these two site types with an averaging or trading program akin to what the EPA has referred to in the past as a "bubble" approach. For further discussion on this topic, see Section VI.C.2 of this preamble.
	The second point raised by commenters was that requiring site-specific approvals (i.e., AMELs that list specific well sites or compressor stations) would result in unnecessary burden as new sites with the same owner or operator, similar equipment, operating conditions, and in the same geographic area (e.g., basin) are constructed. According to commenters, this unnecessary burden results from the need for the owner or operator to apply for an AMEL for each of these sites in the future, even though the AMEL would be identical to the previously approved AMELs for similar sites. We agree with the commenters that it is possible that AMELs could, where appropriate, be approved for future use at sites not included in the original application as discussed below.
	While the EPA is not amending 40 CFR 60.5398a at this time to address broad approvals of AMEL applications, we do recognize that the Agency has discretion in certain circumstances to allow for broad approval of alternatives via several different paths. First, for example, an applicant could submit an AMEL application for an alternative technology (and associated work practice) that includes specific site characteristics under which the technology (and associated work practice) has been tested and that demonstrates equivalent reductions to the standards in the NSPS. The application would include an explanation of these characteristics (e.g., characteristics of the formation, operating conditions at the site, type of equipment and processes located at the site, and variables that affect performance of the technology or work practice) and a request that the EPA consider broad approval of the application such that sites (including those subject to the NSPS at the time of application and future sites) that meet the same characteristics could utilize the same approved alternative without the need for additional application to the EPA. The scope of such an approval might be limited based on any number of conditions as appropriate (such as those mentioned above). The EPA believes that, depending on the facts of the application, some type of broad approval may be a feasible path forward, but we will need to evaluate the information specific to the application in hand once received. As of the date of this final rule, the EPA has received no applications for AMELs to be able to determine if additional amendments (beyond those in this final rule) are necessary for such a situation, and how such potential amendments might be drafted to facilitate such broad approvals. In summary, if the applicant believes that it is appropriate to apply the alternative to more sites than those listed in the application because the proposed alternative can achieve equivalency for other sites, then the applicant should state this intent and make this demonstration to the EPA within the application. If provided with sufficient information, explanation, justification, and documentation, the EPA may determine under what defined conditions, if any, it is appropriate to allow the use of the alternative once approved at any site meeting those conditions, including sites constructed in the future.
	Second, the EPA might be able to develop a framework in the future for AMEL requests that share similar characteristics (e.g., technologies) in order to streamline both applications and approvals. While the EPA has not received applications related to the work practice standards in the 2016 NSPS OOOOa, we have evaluated and approved AMELs for other sources in a few instances for one specific control technology, pressure assisted multi-point flares (for further information, see the EPA rulemaking Docket ID No. EPA-HQ-OAR-2014-0783). In the course of reviewing those applications, the EPA was able to establish testing criteria for this particular control technology to demonstrate equivalency with the underlying operational standards (i.e., 98 percent control efficiency) as well as other certain design, equipment, and work practice standards, which if met would help streamline approval of applications submitted after that point. We are open to the development of testing criteria for technologies and work practices for NSPS OOOOa, however, due to the variability of this sector, as well as the wide-ranging array of technologies currently being pursued for development, we are unable to amend the language within this rule and provide such a framework at this time. For the pressure assisted multi-point flares, the EPA developed the testing framework in conjunction with an application and with stakeholder feedback from the first AMEL requests received and approved for that particular technology. We have not reached that critical first step of an application being submitted to the EPA to determine what testing framework might be appropriate, or how that framework might be technology family-specific (e.g., continuous point monitors, aerial surveys, mobile equipment) While we are not able to establish criteria through this rule, we encourage interested stakeholders to continue engaging with us early in any application process so additional streamlining measures can be evaluated.
	Third, if an applicant can demonstrate that a technology has very broad applicability across the entire industry, then, in addition to exploring the possibility of an AMEL, the EPA also would consider whether to undertake a rulemaking process to amend NSPS OOOOa to allow for widespread use of the technology. As always, the EPA will review each application individually to determine if it has demonstrated that the alternative will achieve equivalent or greater emission reductions than the work practice standard the alternative would replace.
	In summary, we are finalizing amendments to the application requirements for an AMEL in 40 CFR 60.5398a. We are allowing applications from any person. Further, we are allowing the use of supplemental data, such as test data, data collected at controlled testing facilities, modeling analyses, and other relevant documentation, to support field data that are collected to demonstrate the emissions reductions achieved. While we are not amending the rule to specifically state an approved AMEL can be used for future sources, we recognize that it may be possible, where appropriate, for the EPA to establish specific conditions during the AMEL process under which an approved alternative may be applied at sites not specifically listed in the application.
2. State Fugitive Emissions Programs
	To reduce duplicative burdens to the industry related to the fugitive emissions requirements, the EPA proposed alternative fugitive emissions standards for well sites and compressor stations located in specific states. These alternative standards were proposed based on the EPA's review of the monitoring and repair requirements of the individual state fugitive emissions requirements relevant to well sites and compressor stations. In the proposal, we stated that a well site or compressor station, located in the specified state, could elect to comply with the specified state program as an alternative to the monitoring, repair, and recordkeeping requirements in the NSPS. However, these sites would be required to monitor all fugitive emissions components, as defined in the NSPS, comply with the requirement to develop a monitoring plan, and report the information required by the NSPS because the sites remain affected facilities.
      Similar to the proposed amendments for emerging technologies, we received support for the proposed amendments for state programs. However, some commenters stated that the EPA should recognize the approved state programs as wholly equivalent to the NSPS, including for all reporting and recordkeeping requirements. The commenters indicated that the EPA's equivalency determination still leaves the regulated community in certain states subject to duplicative requirements. They added that complying with two different reporting and recordkeeping schemes for the same site is very burdensome and provided no environmental benefit.
	For the proposal, we evaluated 14 existing state programs to determine whether they are equivalent to the fugitive emissions requirements in 40 CFR 60.5397a. That evaluation included a qualitative comparison of the fugitive emissions components covered by the state programs, monitoring instruments, leak or fugitive emissions definitions, monitoring frequencies, repair requirements, and recordkeeping requirements to the requirements of the NSPS. However, at the time of the proposal, the EPA had not evaluated the reporting requirements of the 14 individual state programs. We have completed that evaluation for this final rule for the state programs that we proposed as alternative standards and the results of that evaluation are discussed in more detail in Section VI.C.2 of this preamble. We also updated the overall analysis of equivalency. Through this additional evaluation, we concluded that the recordkeeping and reporting requirements of the various state programs do not need to be exactly equivalent to the requirements of the NSPS OOOOa because the purpose of recordkeeping and reporting requirements is to ensure compliance with whatever standards apply. Obviously, the state programs we evaluated are not identical to the NSPS, so it stands to reason that their associated recordkeeping and reporting requirements might differ. Therefore, when evaluating the recordkeeping and reporting requirements in the individual state programs, we focused our review on the elements of those requirements that we deemed essential to a demonstration of compliance with the individual alternative standards. Sites remain subject to the NSPS, because the alternative standards are standards within the NSPS, therefore compliance demonstrations are necessary through recordkeeping and reporting.
	At a minimum, the EPA requires reports to include information that allows a demonstration of compliance for all fugitive emissions components (as defined in 40 CFR 60.5430a) at the individual site level (i.e., well site or compressor station). This means the report must provide information on each individual monitoring survey conducted at each well site or compressor station adopting the alternative fugitive emissions standards. We reviewed the reports required under state law for the six states for which we are finalizing alternative fugitive emissions standards (i.e., California, Colorado, Ohio, Pennsylvania, Texas, and Utah) to determine (1) if site-level information is required in the reports and (2) if the information reported demonstrates compliance through inclusion of elements such as the date of the survey, monitoring instrument used, information for each identified fugitive emission, repair information, and delayed repair information. For three of the six states (California, Ohio, and Pennsylvania) where we are finalizing alternative standards, the required state reports are site-specific and include information that will demonstrate compliance with the alternative standards. For the other three states (Colorado, Texas, and Utah), site-specific reporting is not required, or will not demonstrate compliance with the alternative standards. Therefore, the sites adopting the alternative standards for Colorado, Texas, and Utah, would need to provide the site-specific reports required in 40 CFR 60.5420a(b)(7). As discussed in detail in section V.B.2 of this preamble, the EPA is amending the recordkeeping and reporting requirements related to the fugitive emissions requirements. The result of these amendments is an annualized burden reduction of approximately 27% for well sites and 30% for gathering and boosting compressor stations, and those same burden reductions will be realized by sites in these three states.
      For the three states that do not require site-specific reporting, we reviewed the state's recordkeeping requirements to determine if any additional records would be necessary for reporting the required information under the NSPS. We found that for each of the three states, the records are very similar to, if not the same as, the information required under the NSPS. Given that additional records beyond those required by the state are not necessary, the EPA concludes that there is no duplicative recordkeeping burden associated with compliance with these alternative standards. This, in addition to the significant reduction in reporting burden discussed in section V.B.2 of this preamble, allows the EPA to conclude the submission of the reports required in 40 CFR 60.5420a(b)(7) presents minimal burden for sites in Colorado, Texas, and Utah.
      Therefore, to summarize, the final rule requires reporting of information to demonstrate site-level compliance with the alternative fugitive emissions standards as follows:
       Where the state report includes site-specific information for each fugitive emissions survey that demonstrates compliance with the alternative standard, the owner or operator has the option to either (a) provide the EPA with a copy of the state report, in the format in which is it submitted to the state, based on the following order of preference: (1) as a binary file; (2) as a XML schema; (3) as a searchable PDF; or (4) as a scanned PDF of a hard copy, or (b) provide the report required by 40 CFR 60.5420a(b)(7)(i) and (ii) to the EPA in accordance with the applicable reporting procedures.
       Where the state report does not include site-specific information for each fugitive emissions survey, the owner or operator must report the information required by 40 CFR 60.5420a(b)(7)(i) and (ii) to the EPA in accordance with the procedures applicable to such a submission.
      Any owner or operator has the option to complete the information required by 40 CFR 60.5420a(b)(7) in lieu of submitting a copy of the state report. As described in Section IV.I of this preamble, electronic reporting through CEDRI is now required for all reports under 40 CFR 60.5420a(b). Thus, the EPA is requiring electronic submission of reports for the alternative fugitive emissions requirements, regardless of whether the state continues to allow paper copy submissions.
      The EPA believes that adoption of these alternative standards will further reduce the burden of the fugitive emissions standards on the industry from this rule. No additional recordkeeping beyond that required by the alternative standard is necessary. Additional justification for the EPA's decision to adopt these state programs as alternative fugitive emission standards is provided in the memorandum summarizing the EPA's review of each state program's requirements and in Section VI of this preamble.
	We note that one commenter expressed concern over the proposed state equivalency determinations and noted that several of the programs evaluated have specific applicability thresholds where the standards only apply to a subset of sources, whereas the NSPS applies to all new, modified, or reconstructed sources. We agree that the applicability thresholds for these state programs are different from the NSPS, but we do not agree that additional regulatory text is necessary to address this concern. The regulatory thresholds included in state programs that limit or reduce monitoring and repair requirements do not affect the requirements for sources subject to the NSPS. Therefore, if a site subject to the NSPS is not also subject to the state program because of the state-specific applicability threshold, the site would still be required to comply with the requirements of the NSPS. Where appropriate, we have amended the regulatory text to clearly define the requirements of the alternative standard. More discussion of this comment and our response is provided in Section VI.C.2 of this preamble.
VI. Summary of Significant Comments and Responses
	This section summarizes the significant comments on the proposed amendments and our responses to those comments. Additional comments and responses are summarized in the Response to Comments (RTC) document available in the docket.
A. Major Comments Concerning Storage Vessels
      The EPA received numerous comments on the proposed amendments to the definition of "maximum average daily throughput," which is key in the determination of storage vessel affected facility status under the 2016 NSPS OOOOa. Many of the comments we received were related to manifolded storage vessel systems. The EPA considered those comments and is finalizing changes to the rule to address a subset of these manifolded storage vessel systems (i.e., controlled storage vessel batteries as described in section V.A of this preamble). A more detailed summary of the comments regarding controlled storage vessel batteries, and our responses to those comments, is available in the RTC document for this action (see Chapter 6).
      In addition to the comments the EPA received on controlled storage vessel batteries, we also received other comments related to storage vessel applicability determination criteria. Below is a discussion related to three of these topics: (1) the use of legally and practicably enforceable limits that maintain VOC emissions from storage vessels below 6 tpy, (2) the calculation of maximum average daily throughput based only on the days of actual production in the first 30 days, and (3) the determination of maximum average daily throughput for storage vessels at gathering and boosting compressor stations, onshore natural gas processing plants, and transmission and storage compressor stations.
	Comment: Some commenters stated that the EPA proposed additional parameters on what constitutes a "legally and practicably enforceable" limit; and, therefore, heightened the standard for allowing use of such limit in estimating a storage vessel's potential VOC emissions for purposes of determining applicability of the storage vessel standards at 40 CFR 60.5395a. Specifically, the commenters took issue with the statement in the preamble to the October 15, 2018 proposed rule where the EPA stated "only limits that meet certain enforceability criteria may be used to restrict a source's potential to emit, and the permit or requirement must include sufficient compliance assurance terms and conditions such that the source cannot lawfully exceed the limit." 83 FR 52085. One commenter claimed that these additional criteria (1) conflict with prior EPA statements made during earlier oil and gas NSPS rulemakings; (2) conflict with the EPA's traditional practice of deferring to states regarding the appropriate mechanisms for limiting potential to emit (PTE); (3) raise concerns about how this new interpretation/approach would apply in the Title V and New Source Review ("NSR")/Prevention of Significant Deterioration ("PSD") context where operators are relying on the same control requirements to limit their PTE; (4) raise significant concerns about retroactive application; and (5) ignore that the requirements for fugitive components under the 2016 NSPS OOOOa are not tied to storage tank applicability and apply regardless of whether a storage tank is an affected facility under the rule.
	Commenters also cited the EPA's "enforceability criteria" guidance, which was first introduced in 1995, and asserted that the EPA's proposed additional criteria were not consistent with that guidance. One commenter was concerned that the EPA's proposal not only conflicted with the Agency's traditional and consistent practice, it also threatened to subject sources to the NSPS that already determined their potential for VOC emissions was below the 6 tpy threshold by using the EPA's prior guidance.
	Response: The EPA disagrees with the commenters because we did not propose additional parameters on what would constitute a legally and practicably enforceable limit. Rather, in the proposal preamble, the EPA simply summarized its position on this matter based on the existing substantial body of EPA guidance and administrative decisions relating to potential emissions and emissions limits. As the EPA explained, limits that meet certain enforceability criteria may be used to restrict a source's potential emissions. For example, any such emission limit must be enforceable as a practical matter, which requires that the permit or requirement specifies how emissions will be measured or determined for purposes of demonstrating compliance with the limit. The permit or requirement must also include sufficient terms and conditions such that the source cannot lawfully exceed the limit (e.g., monitoring, recordkeeping, and reporting). For additional information and a summary of the EPA's position on establishing legally and practicably enforceable limits on potential emissions, including examples of "enforceability criteria," see In the Matter of Yuhuang Chemical Inc. Methanol Plant St. James Parish, Louisiana, Order on Petition No. VI-2015-03 (August 31, 2016) at 13-15.
      Comment: Under the 2016 NSPS OOOOa, the applicability of the storage vessel standards is based on a single storage vessel's potential for VOC emissions, which is calculated using the storage vessel's "maximum average daily throughput." While "maximum average daily throughput" is defined in 40 CFR 60.5430a of the 2016 NSPS OOOOa, several stakeholders indicated that clarification of this definition was needed. As a result, the EPA proposed a revised definition. 83 FR 52106. The EPA received several comments related to the proposed definition, which requires that "production to a single storage vessel must be averaged over the number of days production was actually sent to that storage vessel." Most of the commenters objected to this proposed definition, claiming that it would be more appropriate to average over the entire 30-day evaluation period rather than only those days when production was sent to the storage vessel. With regard to tank batteries, one commenter asserted that the proposed definition would not result in an accurate estimate of the potential emissions from individual storage vessels because it would overestimate the total amount of production that each tank could receive over the 30-day evaluation period. Further, the commenter stated that the proposed definition would significantly overestimate the volume of flow to the tank battery as a whole when compounded across multiple tanks and extrapolated across an entire year. Multiple commenters also generally stated that the EPA's proposed definition failed to account for the fact that maximum well production has a limit based on what the wells can produce. However, the EPA did receive one comment that agreed with the proposed definition and that owners and operators should not be able to include days where the storage vessel does not receive production when determining storage vessel applicability.
      Response: The EPA disagrees with the comments suggesting that "maximum average daily throughput" should be determined by averaging across the full 30-day evaluation period instead of the days when production is actually sent to an individual storage vessel during that period. As stated in the proposal, the maximum average daily throughput "was intended to represent the maximum of the average daily production rates in the first 30-day period to each individual storage vessel," 83 FR 52084, which is not the same as an average daily production rate based on averaging total production across a full 30-day period. As explained further in the proposal, in all possible scenarios for determining the daily production, only the number of days in which production is sent to the individual storage vessel is used for averaging, which may be less than the full 30 days in the evaluation period. Indeed, including days where no production was received would reduce the maximum average daily throughput to an individual storage vessel under any of the scenarios described in the proposal. 83 FR 52084. The commenters did not explain how averaging actual throughput to a storage vessel across the full 30 days would accurately reflect the "maximum average daily production rates," therefore we do not agree with the commenters' suggestion to use this value for the purpose of determining a storage vessel's potential for VOC emissions.
      The EPA also disagrees with comments suggesting that the EPA's proposed definition would overestimate the potential for VOC emissions for individual storage vessels in a tank battery by failing to account for the overall production to the tank battery during the 30-day period. In addition to the definition of "maximum average daily throughput" which provided for two operational scenarios, the EPA further explained in the proposal how to determine the daily or average daily throughput, from which the maximum average daily throughput is determined, depending on how throughput is measured. 83 FR 52084. The EPA's proposed definition is based on either the daily (i.e., directly measured via automated level gauging or daily manual gauging) or average daily (i.e., manual gauging at the start and end of loadouts which occur over more than one day) throughput routed to a storage vessel while receiving production; the fact that the storage vessel is receiving that amount daily clearly indicates that it has the potential to do so. The total throughput to the entire tank battery during the 30-day period is not germane to this determination. Because there are likely multiple daily throughput or average daily throughput values for an individual storage vessel during the 30-day evaluation period, the maximum of those values is used to calculate the potential for VOC emissions, thus the use of the term "maximum average daily throughput".
      While the EPA is finalizing the definition of "maximum average daily throughput" as proposed, we note that the final rule provides other mechanisms for determining a storage vessel's applicability without having to calculate the maximum average daily throughput. Specifically, the final rule allows owners and operators of controlled tank batteries meeting specified criteria to average VOC emissions across the number of storage vessels in the tank battery to determine applicability for the individual storage vessels in the battery. Also, as provided in the 2016 NSPS OOOOa, and unchanged by this final rule, if a facility has a legally and practicably enforceable limit that restricts production to an individual storage vessel, then it is acceptable to use this restricted production level as the maximum average daily throughput for that individual storage vessel.
	Comment: Commenters stated that the methods for determining the potential for VOC emissions from storage vessels in the 2016 NSPS OOOOa were not appropriate for storage vessels located at compressor stations (including gathering and boosting compressor stations) and onshore natural gas processing plants, and they indicated that the proposed revisions to 40 CFR 60.5365a(e) and the definition of maximum average daily throughput did not alleviate this problem. More specifically, commenters noted that the 2016 NSPS OOOOa is clear that storage vessels at well sites must determine the potential for VOC emissions based on the maximum average daily throughput based on the first 30 days that liquids are sent to the storage vessel. The commenter noted that storage vessels at compressor stations and onshore natural gas processing plants are designed to receive liquids from multiple well sites that may startup production over a longer period of time. Because these storage vessels may not experience the same peak in throughput to the storage vessels during the first 30-days of receiving liquids as storage vessels at well sites, the commenter indicated that owners or operators may underestimate the potential emissions using the throughput for the first 30 days. Therefore, commenters requested that the EPA clarify the appropriate time period for calculating the maximum average daily throughput for storage vessels at facilities located downstream of well sites. Alternatively, commenters suggested that storage vessels at gathering and boosting compressor stations be allowed to use generally accepted engineering models that project future throughput. The commenters explained that compressor stations (including gathering and boosting compressor stations) and onshore natural gas processing plants typically utilize process simulations based on representative or actual liquid analysis to determine potential VOC emissions and volumetric condensate rates from the storage vessels based on the maximum gas throughput capacity of each facility. These generally accepted engineering models and calculation methodologies are then utilized to obtain federal, state, local, or tribal authority issued permits to set legally and practicably enforceable limits to maintain potential VOC emissions from storage vessels at less than 6 tpy. The commenter requested that the EPA allow use of these generally accepted models and calculation methodologies to project future maximum throughput volumes.
	Response: The EPA agrees with these commenters that potential VOC emissions from storage vessels at facilities downstream of well sites should not be determined based on the first 30 days that liquids are sent to those storage vessels as they are unlikely to experience the same peak in throughput during that period as storage vessels at well sites. It is the EPA's understanding, based on the information provided by the commenters and subsequent conversations, that these midstream and downstream storage vessels may continue to see an increase in throughput as additional upstream well sites begin sending fluids to these compressor stations and onshore natural gas processing plants. Based on the EPA's review and understanding of the generally accepted engineering models for projecting future throughput to a storage vessel, the EPA agrees that these engineering models are appropriate for projecting the maximum throughput for purposes of calculating the potential for VOC emissions from storage vessels located downstream of well sites.
	Based on the above reasons, the EPA is amending the 2016 NSPS OOOOa to specifically provide the following two options for determining the potential for VOC emissions from storage vessels at facilities downstream of well sites. The first option, which is already allowed in the 2016 NSPS OOOOa, allows owners or operators to take into account throughput and/or emission limits incorporated as legally and practicably enforceable limits in a permit or other requirement established under a federal, state, local, or tribal authority. The second option allows the use of generally accepted engineering models (e.g., volumetric condensate rates from the storage vessels based on the maximum gas throughput capacity of each producing facility) to project the maximum throughput used to calculate the potential for VOC emissions.
B. Major Comments Concerning Fugitive Emissions at Well Sites and Compressor Stations
      In Section V.B, we discuss the significant changes from the proposal to this final rule related to the fugitive emissions requirements for well sites and compressor stations. The discussions in Section V.B include a summary of the major comments and our responses related to those changes. Specifically, Section V.B discusses the following topics: (1) the three areas of uncertainty potentially affecting the cost-effectiveness analysis that were identified in the October 15, 2018 proposal; (2) recordkeeping, reporting, and other administrative burden from the fugitive emissions requirements; (3) other updates to the model plants; and (4) cost-effectiveness of fugitive emissions requirements. We also discuss our re-evaluation of BSER after consideration of all these topics.
      In addition to the topics discussed in Section V.B, the EPA received comments on other aspects related to the fugitive emissions requirements. This section provides a discussion of comments and our responses regarding the following three topics: (1) the EPA's model plant analysis for low production well sites; (2) the effect of system pressure on fugitive emissions at low production well sites; and (3) monitoring of compressors at compressor stations when operating and not in standby mode. More detailed summaries and additional comments on the fugitive emissions requirements are included in Chapter 8 of the RTC document included in the rulemaking docket for this action.
	Comment: The EPA created model plants representing low production well sites for purposes of analyzing the emissions and costs of a fugitive emissions monitoring and repair program at these types of well sites. In the proposal, we also acknowledged that operating pressures and production volumes are factors that can cause changes in the fugitive emissions at a well site. 83 FR 52067. However, the EPA was unable to incorporate these factors into the emission estimates in the model plants, and therefore, developed model plants that relied on equipment and component counts to analyze fugitive emissions from low production well sites.
	Some industry commenters disagreed with the use of model plants that rely on component counts alone to estimate fugitive emissions from low production wells due to differences in the type and size of equipment and operating conditions (e.g., operating pressure) at low production well sites. The commenters did agree that it is reasonable to associate the number of components to the potential for leaks. However, the commenters continued to maintain that emissions from low production wells are inherently different from large production wells because of the basic physics of production and how operators change the physical equipment as production warrants. Commenters indicated that the fugitive emissions factors used by the EPA, which were developed for generally predicting emission levels, account for different types of fugitive emission components, but do not factor in the amount of production or line pressure.
      Response: As stated in the proposal, the EPA continues to recognize that variations in equipment, operating conditions, and geological aspects across the country at low production well sites may affect fugitive emissions from low production well sites. As described in Section V.B, we have made updates to the low production well site model plants and re-evaluated the emissions and costs of fugitive emissions monitoring and repair requirements at low production well sites. Based on this updated analysis, the EPA concludes that fugitive emissions monitoring and repair is not cost-effective at any monitoring frequency for low production well sites. See Section V.B for additional discussion.
      Comment: The EPA received additional comments and data related to the low production well site model plants developed and analyzed for the proposal. One commenter conducted a brief survey of its member companies' gas well site operations in 13 states and provided low production well site component counts. This commenter pointed out that the majority of emissions (around 80 percent) from the low production well site model plants are from valves and storage vessel thief hatches. Therefore, the commenter only provided counts of these components, along with the number of wellheads. This commenter explained that the data show fewer wellheads and valves than assumed in the proposal model plant for low production gas well sites. The commenter stated that it did not consider the data to be fully representative of low production well sites nationwide; nevertheless, relying on the difference in component counts, the commenter claimed that the EPA overestimated the fugitive emissions in the low production model plants used for the proposal.
      Response: While the commenter specifically stated that it did not consider the data to be fully representative of low production well sites nationwide, we reviewed the information and compared it to the low production well site model plants used for the proposal analysis. Specifically, we compared the weighted-average component counts of the information provided by the commenter to the EPA's low production well site model plant. The information provided by the commenter showed that the weighted-average number of storage vessels was approximately the same as that used in the EPA model plant, the number of well heads was half (1 versus 2 in the EPA model plant), and the number of valves was just under 25 percent (23 versus 100 in the EPA model plant). If the model plant was modified with these adjusted component counts, the overall difference in emissions would be just over 50 percent.
      After consideration of this information, the EPA concluded it provides an insufficient basis to revise the low production well site model plant component counts because the information was limited to valves, connectors, and storage vessels at a sample of sites the commenter admitted were not fully representative of low production well sites. However, as discussed above in Section V.B, we did conduct further review of the data originally used to develop the model plant parameters, as well as GHGI data. That review resulted in a 35% decrease in the number of valves for the low production gas well site model plant, as well as decreases in the numbers of the other components. More detailed information on our analysis of the component count information submitted by commenters is contained in a technical memorandum. As shown in the revised model plant analysis, a fugitive emissions monitoring program is not cost-effective for low production well sites at any of the frequencies analyzed.
      Comment: The EPA proposed defining low production well sites as sites where the average combined oil and natural gas production for the wells at the site is less than 15 boe per day averaged over the first 30 days of production. 83 FR 52093. Several commenters recommended changing the definition of a low production well site to be based on the U.S. Tax Code definition of stripper wells. These commenters also recommended using 12 months of production to determine if a site is low production because most well sites newly affected by NSPS OOOOa will not meet the definition based on the first 30 days of production and because production declines over time such that eventually all well sites become low production..
      Response: The EPA has not adopted the stripper well definition for purposes of determining if a well site is low production in this action because the U.S. Tax Code definition applies to individual wells, not well sites. The fugitive emissions standards apply to the collection of fugitive emissions components located at a well site. Adoption of the stripper well definition could result in a scenario where one well at the site is considered low production but the other wells are not, which is inconsistent with the affected facility definition for fugitive emissions components, where the entire site is treated as one unit. Therefore, the calculation of production for purposes of determining if the well site is low production is based on the total well site production and not the individual well production averaged across the number of wells at the well site.
      However, the EPA does agree with the commenters that determination of low production status based solely on the first 30 days of production does not account for decline in production over time. Therefore, the final rule specifies that a low production well site is a well site with total well site production of oil and natural gas at or below 15 boe per day. This calculation can be based on the first 30 days of production for determining initial applicability to the rule and based on a rolling 12-month average to account for production decline. See section V.B for additional discussion.
      Comment: Commenters urged the EPA to use the Department of Energy (DOE) research program announced on October 23, 2018, to determine more accurate assessments of low production well emissions. The commenters asserted that the DOE study provides the EPA the opportunity to collect direct emissions data on fugitive emissions at low production well sites. The commenters concluded that these data would provide the EPA with a baseline that shows the distinctions between large wells and low production wells and the differences that may exist between types of wells and between production regions.
      Response: The EPA is regularly updated on the DOE program and provides technical input on many projects. However, data from the DOE-funded study on low production wells are not currently available. The conclusions made in this final rule are based on currently available information, which includes many data sources that cover low production wells, such as DrillingInfo, GHGRP, and other emission measurement studies. As discussed in this section and in Section V.B, the EPA agrees that existing information shows that low production well sites may have lower emissions than well sites with higher production. As such, the final rule has separate requirements for well sites with total production at or below 15 boe per day, instead of the required fugitive emissions monitoring program (including semiannual monitoring) for well sites above this production threshold.
      Comment: In addition to co-proposing annual monitoring of fugitive emissions components located at a compressor station, the EPA proposed a requirement that each compressor at the station must be monitored at least once per calendar year when it is operating. The EPA also solicited comment regarding the effect the compressor operating mode has on fugitive emissions and the proposal to require at least one monitoring a year during times that are representative of operating conditions for the compressor station.
      Several industry commenters opposed the EPA's proposal to require that each compressor be monitored while in operation (i.e., not in stand‐by mode), because if the station is subject to annual monitoring (which was co-proposed), this requirement would result in a requirement for every compressor to be operating during the monitoring survey, even if all of the compressors are not needed at that time to move gas downstream. The commenters believed that the result of this requirement would be the generation of emissions from compressor blowdowns following the monitoring survey in order to return the compressors to the operating modes they were in prior to the survey. The requirement would also create unnecessary recordkeeping and scheduling complexity/burden, according to commenters. Requiring equipment to be monitored in a specific mode of operation, especially at less frequent monitoring than quarterly, would increase overall emissions if that equipment must change its operational status solely to fulfill that requirement. These commenters recommended that the EPA allow operators to conduct surveys with facility operations as they are found when the survey is conducted.
      However, another commenter stated that its data suggests that it is important to conduct monitoring on fully operating compressors to maximize the number of leaks detected. The commenter stated that beyond these data, it is also simply common sense that as the ratio of pressurized to depressurized components increases, so will the number of leaks detected (depressurized components do not leak). One of the problems is that operation modes vary seasonally at each compressor station, and within each compressor station, the operating modes of each unit can vary daily based on demand. The commenter asserted that the current quarterly compressor monitoring frequency creates a higher probability of conducting a survey where each compressor is monitored in a pressurized mode at least once per year. If the EPA moved to less frequent monitoring, the commenter recommended that there should be some condition to ensure that a reasonable effort is made to schedule the surveys during a time of peak operation.
      Response: The EPA reviewed the input provided by the commenters. While we agree with the one commenter that the opportunity for fugitive emissions is greater when a compressor is pressurized and operating, the EPA is not finalizing the proposed requirement that each compressor must be monitored while in operation (i.e., not in stand-by mode) at least annually. The EPA has specified in the final rule that the monitoring survey of fugitive emissions components at a gathering and boosting compressor station remains quarterly after the initial survey and subsequent quarterly monitoring surveys must be conducted at least 60 days apart. Therefore, as pointed out by the commenter, the likelihood that all monitoring events in a year will be when a specific individual compressor is not operating is relatively low. For the reason stated above, this final rule does not require monitoring of each individual compressor at the station while it is in operation (i.e., not in stand-by mode) at least once per calendar year.
      However, the EPA does conclude that it is important that the operating mode during the monitoring survey be recorded. While we would not expect that owners or operators would modify their operating schedules to avoid monitoring when the compressor is operating, or that they would purposely schedule every monitoring event during shutdown periods, we believe that this record would inform the Agency if this were occurring and, if so, how often. This information will provide valuable points for future analyses on leak rates and operating modes. Therefore, the final rule requires that owners and operators keep a record of the operating mode of each compressor at the time of the monitoring survey.
C. Major Comments Concerning AMELs
1. Emerging Technologies
	 The EPA received comments related to AMEL for emerging technologies on several topics. The comments received by the EPA that resulted in significant rule changes are discussed in section V.C.1 of this preamble, along with our response and rationale for the changes. The specific topics were (1) who can submit an AMEL application, (2) what data can or must be included in an AMEL application, and (3) what broader applications of alternatives are permitted. Further details on comments related to the broader applications of AMEL technology, specifically on the issues of applying AMEL to multiple similar sites or to categories of sources, are provided below along with EPA's responses. Other comments, and more detailed comments covering the topics discussed in this preamble related to emerging technologies can be found in the RTC document available in the docket, along with EPA's responses.
	Comment: In the proposal, the EPA reiterated its position that AMEL approvals would be made on a site-specific basis but noted that applicants could include multiple sites within one application as necessary. Many commenters disagreed with that proposal, stating that the EPA should allow approved AMELs to apply more broadly to multiple sites, basin-wide, industry-wide, or even based on nation-wide efficacy. Commenters asserted that restricting AMEL approval to a specific site is inconsistent with the EPA's past practice for OGI, in which the EPA determined that OGI achieves emission reductions equivalent to Method 21 for several industries and source categories in a single rulemaking. Some commenters feared that the site-specific approval process that includes Federal Register notice and comment requirements is so onerous that it will stifle innovation in new technology, and another noted that its customers have indicated that they would not apply for an AMEL if approval is site-specific. Commenters pointed out that the site-specific approval process could create a crush of AMEL applications for hundreds or thousands of sites, but the applications would be limited to only the technologies previously approved or most likely to be approved as AMEL.
      In response to the EPA's concern that alternative technologies may need to be adjusted for site-specific conditions, such as gas compositions, allowable emissions, or the landscape, several commenters suggested that the EPA could account for factors affecting variability, such as the weather or landscaping, by imposing conditions for the use of the technology and/or require periodic instrument checks, calibration records, or other actions to ensure equivalent emission reductions are achieved within the approved AMEL. The commenters also noted that if there is concern about allowable emissions impacting the usability of a particular technology, that technology may only be approvable for use as an approach to direct inspection efforts, but this factor would not affect the ability for it to be approved for that use at multiple sites.
	Response: The EPA does not seek to stifle innovation of emerging technologies. In fact, the Agency is actively involved in many multi-stakeholder groups aimed at developing frameworks and criteria that will promote the development of possible alternatives. As such, the EPA strongly encourages interested parties to discuss possible alternatives with the Agency. However, the EPA disagrees that this final rule should be the vehicle used to make determinations about any particular technology because the proposed rule did not evaluate any specific technology. The EPA also disagrees that this rule is inconsistent with the EPA's past practice for OGI, in which the EPA allowed the use of OGI as an alternative to Method 21 for several industries and source categories in a single rulemaking. The EPA notes that while the AMEL process provided for in CAA section 111(h)(3) contains elements similar to a rulemaking (such as notice and opportunity for public hearing), approval of an alternative does not always require rulemaking. If a technology is developed that could be broadly applied to oil and gas sites as an alternative to what is required in NSPS OOOOa, it may be more appropriate to incorporate such a technology into the rule through a formal rulemaking process so that every affected facility can make use of that alternative.
	As discussed in Section V.C.1 of this preamble, the EPA agrees that in some circumstances, it may be appropriate to apply an approved AMEL to multiple sites, including future sites. If the applicant of an AMEL believes that it is appropriate to apply the alternative to more sites than those listed in the application, the applicant should specify this within the application and provide any characteristics or variables that are applicable to the type of sites where the equivalency demonstration is being made. Specifically, the applicant should provide relevant information, including any specific conditions (e.g., technology-specific variables that affect performance), procedures (e.g., specific work practice that will be followed to identify emissions and make repairs), or site characteristics under which the alternative must be applied (e.g., formation variables, site operating conditions, equipment at the site, etc.), to demonstrate equivalence with the emissions reductions that would be achieved under the requirements of the NSPS. The EPA will evaluate these defined conditions and additional conditions, if any, under which it might be appropriate to allow future use of the alternative once approved via the AMEL process. For example, the EPA might approve the use of a specific fugitive emissions detection technology that operates with the same performance under specific work practice requirements, environmental conditions, and site configurations and operations. In that example, the EPA might determine it is appropriate to approve the AMEL and define the specific parameters (e.g., environmental conditions, site configurations, and operations) within the approval to allow the use of that alternative at sites meeting those same conditions without the need for additional future application to the EPA. However, each of these determinations would necessarily be made on a case-by-case basis provided the application contains all necessary information to make such a broad determination for applicability of the AMEL. Given that these determinations are made on facts and showings that are specific to each proposed alternative, the EPA has determined that the best course forward is for an applicant to submit an application seeking a broadly applicable AMEL and for the Agency to then use its evaluation of that application as a template for future applications, thereby streamlining the process.
	Comment: Several commenters stated that the EPA should approve the use of alternative technologies under the Agencies' AMEL authority for broad categories of sources subject to NSPS OOOOa, such as fugitive emissions components across multiple sites. They remarked that there is nothing in the statute that requires the EPA to set source-specific AMELs, and the EPA's position regarding the necessity of source-by-source applications and approvals for AMEL is incorrectly taken from a narrow reading of the language of CAA section 111(h)(3). The commenters stated that, while the language of section 111(h)(3) provides that an AMEL is permitted to be used "by the source" for purposes of compliance, the EPA's reading of this provision to disallow the granting of AMEL for use by multiple sources is inconsistent with the NSPS approach of developing standards for whole categories of sources.
	Some commenters said that because an AMEL will serve as a replacement for a category-wide CAA section 111(h)(1) standard, a demonstration that an AMEL will achieve an emission reduction at least equivalent to a 111(h)(1) standard could be made on a category-wide basis and be applied to an entire source category. These commenters suggested that allowing for source category-wide AMEL determinations would be consistent with the overall structure of CAA section 111 and its focus on category-wide standards under sections 111(b) and 111(h)(1) and with the limitation prohibiting the EPA from imposing specific technological emission reduction requirements pursuant to section 111(b)(5).
	These commenters further stated that the EPA's regulation implementing CAA section 112(h)(3) recognizes that the EPA is authorized to approve an AMEL for "source(s) or category(ies) of sources on which the alternative means will achieve equivalent emission reductions." They contended that, given the similarities between the programs authorized under CAA section 111 and CAA section 112, and particularly the similarity of sections 111(h)(3) and 112(h)(3), the EPA should adopt a policy of applying an AMEL to source categories for section 111(h)(3) in the same manner as it has done with respect to section 112(h)(3). They noted that in other rules, such as the visibility provisions that require the best available retrofit technology (BART), the EPA's rules allow the EPA and the states to authorize BART alternatives that can apply to groups of sources and that allow emission averaging across sources, even over wide regions, rather than imposing source-specific emission limits or source-specific alternatives to such limits. The commenters stated that if alternatives to emission limits (or work practice standards) for groups of sources under these provisions are permissible despite the continued references to the term "source" in the statutory language, then a source category-wide AMEL is surely permissible under section 111(h)(3).
	Response: On the first point raised by commenters, and as explained in the EPA's response above, the EPA agrees that in some instances broad use of an approved alternative may be appropriate. The current construct of the AMEL application process in NSPS OOOOa does not prevent the EPA from taking this path as suggested by the commenters.
	The commenters also suggest that the EPA should apply AMEL to a source category in the same manner in which the EPA has done for applications submitted through section 112(h)(3) of the CAA. While the EPA has approved AMEL for sources subject to standards under section 112 of the CAA, these approvals have been made on a site-specific basis, in which each application specifically lists the facilities that are applying for approval. Further, while similar, section 112(h)(3) does not apply for purposes of demonstrating equivalence with work practice standards in the NSPS.
	For purposes of evaluating whether an alternative to fugitives monitoring provides at least equivalent emission reductions as the applicable standards in the context of NSPS OOOOa, the EPA asserts that the emissions from an individual site are the only appropriate measure for comparison. First, the BSER determination for the collection of fugitive emissions components is based on a single well site, or a single compressor station, not a collection of well sites and/or compressor stations, and not the emissions of the entire source category. The source category for which NSPS OOOOa sets standards of performance under CAA section 111 is the crude oil and natural gas production source category. This category is defined in 40 CFR 60.5430a as "(1) crude oil production, which includes the well and extends to the point of custody transfer to the crude oil transmission pipeline or any other forms of transportation; and (2) natural gas production and processing, which includes the well and extend to, but does not include, the point of custody transfer to the natural gas transmission and storage segment." Within this source category, the EPA has set standards of performance (BSER) for individual affected facilities. These affected facilities are the only emission sources within the crude oil and natural gas production source category for which these NSPS apply and are defined in 40 CFR 60.5365a.
	Specifically, the EPA has defined the collection of fugitive emissions components at a well site and the collection of fugitive emissions components at a compressor station as individual affected facilities in the rule. Affected facilities are defined at the individual site level, and not as the collection of fugitive emissions components across multiple sites, or a collection of sources within a basin. Further, the standards that apply to these affected facilities are specific to the individual well site or compressor station, as defined in 40 CFR 60.5365a(i) and (j) and 40 CFR 60.5397a. For example, the collection of fugitive emissions components at an existing well site become subject to the fugitive emissions requirements when (1) a new well is drilled at that well site, (2) an existing well at that well site is hydraulically fractured, or (3) an existing well at that well site is hydraulically refractured. In all three cases, the event that triggers the requirements for an existing well site are based on site-specific changes, and not changes at other nearby sites. Drilling a new well at a well site within the same basin, for instance, does not trigger the fugitive emissions requirements for all well sites located in that basin.
      When establishing the requirements for the collection of fugitive emissions components, the EPA limited the applicability to individual well sites or compressor stations. The work practice standards set in accordance with section 111(h)(1) of the CAA were established for the collection of fugitive emissions components at an individual well site or compressor station. Since the NSPS does not define the emission source subject to BSER as a basin, or other aggregation of emission points, the EPA finds it inappropriate to evaluate alternatives that seek to implement such a definition. As a practical matter the EPA concludes that any determination of equivalent emission reductions through an AMEL under section 111(h)(3), or for an alternative work practice under section 111(h)(1), of the CAA for these NSPS should be determined at the same affected facility level (i.e., collection of fugitive emissions components at a well site or at a compressor station) as the original work practice standards.
      Similar to the EPA's explanation in the Affordable Clean Energy rule ("ACE"), here the EPA does not need to determine whether it would have reasonable grounds to define "source" for purposes of the fugitive emissions monitoring work practice standard as a geographic area, such as a basin.  Because these NSPS define an affected facility for this purpose as the collection of fugitive emissions components at a well site, and the collection of fugitive emissions components at a compressor station, the EPA does not think it is appropriate for AMEL applications to accommodate the averaging of emissions.
      Second, it is unclear whether the commenters are suggesting that such aggregation would take into account emissions from sources within a basin not subject to these NSPS, such as existing oil and gas well sites or compressor stations, or sources that emit VOC that are included in a different source category. In response to this point, the EPA directs commenters to the discussion of CAA Section 111, generation shifting, and emission offsets included in ACE. "[T]he plain language of CAA section 111 does not authorize the EPA to select as the BSER a system that is premised on application to the source category as a whole or to entities entirely outside the regulated source category". This principle also applies in the context of evaluating alternatives to the established BSER.
      Lastly, commenters suggest that averaging should be appropriate here because the EPA allows averaging in its best available retrofit technology (BART) program. However, that comparison is not appropriate because it fails to consider differences between BART and the BSER for this NSPS. The BART requirement is just one component of a larger strategy to make reasonable progress towards the national goal of remedying visibility impairment in certain areas. The EPA determined in the BART context that if a state can demonstrate that an alternative strategy, such as an emissions trading scheme, will be even more effective at improving visibility, such a "better-than-BART" strategy may be adopted to fulfill the role that would otherwise by filled by BART. However, in the context of this NSPS there is less flexibility on this point than in the BART program because, as explained above, there are no other components to reducing emissions aside from the BSER, the BSER is not based on reasonable progress, and this NSPS does not define the emission source subject to BSER as a basin or other aggregation of emission points.
2. State Fugitive Emissions Programs
	The EPA received comments related to the alternative fugitive emissions standards on several topics. The comments received by the EPA that resulted in significant rule changes are discussed in section V.C.2 of this preamble, along with our response and rationale for the changes. Specifically, these topics were related to whether the state regulations/requirements determined to be alternative fugitive standards to NSPS OOOOa fugitive requirements will provide adequate coverage of the emission sources in the state and the potential for duplicative reporting and recordkeeping requirements. Further details on comments related to these topics are provided below, along with other significant comments and the EPA's responses. Other comments, and more detailed comments covering the topics discussed in this preamble, related to the state fugitive monitoring programs can be found in the RTC document available in the docket, along with the EPA's responses.
	Comment: The EPA proposed alternative fugitive emissions standards based on our determination that certain states had existing requirements equivalent to the proposed fugitive emissions requirements. These determinations were based on qualitative assessments comparing various aspects of the requirements, such as monitoring frequencies and repair deadlines. Two commenters stated that the equivalency determinations must be quantitative if the EPA wants to set alternative standards because they are similar to AMELs. The commenters indicated that the Agency's analysis evaluated whether a state has regulations that are similar to the EPA's regulations, rather than whether the emissions reductions achieved by those regulations are quantitatively equivalent. One of the commenters stated that the EPA's qualitative comparison is legally insufficient because it does not meet the statutory requirement that an applicant "establish" that an AMEL "will achieve" reductions in emissions "at least equivalent to" the reduction achieved under the federal standards. This commenter stated that, without a quantitative comparison, it is impossible to determine whether an AMEL will achieve at least an equivalent reduction in pollutant emissions. The commenter further notes that past AMEL approvals under this provision were based on detailed quantitative determinations for each facility to determine the exact emissions levels that would be achievable at that facility, and then those levels were compared to the emissions levels achievable under the present NSPS. The commenter stated that the EPA's policy changes in how equivalency is determined are inconsistent with the requirements of section 111(h) of the CAA and also stated that the EPA's approach of "combining . . . aspects of the state requirements to formulate alternatives," to determine equivalency is not a permissible or reasonable approach. The commenter noted that while some aspects of a state-level program may be more protective than the corresponding federal requirements, others may not be, and the commenter stated that qualitative comparisons cannot determine the net effects of program elements that point in opposite directions.
	Response: The EPA agrees that in some instances when the EPA is evaluating an alternative, it would be preferable to use a quantitative analysis, but we do not agree that such analysis is necessary or prudent in this instance for determining the equivalency of fugitive emissions requirements in state regulations. The CAA does not require the EPA to conduct a quantitative analysis to evaluate an alternative standard or to determine whether that alternative is equivalent to the underlying standard. Work practice standards under section 111(h)(1) of the CAA are set when "it is not feasible to prescribe or enforce a standard of performance." Section 111(h)(2) of the CAA further defines that the phrase not feasible to prescribe or enforce a standard of performance "means any situation in which the Administrator determines that (A) a pollutant or pollutants cannot be emitted through a conveyance designed and constructed to emit or capture such pollutant..., or (B) the application of measurement methodology to a particular class of sources is not practicable due to technological or economic limitations." Fugitive emissions are not quantified within the rule, and the technologies used in this rule to detect fugitive emissions do not quantify the actual emissions that are detected and then remediated through repair. Further, even if direct quantification were possible through the currently approved technologies, those quantified emissions would only represent the fugitive emissions detected on that specific day and would not offer information related to how long those emissions were present prior to detection, or account for any emissions that occur between monitoring surveys. Due to the fact-specific circumstances of the work practice standard in the existing rule, it is not practical for the EPA to conduct an accurate and meaningful quantitative analysis of the alternatives. It is also not necessary for the EPA to conduct a quantitative analysis. The statute does not require a quantitative analysis. Therefore, the most practical way to evaluate the equivalence of a fugitive emissions monitoring and repair program is through the site-specific qualitative comparison that we used. It is the EPA's determination that the analysis, which evaluates the types of components monitored, the frequency of monitoring, the detection instrument, the threshold that triggers repairs, and the repair deadline, is sufficient and appropriate for demonstrating that the six programs identified as alternative fugitive standards are equivalent to the fugitive emissions requirements of NSPS OOOOa. Therefore, we have not conducted a quantitative analysis of the individual state programs that are finalized in this action as alternative standards.
	Comment: One commenter performed its own quantitative assessment of the state programs that the EPA proposed as equivalent to NSPS OOOOa with the October 15, 2018, proposal. From this analysis, the commenter stated that it found differences in the applicability thresholds for several of the state programs, which results in the state programs (combined) covering only 34% of the total wells that would be covered by the proposal or the 2016 NSPS OOOOa in these states. The commenter also stated that state programs vary in stringency and may not reduce emissions to the same level as the EPA standards, such as the Ohio and Texas provisions that allow for inspection frequency to decrease based on the percentage of components leaking. The commenter asserted that its assessment demonstrates that both the Ohio and Texas programs reduce emissions to a lesser extent than the proposed requirements, while California and Colorado meet the emission reduction levels accomplished by the proposal. Overall, the commenter said that the state programs will achieve a reduction of methane emissions that is 36% less than the reduction that would be achieved by the amendments proposed on October 15, 2018. When compared to the 2016 NSPS OOOOa requirements, the commenter said that the state programs would result in 58% less emissions reductions. The commenter remarked that these findings demonstrate that these state programs are not equivalent to either the proposal or the 2016 NSPS OOOOa. Another commenter also remarked that California Air Resources Board has performed a preliminary assessment of state programs against the 2016 NSPS OOOOa and found that only the California, Colorado, Pennsylvania, Utah, and Texas programs (within narrow parameters) are likely to be equivalent.
	Response: The EPA reviewed the analysis provided by the commenter but notes that the analysis appears to include an incorrect assumption. Specifically, the commenter stated that only 34% of the wells covered by the fugitive emissions requirements in NSPS OOOOa and that are also located in one of the six states with proposed alternative fugitive standards would actually be subject to those alternative fugitive standards. This is not correct. The assumption by the commenter is that the alternative standards are deficient because not all of the sites that are currently subject to NSPS OOOOa would be required to monitor and thus reduce fugitive emissions. This assumption is incorrect. The applicability criteria found in NSPS OOOOa will continue to apply regardless of the state's applicability criteria.
	Using Texas as an example, the commenters stated that only 5% of the sites that are subject to NSPS OOOOa would have monitoring requirements under the alternative fugitive standards for well sites located in Texas. While this percentage may represent those sites in Texas that can utilize the alternative, this does not mean that the other 95% of sites escape regulation under the NSPS. If a well site is subject to the Texas standards, then that well site may opt to comply with those state-level standards as an alternative to certain federal fugitive emissions requirements in NSPS OOOOa. However, if a well site located in Texas is not subject to the state-level requirements and is subject to the NSPS (95% of the sites according to commenter), then the alternative standard would not be available to that site, and monitoring would be required through the requirements in NSPS OOOOa. Put another way, the alternatives included in this final rule do not alter the applicability criteria of the NSPS for any sites. If a well site in Texas was required to comply with the NSPS before the alternative was approved, then that site is still required to comply with the NSPS, but the final rule affords certain sites an alternative way to demonstrate that compliance with the NSPS, if they so choose. Moreover, regardless of whether the site complies with the fugitive emissions requirements in NSPS OOOOa, or the alternative fugitive standards for their state, they must conduct the specific monitoring and repair for the NSPS OOOOa defined fugitive emissions components at a well site or compressor station, as applicable.
	Comment: Several commenters asserted that the EPA should recognize the approved state programs as wholly equivalent to the fugitive emissions requirements in the NSPS and fully delegate the implementation of those fugitive emissions requirements to those states, including the states' recordkeeping and reporting requirements. The commenters noted that the EPA is requiring operators to use the fugitive emission component definition from the 2016 NSPS OOOOa and the 2016 NSPS OOOOa reporting and monitoring plan.
	Two of the commenters observed that they are required to comply with both the state requirements and federal fugitive emissions programs concurrently. The commenters stated that complying with two different recordkeeping and reporting schemes for the same site is very burdensome with no added benefit for the environment. Sites that operate where they are subject to both the NSPS and a state program will sometimes be required to keep two very similar sets of records to comply with both standards. Likewise, sites in this situation may be required to report similar overlapping information to both the federal system and a state system. According to commenters, this overlap in recordkeeping and reporting (and sometimes in monitoring plans) creates redundant work that unnecessarily consumes resources. The commenters go on to assert that requiring the federal reporting and monitoring plan defeats the purpose and any benefit from the EPA approving state programs and suggest that if a state program is not adequate in the EPA's opinion, then the EPA should address the issue with the individual state, so it can be approved in whole. Commenters added that as an alternative, the EPA could require that the fugitive emissions component definition from NSPS OOOOa be used when following an alternative standard, even if the state program definitions differ, but the EPA should not require any duplicative administrative burden.
	Further, the commenters stated that CAA Section 111 fits squarely within the cooperative federalism tradition, with Section 111(c) expressly calling on states to develop "a procedure for implementing and enforcing standards of performance for new sources" and calling on the Administrator to delegate "any authority he has ... to implement and enforce such standards." Two commenters noted that the EPA did not evaluate the equivalency of state reporting requirements or monitoring plans and, thus, did not propose any alternative standards for these aspects of the NSPS OOOOa fugitive emissions requirements. These commenters stated that the exclusion of state reporting and monitoring plan requirements from the EPA's equivalency evaluation leaves the regulated community in certain states subject to potentially duplicative regulation.
	Response: It is unclear to the EPA what commenters mean by "wholly equivalent" and "fully delegate", but we are providing a response based on our interpretation that commenters are requesting approved alternative standards only require recordkeeping and reporting to the individual states and not to the EPA. After considering the comments provided, the EPA reviewed the recordkeeping and reporting requirements for each of the 6 states that were proposed for alternative fugitive standards in the October 15, 2018 proposal (California, Colorado, Ohio, Pennsylvania, Texas, and Utah). For California, Ohio, and Pennsylvania, the EPA was able to identify site-specific reporting requirements in the state reports which, while not identical to the reporting for NSPS OOOOa, were determined to be appropriate to demonstrate compliance with the alternative fugitive standards for those states. Therefore, in this final rule, we are allowing well sites and compressor stations located in California, Ohio, and Pennsylvania that adopt the alternative fugitive standards to electronically submit a copy of the report that is submitted to their state as specified in 40 CFR 60.5420a(b)(7)(iii). As discussed in Section V.C of this preamble, this report must be submitted in the format in which it was submitted to the state, noting the following order of preference: (1) as a binary file, (2) as a XML schema, (3) as a searchable PDF, or (4) as a scanned PDF of a hard copy.
	In reviewing the reporting requirements for Colorado, we noted that the report is a fillable form to the state that summarizes all monitoring events for that year at the company-level. Therefore, no site-specific information is available. We then reviewed the recordkeeping forms for Colorado to identify what information is required for the individual sites and compared that information to the required annual report for NSPS OOOOa. We identified one recordkeeping element required by NSPS OOOOa that was not already included in the recordkeeping requirements for Colorado: deviations from certain requirements in the monitoring plan. Given that the federal monitoring plan, and deviations from that plan, are still required for all sites that adopt the alternative fugitive standards, there are no additional recordkeeping elements that would be needed beyond what the state already requires. While the EPA has determined that the Colorado program for fugitive emissions requirements is an acceptable alternative to NSPS OOOOa, the company-level reports in Colorado are insufficient to demonstrate compliance for individual sites. Therefore, we are still requiring that well sites and compressor stations located in Colorado that adopt the alternative fugitive standard must report the information required by NSPS OOOOa for fugitive emissions components at well sites and compressor stations.
	Our review of the Texas reporting requirements found that sites only report information when fugitive emissions are found. While this may be appropriate for demonstrating compliance to the state, it is not adequate information for the EPA to ensure compliance with the alternative fugitive standards for well sites and compressor stations located in Texas. Similar to Colorado, we examined the recordkeeping requirements and found that sites located in the state are already required by the state to keep records that facilitate the reporting required by NSPS OOOOa for fugitive emissions components at well sites and compressor stations. Therefore, we are requiring that well sites and compressor stations located in Texas that adopt the alternative fugitive standards must report the information required in NSPS OOOOa.
	Finally, the requirements in Utah do not include reporting. Similar to Colorado and Texas, we reviewed the recordkeeping requirements. For Utah, sites must keep records of the monitoring plan and the monitoring surveys. We found these records are similar to the information that is required in the NSPS OOOOa report for fugitive emissions components and would not require additional recordkeeping. Therefore, we are requiring that well sites located in Utah that adopt the alternative fugitive standards must report the information required in NSPS OOOOa.
VII. Impacts of These Final Amendments
A. What are the air impacts?
      The EPA projected that, from 2021 to 2030, relative to the baseline, the final rule will forgo about 367,000 short tons of methane emissions reductions (8.3 million tons CO2 Eq.), 102,000 short tons of VOC emissions reductions, and 4,000 short tons of HAP emission reductions from facilities affected by this reconsideration. The EPA estimated regulatory impacts beginning in 2021 as it is the first full year of implementation of this rule. The EPA estimated impacts through 2030 to illustrate the accumulating effects of this rule over a longer period. The EPA did not estimate impacts after 2030 for reasons including limited information, as explained in the RIA.
B. What are the energy impacts?
	There will likely be minimal change in emissions control energy requirements resulting from this rule. Additionally, this final action continues to encourage the use of emission controls that recover hydrocarbon products that can be used on-site as fuel or reprocessed within the production process for sale. The energy impacts described in this section are those energy requirements associated with the operation of emission control devices. Potential impacts on the national energy economy from the rule are discussed in the economic impacts section.
C. What are the compliance cost reductions?
The present value (PV) of the regulatory compliance cost reduction associated with this final rule over the 2021 to 2030 period was estimated to be $721 million (in 2016 dollars) using a 7 percent discount rate and $910 million using a 3 percent discount rate. The equivalent annualized value (EAV) of these cost reductions is estimated to be $125 million per year using a 7 percent discount rate and $142 million per year using a 3 percent discount rate.
These estimates do not, however, include the forgone producer revenues associated with the decrease in the recovery of saleable natural gas, though some of the compliance actions required in the baseline would likely have captured saleable product that would have otherwise been emitted to the atmosphere. Estimates of the value of the recovered product were included in previous regulatory analyses as offsetting compliance costs. Because of the deregulatory nature of this final action, the EPA projected a reduction in the recovery of saleable product. Using the 2020 Annual Energy Outlook (AEO) projection of natural gas prices to estimate the value of the change in the recovered gas at the wellhead projected to result from the final action, the EPA estimated a PV of regulatory compliance cost reductions of the final rule over the 2021 to 2030 period of $684 million using a 7 percent discount rate and $863 million using a 3 percent discount rate. The corresponding estimates of the EAV of cost reductions after accounting for the forgone revenues were $119 million per year using a 7 percent discount rate and $134 million per year using a 3 percent discount rate.
D. What are the economic and employment impacts?
      The EPA used the National Energy Modeling System (NEMS) to estimate the impacts of the 2016 NSPS OOOOa on the U.S. energy system. The NEMS is a publicly available model of the U.S. energy economy developed and maintained by the U.S. EIA and is used to produce the AEO, a reference publication that provides detailed projections of the U.S. energy economy. The EPA estimated small impacts on crude oil and natural gas markets of the 2016 NSPS OOOOa rule over the 2020 to 2025 period. This final rule will result in a decrease in total compliance costs relative to the baseline. Therefore, the EPA expects that this rule will partially reduce the impacts estimated for the 2016 NSPS OOOOa in the 2016 NSPS OOOOa RIA.
      Executive Order 13563 directs federal agencies to consider the effect of regulations on job creation and employment. According to the Executive Order, "our regulatory system must protect public health, welfare, safety, and our environment while promoting economic growth, innovation, competitiveness, and job creation. It must be based on the best available science." (Executive Order 13563, 2011). While a standalone analysis of employment impacts is not included in a standard benefit-cost analysis, such an analysis is of concern in the current economic climate given continued interest in the employment impact of regulations such as this final rule. The EPA estimated the changes in compliance-related labor impacts due to the changes finalized in this rule. As presented in the RIA for this action, the EPA projected there will be reductions in the labor required for compliance-related activities associated with the 2016 NSPS OOOOa requirements relating to fugitive emissions monitoring and certifications of CVS.
E. What are the forgone benefits?
The EPA expects forgone climate and health benefits due to the forgone emissions reductions projected under this final rule. The EPA estimated the forgone domestic climate benefits from the forgone methane emissions reductions using an interim measure of the domestic social cost of methane (SC-CH4). The SC-CH4 estimates used here were developed under Executive Order 13783 for use in regulatory analyses until an improved estimate of the impacts of climate change to the U.S. can be developed based on the best available science and economics. Executive Order 13783 directed agencies to ensure that estimates of the social cost of GHG used in regulatory analyses "are based on the best available science and economics" and are consistent with the guidance contained in OMB Circular A-4, "including with respect to the consideration of domestic versus international impacts and the consideration of appropriate discount rates" (Executive Order 13783, Section 5(c)). In addition, Executive Order 13783 withdrew the technical support documents (TSDs) and the August 2016 Addendum to these TSDs describing the global social cost of GHG estimates developed under the prior Administration as no longer representative of government policy. The withdrawn TSDs and Addendum were developed by an interagency working group that included the EPA and other executive branch entities and were used in the 2016 NSPS OOOOa RIA.
The EPA estimated the PV of the forgone domestic climate benefits over the 2021 to 2030 period to be $15 million under a 7 percent discount rate and $58 million under a 3 percent discount rate. The EAV of these forgone benefits is estimated $3 million per year under a 7 percent discount rate and $9 million per year under a 3 percent discount rate. These values represent only a partial accounting of domestic climate impacts from methane emissions and do not account for health effects of ozone exposure from the increase in methane emissions.