Response: The EPA disagrees with the commenters that the rule should include an alternative maintenance program and allow operators flexibility to use condition-based maintenance approach to reduce emissions rather than a prescribed maintenance schedule. While we received comment supporting the addition of a threshold-based or condition-based maintenance provision, we did not receive sufficient technical details to properly evaluate this alternative for inclusion in the rule. Although condition-based maintenance has been shown to be effective under the Natural Gas STAR program, the criteria on which rule requirements could be based would require significantly more data and analysis. Specifically, in order to evaluate such a provision for the rule, we would need to determine an appropriate leak-rate threshold which would trigger rod packing replacement. Commenters suggested 2 scfm demonstrated acceptable rod packing leakage; however, the commenters provided no substantive data as to the reason for this threshold. Commenters also recommended that we model the provision after the California Air Resources Board proposed regulation which was based on input from rod packing vendors. Although some valuable information was provided, the level of technical data and information necessary to analyze all aspects of such a provision were not provided. Therefore, we are unable to evaluate the condition-based maintenance provision for inclusion in the rule at this time.
 D. Major Comments Concerning Pneumatic Controllers
 1. Studies That Indicate Emission Rates for Low-Bleed Pneumatic Controllers That Are Higher Than the EPA Estimates
 Comment: The EPA received comment that several recent studies report that pneumatic controllers emit more than they are designed to emit and that their emission rate is higher than the currently estimated EPA emission rate for pneumatic controllers. Specifically, the commenters noted that studies indicated that controllers were observed to have emissions inconsistent with the manufacturer's design and were likely operating incorrectly due to maintenance or equipment issues. Low-bleed pneumatic controllers were observed to have emission rates that were 270 percent higher than the EPA's emission factor for these devices, in some cases approaching the emission rate of high-bleed controllers.
 Response: The emissions estimates presented in the proposal were based on the most robust data available at the time of their development. The EPA is familiar with the studies discussed in the comments summarized here and several of those studies were discussed in the EPA's Oil and Gas White Paper. The EPA has reviewed available data; because of the lack of emissions data that are straightforward to use in assessment of emissions from specific bleed rate categories (i.e., high-bleed and low-bleed), the EPA has retained the emission factors for pneumatic controllers used in the proposal analysis and has retained the requirements for pneumatic controllers.
2. Capture and Control of Emissions from Pneumatic Controllers
Comment: The EPA received comment that pneumatic controllers should be required to capture emissions through a closed vent system and route the captured emissions to a process or a control device, similar to the approach the EPA has taken in its proposed standards for pneumatic pumps and compressors. The commenters cite recent Wyoming proposed rules for existing pneumatic controllers that allow operators of existing high-bleed controllers to route emissions to a process and the California Air Resources Board (CARB) proposed rules which requires that operators capture emissions and route to a process or control device. Commenters state that this approach would work for all types of pneumatic controllers and that this approach would be cost effective based on the costs identified for pneumatic pumps in the TSD.
 Response: The EPA disagrees with the commenters that capturing and routing emissions from pneumatic controllers to a process or control device is a viable control option under our BSER analysis. While the commenter stated that a few permits in Wyoming indicate that a facility is capturing emissions from controllers and routing to a control device, we believe that there is insufficient information and data available for the EPA to establish this the control option as the BSER. For more information, please see the RTC.
 E. Major Comments Concerning Pneumatic Pumps
 1. Compliance Date
 Comment: Commenters stated that the EPA requires that new or modified pneumatic pumps at a site that currently lack an emission control device will become an affected facility if a control device is later installed; and, the facility must be in compliance within 30 days of installation of the new control device. One commenter states that 30 days does not provide such sources sufficient time to come into compliance. The commenter suggests that the rule be revised to require compliance within 30 days of startup of the control device so that the operator can ensure that the control device is properly tested after installation without concern over triggering non-compliance for pneumatic pump controls.
 Response: We agree that additional time is appropriate for designing connections and testing after control device installation. Therefore, we have revised the compliance date in the final rule with respect to control devices that are installed on site after installation of the pneumatic pump affected facility. In the final rule, the compliance date for pneumatic pump affected facilities to be routed to a newly installed onsite control device 30 days after startup of the control device.
 2. Subsequent Removal of Control Device
 Comment: Several commenters expressed concern that the rule did not provide a way to remove control equipment from a site when it is no longer needed for the purpose for which it was installed. Further, they requested that the EPA clarify that a source ceases to be an affected facility if the control device is no longer needed for other equipment. The commenters cite an example where the exiting control device onsite is installed for a subpart OOOO storage vessel and subsequently the storage vessel's potential to emit falls below 6 tpy. If this were to occur, the storage vessel would no longer be subject to regulation and the control device would no longer be necessary.
 Response: The EPA agrees that the intent of the proposal was not to require existing control devices that are no longer required for their original purposes to remain at a site only to control pneumatic pump affected facility emissions. Therefore, the final rule clarifies that subsequent to the removal of a control device and provided that there is no ability to route to a process, a pneumatic pump affected facility is no longer required to comply with §60.5393a(b)(1)or (2). However, these units will continue to be affected facilities and we are requiring pneumatic pump affected facilities to continue following the relevant recordkeeping requirements of §60.5420a even after an existing control device is removed.
 3. Limited-Use Pneumatic Pumps
Comment: Commenters state that there are natural gas-driven pneumatic pumps which are used intermittently to transfer bulk liquids. These limited use pumps may be manually operated as needed or may be triggered by a level controller or other sensor. Specific examples provided by the commenters include engine skid sump pumps, pipeline sump pumps, tank bottom pumps, flare knockout drum pumps, and separator knockout drum pumps that are used to pump liquids from one place to another. The commenters contend that these pumps do not run continuously or even seasonally for long periods but only run periodically as needed. Thus, these pumps do not exhaust large volumes of gas in the aggregate. For this reason, the commenters requested that the final rule include an exemption for limited-use pneumatic pumps.
 Response: In the TSDs to the proposed and final rule, the emission factors we used for pneumatic pumps assumed that the pumps operated 40 percent of the time. While we understood that pneumatic pumps typically do not run continuously, we did assume that the 40 percent usage was distributed evenly throughout the year. However, based upon the comments we received, the usage of some pneumatic pumps is much more limited than we previously determined and not spread evenly throughout the year. We did not intend to regulate these limited-use pneumatic pumps and are not including limited-use pneumatic pumps in the definition of pneumatic pump affected facilities that are located at well sites. Specifically, if a pump located at a well site operates for any period of time each day for less than a total of 90 days per year, this limited-use pneumatic pump is not an affected facility under this rule. We believe this requirement is sufficient to address the commenters' concerns for both intermittent use and temporary use pneumatic pumps.
 	Because we believe there are multiple viable alternatives available at natural gas processing plants that are not available at well sites, we do not believe it is necessary to exclude limited-use pneumatic pumps located at natural gas processing plants from the definition of pneumatic pump affected facility. Based on our best available information, both instrument air and electricity are readily available at natural gas processing plants. We believe owners and operators will choose instrument air over natural gas-driven pumps since their other pumps will be air powered. We also believe owners and operators can utilize electric pumps for intermittent activities cited by the commenters such as sump pumps and transfer pumps where it is safe to use an electric pump. Given these options, we conclude that it is not necessary to exclude limited-use pneumatic pumps located at natural gas processing plants from the definition of pneumatic pump affected facility in the final rule.
 4. Removal of Tagging Requirements
 Comment: Several commenters requested that the EPA remove the tagging requirement for pneumatic pump affected facilities. As written, the proposed rule required that operators tag pumps that are affected facilities and those that are not affected facilities. The commenters contend that the tagging requirement appears to add little value and is confusing. Commenters suggest operators should only be required to maintain a list of make, model, and serial number, rather than individual tags and that a list of make, model, and serial number will achieve the same results desired by the EPA, without presenting the unnecessary operational hurdles associated with individual tagging and recordkeeping.
 Response: The EPA has reviewed the proposed tagging requirements and agrees with the commenters that the recordkeeping in lieu of tagging for pneumatic pumps affected facilities is sufficient. Therefore, the EPA has removed the tagging requirements for pneumatic pump affected facilities in the final rule.
 5. Lean Glycol Circulation Pumps
 Comment: The EPA solicited comments on the level of uncontrolled emissions from lean glycol circulation pumps and how they are vented through the dehydrator system. We received comments corroborating our understanding at proposal and in the white papers that emissions from these pumps are vented through the rich glycol separator vent or the reboiler still vent and are already regulated under 40 CFR part 63 subparts HH and HHH.
Response: The EPA's understanding during the proposal was that the lean glycol pumps are integral to the operation of the dehydrator, and as such, emissions from glycol dehydrator pumps are not separately quantified because these emissions are released from the same stack as the rest of the emissions from the dehydrator system, including HAP emission that are being controlled to meet the standards under the National Emission Standards for Hazardous Air Pollutants (NESHAP) at 40 CFR part 63 subparts HH and HHH. It is also our understanding from white paper commenters that replacing the natural gas in gas-assisted lean glycol pumps with instrument air is not feasible and would create significant safety concerns. Commenters on the white paper stated that the only option for these types of pumps are to replace them with electric motor driven pumps; however, solar and battery systems large enough to power these types of pumps are not currently feasible. Therefore, we have clarified that lean glycol circulation pumps are not affected facilities under the final pneumatic pumps standards.
 F. Major Comments Concerning Well Completions
 1. Request for a Limited Use of Combustion
Comment: Several commenters support the requirements for reducing completion emissions at oil wells; however, they express concern that the proposed rule does not go far enough in establishing a hierarchy of preference for the beneficial use options provided in the rule (i.e., routing the recovered gas from the separator into a gas flow line or collection system, re-injecting the recovered gas into the well or another well, use of the recovered gas as an onsite fuel source or use of the recovered gas for another useful purpose that a purchased fuel or raw material would serve) over what the commenters perceive to be the least-preferable option to route the emission to a combustion control device. Further, one commenter states that the technical infeasibility exemption in the rule is vague and could detract significantly from the overall value of this standard if not narrowly limited in application. The commenter notes that because of the swiftly increasing production of oil (along with associated natural gas) in the United States which produces very high initial rates of oil and associated gas, it is vital that the rule's requirements apply rigorously.
Response: The EPA agrees that REC should be preferred over combustion due to the secondary environmental impact from combustion. The final rule reflects such preference by requiring REC unless it is technically infeasible, in which event the recovered gas is to be routed to a completion combustion device. Further, to ensure that the exemption from REC due to technical infeasibility is limited to those situations where the operator can demonstrate that each of the options to capture and use gas beneficially is not feasible and why, we have expanded recordkeeping requirements in the final rule to include: (1) detailed documentation of the reasons for the claim of technical infeasibility with respect to all four options provided in §60.5375a(a)(1)(ii), including but not limited to, names and locations of the nearest gathering line; capture, re-injection, and reuse technologies considered; aspects of gas or equipment prohibiting use of recovered gas as a fuel onsite; and (2) technical considerations prohibiting any other beneficial use of recovered gas on site.
       We believe these additional provisions will support a more diligent and transparent application of the intent of the technical infeasibility exemption from the REC requirement in the final rule. This information must be included in the annual report made available to the public 30 days after submission through CEDRI and WebFIRE, allowing for public review of best practices and periodic auditing to ensure flaring is limited and emissions are minimized.
 G. Major Comments Concerning Fugitive Emissions from Well Sites and Compressor Stations
 1. Modification Definitions for Well Sites
 Comment: Several commenters assert that the definition of "modification" of a well site under the proposed rule in §60.5365a(i) is overly broad because it would bring many existing well sites under the Rule's requirements. The commenters believe that drilling a new well or hydraulically fracturing an existing well does not increase the probability of a leak from an individual component and no new components result from these activities, thus the potential emissions rate does not change and should not be consider a modification.
 Response: The EPA believes the addition of a new well or the hydraulically fracturing or refracturing of an existing well will increase emissions from the well site for the following reasons. These events are followed by production from these wells which generate additional emissions at the well sites. Some of these additional emissions will pass through leaking fugitive emission components at the well sites (in addition to the emissions already leaking from those components). Further, it is not uncommon that an increase in production would require additional equipment and, therefore, additional fugitive emission components at the well sites. We also believe that defining "modification" to include these two events, rather than requiring complex case-by-case analysis to determine whether there is emission increase in each event, will ease implementation burden for owners and operators. For the reasons stated above, EPA is finalizing the definition of "modification" of a well site, as proposed.
 2. Monitoring Plan
 Comment: Commenters expressed concerns about the elements of the proposed monitoring plans and encouraged the EPA to consult with the oil and gas industry and states to adopt requirements that would meet their specific needs. Commenters suggested that an area-wide monitoring plan should be allowed instead of a corporate-wide or site specific plan. The area plan would allow owners to write a plan that covers various areas for each specific region since operators may rely on contractors in one area due to location while company-owned monitoring equipment may be used within another area.
 Response: The EPA participated in numerous meetings with industry, environmental and state stakeholders to discuss the proposed rule. During these meetings industry stakeholders further explained why a corporate-wide monitoring plan would be difficult to develop due to their corporate structures, well site locations, basin characteristics and many other factors. They also indicated that a site-specific plan would be redundant since many well sites within a district or field office are similar and would utilize the same personnel, contractors or monitoring equipment. The industry stakeholders provided input on specific elements of the monitoring plan, such as the walking path requirement. Based on the comments that we received and subsequent stakeholder meetings, we have made changes to the monitoring plan and have further explained our intent for the walking path. We have also modified the digital photograph recordkeeping requirements for sources of fugitive emissions. See section VI.f.1.h of this preamble for further discussion.
 H. Major Comments Concerning Final Standards Reflecting Next Generation Compliance and Rule Effectiveness Strategies
 1. Electronic Reporting
 Comment: While some commenters express support, several commenters oppose electronic reporting of compliance-related records. Some of the commenters state that they have an obligation under the rule to maintain these records and make them available to the regulatory agency upon request, and this should be sufficient. Providing all the records requested under the proposed rule would likely cause a backlog of correspondence between the regulatory agency and the industry. Other commenters expressed concern that sensitive company information could be present in the records, and other parties could use a FOIA request to obtain the records.
 	Additional commenters pointed out that the EPA should not require electronic reporting until CEDRI is modified to accommodate the unique nature of the oil and natural gas production industry. As the commenters understand the operational characteristics of CEDRI, the system links reports for each affected facility to the site at which they are located. Under subparts OOOO and OOOOa, there is no unique site identifier. This would result in owners and operators having to deconstruct the annual report in order to obtain the affected facility level data needed for CEDRI. The EPA did not account for this burden and cost. The commenters request that should electronic reporting be required, that CEDRI be revised to accept the annual reports as currently specified in the proposed rule as a pdf file or hardcopy until these issues can be resolved. Commenters also request that CEDRI be modified to accept area-wide reports rather than site-level reports. Additionally, commenters noted that the definition of "certifying official" under CEDRI is different than in the proposed rule.
 	Finally, since the EPA did not propose regulatory language for these requirements, some commenters believe that the EPA cannot finalize these requirements without first proposing the regulatory language.
Response: The EPA notes that regulatory language for the electronic reporting requirements was available in §60.5420a, §60.5422a and §60.5423a of the proposed rule.
      The EPA thanks the commenters for the support for electronic reporting. Electronic reporting is in ever-increasing use and is universally considered to be faster, more efficient and more accurate for all parties once the initial systems have been established and start-up costs completed. Electronic reporting of environmental data is already common practice in many media offices at the EPA; programs such as the Toxics Release Inventory (TRI), the Greenhouse Gas Reporting Program, Acid Rain and NOX Budget Trading Programs and the Toxic Substances Control Act (TSCA) New Chemicals Program all require electronic submissions to the EPA. The EPA has previously implemented similar electronic reporting requirements in over 50 different subparts within parts 60 and 63. WebFIRE, the public access site for these data, currently houses over 5000 reports that have been submitted to the EPA via CEDRI.
      The EPA notes that reporting is an essential element in compliance assurance, and this is especially true in this sector. Because of the large number of sites and the remoteness of sites, it is unlikely that the delegated agencies will be able to visit all sites. By providing reports electronically in a standardized format, the system benefits air agencies by streamlining review of data, facilitating large scale data analysis, providing access to reports and providing cost savings through a reduction in storage costs. The narrative and upload fields within the CEDRI forms can even be used to provide information to satisfy extra reporting requirements that state and local air agencies may impose.
      The EPA is sensitive to the complexity of the oil and gas regulations and the unique challenges presented by this sector. CEDRI forms are designed to be consistent with the requirements of the underlying subparts and are unique to each regulation. The forms are reviewed multiple times before being finalized, and they are subjected to a beta testing period that allows end-users to provide feedback on issues with the forms prior to requiring their use. Also, if a form has not yet been completed by the time the rule is effective, affected facilities will not be required to use CEDRI until the form has been available for at least 90 days. The EPA notes that we have recently developed a bulk upload feature for several subparts within CEDRI. The bulk upload feature allows users to enter data for sites across the country in a single file instead of having to submit individual reports for each site. This feature should alleviate some of the commenters' concerns.
      The EPA is aware that facility personnel must learn the new reporting system, but the savings realized by simplified data entry outweighs the initial period of learning the system. Electronic reporting can eliminate paper-based, manual processes, thereby saving time and resources, simplifying data entry, eliminating redundancies, minimizing data reporting errors and providing data quickly and accurately. Reporting form standardization can also lead to cost savings by laying out the data elements specified by the regulations in a step-by-step process, thereby helping to ensure completeness of the data and allowing for accurate assessment of data quality. Additionally, the EPA's electronic reporting system will be able to access existing information in previously submitted reports and data stored in other EPA databases. These data can be incorporated into new reports, which will lead to reporting burden reduction through labor savings.
In 2011, in response to Executive Order 13563, the EPA developed a plan to periodically review its regulations to determine if they should be modified, streamlined, expanded, or repealed in an effort to make regulations more effective and less burdensome. The plan includes replacing outdated paper reporting with electronic reporting. In keeping with this plan and the White House's Digital Government Strategy, in 2013 the EPA issued an agency-wide policy specifying that EPA will start with the assumption that reporting will be electronic and not paper. The EPA believes that the electronic submittal of the reports addressed in this rulemaking increases the usefulness of the data contained in those reports, is in keeping with current trends in data availability, further assists in the protection of public health and the environment and will ultimately result in less burden on the regulated community. Therefore, the EPA is retaining the requirement to report these data electronically.

 2. Third-Party Verification for Closed Vent Systems
 Comment: Several commenters express opposition to a third-party verification system for the design of closed vent systems. Some of the commenters explain that they design their closed vent system using in-house staff. Many of the details regarding actual flow volumes and gas composition are unknown at the initial design stage, so it would not be possible to certify the design's effectiveness prior to construction. Also, storage vessels are designed to have some level of losses, so it would also not be possible to certify that the closed vent system routes all emissions to the control device.
 	Several of the commenters also express concern that the verification process discussed in the preamble to the proposed rule would create a complex bureaucratic scheme with no measurable benefits. Many of the commenters believe such a verification process would add a significant labor and cost burden that the EPA has not quantified. The EPA's contention that third-party verification "may" improve compliance is presented without any analysis or support and does not justify the costs of such a program.
 	Concerning the impartiality requirements outlined by the EPA, some of the commenters believe that it would be impossible to find someone who is qualified to do verification that could pass those requirements due to the interrelationship between the production and support companies over decades of working with one another. Some commenters contend that the EPA overestimates the availability of qualified third-party consultants, assuming that an impartial one could be found, that understands the industry well enough to competently review designs for closed vent systems.
 	Some of the commenters remind the EPA of the conclusions the Agency reached after proposing a similar third-party verification system for the Greenhouse Gas Reporting Program, in which the EPA expressed concerns about establishing third-party verification protocols, developing a system to accredit third-party verifiers, and developing a system to ensure impartiality.
 Response: The EPA continues to believe that independent third party verification can furnish more, and sometimes better, data about regulatory compliance. With better data about compliance, regulatory agencies, including the EPA, would have more information to determine what types of regulations are effective and how to spend their resources. A critical element to independent third party verification is to ensure third-party verifiers are truly independent from their clients and perform competently. We continue to believe that this model best limits the risk of bias or "capture" due to the third-party verifier identifying or aligning his interests too closely with those of the client. However, in other rulemakings, we have explored and implemented an alternative to the independent third party verification, where engineering design is the element we wish to ensure is examined and implemented without bias. This is the "qualified professional engineer" model. In the ``Resource Conservation and Recovery Act (RCRA) Burden Reduction Initiative'' (Burden Reduction Rule) (71 FR 16826, April 4, 2006) and the ``Oil Pollution Prevention and Response; Non-Transportation-Related Onshore and Offshore Facilities rule (67 FR 47042, July 17, 2002), the Agency came to similar conclusions. First, that professional engineers, whether independent or employees of a facility, being professionals, will uphold the integrity of their profession and only certify documents that meet the prescribed regulatory requirements and that the integrity of both the professional engineer and the professional oversight of boards licensing professional engineers are sufficient to prevent any abuses. And second, that in-house professional engineers may be the persons most familiar with the design and operation of the facility and that a restriction on in-house professional certifications might place an undue and unnecessary financial burden on owners or operators of facilities by forcing them to hire an outside engineer. Also in the ``Burden Reduction Rule'' the Agency concluded that a professional engineer is able to give fair and technical review because of the oversight programs established by the state licensing boards that will subject the professional engineer to penalties, including the loss of license and potential fines if certifications are provided when the facts do not warrant it. A qualified professional engineer maintains the most important components of any certification requirement: (1) That the engineer be qualified to perform the task based on training and experience; and (2) that she or he be a professional engineer licensed to practice engineering under the title Professional Engineer which requires following a code of ethics with the potential of losing his/her license for negligence (see 71 FR 16868, April 4, 2006). The personal liability of the professional engineer provides strong support for both the requirement that certifications must be performed by licensed professional engineers. The Agency is convinced that an employee of a facility, who is a qualified professional engineer and who has been licensed by a state licensing board, would be no more likely to be biased than a qualified professional engineer who is not an employee of the owner or operator. The EPA has concluded that the programs established by state licensing boards provide sufficient guarantees that a professional engineer, regardless of whether he/she is ``independent'' of the facility, will give a fair technical review. As an additional protection, the Agency has re-evaluated the design criteria for closed vent systems to ensure that the requirements are sufficiently objective and technically precise, while providing site specific flexibility, that a qualified professional engineer will be able to certify that they have been met.
       It is important to reiterate that state licensing boards can investigate complaints of negligence or incompetence on the part of professional engineers and may impose fines and other disciplinary actions, such as cease-and-desist orders or license revocation. (See 71 FR 16868.) In light of the third party oversight provided by the state licensing boards in combination with the numerous recordkeeping and recording requirements established in this rule, the Agency is confident that abuses of the certification requirements will be minimal and that human health and the environment will be protected.
       In other rulemakings, which have allowed for a qualified professional engineer in lieu of an independent reviewer, the Agency has required that the professional engineer be licensed in the state in which the facility is located. (See "Hazardous and Solid Waste Management System; Disposal of Coal Combustion Residuals from Electric Utilities; Final Rule" (Coal Ash Rule) (80 FR 21302, April 17, 2015)). The Agency has made this decision, in that rule, for a number of reasons, but primarily because state licensing boards can provide the necessary oversight on the actions of the professional engineer and investigate complaints of negligence or incompetence as well as impose fines and other disciplinary actions such as cease-and-desist orders or license revocation. The Agency concluded that oversight may not be as rigorous if the professional engineer is operating under a license issued from another state. While we believe this is the appropriate outcome for the Coal Ash Rule, in part due to the regional and geological conditions specific to the landfill design, we do not believe that we need to provide this restriction for the closed vent system design under this rulemaking. Closed vent system design elements are not predicated on regional characteristics but instead follow generally and widely understood engineering analysis such as volumetric flow, back pressure and pressure drops. We do believe that the professional engineer should be licensed in a minimum of one of the states in which the certifying official does business.
       Whether to specify independent third-party reporting, some other type of third-party or self-reporting, or a Professional Engineer is a case-specific decision that will vary depending on the nature of the rule, the characteristics of the sector(s) and regulated entities, and the applicable regulatory requirements. Based on all relevant factors for this rule, the EPA has determined that a qualified Professional Engineer approach is appropriate and that it is unnecessary to require the individual making certifications under this rule to be ``independent third parties.'' Thus the final rule does not prohibit an employee of the facility from making the certification, provided they are a professional engineer that is licensed by a state licensing board.
 3. The EPA's Authority and Costs for Standards Reflecting Next Generation Compliance and Rule Effectiveness
 Comment: Several commenters believe that standards reflecting Next Generation Compliance and rule effectiveness strategies discussed in the preamble to the proposed rule are not legal and represent an overreach of its authority. While the EPA has authority to require reasonable recordkeeping, reporting and monitoring under the CAA, there is nothing in the CAA that can be construed to authorize the EPA to force the regulated community to hire a third-party contractor to do the EPA's work. The commenters point out that the EPA admitted in the preamble to the 2011 proposal of subpart OOOO that ensuring compliance with the well completion requirements would be very difficult and burdensome for regulatory agencies. The commenters believe that the EPA is using the requirements to relieve the regulatory agencies of some of this burden. One commenter stated that the requirements amount to an unfunded enforcement mandate on the facilities it is supposed to be regulating.
 	The commenters also state that the compliance requirements would violate the Anti-Deficiency Act because the third-party verification requirements would circumvent budget appropriations for EPA enforcement activities (see 31 U.S.C. 1341(a)(1)(A)).
 	Some of the commenters also object to the EPA justifying increased monitoring, recordkeeping and reporting requirements on consent decrees in enforcement actions. The commenters point out that consent decrees impose more stringent requirements on facilities that have been found to be in violation of a regulatory requirement; therefore, consent decree requirements would be inappropriate for generally applicable regulations. The commenters state that the EPA has provided no justification for imposing heightened requirements on all facilities regardless of their compliance history.
 	Several commenters also state that the EPA must propose the regulatory language for all of the compliance provisions reflecting Next Generation Compliance and rule effectiveness strategies before they can be finalized and doing otherwise would raise a notice and comment issue. One commenter added that the EPA's intent is to apply such compliance requirements to more industries than just oil and natural gas production. Therefore, the EPA must separately propose the compliance requirements in their entirety, including estimated costs and benefits, before using them in any specific rulemakings.
 	Many commenters believe the standards reflecting Next Generation and rule effectiveness strategies will add significant labor and cost burdens over and above the compliance costs that the EPA already estimated for complying with the proposed rule. For example, one commenter calculates that their company will have to generate 270,000 closed vent system monthly inspection reports in the first five years of the rule if current requirements are finalized. Another commenter estimates the cost of installing continuous pressure monitoring equipment at a single site to be $20,000, resulting in potential company-wide costs of about $15 million. One commenter adds, based on their own experience with third-party auditors, the cost of an audit can range from $8,000 to $15,000 per audit, per facility. In general, the commenters state that the compliance requirements raise technical and operational complexities which can only result in increased costs. Some of the commenters note that these costs would be untenable for small businesses.
 	Some of the commenters also expressed concern about a lack of necessary IT infrastructure, such as data acquisition hardware, data management software, and appropriate software, at remote oil and natural gas production and transmission facilities. The commenters also point out the lack of electricity at these sites. The commenters point out that dealing with these issues further increase the costs associated with these compliance measures.
 Response: The EPA believes that the comment regarding our legal authority may be based upon a misunderstanding of EPA's Next Generation Compliance and rule effectiveness strategies. The EPA describes these strategies as follows:
 	"Today's pollution challenges require a modern approach to compliance, taking advantage of new tools and approaches while strengthening vigorous enforcement of environmental laws. Next Generation Compliance is EPA's integrated strategy to do that, designed to bring together the best thinking from inside and outside EPA." Among the referenced modern approaches to compliance is to "[d]esign regulations and permits that are easier to implement, with a goal of improved compliance and environmental outcomes."
 	Thus EPA's Next Generation Compliance and rule effectiveness strategies, in and of themselves, impose no requirements or obligations on the regulated community. The strategies establish no regulatory terms for any sector or facility nor create rights or responsibilities in any party. Rather, the strategies describe general compliance assurance and regulatory design principles, approaches, and tools that EPA may consider in conducting rulemaking, permitting, and compliance assurance, and enforcement activities.
       Regarding comments that in order to avoid notice and comment issues the EPA must propose regulatory language before finalizing any regulatory language, the EPA disagrees. Section 307(d)(3) of the CAA states that "notice of proposed rulemaking shall be published in the Federal Register, as provided under section 553(b) of title 5, United States Code...." There is nothing in the remainder of section 307(d) that requires the EPA to publish the regulatory text. Similarly, section 553(b) of the Administrative Procedure Act (APA) does not require agencies to publish the actual regulatory text. See EMILY's List v. FEC, 362 F. Supp. 2d 43, 53 (D.D.C. 2005), where "[t]he Court notes that section 553 itself does not require the Agency to publish the text of a proposed rule, since the Agency is permitted to publish 'either the terms or substance of the proposed rule or a description of the subjects and issues involved.'". For this rulemaking, the EPA has provided notice and opportunity to comment for all of the specific regulatory requirements applicable to the sector and facilities covered by the rulemaking, either through proposed regulatory language or a description in the preamble.
 	The EPA notes that the proposal for independent third party verification  -  replaced in the final rule with qualified Professional Engineer requirements  -  reflects the responsibility of regulated entities to comply with the new NSPS. CAA Section 111(a)(1) defines "a standard of performance" as "a standard for emissions of air pollutants which reflects the degree of emission limitation achievable through the application of the best system of emission reduction which (taking into account the cost of achieving such reduction and any non-air quality health and environmental impact and energy requirement) the Administrator determines has been adequately demonstrated." Further, in directing the Administrator to propose and promulgate regulations under section 111(b)(1)(B), Congress provided that the Administrator should take comment and then finalize the standards with such modifications "as he deems appropriate." The DC Circuit has considered similar statutory phrasing from CAA section 231(a)(3) and concluded that "[t]his delegation of authority is both explicit and extraordinarily broad." National Assoc. of Clean Air Agencies v. EPA, 489 F.3d 1221, 1229 (D.C. Cir. 2007).
 	In addition, the information to be collected for the proposed NSPS is based on notification, performance tests, recordkeeping and reporting requirements which will be mandatory for all operators subject to the final standards. Recordkeeping and reporting requirements are specifically authorized by section 114 of the CAA (42 U.S.C. 7414) which provides that for "any standard of performance under section 7411," the Administrator may require the sources to, among other things, "install, use, and maintain such monitoring equipment, and use such audit procedures, or methods" and submit compliance certifications in accordance with subsection (a)(3) of this section," as the Administrator may require. CAA section 114(a)(1)(A)-(G).
       As discussed in section VI and in this section, the EPA has determined that to comply with the new NSPS and meet its emissions standard, regulated entities must obtain certifications from qualified Professional Engineers to demonstrate technical infeasibility to connect a pneumatic pump to an existing control device and to ensure the proper closed vent system design. The EPA believes for the sources covered by this rule, a professional engineer can furnish more, and sometimes better, data about regulatory compliance, especially where engineering design (e.g., closed vent system design) is the element we want to ensure is examined and implemented without bias.
       The EPA notes that nothing in this rule relieves the EPA of any of its responsibilities under the CAA or implies that the EPA will not continue to use its enforcement authorities under the CAA or devote resources to monitoring and enforcing this rule. This rule simply ensures that regulated parties will have the tools available to assess and ensure their own compliance.
 	The EPA wishes to explain that unfunded mandates are typically rules that impose significant obligations, without funding, on state, local, or tribal governments. Interpreting this comment as applying to the obligations this NSPS imposes on entities to which it will apply, all rules, by definition, impose some obligations and responsibilities on subject facilities. In this preamble, the EPA explains the benefits, costs, and justification for each regulatory requirement.
       As discussed above, the EPA explains the emission standards in this NSPS apply to the subject regulated entities. The EPA remains responsible for ensuring and enforcing compliance with the rule. The EPA notes that nothing in this rule relieves the EPA of any of its responsibilities under the CAA to ensure and enforce regulatory compliance.
 	The EPA agrees, that if the EPA were to seek to apply the standards in this rule  -  or any other regulatory standards, reflecting the Agency's Next Generation Compliance and rule effectiveness strategies or otherwise  -  to additional sectors beyond oil and natural gas production, the EPA would need to separately propose and justify the standards. As discussed above, however, the EPA's Next Generation Compliance and rule effectiveness strategies, in and of themselves, impose no requirements on the regulated community. The strategies prescribe no specific regulatory terms for any sector or facility nor do they create rights or responsibilities in any party. Rather, they describe compliance assurance and regulatory design strategies and approaches that the EPA will consider in conducting rulemaking, permitting, and compliance assurance, and enforcement activities that are inappropriate for notice and comment rulemaking. If the EPA believes that these strategies and approaches should be applied in other circumstances and to other industry sectors, the Agency will do this through other regulatory actions.
       The EPA agrees with the commenters that certain of the Next Generation and rule effectiveness strategies are the result of information that the Agency has gained from implementation of past consent decrees (e.g., closed vent system design and fugitives monitoring program audit). It is not unusual for the Agency to require additional monitoring practices, and recordkeeping and reporting requirements through consent, as this provides us an opportunity to identify the effectiveness of these standards from those companies that have engaged in violative conduct. Furthermore, through our enforcement efforts, when we see common and widespread compliance problems that can be addressed through improved monitoring, reporting and recordkeeping practices, it is our duty to include these tools in rulemaking, resulting in greater environmental benefit. As discussed elsewhere in this preamble, we are not requiring an "independent third party" verification of closed vent system design, nor are we requiring that the fugitive emissions monitoring program be audited. However, because of the widespread issues we have found with closed vent system design, the Agency will require a certification by a qualified professional engineer.
       Regarding the comment about necessary IT infrastructure, such as data acquisition hardware, data management software, and appropriate software, at remote oil and natural gas production and transmission facilities and the lack of electricity at these sites, the Agency does not believe that the next generation and rule effectiveness initiatives we are proposing directly require IT infrastructure beyond that already required by other aspects of the rule. Likewise, onsite electrical availability for remote well sites is not an issue for the Next Generation and Rule Effectiveness strategies that we are finalizing.
 IX. Impacts of the Final Amendments
A. What are the air impacts?
	For this action, the EPA estimated the emission reductions that will occur due to the implementation of the final emission limits. The EPA estimated emission reductions based on the control technologies proposed as the BSER. This analysis estimates regulatory impacts for the analysis years of 2020 and 2025. The analysis of 2020 represents the accumulation of new and modified sources from the first full year of compliance, 2016, through 2020 to illustrate the near-term impacts of the rule. The regulatory impact estimates for 2020 include sources newly affected in 2020 as well as the accumulation of affected sources from 2016 to 2019 that are also assumed to be in continued operation in 2020, thus incurring compliance costs and emissions reductions in 2020. We also estimate impacts in 2025 to illustrate the continued compound effect of this rule over a longer period. The regulatory impact estimates for 2025 include sources newly affected in 2025 as well as the accumulation of affected sources from 2016 to 2024 that are also assumed to be in continued operation in 2025, thus incurring compliance costs and emissions reductions in 2025.
      In 2020, we have estimated that the final NSPS would reduce about 300,000 tons of methane emissions and 150,000 tons of VOC emissions from affected facilities. In 2025, we have estimated that the proposed NSPS would reduce about 510,000 tons of methane emissions and 210,000 tons of VOC emissions from affected facilities. The NSPS is also expected to concurrently reduce about 1,900 tons HAP in 2020 and 3,900 tons HAP in 2025.
      As described in the TSD and RIA for this rule, the EPA projected affected facilities using a combination of historical data from the United States GHG Inventory, and projected activity levels, taken from the Energy Information Administration (EIA's) Annual Energy Outlook (AEO). The EPA also considered state regulations with similar requirements to the final NSPS in projecting affected sources for impacts analyses supporting this rule.
B. What are the energy impacts?
	Energy impacts in this section are those energy requirements associated with the operation of emission control devices. Potential impacts on the national energy economy from the rule are discussed in the economic impacts section. There would be little national energy demand increase from the operation of any of the environmental controls expected to be used for compliance with the final NSPS.
	The final NSPS encourages the use of emission controls that recover hydrocarbon products, such as methane, that can be used onsite as fuel or reprocessed within the production process for sale. We estimate that the standards will result in a total cost of about $320 million in 2020 and $530 million in 2025 (in 2012 dollars).
C. What are the compliance costs?
	The EPA estimates the total capital cost of the final NSPS will be $250 million in 2020 and $360 million in 2025. The estimate of total annualized engineering costs of the final NSPS is $390 million in 2020 and $640 million in 2025. This annual cost estimate includes capital, operating, maintenance, monitoring, reporting, and recordkeeping costs. This estimated annual cost does not take into account any producer revenues associated with the recovery of salable natural gas. The EPA estimates that about 16 billion cubic feet in 2020 and 27 billion cubic feet of natural gas in 2025 will be recovered by implementing the NSPS. In the engineering cost analysis, we assume that producers are paid $4 per thousand cubic feet (Mcf) for the recovered gas at the wellhead. After accounting for these revenues, the estimate of total annualized engineering costs of the final NSPS are estimated to be $320 million in 2020 and $530 million in 2025. The price assumption is influential on estimated annualized engineering costs. A simple sensitivity analysis indicates $1/Mcf change in the wellhead price causes a change in estimated engineering compliance costs of about $16 million in 2020 and $27 million in 2025.
D. What are the economic and employment impacts?
      The EPA used the National Energy Modeling System (NEMS) to estimate the impacts of the final rule on the United States energy system. The NEMS is a publically-available model of the United States energy economy developed and maintained by the EIA and is used to produce the AEO, a reference publication that provides detailed forecasts of the United States energy economy.
      The EPA estimate that natural gas and crude oil drilling levels decline slightly over the 2020 to 2025 period relative to the baseline (by about 0.17 percent for natural gas wells and about 0.02 percent for crude oil wells). Natural gas production decreases slightly over the 2020 to 2025 period relative to the baseline (by about 0.03 percent), while crude oil production does not vary appreciably. Crude oil wellhead prices for onshore lower 48 production are not estimated to change appreciably over the 2020 to 2025 period relative to the baseline. However, wellhead natural gas prices for onshore lower 48 production are estimated to increase slightly over the 2020 to 2025 period relative to the baseline (about 0.20 percent). Net imports of natural gas are estimated to increase slightly over the 2020 to 2025 period relative to the baseline (by about 0.11 percent). Crude oil net imports are not estimated to change appreciably over the 2020 to 2025 period relative to the baseline.
      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 particular concern in the current economic climate given continued interest in the employment impact of regulations such as this final rule.
      The EPA estimated the labor impacts due to the installation, operation, and maintenance of control equipment, control activities, and labor associated with new reporting and recordkeeping requirements. We estimated up-front and continual, annual labor requirements by estimating hours of labor required for compliance and converting this number to full-time equivalents (FTEs) by dividing by 2,080 (40 hours per week multiplied by 52 weeks). The up-front labor requirement to comply with the proposed NSPS is estimated at about 270 FTEs in both 2020 and 2025. The annual labor requirement to comply with final NSPS is estimated at about 1,100 FTEs in 2020 and 1,800 FTEs in 2025.
      We note that this type of FTE estimate cannot be used to identify the specific number of employees involved or whether new jobs are created for new employees versus displacing jobs from other sectors of the economy.
E. What are the benefits of the final standards?
	The final rule is expected to result in significant reductions in emissions. In 2020, the final rule is anticipated to reduce 300,000 short tons, or 280,000 metric tons, of methane (a GHG and a precursor to tropospheric ozone formation), 150,000 tons of VOC (a precursor to both PM (2.5 microns and less) (PM2.5) and ozone formation), and 1,900 tons of HAP. In 2025, the final rule is anticipated to reduce 510,000 short tons (460,000 metric tons) of methane, 210,000 tons of VOC, and 3,900 tons of HAP. These pollutants are associated with substantial health effects, climate effects, and other welfare effects.
      The final standards are expected to reduce methane emissions annually by about 6.9 million metric tons CO2 Eq. in 2020 and by about 11 million metric tons CO2 Eq. in 2025. It is important to note that the emission reductions are based upon predicted activities in 2020 and 2025; however, the EPA did not forecast sector-level emissions in 2020 and 2025 for this rulemaking. To give a sense of the magnitude of the reductions, the methane reductions expected in 2020 are equivalent to about 2.8 percent of the methane emissions for this sector reported in the United States GHG Inventory for 2014 (about 232 million metric tons CO Eq. from petroleum and natural gas production and gas processing, transmission, and storage). Expected reductions in 2025 are equivalent to around 4.7 percent of 2014 emissions. As it is expected that emissions from this sector would increase over time, the estimates compared against the 2014 emissions would likely overestimate the percent of reductions from total emissions in 2020 and 2025.
      Methane is a potent GHG that, once emitted into the atmosphere, absorbs terrestrial infrared radiation that contributes to increased global warming and continuing climate change. Methane reacts in the atmosphere to form tropospheric ozone and stratospheric water vapor, both of which also contribute to global warming. When accounting for the impacts of changing methane, tropospheric ozone, and stratospheric water vapor concentrations, the Intergovernmental Panel on Climate Change (IPCC) 5th Assessment Report (2013) found that historical emissions of methane accounted for about 30 percent of the total current warming influence (radiative forcing) due to historical emissions of GHGs. Methane is therefore a major contributor to the climate change impacts described previously. In 2013, total methane emissions from the oil and natural gas industry represented nearly 29 percent of the total methane emissions from all sources and account for about 3 percent of all CO2-equivalent emissions in the United States, with the combined petroleum and natural gas systems being the largest contributor to United States anthropogenic methane emissions.
      We calculated the global social benefits of methane emission reductions expected from the final NSPS standards for oil and natural gas sites using estimates of the social cost of methane (SC-CH4), a metric that estimates the monetary value of impacts associated with marginal changes in methane emissions in a given year. The SC-CH4 estimates applied in this analysis were developed by Marten et al. (2014) and are discussed in greater detail below.
      A similar metric, the social cost of CO2 (SC-CO2), provides important context for understanding the Marten et al. SC-CH4 estimates. The SC-CO2 is a metric that estimates the monetary value of impacts associated with marginal changes in CO2 emissions in a given year. Similar to the SC-CH4, it includes a wide range of anticipated climate impacts, such as net changes in agricultural productivity, property damage from increased flood risk, and changes in energy system costs, such as reduced costs for heating and increased costs for air conditioning. Estimates of the SC-CO2 have been used by the EPA and other federal agencies to value the impacts of CO2 emissions changes in benefit cost analysis for GHG-related rulemakings since 2008.
      The SC-CO2 estimates were developed over many years, using the best science available, and with input from the public. Specifically, an interagency working group (IWG) that included the EPA and other executive branch agencies and offices used three integrated assessment models (IAMs) to develop the SC-CO2 estimates and recommended four global values for use in regulatory analyses. The SC-CO2 estimates were first released in February 2010 and updated in 2013 using new versions of each IAM. The 2010 SC-CO2 Technical Support Document (2010 TSD) provides a complete discussion of the methods used to develop these estimates and the current SC-CO2 TSD presents and discusses the 2013 update (including recent minor technical corrections to the estimates).
      The SC-CO2 TSDs discuss a number of limitations to the SC-CO2 analysis, including the incomplete way in which the IAMs capture catastrophic and non-catastrophic impacts, their incomplete treatment of adaptation and technological change, uncertainty in the extrapolation of damages to high temperatures, and assumptions regarding risk aversion. Currently, IAMs do not assign value to all of the important physical, ecological, and economic impacts of climate change recognized in the climate change literature due to a lack of precise information on the nature of damages and because the science incorporated into these models understandably lags behind the most recent research. Nonetheless, these estimates and the discussion of their limitations represent the best available information about the social benefits of CO2 reductions to inform benefit-cost analysis. The EPA and other agencies continue to engage in research on modeling and valuation of climate impacts with the goal to improve these estimates and continue to consider feedback on the SC-CO2 estimates from stakeholders through a range of channels, including public comments on Agency rulemakings, a separate Office of Management and Budget (OMB) public comment solicitation, and through regular interactions with stakeholders and research analysts implementing the SC-CO2 methodology. See the RIA of this rule for additional details.
       A challenge particularly relevant to this rule is that the IWG did not estimate the social costs of non-CO2 GHG emissions at the time the SC-CO2 estimates were developed. In addition, the directly modeled estimates of the social costs of non-CO2 GHG emissions previously found in the published literature were few in number and varied considerably in terms of the models and input assumptions they employed (EPA 2012). In the past, EPA has sought to understand the potential importance of monetizing non-CO2 GHG emissions changes through sensitivity analysis using an estimate of the GWP of methane to convert emission impacts to CO2 equivalents, which can then be valued using the SC-CO2 estimates. This approach approximates the social cost of methane (SC-CH4) using estimates of the SC-CO2 and the GWP of methane.
      The published literature documents a variety of reasons that directly modeled estimates of SC-CH4 are an analytical improvement over the estimates from the GWP approximation approach. Specifically, several recent studies found that GWP-weighted benefit estimates for methane are likely to be lower than the estimates derived using directly modeled social cost estimates for these gases. The GWP reflects only the relative integrated radiative forcing of a gas over 100 years in comparison to CO2. The directly modeled social cost estimates differ from the GWP-scaled SC-CO2 because the relative differences in timing and magnitude of the warming between gases are explicitly modeled, the non-linear effects of temperature change on economic damages are included, and rather than treating all impacts over a hundred years equally, the modeled damages over the time horizon considered (300 years in this case) are discounted to present value terms. A detailed discussion of the limitations of the GWP approach can be found in the RIA.
      In general, the commenters on previous rulemakings strongly encouraged the EPA to incorporate the monetized value of non-CO2 GHG impacts into the benefit cost analysis. However, they noted the challenges associated with the GWP approach, as discussed above, and encouraged the use of directly modeled estimates of the SC-CH4 to overcome those challenges.
      Since then, a paper by Marten et al. (2014) has provided the first set of published SC-CH4 estimates in the peer-reviewed literature that are consistent with the modeling assumptions underlying the SC-CO2 estimates.[,] Specifically, the estimation approach of Marten et al. used the same set of three IAMs, five socioeconomic and emissions scenarios, equilibrium climate sensitivity distribution, three constant discount rates, and aggregation approach used by the IWG to develop the SC-CO2 estimates.
      The SC-CH4 estimates from Marten et al. (2014) are presented below in Table 8. More detailed discussion of the SC-CH4 estimation methodology, results and a comparison to other published estimates can be found in the RIA and in Marten et al.
TABLE 8: SOCIAL COST OF CH4, 2012  -  2050[a] [in 2012$ per metric ton] (Source: Marten et al., 2014[b])
Year
                                    SC-CH4

                                      5%
                                    Average
                                      3%
                                    Average
                                     2.5%
                                    Average
                                      3%
                                95th percentile
2012
                                     $430
                                     $1000
                                     $1400
                                     $2800
2015
                                      490
                                     1100
                                     1500
                                     3000
2020
                                      580
                                     1300
                                     1700
                                     3500
2025
                                      700
                                     1500
                                     1900
                                     4000
2030
                                      820
                                     1700
                                     2200
                                     4500
2035
                                      970
                                     1900
                                     2500
                                     5300
2040
                                     1100
                                     2200
                                     2800
                                     5900
2045
                                     1300
                                     2500
                                     3000
                                     6600
2050
                                     1400
                                     2700
                                     3300
                                     7200
Notes:
a There are four different estimates of the SC-CH4, each one emissions-year specific. The first three shown in the table are based on the average SC-CH4 from three integrated assessment models at discount rates of 5, 3, and 2.5 percent. The fourth estimate is the 95th percentile of the SC-CH4 across all three models at a 3 percent discount rate. See RIA for details.
b The estimates in this table have been adjusted to reflect the minor technical corrections to the SC-CO2 estimates described above. See the Corrigendum to Marten et al. (2014), http://www.tandfonline.com/doi/abs/10.1080/14693062.2015.1070550.

      The application of these directly modeled SC-CH4 estimates from Marten et al. (2014) in a benefit-cost analysis of a regulatory action is analogous to the use of the SC-CO2 estimates. In addition, the limitations for the SC-CO2 estimates discussed above likewise apply to the SC-CH4 estimates, given the consistency in the methodology.
      In early 2015, the EPA conducted a peer review of the application of the Marten et al. (2014) non-CO2 social cost estimates in regulatory analysis and received responses that supported this application. See the RIA for a detailed discussion.
      The EPA also carefully considered the full range of public comments and associated technical issues on the Marten et al. SC-CH4 estimates received through this rulemaking. The comments addressed the technical details of the SC-CO2 estimates and the Marten et al. SC-CH4 estimates as well as their application to this rulemaking analysis. The commenters also provided constructive recommendations to improve the SC-CO2 and SC-CH4 estimates in the future. Based on the evaluation of the public comments on this rulemaking, the favorable peer review of the Marten et al. application, and past comments urging the EPA to value non-CO2 GHG impacts in its rulemakings, the EPA concluded that the estimates represent the best scientific information on the impacts of climate change available in a form appropriate for incorporating the damages from incremental methane emissions changes into regulatory analysis. The EPA has included those benefits in the main benefits analysis. See the RTC document for the complete response to comments received on the SC-CH4 as part of this rulemaking.
      The methane benefits calculated using Marten et al. (2014) are presented in Table 9 for years 2020 and 2025. Applying this approach to the methane reductions estimated for the NSPS, the 2020 methane benefits vary by discount rate and range from about $160 million to approximately $960 million; the mean SC-CH4 at the 3-percent discount rate results in an estimate of about $360 million in 2020. The methane benefits increase in the 2025, ranging from $320 million to $1.8 billion, depending on discount rate used; the mean SC-CH4 at the 3-percent discount rate results in an estimate of about $690 million in 2025.
           TABLE 9: ESTIMATED GLOBAL BENEFITS OF METHANE REDUCTIONS
                             (in millions, 2012$)
                          Discount rate and statistic
                                     Year

                                     2020
                                     2025
                            Million metric tonnes
                              of methane reduced
                                     0.28
                                     0.46
                            Million metric tonnes
                                  of CO2 Eq.
                                      6.9
                                      11
                                 5% (average)
                                     $160
                                     $320
                                 3% (average)
                                     $360
                                     $690
                                2.5% (average)
                                     $480
                                     $890
                            3% (95[th] percentile)
                                     $960
                                    $1,800

      In addition to the limitation discussed above, and the referenced documents, there are additional impacts of individual GHGs that are not currently captured in the IAMs used in the directly modeled approach of Marten et al. (2014) and, therefore, not quantified for the rule. For example, in addition to being a GHG, methane is a precursor to ozone. The ozone generated by methane has important non-climate impacts on agriculture, ecosystems, and human health. The RIA describes the specific impacts of methane as an ozone precursor in more detail and discusses studies that have estimated monetized benefits of these methane generated ozone effects. The EPA continues to monitor developments in this area of research.
	With the data available, we are not able to provide credible health benefit estimates for the reduction in exposure to HAP, ozone and PM2.5 for these rules, due to the differences in the locations of oil and natural gas emission points relative to existing information and the highly localized nature of air quality responses associated with HAP and VOC reductions. This is not to imply that there are no benefits of the rules; rather, it is a reflection of the difficulties in modeling the direct and indirect impacts of the reductions in emissions for this industrial sector with the data currently available. In addition to health improvements, there will be improvements in visibility effects, ecosystem effects and climate effects, as well as additional product recovery.
	Although we do not have sufficient information or modeling available to provide quantitative estimates for this rulemaking, we include a qualitative assessment of the health effects associated with exposure to HAP, ozone and PM2.5 in the RIA for this rule. These qualitative effects are briefly summarized below, but for more detailed information, please refer to the RIA, which is available in the docket. One of the HAP of concern from the oil and natural gas sector is benzene, which is a known human carcinogen. VOC emissions are precursors to both PM2.5 and ozone formation. As documented in previous analyses (U.S. EPA, 2006, U.S. EPA, 2010, and U.S. EPA, 2014), exposure to PM2.5 and ozone is associated with significant public health effects. PM2.5 is associated with health effects, including premature mortality for adults and infants, cardiovascular morbidity such as heart attacks, and respiratory morbidity such as asthma attacks, acute bronchitis, hospital admissions and emergency room visits, work loss days, restricted activity days and respiratory symptoms, as well as visibility impairment. Ozone is associated with health effects, including hospital and emergency department visits, school loss days and premature mortality, as well as injury to vegetation and climate effects.
	Finally, the control techniques to meet the standards are anticipated to have minor secondary emissions impacts, which may partially offset the direct benefits of this rule. The magnitude of these secondary air pollutant impacts is small relative to the direct emission reductions anticipated from this rule.
      In particular, the EPA has estimated that an increase in flaring of natural gas in response to this rule will produce a variety of emissions, including about 1.0 million short tons of CO2 in 2020 and about 1.2 million short tons of CO2 in 2025. The EPA has not estimated the monetized value of the secondary emissions of CO2 because much of the VOCs and methane that would have been released in the absence of the flare would have eventually oxidized into CO2 in the atmosphere. Note that the CO2 produced from the methane oxidizing in the atmosphere is not included in the calculation of the SC-CH4.
      For VOC emissions, the oxidization period is relatively short, on the order of a couple of weeks. However, for methane, the oxidization period is longer, on the order of a decade, and the EPA recognizes that because the growth rate of the SC-CO2 estimates are lower than their associated discount rates, the estimated impact of CO2 produced in the future via oxidized methane from fossil-based emissions may be less than the estimated impact of CO2 released immediately from combustion. This would imply a small disbenefit associated with the earlier release of CO2 during combustion of the methane emissions.
      In the proposal, the EPA solicited comment on the appropriateness of monetizing the impact of the earlier release of CO2 due to combusting methane emissions from oil and gas sites and an illustrative analysis that described a potential approach to approximate this value using the SC-CO2. The EPA did not receive any comments regarding the appropriate methodology for conducting such an analysis, but did receive one comment letter that voiced general support for monetizing the secondary impacts. In consideration of this comment and recognizing the challenges and uncertainties related to estimation of these secondary emissions impacts for this rulemaking, EPA has continued to examine this issue in the context of this regulatory analysis (i.e., the combusting of fossil-based methane at oil and gas sites) and explored ways to improve the illustrative analysis. See RIA for details.
X. Statutory and Executive Order Reviews
      Additional information about these statutes and Executive Orders can be found at http://www2.epa.gov/laws-regulations/laws-and-executive-orders.
A. Executive Order 12866: Regulatory Planning and Review and Executive Order 13563: Improving Regulation and Regulatory Review
	This action is an economically significant regulatory action that was submitted to the Office of Management and Budget (OMB) for review. Any changes made in response to OMB recommendations have been documented in the docket. The EPA prepared an analysis of the potential costs and benefits associated with this action.
	In addition, the EPA prepared a Regulatory Impact Analysis (RIA) of the potential costs and benefits associated with this action. The RIA available in the docket describes in detail the empirical basis for the EPA's assumptions and characterizes the various sources of uncertainties affecting the estimates below. Table 10 shows the results of the cost and benefits analysis for the final rule.
TABLE 10. SUMMARY OF THE MONETIZED BENEFITS, SOCIAL COSTS AND NET BENEFITS FOR THE FINAL OIL AND NATURAL GAS NSPS IN 2020 AND 2025 (MILLIONS OF 2012$)

                                     2020
                                     2025
Total Monetized Benefits[1]
                                 $360 million
                                 $690 million
Total Costs[2]
                                 $320 million
                                 $530 million
Net Benefits[3]
                                  $35 million
                                 $170 million

Non-monetized Benefits

Non-monetized climate benefits

Health effects of PM2.5 and ozone exposure from 150,000 tons of VOC in 2020 and 210,000 tons of VOC in 2025

Health effects of HAP exposure from 1,900 tons of HAP in 2020 and 3,900 tons of HAP in 2025

Health effects of ozone exposure from 300,000 tons of methane in 2020 and 510,000 tons methane in 2025

Visibility impairment

Vegetation effects
1 We estimate methane benefits associated with four different values of a one ton methane reduction (model average at 2.5 percent discount rate, 3 percent, and 5 percent; 95th percentile at 3 percent). For the purposes of this table, we show the benefits associated with the model average at 3 percent discount rate, however we emphasize the importance and value of considering the full range of social cost of methane values. We provide estimates based on additional discount rates in preamble section IX.E and in the RIA. The CO2-equivalent (CO2 Eq.) methane emission reductions are 6.9 million metric tons in 2020 and 11 million metric tons in 2025. Also, the specific control technologies for the proposed NSPS are anticipated to have minor secondary disbenefits.
[2] The engineering compliance costs are annualized using a 7 percent discount rate and include estimated revenue from additional natural gas recovery as a result of the NSPS. When rounded, the cost estimates are the same for the 3 percent discount rate as they are for the 7 percent discount rate cost estimates, so rounded net benefits do not change when using a 3 percent discount rate.
[3] Figures may not sum due to rounding.

B. Paperwork Reduction Act (PRA)
      The Office of Management and Budget (OMB) has previously approved the information collection activities contained in 40 CFR part 60, subpart OOOO under the PRA and has assigned OMB control number 2060-0673 and ICR number 2437.01; a summary can be found at 77 FR 49537. The information collection requirements in the final action titled, Standards of Performance for Crude Oil and Natural Gas Facilities for Construction, Modification, or Reconstruction (40 CFR part 60 subpart OOOOa) have been submitted for approval to the OMB under the PRA. The ICR document prepared by the EPA has been assigned EPA ICR Number 2523.01. You can find a copy of the ICR in the docket for this rule, and is briefly summarized below.
      The information to be collected for the final NSPS is based on notification, performance tests, recordkeeping and reporting requirements which will be mandatory for all operators subject to the final standards. Recordkeeping and reporting requirements are specifically authorized by section 114 of the CAA (42 U.S.C. 7414). The information will be used by the delegated authority (state agency, or Regional Administrator if there is no delegated state agency) to ensure that the standards and other requirements are being achieved. Based on review of the recorded information at the site and the reported information, the delegated permitting authority can identify facilities that may not be in compliance and decide which facilities, records, or processes may need inspection. All information submitted to the EPA pursuant to the recordkeeping and reporting requirements for which a claim of confidentiality is made is safeguarded according to Agency policies set forth in 40 CFR part 2, subpart B.
      Potential respondents under subpart OOOOa are owners or operators of new, modified or reconstructed oil and natural gas affected facilities as defined under the rule. None of the facilities in the United States are owned or operated by state, local, tribal or the Federal government. All facilities are privately owned for-profit businesses. The requirements in this action result in industry recording keeping and reporting burden associated with review of the requirements for all affected entities, gathering relevant information, performing initial performance tests and repeat performance tests if necessary, writing and submitting the notifications and reports, developing systems for the purpose of processing and maintaining information, and train personnel to be able to respond to the collection of information.
      The estimated average annual burden (averaged over the first 3 years after the effective date of the standards) for the recordkeeping and reporting requirements in subpart OOOOa for the 2,554 owners and operators that are subject to the rule is 98,438 labor hours, with an annual average cost of $3,361,074. The annual public reporting and recordkeeping burden for this collection of information is estimated to average 20 hours per response. Respondents must monitor all specified criteria at each affected facility and maintain these records for 5 years. Burden is defined at 5 CFR 1320.3(b).
      An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. The OMB control numbers for the EPA's regulations in 40 CFR are listed in 40 CFR part 9.
C. Regulatory Flexibility Act (RFA)
      Pursuant to sections 603 and 609(b) of the RFA, the EPA prepared an initial regulatory flexibility analysis (IRFA) for the proposed rule and convened a Small Business Advocacy Review (SBAR) Panel to obtain advice and recommendations from small entity representatives that potentially would be subject to the rule's requirements. Summaries of the IRFA and Panel recommendations are presented in the proposed rule at 80 FR 56593.
      As required by section 604 of the RFA, the EPA prepared a final regulatory flexibility analysis (FRFA) for this action. The FRFA addresses the issues raised by public comments on the IRFA for the proposed rule. The complete FRFA is available for review in the RIA in the public docket and is summarized here.
 Statutory Authority
      The legal authority for this rule stems from section 111 of the CAA, which requires the EPA to issue "standards of performance" for new sources in the list of categories of stationary sources that cause or contribute significantly to air pollution and which may reasonably be anticipated to endanger public health or welfare. See section III.A of this preamble for more information.
 Significant Issues Raised and Agency Responses
      The EPA received comments on the proposed standards related to the potential impacts on small entities and requests for comments that were included based on the SBAR Panel Recommendations. See sections VI and VIII of this preamble and the RTC Document in Docket ID EPA-HQ-OAR-2010-0505 for more detailed responses.
Low production wells: Several commenters supported the proposed exemption of low production well sites from the fugitive monitoring requirements. Commenters noted that marginal wells generate relatively low revenue and these wells are often drilled and operated by small companies.
Response: While these commenters did provide support for the proposed low production well exemption, other commenters indicated that low production well sites have the potential to emit substantial amounts of fugitive emissions, and that a significant number of wells would be excluded from fugitive emissions monitoring based on this exemption. We did not receive data showing that low production well sites have lower emissions than non-low production well sites. In fact, the data that were provided indicated that the potential emissions from these well sites could be as significant as the emissions from non-low production well sites since the type of equipment and the well pressures are more than likely the same. In discussions with stakeholders, they indicated that well site fugitive emissions are not based on production, but rather on the number of pieces of equipment and components. Therefore, we believe that the emissions from low production and non-low production well sites are comparable and we did not finalize the proposed exclusion of low production well sites from fugitive emissions monitoring.
REC costs: Commenters stated that small operators have higher well completion costs, and typically conduct completions less frequently. Generally, small operators lack the purchasing power to get the discounted prices service companies offer to larger operators. However, small entity commenters did not provide specific cost information.
Response: The BSER analysis is based on the averages of nationwide data. It is possible for a small operator to have higher than the nationwide average completion costs, however, the daily completion cost provided by the commenters is not significantly different than the EPA's estimate. Therefore, we do not believe that the cost of RECs disfavor small businesses.
Phase-in period for RECs: Commenters stated that the EPA should create a compliance phase-in period of at least 6 months for the REC requirements, to accommodate small operators. Commenters stated that REC equipment is in short supply, and this will drive up REC costs. Commenters stated that small entities lack the purchasing power of larger operators, which makes it difficult to obtain the needed equipment before the compliance period begins.
Response: We agree that compliance with the REC requirements in the final rule could be burdensome for some in the near term due to the unavailability of REC equipment. As discussed in section VI of the preamble, the final rule provides a phase-in approach that would allow a quick build-up of the REC supplies in the near term.
Alternatives to OGI technology: Several commenters indicated that the EPA should allow alternatives to OGI technology as the cost is excessive for small operators.
Response: In the final rule, the EPA is allowing Method 21 with a repair threshold of 500 ppm as an alternative to OGI. We believe this alternative will alleviate some of the burden on small entities.
Basing monitoring frequency on the percentage of leaking components: Commenters indicated that using a percentage of components, rather than a set number of components, to determine the frequency of surveys is also unfair to small entities since a small site will have fewer fugitive emission components than a larger site. Commenters stated that smaller entities are much more likely to operate these smaller sites, and thus are more likely to have higher frequency survey requirements under the percentage-based system.
Response: The EPA agrees that imposing a performance based monitoring schedule would require operators to develop a program that would require extensive administration to ensure compliance. We believe that the potential for a performance - based approach to encourage greater compliance is outweighed in this case by these additional burdens and the complexity it would add. Therefore, the EPA is finalizing a fixed monitoring frequency instead of performance based monitoring.
Timing of initial fugitive monitoring periods: Commenters stated that the requirement to conduct surveys for affected facilities using OGI technology within 30 days of the well completion or within 30 days of modification is overly restrictive. Additionally, commenters stated that small operators may not be able to find vendors available to survey a small number of wells within the required timeframe. One commenter stated that contractors will be in high demand and may give scheduling preference to larger clients versus small business entities.
Response: The EPA considered these and other comments and concluded that the proposed time of 30 days within a well completion or modification is not enough time to complete the necessary preparations for the initial monitoring survey. In addition, other commenters pointed out that first date of production should be the trigger, rather than the date of well completion. Therefore, for the collection of fugitive emissions components at a new or modified well site, we are finalizing that the initial monitoring survey must take place within [insert date 1 year after publication of the final rule in the Federal Register] or within 60 days of the startup of production, whichever is later. We believe this extended timeframe for compliance will alleviate some of the burden on smaller operators.
Third party compliance: Commenters believe that requiring third party compliance audits will be a significant burden on small entities. One commenter said that a third-party audit requirement will dramatically increase the costs of the program and have a negative competitive impact on smaller, less funded operators.
 Response: While the EPA continues to believe that independent third party verification can furnish more, and sometimes better, data about regulatory compliance, we have explored alternatives to the independent third party verification. Specifically, the "qualified professional engineer" model was assessed to focus on the element of engineering design. The final rule requires a professional engineer certification of technical infeasibility of connecting a pneumatic pump to an existing control device, and a professional engineer design of closed vent systems. These certifications will ensure that the owner or operator has effectively assessed appropriate factors before making a claim of infeasibility and that the closed vent system is properly designed to verify that all emissions from the unit being controlled in fact reach the control device and allow for proper control. We believe this simplified approach will reduce the burden imposed on all affected facilities, including those owned by small businesses.
 Affected Small Entities
      To identify potentially affected entities under the proposed NSPS, the EPA combined information from industry databases to identify firms drilling and completing wells in 2012, as well as identified their oil and natural gas production levels for that year.
      The analysis indicates about 2,031 small entities may be subject to the requirements for hydraulically fractured and re-fractured oil well completions and fugitive emissions requirements at well sites.
 Reporting, Recordkeeping and Other Compliance Requirements
      The information to be collected for the NSPS is based on notification, performance tests, recordkeeping and reporting requirements which will be mandatory for all operators subject to the final standards. The estimated average annual burden (averaged over the first 3 years after the effective date of the standards) for the recordkeeping and reporting requirements in subpart OOOOa for the 2,554 owners and operators that are subject to the rule is 98,438 labor hours, with an annual average cost of $3,361,074. The annual public reporting and recordkeeping burden for this collection of information is estimated to average 20 hours per response. Respondents must monitor all specified criteria at each affected facility and maintain these records for 5 years. Burden is defined at 5 CFR 1320.3(b).
      The EPA summarized the potential regulatory cost impacts of the proposed rule and alternatives in Section 3 of the RIA. The analysis in the FRFA drew upon the same analysis and assumptions as the analyses presented in the RIA. The FRFA analysis is presented in its entirely in Section 6.3 of the RIA.
      The EPA based the analysis in the FRFA on impacts estimates for the proposed requirements for hydraulically fractured and re-fractured oil well completions and well site fugitive emissions, which represent about 98 percent of the estimated compliance costs of the NSPS in 2020 and 2025. Not incorporating impacts from other provisions in this analysis underestimates impacts, but the EPA believes that detailed analysis of the two provisions impacts on small entities is illustrative of impacts on small entities from the rule in its entirety. The cost of compliance for small firms is estimated to be about $110 million in 2020 and $190 million in 2025.
      We also estimate cost-to-sales ratios for small firms. For some firms, we estimate their 2012 sales levels by multiplying their 2012 oil and natural gas production levels reported in an industry database by the assumed oil and natural gas prices at the wellhead. For natural gas, we assumed the $4/Mcf for natural gas. For oil prices, we estimated revenues using two alternative prices, $70/bbl and $50/bbl. In the results, we call the case using $70/bbl the "primary scenario" and the case using the $50/bbl the "low oil price scenario". For projected 2020 and 2025 potentially affected activities, we allocated compliance costs across entities based upon the costs estimated in the TSD and used in the RIA.
      The percent of small firms with cost-to-sales ratios greater than 1 percent and greater than 3-percent increase from 2020 to 2025 as affected sources accumulate under the NSPS. Cost-to-sales ratios exceeding 1 percent and 3 percent. Also, cost-to-sales ratios fall as the oil price falls from the main scenario to the low oil price scenario.
      The analysis above is subject to a number of caveats and limitations. These are discussed in detail in the IRFA, as well as in Section 3 of the RIA.
 Steps taken to minimize impact on small entities
The EPA considered three major options for this rule. The finalized option includes reduced emission completion (REC) and completion combustion requirements for a subset of newly completed oil wells that are hydraulically fractured or refractured and requirements that fugitive emissions survey and repair programs be performed semiannually at affected well sites and quarterly at affected transmission and storage or compressor stations. One option examined includes an exemption from low production well site fugitive requirements, but was rejected because we believe that low production well sites have similar equipment and components as sites that are not categorized as low production. Without data supporting a difference in emissions between low production well sites and not low production well sites, the EPA believes exempting low production well sites would reduce the effectiveness of the rule, especially considering the high proportion of small firms in the industry. The more stringent option required quarterly monitoring for all sites under the fugitive emissions programs, which leads to greater emissions reductions, however it also increases net costs and results in lower net benefits compared to the finalized option.
      Significant comments with regard to the small business analysis received by the EPA include the topics of low production well exemptions, well completion costs, compliance phase-in periods, alternatives to OGI technology, monitoring frequency and timing, and third party compliance.
      Though all comments were seriously considered, the EPA is unable to incorporate all suggestions without compromising the effectiveness of the final regulation. Changes to the rule from proposal that may benefit small entities due to comments received include allowing both OGI and Method 21 as acceptable monitoring technology, replacing a performance based monitoring schedule with a fixed frequency, lengthening the time of initial fugitive monitoring from within 30 days to the later of either [insert date 1 year after publication of the final rule in the Federal Register] or within 60 days of the startup of production, whichever is later, and simplifying the third party verification of technical infeasibility requirements. Though these are not monetized, we believe the flexibility and simplifications these changes have added to the rule result in a reduced burden on small entities.
	In addition, the EPA is preparing a Small Entity Compliance Guide to help small entities comply with this rule. The guide will be available on the World Wide Web 60 days after publication of the final rule at https://www3.epa.gov/airquality/oilandgas/implement.html
D. Unfunded Mandates Reform Act of 1995 (UMRA)
      This action contains a federal mandate under UMRA, 2 U.S.C. 1531 - 1538, that may result in expenditures of $100 million or more for state, local and tribal governments, in the aggregate, or the private sector in any one year. More specifically, this action contains a federal private sector mandate that may result in the expenditures of $100 million or more for the private section in any one year. Accordingly, the EPA has prepared the following written statement in compliance with sections 202 and 205 of UMRA. This rule is not subject to the requirements of section 203 of UMRA because it contains no regulatory requirements that might significantly or uniquely affect small governments.
1. Statutory Authority
      The legal authority for this rule stems from section 111 of the CAA, which requires the EPA to issue "standards of performance" for new sources in the list of categories of stationary sources that cause or contribute significantly to air pollution and which may reasonably be anticipated to endanger public health or welfare. See section III.A of this preamble for more information.
2. Costs and Benefits
      As discussed in sections II.A.3, IX.C and IX.E of this preamble, this rule results in a net benefit. Including the resources from recovered natural gas that would otherwise be vented, the quantified net benefits of the regulation are estimated to be $35 million in 2020 and $170 million in 2025 in 2012 dollars using a 3 percent discount rate for climate benefits. The estimated total annualized engineering costs of the final rule, accounting for the recovered natural gas are $320 million in 2020 and $530 million in 2025. The EPA estimates the final rule will lead to monetized benefits of about $360 million in 2020 and $690 million in 2025, at the model average at a 3 percent discount rate. More in depth information on costs and benefits, including non-monetized or quantified benefits, of the final regulation can be found in the RIA.
3. Effects on National Economy
	As seen in section IX.D of this preamble, the EPA used the National Energy Modeling System (NEMS) to estimate the impacts of the final rule on the United States energy system. Estimates show slight declines in natural gas and crude oil drilling, and natural gas production over the 2020 to 2025 period under the rule, while wellhead natural gas prices are estimated to increase slightly over the 2020 to 2025 period under the rule. Crude oil production and crude oil wellhead prices are not estimated to change appreciably over the 2020 to 2025 period under the rule. Net imports of natural gas are estimated to increase slightly over the 2020 to 2025 period, while net imports of crude oil are not estimated to change appreciably.
      Also discussed in section IX.D, the up-front labor requirement to comply with the proposed NSPS is estimated at about 270 FTEs in 2020 and 2025. The annual labor requirement to comply with final NSPS is estimated at about 1,100 FTEs in 2020 and 1,800 FTEs in 2025. For more in depth information on both the estimated energy markets impacts and estimated job creation and employment impacts of this rule, see the RIA.
4. Regulatory Alternatives
	Alternate regulatory options examined in the RIA include decreasing fugitive survey requirements to annual at well sites and semiannual at all other affected locations (termed Option 1 in the RIA), and increasing fugitive survey frequency at all wells to quarterly (termed Option 3 in the RIA). The finalized regulation results in estimated net benefits of $35 million in 2020 and $170 million in 2025. Reducing fugitive survey requirements, Option 1, leads to lower costs as well as lower benefits and results in estimated net benefits of $54 million in 2020 and $180 million in 2025. Increasing the survey frequency leads to an increase in capital costs with a non-commensurate increase in monetized benefits, resulting in estimated net benefits of -$75 million in 2020, and -$38 million in 2025. Both of these regulatory options result in lower net benefits in 2025 compared to the finalized regulation. For a more in depth analysis of these options, see the RIA.
E. Executive Order 13132: Federalism
      This action does not have federalism implications. It will not have substantial direct effects on the states, on the relationship between the national government and the states, or on the distribution of power and responsibilities among the various levels of government. These final rules primarily affect private industry and would not impose significant economic costs on state or local governments.
F. Executive Order 13175: Consultation and Coordination with Indian Tribal Governments
      Subject to Executive Order 13175 (65 FR 67249; November 9, 2000), the EPA may not issue a regulation that has tribal implications, that imposes substantial direct compliance costs, and that is not required by statute, unless the federal government provides the funds necessary to pay the direct compliance costs incurred by tribal governments, or the EPA consults with tribal officials early in the process of developing the proposed regulation and develops a tribal summary impact statement.
      The EPA has concluded that this action has tribal implications. However, it will neither impose substantial direct compliance costs on federally recognized tribal governments, nor preempt tribal law, thus Executive Order 13175 does not apply to this rule. The EPA believes that the affected facilities impacted by this rulemaking on tribal lands are owned by private entities, and tribes will not be directly impacted by the compliance costs associated with this rulemaking. There would only be tribal implications associated with this rulemaking in the case where a unit is owned by a tribal government or a tribal government is given delegated authority to enforce the rulemaking.
      The EPA offered consultation with tribal officials early in the regulation development process to permit them an opportunity to have meaningful and timely input. Consultation letters were sent to the tribal leaders of 567 federally recognized tribes, provided information regarding this rule, and offered consultation. The EPA did not receive any requests for tribal consultation on this rulemaking. In addition, the EPA has conducted meaningful involvement with tribal stakeholders throughout the rulemaking process and provided an update on the Methane Strategy on the January 29, 2015 and September 10, 2015 National Tribal Air Association and EPA Air Policy monthly calls. Consistent with previous actions affecting the oil and natural gas sector, there is significant tribal interest because of the growth of the oil and natural gas production in Indian country. The EPA specifically solicited comment on the proposed action from tribal officials and considered comments received from tribal officials in the development of this final action. Please see the RTC document in the public docket.
G. Executive Order 13045: Protection of Children from Environmental Health Risks and Safety Risks
      This action is subject to Executive Order 13045 (62 FR 19885, April 23, 1997) because it is an economically significant regulatory action as defined by Executive Order 12866, and the EPA believes that the environmental health or safety risk addressed by this action has a disproportionate effect on children. Accordingly, the Agency has evaluated the environmental health and welfare effects of climate change on children.
      Greenhouse gases including methane contribute to climate change and are emitted in significant quantities by the oil and gas sector. The EPA believes that the GHG emission reductions resulting from implementation of these final rules will further improve children's health.
      The assessment literature cited in the EPA's 2009 Endangerment Finding concluded that certain populations and life stages, including children, the elderly, and the poor, are most vulnerable to climate-related health effects. The assessment literature since 2009 strengthens these conclusions by providing more detailed findings regarding these groups' vulnerabilities and the projected impacts they may experience.
      These assessments describe how children's unique physiological and developmental factors contribute to making them particularly vulnerable to climate change. Impacts to children are expected from heat waves, air pollution, infectious and waterborne illnesses, and mental health effects resulting from extreme weather events. In addition, children are among those especially susceptible to most allergic diseases, as well as health effects associated with heat waves, storms, and floods. Additional health concerns may arise in low income households, especially those with children, if climate change reduces food availability and increases prices, leading to food insecurity within households.
      More detailed information on the impacts of climate change to human health and welfare is provided in section IV.B of this preamble.
H. Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use
	Executive Order 13211 (66 FR 28355, May 22, 2001) provides that agencies will prepare and submit to the Administrator of the Office of Information and Regulatory Affairs, Office of Management and Budget, a Statement of Energy Effects for certain actions identified as "significant energy actions." Section 4(b) of Executive Order 13211 defines "significant energy actions" as any action by an agency (normally published in the Federal Register) that promulgates or is expected to lead to the promulgation of a final rule or regulation, including notices of inquiry, advance notices of proposed rulemaking, and notices of proposed rulemaking: (1)(i) that is a significant regulatory action under Executive Order 12866 or any successor order, and (ii) is likely to have a significant adverse effect on the supply, distribution, or use of energy; or (2) that is designated by the Administrator of the Office of Information and Regulatory Affairs as a significant energy action.
      This action is not a "significant energy action" as defined in Executive Order 13211 (66 FR 28355, May 22, 2001), because it is not likely to have a significant adverse effect on the supply, distribution, or use of energy. The basis for these determinations follows.
      The EPA used the NEMS to estimate the impacts of the final rule on the United States energy system. The NEMS is a publically-available model of the United States energy economy developed and maintained by the Energy Information Administration of the DOE and is used to produce the Annual Energy Outlook, a reference publication that provides detailed forecasts of the United States energy economy.
      The EPA estimates that natural gas and crude oil drilling levels decline slightly over the 2020 to 2025 period under the final NSPS (by about 0.17 percent for natural gas wells and 0.02 percent for crude oil wells). Crude oil production does not vary appreciably under the rule, while natural gas production declines slightly over the 2020 to 2025 period (about 0.03 percent). Crude oil wellhead prices for onshore lower 48 production are not estimated to change appreciably over the 2020 to 2025 period. However, wellhead natural gas prices for onshore lower 48 production are estimated to increase slightly over the 2020 to 2025 period (about 0.20 percent). Net imports of natural gas are estimated to increase slightly in 2020 (by about 0.12 percent) and in 2025 (by about 0.11 percent). Crude oil net imports are not estimated to change in 2020, but decrease slightly in 2025 (by about 0.02 percent). Net imports of crude oil do not change appreciably over the 2020 to 2025 period.
 	Additionally, the NSPS establishes several performance standards that give regulated entities flexibility in determining how to best comply with the regulation. In an industry that is geographically and economically heterogeneous, this flexibility is an important factor in reducing regulatory burden. For more information on the estimated energy effects of this final rule, please see the Regulatory Impact Analysis, which is in the docket for this rule.
I. National Technology Transfer and Advancement Act (NTTAA) and 1 CFR part 51
	This action involves technical standards. Therefore, the EPA conducted searches for the Oil and Natural Gas Sector: Emission Standards for New and Modified Sources through the Enhanced National Standards Systems Network (NSSN) Database managed by the American National Standards Institute (ANSI). Searches were conducted for EPA Methods 1, 1A, 2, 2A, 2C, 2D, 3A, 3B, 3C, 4, 6, 10, 15, 16, 16A, 18, 21, 22, and 25A of 40 C.F.R. part 60 Appendix A. No applicable voluntary consensus standards were identified for EPA Methods 1A, 2A, 2D, 21, and 22 and none were brought to its attention in comments. All potential standards were reviewed to determine the practicality of the voluntary consensus standards (VCS) for this rule.
	Two VCS were identified as an acceptable alternative to EPA test methods for the purpose of this rule. First, ANSI/ASME PTC 19-10 - 1981, Flue and Exhaust Gas Analyses (Part 10) was identified to be used in lieu of EPA Methods 3B, 6, 6A, 6B, 15A and 16A manual portions only and not the instrumental portion. This standard includes manual and instructional methods of analysis for carbon dioxide, carbon monoxide, hydrogen sulfide, nitrogen oxides, oxygen, and sulfur dioxide. Second, ASTM D6420-99 (2010), "Test Method for Determination of Gaseous Organic Compounds by Direct Interface Gas Chromatography/Mass Spectrometry" is an acceptable alternative to EPA Method 18 with the following caveats, only use when the target compounds are all known and the target compounds are all listed in ASTM D6420 as measurable. ASTM D6420 should never be specified as a total VOC Method. (ASTM D6420-99 (2010) is not incorporated by reference in 40 CFR part 60.) The search identified 19 VCS that were potentially applicable for this rule in lieu of EPA reference methods. However, these have been determined to not be practical due to lack of equivalency, documentation, validation of data and other important technical and policy considerations. For additional information, please see the April 6, 2016, memo titled, "Voluntary Consensus Standard Results for Oil and Natural Gas Sector: Emission Standards for New and Modified Sources" in the public docket.
      In this rule, the EPA is finalizing regulatory text for 40 CFR part 60, subpart OOOOa that includes incorporation by reference in accordance with requirements of 1 CFR 51.5 as discussed below. Ten standards are incorporated by reference.
 ASTM D86-96, Distillation of Petroleum Products (Approved April 10, 1996) covers the distillation of natural gasolines, motor gasolines, aviation gasolines, aviation turbine fuels, special boiling point spirits, naphthas, white spirit, kerosines, gas oils, distillate fuel oils, and similar petroleum products, utilizing either manual or automated equipment.
 ASTM D1945-03 (Reapproved 2010), Standard Test Method for Analysis of Natural Gas by Gas Chromatography covers the determination of the chemical composition of natural gases and similar gaseous mixtures within a certain range of composition. This test method may be abbreviated for the analysis of lean natural gases containing negligible amounts of hexanes and higher hydrocarbons, or for the determination of one or more components.
 ASTM D3588-98 (Reapproved 2003), Standard Practice for Calculating Heat Value, Compressibility Factor, and Relative Density of Gaseous Fuel covers procedures for calculating heating value, relative density, and compressibility factor at base conditions for natural gas mixtures from compositional analysis. It applies to all common types of utility gaseous fuels.
 ASTM D4891-89 (Reapproved 2006), Standard Test Method for Heating Value of Gases in Natural Gas Range by Stoichiometric Combustion covers the determination of the heating value of natural gases and similar gaseous mixtures within a certain range of composition.
 ASTM D6522-00 (Reapproved December 2005), Standard Test Method for Determination of Nitrogen Oxides, Carbon Monoxide, and Oxygen Concentrations in Emissions from Natural Gas-Fired Reciprocating Engines, Combustion Turbines, Boilers, and Process Heaters Using Portable Analyzers covers the determination of nitrogen oxides, carbon monoxide, and oxygen concentrations in controlled and uncontrolled emissions from natural gas-fired reciprocating engines, combustion turbines, boilers, and process heaters.
 ASTM E168-92, General Techniques of Infrared Quantitative Analysis covers the techniques most often used in infrared quantitative analysis. Practices associated with the collection and analysis of data on a computer are included as well as practices that do not use a computer.
 ASTM E169-93, General Techniques of Ultraviolet Quantitative Analysis (Approved May 15, 1993) provide general information on the techniques most often used in ultraviolet and visible quantitative analysis. The purpose is to render unnecessary the repetition of these descriptions of techniques in individual methods for quantitative analysis.
 ASTM E260-96, General Gas Chromatography Procedures (Approved April 10, 1996) is a general guide to the application of gas chromatography with packed columns for the separation and analysis of vaporizable or gaseous organic and inorganic mixtures and as a reference for the writing and reporting of gas chromatography methods.
 ASME/ANSI PTC 19.10 - 1981, Flue and Exhaust Gas Analyses [Part 10, Instruments and Apparatus] (Issued August 31, 1981) covers measuring the oxygen or carbon dioxide content of the exhaust gas.
 EPA-600/R-12/531, EPA Traceability Protocol for Assay and Certification of Gaseous Calibration Standards (Issued May 2012) is mandatory for certifying the calibration gases being used for the calibration and audit of ambient air quality analyzers and continuous emission monitors that are required by numerous parts of the CFR.
   The EPA determined that the ASTM and ASME/ANSI standards, notwithstanding the age of the standards, are reasonably available because it they are available for purchase from the following addresses: American Society for Testing and Materials (ASTM), 100 Barr Harbor Drive, Post Office Box C700, West Conshohocken, PA 19428 - 2959; or ProQuest, 300 North Zeeb Road, Ann Arbor, MI 48106 and the American Society of Mechanical Engineers (ASME), Three Park Avenue, New York, NY 10016 - 5990. The EPA determined that the EPA standard is reasonably available because it is publically available through the EPA's Web site: http://nepis.epa.gov/Adobe/PDF/P100EKJR.pdf.
J. Executive Order 12898: Federal Actions to Address Environmental Justice in Minority Populations and Low-Income Populations
      The EPA believes the human health or environmental risk addressed by this action will not have potential disproportionately high and adverse human health or environmental effects on minority, low-income, or indigenous populations. The EPA has determined this because the rulemaking increases the level of environmental protection for all affected populations without having any disproportionately high and adverse human health or environmental effects on any population, including any minority, low-income, or indigenous populations. The EPA has provided meaningful participation opportunities for minority, low-income, indigenous populations and tribes during the rulemaking process by conducting community calls and webinars. Documentation of these activities can be found in the public docket for this rulemaking.
K. Congressional Review Act (CRA)
      	This action is subject to the CRA, and the EPA will submit a rule report to each House of the Congress and to the Comptroller General of the United States. This action is a "major rule" as defined by 5 U.S.C. 804(2).
 List of Subjects in 40 CFR Part 60
       Environmental protection, Administrative practice and procedure, Air pollution control, Incorporation by reference,
Intergovernmental relations, Reporting and recordkeeping.

Dated: __________________________________.

________________________________________
Gina McCarthy,
Administrator.
For the reasons set out in the preamble, title 40, chapter I of
the Code of Federal Regulations is amended as follows:
PART 60-STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES
1. The authority citation for part 60 continues to read as follows:
Authority: 42 U.S.C. 4701, et seq.
2. Section 60.17 is amended by:
a. Revising paragraph (g)(14); and
b. Revising paragraphs (h)(19), (75), (137), (167), (184), (193), (196), and (199)
c. Adding (j)(2).
§60.17 Incorporations by reference.
*	*	*	*	*
(g) *	*	*
(14) ASME/ANSI PTC 19.10-1981, Flue and Exhaust Gas Analyses [Part 10, Instruments and Apparatus], (Issued August 31, 1981), IBR approved for §§60.56c(b), 60.63(f), 60.106(e), 60.104a(d), (h), (i), and (j), 60.105a(d), (f), and (g), §60.106a(a), §60.107a(a), (c), and (d), tables 1 and 3 to subpart EEEE, tables 2 and 4 to subpart FFFF, table 2 to subpart JJJJ, §60.285a(f), §§60.4415(a), 60.2145(s) and (t), 60.2710(s), (t), and (w), 60.2730(q), 60.4900(b), 60.5220(b), tables 1 and 2 to subpart LLLL, tables 2 and 3 to subpart MMMM, 60.5406(c), 60.5406a(c), 60.5407a(g), 60.5413(b), 60.5413a(b) and 60.5413a(d).
*	*	*	*	*
(h) *	*	*
(19) ASTM D86-96, Distillation of Petroleum Products, (Approved April 10, 1996), IBR approved for §§60.562-2(d), 60.593(d), 60.593a(d), 60.633(h), 60.5401(f), 60.5401a(f).
*	*	*	*	*
(75) ASTM D1945-03 (Reapproved 2010), Standard Method for Analysis of Natural Gas by Gas Chromatography, (Approved January 1, 2010), IBR approved for §§60.107a(d), 60.5413(d), 60.5413a(d).
*	*	*	*	*
(137) ASTM D3588-98 (Reapproved 2003), Standard Practice for Calculating Heat Value, Compressibility Factor, and Relative Density of Gaseous Fuels, (Approved May 10, 2003), IBR approved for §§60.107a(d), 60.5413(d), and 60.5413a(d).
*	*	*	*	*
(167) ASTM D4891-89 (Reapproved 2006) Standard Test Method for Heating Value of Gases in Natural Gas Range by Stoichiometric Combustion, (Approved June 1, 2006), IBR approved for §§60.107a(d), 60.5413(d), and 60.5413a(d).
*	*	*	*	*
(184) ASTM D6522-00 (Reapproved 2005), Standard Test Method for Determination of Nitrogen Oxides, Carbon Monoxide, and Oxygen Concentrations in Emissions from Natural Gas-Fired Reciprocating Engines, Combustion Turbines, Boilers, and Process Heaters Using Portable Analyzers, (Approved October 1, 2005), IBR approved for table 2 to subpart JJJJ, §§60.5413(b) and (d), and 60.5413a(b).
*	*	*	*	*
(193) ASTM E168-92, General Techniques of Infrared Quantitative Analysis, IBR approved for §§60.485a(d), 60.593(b), 60.593a(b), 60.632(f), 60.5400, 60.5400a(f).
*	*	*	*	*
(196) ASTM E169-93, General Techniques of Ultraviolet Quantitative Analysis, (Approved May 15, 1993), IBR approved for §§60.485a(d), 60.593(b), 60.593a(b), 60.632(f), 60.5400(f), and 60.5400a(f).
*	*	*	*	*
(199)ASTM E260-96, General Gas Chromatography Procedures, (Approved April 10, 1996), IBR approved for §§60.485a(d), 60.593(b), 60.593a(b), 60.632(f), 60.5400(f), 60.5400a(f) 60.5406(b), and 60.5406a(b)(3).
*	*	*	*	*
(j) *	*	*
(2) EPA-600/R-12/531, EPA Traceability Protocol for Assay and Certification of Gaseous Calibration Standards, May 2012,IBR approved for §§60.5413(d) and 60.5413a(d).
3. Part 60 is amended by revising the heading for Subpart OOOO to read as follows:
Subpart OOOO -- Standards of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution for which Construction, Modification or Reconstruction Commenced after August 23, 2011, and on or before September 18, 2015
4. Section 60.5360 is revised to read as follows:
§60.5360 What is the purpose of this subpart?
	This subpart establishes emission standards and compliance schedules for the control of volatile organic compounds (VOC) and sulfur dioxide (SO2) emissions from affected facilities that commence construction, modification or reconstruction after August 23, 2011, and on or before September 18, 2015.
5. Section 60.5365 is amended by:
a. Revising the introductory text; and
b. Revising paragraph (e)(4)
c. Adding paragraph (e)(5)
d. Revising paragraph (h)(4).
The revisions read as follows:
§60.5365 Am I subject to this subpart?
	You are subject to the applicable provisions of this subpart if you are the owner or operator of one or more of the onshore affected facilities listed in paragraphs (a) through (g) of this section for which you commence construction, modification or reconstruction after August 23, 2011, and on or before September 18, 2015.
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(e) * * *
(4) The following requirements apply immediately upon startup, startup of production, or return to service. A storage vessel affected facility that is reconnected to the original source of liquids is a storage vessel affected facility subject to the same requirements that applied before being removed from service. Any storage vessel that is used to replace any storage vessel affected facility is subject to the same requirements that apply to the storage vessel affected facility being replaced.
(5) A storage vessel with a capacity greater than 100,000 gallons used to recycle water that has been passed through two stage separation is not a storage vessel affected facility.
(h) * * *
(4) A gas well facility initially constructed after August 23,
 2011, and on or before September 18, 2015 is considered an affected facility regardless of this provision.
6. Section 60.5370 is amended by amending paragraph (b) and adding paragraph (d) read as follows:
§60.5370 When must I comply with this subpart?
*   *   *   *   *
(b) At all times, including periods of startup, shutdown, and malfunction, owners and operators shall maintain and operate any affected facility including associated air pollution control equipment in a manner consistent with good air pollution control practice for minimizing emissions. Determination of whether acceptable operating and maintenance procedures are being used will be based on information available to the Administrator which may include but is not limited to, monitoring results, opacity observations, review of operating and maintenance procedures, and inspection of the source.* * *
* * * * *
(d) You are deemed to be in compliance with this subpart if you are in compliance with all applicable provisions of subpart OOOOa of this part.
7. Section 60.5410 is amended by removing and reserving paragraph (b)(6).
§60.5410 How do I demonstrate initial compliance with the standards for my gas well affected facility, my centrifugal compressor affected facility, my reciprocating compressor affected facility, my pneumatic controller affected facility, my storage vessel affected facility, and my equipment leaks and sweetening unit affected facilities at onshore natural gas processing plants?
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(b) * * *
(6) [Reserved]
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8. Section 60.5411 is amended by revising paragraphs (a)(3)(i)(A) and (c)(3)(i)(A) to read as follows:
§60.5411 What additional requirements must I meet to determine initial compliance for my covers and closed vent systems routing materials from storage vessels and centrifugal compressor wet seal degassing systems?
*   *   *   *   *
(a) * * *
(3) * * *
(i) * * *
(A) You must properly install, calibrate, maintain, and operate a flow indicator at the inlet to the bypass device that could divert the stream away from the control device or process to the atmosphere that is capable of taking periodic readings as specified in §60.5416(a)(4) and either sounds an alarm, or initiates notification via remote alarm to the nearest field office, when the bypass device is open such that the stream is being, or could be, diverted away from the control device or process to the atmosphere. You must maintain records of each time the alarm is activated according to §60.5420(c)(8).
*   *   *   *   *
(c) * * *
(3) * * *
(i) * * *
(A) You must properly install, calibrate, maintain, and operate a flow indicator at the inlet to the bypass device that could divert the stream away from the control device or process to the atmosphere and that either sounds an alarm, or initiates notification via remote alarm to the nearest field office, when the bypass device is open such that the stream is being, or could be, diverted away from the control device or process to the atmosphere. You must maintain records of each time the alarm is activated according to §60.5420 (c)(8).
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9. Section 60.5412 is amended by:
a. Revising paragraphs (a)(1)(ii) and (d)(1) introductory text; and
b. Adding paragraph (d)(1)(iv).
The revisions and addition read as follows:
§60.5412 What additional requirements must I meet for determining initial compliance with control devices used to comply with the emission standards for my storage vessel or centrifugal compressor affected facility?
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(a) * * *
(1) * * *
(ii) You must reduce the concentration of TOC in the exhaust gases at the outlet to the device to a level equal to or less than 275 parts per million by volume as propane on a wet basis corrected to 3 percent oxygen as determined in accordance with the requirements of §60.5413.
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(d) * * *
(1) Each enclosed combustion device (e.g., thermal vapor incinerator, catalytic vapor incinerator, boiler, or process heater) must be designed to reduce the mass content of VOC emissions by 95.0 percent or greater. Each flare must be designed and operated in accordance with the requirements of §60.5413(a)(1). You must follow the requirements in paragraphs (d)(1)(i) through (iv) of this section.
*   *   *   *   *
(iv) Each enclosed combustion control device (e.g., thermal vapor incinerator, catalytic vapor incinerator, boiler, or process heater) must be designed and operated in accordance with one of the performance requirements specified in paragraphs (A) through (D) of this section.
(A) You must reduce the mass content of VOC in the gases vented to the device by 95.0 percent by weight or greater as determined in accordance with the requirements of §60.5413.
(B) You must reduce the concentration of TOC in the exhaust gases at the outlet to the device to a level equal to or less than 275 parts per million by volume as propane on a wet basis corrected to 3 percent oxygen as determined in accordance with the requirements of §60.5413.
(C) You must operate at a minimum temperature of 760°Celsius, provided the control device has demonstrated, during the performance test conducted under §60.5413, that combustion zone temperature is an indicator of destruction efficiency.