A Heavy Lift: EPA Bulks Up Oil and Gas Methane Requirements in New Quad Ob/c Regulations

Quad Ob and Oc generally cover the same “source” types within the oil and gas sector, and the two regulations contain many of the same requirements. A big difference is that Quad Ob addresses “new/modified sources,” — sources that commenced construction, reconstruction, or modification after December 6, 2022. Notably, that means owners and operators need to assess whether any affected facilities have been installed or modified since that date. For such “new/modified sources,” compliance with Quad Ob is required starting on May 7, 2024 (60 days after publication in the Federal Register). It does not depend on any further state-specific actions. Quad Oc, in contrast, sets guidelines for states to follow when developing their Clean Air Act (“CAA”) Section 111(d) implementation plans to regulate “existing sources” (that is, sources that were constructed prior to December 6, 2022, and not subsequently modified). States and Tribes will have until March 8, 2026 (24 months after publication in the Federal Register), to submit their implementation plans to EPA. States and Tribes can provide existing sources up to 36 months after submitting their state or Tribal plans to come into compliance, meaning that the requirements for existing sources may not go into effect for up to five years, depending on choices made by the relevant state or Tribe.

Here, we summarize eight key items that upstream oil and gas owners and operators should know about Quad Ob and Quad Oc and the related methane waste emission charge proposal. Many of the new requirements raise compliance and associated enforcement risks for the oil and gas sector. These regulations are particularly noteworthy given that EPA has already indicated that enforcing rules that it believes will help mitigate climate change will be an agency enforcement priority, and EPA is clear it believes these are such rules.

Super Emitter Program

EPA has included a new Super Emitter Program, which generated much comment and concern in the proposed rule. Under EPA’s finalized Super Emitter Program, local regulatory agencies and certain EPA-certified third parties would be authorized to submit notifications to EPA when they detect “super-emitter events,” defined as emissions of 100 kilograms of methane per hour or greater, at or near an owner’s or operator’s facility. If EPA determines that the submitted notification is complete, timely,¹ and accurate “to a reasonable degree of certainty,” EPA (not the third-party notifier, as originally proposed) will provide the notification to an owner or operator identified in the notification. If an owner or operator receives such a notification, the owner or operator must launch an investigation into the super-emitter event within 5 calendar days of receiving the notice and must submit a report of its investigation to EPA within 15 calendar days of the notification.

Both third-party notifications and owner and operator investigation reports will be submitted through EPA’s publicly accessible Super Emitter Program Portal.² Initially, EPA will post verified notifications without owner/operator attribution, thereby providing the notified party an opportunity to respond before the super-emitter event is publicly (and possibly incorrectly) attributed to the notified party. However, if owner/operator attribution is subsequently confirmed via the owner’s or operator’s response, or if no response is received and EPA “reasonably believes” an attribution “to be accurate,” EPA will then publicly post attribution information.

EPA will certify third-party notifiers that demonstrate “technical expertise” in one of three listed remote detection methods: satellite detection, aerial remote sensing equipment, and mobile monitoring platforms.³ The certification process will require applicants to submit information about the experience and training of the notifiers, the remote detection technologies being used, and the standing operating procedures and process for detection data review.

The final rules reflect EPA’s attempt to address questions about the legality of the program by taking a more central oversight role — certifying notifiers, reviewing data submitted by notifiers prior to sending it to owners and operators, and increasing the number of circumstances where a third-party notifier can have its certification revoked. Nevertheless, this program has potential to, in effect, substantially expand EPA’s de facto investigative capabilities if it deputizes a substantial number of third-party notifiers.

Notably, and further expanding the scope of this program, super-emitter events can be attributed to sources not subject to Quad Ob. The Super Emitter Program will require all sources, regardless of whether or not they are regulated under Section 111 of the CAA, to investigate super-emitter event notifications and report the results of those investigations back to EPA. In order words, the program covers more than just those emission sources identified in the various “Quads.” Notwithstanding any arguments that EPA has exceeded the scope of its authority here, this program could create significant new enforcement risks and burdens for oil and gas operators,⁴ both from any reported emission events themselves and in connection with the new duty to respond to notices and timely report back. As a result, upstream and midstream operators should begin developing plans for how they will respond to super-emitter events, as well as notifications of such events, which may not accurately reflect what actually occurred. These plans should include identifying who will lead any response to an EPA notification and the basic steps expected to be taken given the short timelines the EPA has given companies to respond.

Restrictions on “Associated Gas” Flaring

For both Quad Ob and Quad Oc, EPA finalized restrictions on the circumstances under which owners and operators can engage in what EPA calls “routine flaring,” that is, the flaring of associated gas from wells in the absence of temporary or emergency circumstances necessitating such flaring. Under the new restrictions, an owner or operator must submit a demonstration, certified by a professional engineer or other qualified individual, that flaring is needed because a sales line is unavailable and other beneficial uses are not feasible for technical or safety reasons. For new sources subject to Quad Ob, the flaring restrictions are phased in based on when construction, modification, or reconstruction occurred at the well site. Existing sources that will be subject to Quad Oc are divided into two distinct categories, based on the amount of methane in the associated gas, that determine the applicable flaring restrictions. Chart 1 below summarizes the requirements for both new and existing sources with respect to the permissibility of “routine flaring.”

Although EPA has generally restricted routine flaring, the agency provides owners and operators with exceptions for temporary (or emergency) flaring at well sites. Chart 2 below demonstrates the situations where temporary flaring is allowed and how long owners and operators would be allowed to flare.

IRA Methane Fee

The impacts of the new Quad Ob and Quad Oc rules have implications beyond just the costs of compliance and any equipment upgrades. The Inflation Reduction Act of 2022 (“IRA”) includes a methane emissions fee on certain sources in the oil and gas sector that would start in calendar year 2024 at $900 per ton of methane, increase to $1,200 in 2025, and be set at $1,500 for 2026 and each year thereafter. However, the IRA provides an exemption from the methane fee for facilities that are “subject to and in compliance with” the new methane rules if (i) the EPA finalizes standards that would result in “equivalent or greater emissions reductions as would be achieved by” what EPA predicted in the description of the Quad Ob and Quad Oc regulations EPA proposed in November 2021 (which did not contain regulatory text), and (ii) such standards are in effect in “all states with respect to the applicable facilities.”

As we discuss further in this insight, in EPA’s recently proposed rule for the implementation of the IRA’s methane fee, EPA has proposed that the regulatory compliance exemption will not be available to any facilities until all state plans have been approved and implemented. Under this proposal, no facilities will be able to use the exemption for a number of years, even if a program is in effect in the state where a facility is located and the facility is in compliance with the state program where the facility sits. EPA has also proposed that only facilities (as defined by the proposed rule, as opposed to a Quad Ob or Quad Oc “facility”) in full compliance with Quad Ob/c for the entire reporting year will be able to make use of the exemption. For the “equivalency determination” EPA has proposed that Quad Ob and plans equivalent to Quad Oc in all states will be equivalent to the November 2021 EPA publication.

EPA is currently soliciting public comments on the proposed IRA methane fee implementation. Comments must be received on or before March 26, 2024.

Advanced Leak Detection Monitoring Techniques

The final rules require owners and operators to routinely monitor for and timely repair natural gas leaks. Compared to the proposed rule, the final requirements provide owners and operators with greater flexibility to use advanced emissions monitoring and detection technology to monitor fugitive emissions as an alternative to currently endorsed procedures, such as audible, visual, and olfactory (“AVO”) inspections, optical gas imaging (“OGI”), and EPA Method 21-based leak detection and repair programs. Owners or operators wishing to use an alternative technology must receive approval from EPA to use the new technology or method. The final rules also streamline EPA’s approach to approving new technologies and methods by creating a separate approval process similar to EPA’s existing alternative test method approval process. Owners and operators also can use multiple detection technologies in combination, even at the same site, instead of being limited to choosing a single technology.

Once EPA has approved a new technology or method, owners and operators can adjust their monitoring frequencies based on how effective those technologies are at detecting emissions. In other words, when operators use technologies with greater sensitivity in detecting emissions (that is, technologies that can detect emissions at lower thresholds), they can undertake periodic screening less frequently than if they were to use technologies that are less sensitive to emissions. If an owner or operator wishes to use multiple technologies, the screening frequency is based on the technology that is the least “sensitive” to detecting methane emissions that the owner or operator lists in its monitoring plan. The periodic screening frequencies and the corresponding minimum detection threshold of the screening technology are found in Tables 1 and 2 to Quad Ob and Tables 2 and 3 to Quad Oc. Owners and operators also have the option to replace one or more individual periodic screening events with an OGI survey.

Table 1 to Subpart OOOOb of Part 60 – Alternative Technology Periodic Screening Frequency at Well Sites, Centralized Production Facilities, and Compressor Stations Subject to AVO Inspections with Quarterly OGI or EPA Method 21 Monitoring

Minimum Screening Frequency	Minimum Detection Threshold of Screening Technology
Quarterly	≤1 kg/hr
Bimonthly	≤2 kg/hr
Bimonthly + Annual OGI	≤10 kg/hr
Monthly	≤5 kg/hr
Monthly + Annual OGI	≤15 kg/hr

Table 2 to Subpart OOOOb of Part 60 – Alternative Technology Periodic Screening Frequency at Well Sites and Centralized Production Facilities Subject to AVO Inspections and/or Semiannual OGI or EPA Method 21 Monitoring

Minimum Screening Frequency	Minimum Detection Threshold of Screening Technology
Semiannual	≤1 kg/hr
Triannual	≤2 kg/hr
Triannual + Annual OGI	≤10 kg/hr
Quarterly	≤5 kg/hr
Quarterly + Annual OGI	≤15 kg/hr
Bimonthly	≤15 kg/hr

Table 2 to Subpart OOOOc of Part 60 – Alternative Technology Periodic Screening Frequency at Well Sites, Centralized Production Facilities, and Compressor Stations Subject to AVO Inspections with Quarterly OGI or EPA Method 21 Monitoring

Minimum Screening Frequency	Minimum Detection Threshold of Screening Technology
Quarterly	≤1 kg/hr
Bimonthly	≤2 kg/hr
Bimonthly + Annual OGI	≤10 kg/hr
Monthly	≤5 kg/hr
Monthly + Annual OGI	≤15 kg/hr

Table 3 to Subpart OOOOc of Part 60 – Alternative Technology Periodic Screening Frequency at Well Sites and Centralized Production Facilities Subject to AVO Inspections and/or Semiannual OGI or EPA Method 21 Monitoring

Minimum Screening Frequency	Minimum Detection Threshold of Screening Technology
Semiannual	≤1 kg/hr
Triannual	≤2 kg/hr
Triannual + Annual OGI	≤10 kg/hr
Quarterly	≤5 kg/hr
Quarterly + Annual OGI	≤15 kg/hr
Bimonthly	≤15 kg/hr

Liquids Unloading Requirements

EPA’s December 2022 proposal drew criticism for its zero-emissions requirement for liquids unloading at well sites subject to Quad Ob and Quad Oc. The final rule moved from a numeric standard to a work practice standard that oil and gas operators must follow, along with various recordkeeping and reporting requirements. Under the final rule, owners and operators of wells that undergo liquids unloading will be required to employ techniques or technology(ies) that minimize or eliminate venting of emissions to the maximum extent possible during liquids unloading events. Owners and operators must create a best management practice (“BMP”) plan that provides steps to minimize or eliminate venting of emissions and would apply for both planned venting events and unintended or unplanned venting events due to malfunctions or error. There are also several reporting requirements for owners and operators to follow:

1. identification of each well affected facility that conducted liquids unloading that vented to the atmosphere during the reporting period;
2. the number of liquids unloading events that vented to the atmosphere during the reporting period;
3. documentation of the BMP plan developed that meets the criteria specified in 40 C.F.R. § 60.5376b(d) of Quad Ob;
4. a log of each BMP plan step taken to minimize emissions to the maximum extent possible for each gas well liquids unloading event; and
5. documentation of each gas well liquids unloading event where deviations from the BMP plan steps occurred, the date and time the deviation began, the duration of the deviation, documentation of the BMP plan steps that were not followed, and the steps taken in lieu of the BMP plan steps during those events to minimize emissions to the maximum extent possible.

Requirements for Process Controllers and Pumps

The finalized Quad Ob and Oc regulations require process controllers (known as pneumatic controllers in previous rulemakings) and pumps to have zero methane and VOC emissions, except for sites in Alaska where onsite power is unavailable.⁵ EPA now defines “process controller affected facility” to encompass all natural gas-driven controllers at a particular site, recognizing that many emission elimination measures are site-wide. Quad Ob facilities will have until May 7, 2025 (one year from the rule’s effective date) to come into full compliance with the zero-emissions standard. Until the final compliance date, Quad Ob facilities must demonstrate compliance with an interim standard mirroring the requirements for sites in Alaska that do not have access to electrical power. Quad Oc facilities may have as much as 36 months after the state or Tribal plan submittal deadline to come into compliance with the zero-emissions standard. However, state and Tribal plans may contain their own compliance schedules for facilities which require compliance before EPA’s three-year maximum. Further, EPA will consider process controller affected facilities as having undergone a modification if the number of natural-gas driven pumps in the facility is increased by one or more, which would result in the affected facility becoming subject to Quad Ob. Depending on a company’s operations, this requirement could necessitate equipment upgrades at many facilities.

Storage Tank Requirements

The finalized regulations for storage tanks will dramatically increase the number of new and existing sources subject to federal emissions standards because the emissions thresholds to trigger the requirements now apply not only to individual storage tanks, but also to aggregated emissions from storage tank batteries. The regulations define a tank battery as “a group of all storage vessels that are manifolded together for liquid transfer” and state that a tank battery can consist of a single storage vessel if only one storage vessel is present. The final rule compares battery-wide potential emissions, rather than those of a single storage tank, against the 6 tons per year (“tpy”) applicability threshold for VOCs or the 20 tpy threshold for methane emissions. Tank batteries exceeding the above limits must reduce emissions of VOC and methane by 95 percent. Each tank battery must be equipped with one or more closed vent systems which route all emissions to a process or one or more control devices.

EPA also made it much easier for an existing tank battery to trigger the “modification” test and therefore become subject to Quad Ob: any action that increases throughput at a tank battery (including refracturing a well or connecting a new well to an existing tank battery) will now be considered a modification that triggers Quad Ob requirements.

Many states have emission limits that apply to facilities in the oil and gas sector. EPA has recognized that those limits can reduce the potential for VOC or methane emissions from storage vessels to below the applicability threshold if they are “legally and practicably enforceable.” EPA’s December 2022 proposed rule included a definition of “legally and practicably enforceable” that is narrower than the standard EPA uses when approving state implementation plan provisions as sufficiently robust, meaning that some state limits might no longer be deemed “legally and practicably enforceable.”

Despite concerns raised by states and industry members, EPA finalized its new definition of “legally and practicably enforceable,” which requires, among other things, that the claimed “limit” must include quantitative production and/or operational limit(s), performance testing for control devices that establish parametric limits, ongoing monitoring of parametric limits to ensure continued compliance, and recordkeeping and periodic reporting requirements. Moreover, EPA will not allow owners and operators a transition period to obtain legally and practicably enforceable permit limits for facilities that commenced construction after December 6, 2022. In other words, the permit limits that were in place when the facility was constructed will be the ones that EPA assesses for legal and practicable enforceability at the time the unit begins production. If EPA deems applicable state standards not “legally and practicably enforceable,” it will disregard the state limits and treat the storage vessels as uncontrolled for purposes of federal regulation — in short, potentially making them much more likely to trigger the applicability limits discussed above. This new definition thus has the potential to create substantial friction between EPA and the states, and could result in many more tanks and tank batteries becoming subject to federal emission standards.⁶ Companies may need to review any existing applicability determination procedures that depend on “legally and practicably enforceable” permit limit determinations to confirm that the permits they are relying on meet the EPA definition. Otherwise, they may underestimate the number and identity of vessels subject to the new requirements.

Abandoned and Plugged Well Requirements

In addition to conducting monitoring surveys of fugitive emissions components at well sites or centralized production facilities, owners and operators must now continue those surveys for all well sites until the sites are permanently closed following the required well closure plan. After all well closure activities are completed, a final OGI site survey must be conducted and recorded in the well closure plan, and any emissions detected must be eliminated. These new requirements will increase the end-of-life costs for wells, and may have a particularly big impact on owners and operators whose business models focus on acquiring and operating older wells that already produce less and, therefore, have lower margins.

Requirements for Sources Subject to NSPS OOOO and OOOOa

The final rules clarify that sources currently subject to NSPS Quad O and Quad Oa must continue to comply with those VOC and methane standards until sources are subject to and in compliance with a state or federal plan implementing Quad Oc or undergo a modification and become subject to Quad Ob. Although Quad Oc only sets methane emissions limits and does not have emissions limits for VOCs, EPA stated that “the methane presumptive standards in EG OOOOc will result in the same or greater emission reductions than the VOC and methane standards in previous NSPS KKK, NSPS OOOO, or NSPS OOOOa.” This is so because VOCs and methane are both part of natural gas, and requirements that restrict natural gas leaks result in reductions in both VOC and methane emissions.

However, Quad Oc does not contain SO₂ standards, so sources subject to SO₂ standards in Quad O or Quad Oa should continue to comply with their respective SO₂ related requirements unless they are modified and become subject to the requirements in Quad Ob. If a source currently subject to Quad O or Quad Oa undergoes modification or reconstruction after December 6, 2022, it will become subject to the methane and VOC emissions limits contained in Quad Ob.

Legal Challenges

The final rule will be subject to litigation in the coming months, which could complicate compliance dates and assessments of what owners and operators will need to do to comply with new regulations. Litigation could also delay state and Tribal implementation of Quad Oc, which could, in turn, impact the assessment of IRA methane fees. Owners and operators will want to stay apprised of such developments. For its part, EPA has described the various components of the final rule as “severable” with regard to each emission source being regulated, suggesting that even if particular provisions are successfully challenged in court, EPA will expect compliance with the remaining portions of the rule.

Owners and operators of facilities currently required to report their GHG emissions under CAA subpart W regulations should also be mindful of EPA’s separate proposed rule implementing the “waste emission charge” so that they understand the interaction between these two rules, and consider filing a comment letter with EPA on the new proposed rule.

¹ In a revision to the proposed program, certified third-party notifiers must submit notification within 15 calendar days of the date of detection of the super-emitter event. Otherwise, EPA will not review the notification.

² The portal will be available at https://www.epa.gov/super-emitter. The portal is currently not active. 

³ EPA will only authorize remote sensing technologies — the Super Emitter Program does not authorize certified third parties to enter oil and gas facilities.

⁴ According to Kayrros Methane Watch, there have been over 600 “super-emitter” events in the United States from the oil and gas sector since January 1, 2019.

⁵ Note that the VOC restrictions only apply to sources subject to NSPS Quad Ob. The Quad Oc regulations only set methane emissions limits.

⁶ Some states (for example, New Mexico and Colorado) will need to revise their oil and gas air quality regulations to satisfy these new standards, while other states (for example, Texas) might be able to use their current permit by rule regulations to satisfy this new requirement.