The EPA’s Methane Waste Emission Charge: A Tax by Any Other Name

The Environmental Protection Agency (EPA) has published a proposed rule to assess and collect billions of dollars in methane “waste emission charges” from the oil and gas sector. The proposal implements section 60113 of the Inflation Reduction Act of 2022 (“IRA”), which gives the EPA new powers to act as tax assessor, collector, and enforcer based on a scant four subsections of statutory language. Without more detailed congressional tax policy guidance, the EPA has been left to its own policy preferences in designing this new methane tax program. And it shows. Time and again, the proposed rule interprets the IRA in ways that maximize tax revenue, minimize tax exemptions, and shift oversight costs onto the taxpayer.

After summarizing below how the EPA plans to implement the methane tax, we set out our observations on the most thought-provoking aspects of the proposal, including some that might have significant legal deficiencies that would warrant filing a public comment by March 26, 2024.

Summary of the proposed rule

Applicability. The waste emission charge (“WEC”) is imposed on methane emissions at facilities that emit more than 25,000 metric tons of carbon dioxide equivalent (“CO₂e”), as reported in Subpart W of the EPA’s Greenhouse Gas Reporting Program, in: (1) the onshore and offshore production sector; (2) the onshore natural gas gathering and boosting, processing, transmission, and storage sector; and (3) the liquified natural gas (“LNG”) storage, export, and import sector. Importantly, the Subpart W rules define a “facility” in the production and gathering and boosting sectors as the combination of all individual units under common ownership or control in a single hydrocarbon basin.

Emission thresholds. The proposed rule assesses the WEC only on methane emissions that exceed an “emissions threshold,” which differs based on the type of facility being taxed. In plain terms, these emissions thresholds are congressionally approved methane emission rates that will incur no WEC. For example, production facilities are not taxed on emissions of up to 0.2 percent of the natural gas sent to sales, while gas processing, gathering and boosting, and LNG facilities are not taxed on emissions of up to 0.05 percent of natural gas sent to sale to or through the facility. In addition, facilities that flare associated gas are taxed more aggressively than facilities that sell the associated gas. For example, at a facility with a gas-oil ratio of 3.1 mscf/bbl, the emissions threshold for a 1,000 barrels per day of oil production would be 43 metric tons if the facility sells its gas, but only 4 metric tons if it does not. This means that the facility that does not sell its gas owes the WEC on 39 more metric tons that the facility that sells its gas — a difference in tax year 2024 of about $35,000 per facility.

Tax exemptions. In addition to the emission threshold, the rule defines three exemptions that can lower the assessed tax. The first is called the “regulatory compliance exemption,” and waives the tax at any individual facility that complies perfectly with the EPA’s recently amended New Source Performance Standards Subparts OOOOb and OOOOc. The second is relevant to facilities that do not send associated gas to sales and provides partial tax relief if the failure to sell the gas is attributable to a delay in permitting the gas sales infrastructure in the area. The third provides partial tax relief for abandoned and plugged wells.

Tax netting. The IRA allows emissions at a facility that are below the emissions threshold to offset emissions at another facility under common ownership or control that are above the emissions threshold.

The taxpayer. The “WEC obligated party” is the person who owns or operates the facility on December 31 of each reporting year, or the designated representative of a facility with multiple owners or operators. Importantly, limited partnership shareholders are not considered “owners” for purpose of identifying the taxpayer.

Things We Are Thinking About

While much of the proposed rule is driven by statutory directives (for example, the different emission thresholds for different facilities, and the scope of the tax exemptions), many aspects of the rule — some controversial — are creatures of the EPA rulemaking process. We believe that all these aspects merit a public comment, and some of them, if not corrected, could be challenged successfully on appeal.

What is a facility?

The IRA charges the WEC to the owner or operator of an “applicable facility” that emits more than 25,000 metric tons per year (“mtpy”) of CO₂e. The IRA defines an “applicable facility” to mean a facility within nine industry segments, as further defined by Subpart W. For facilities in the underground natural gas storage segment, for example, it is not hard to decide what the “facility” is — it is the single geographic facility that stores natural gas underground. But for “facilities” in the onshore petroleum and natural gas production and the gathering and boosting segments, the answer is not so clear.

That is because the EPA’s Subpart W rules have a special definition for “facilities” in these two industry segments. In those segments, the “facility” is defined to include all individual production (or gathering and boosting) assets in a single hydrocarbon basin. Otherwise, not many production (or gathering and boosting) facilities would have to report under Subpart W because few production facilities individually emit more than 25,000 mtpy CO₂e.

The problem with the proposed rule is that the IRA did not define “applicable facility” by reference to the Subpart W definitions of “facility.” It did so by reference to the Subpart W definition of the nine industry segments, none of which include the special “facility” definition for production, gathering, and boosting. Moreover, the IRA drafters knew how to aggregate facilities if they wished — tax netting can be performed “within and across all applicable segments.” The proposed rule makes no apparent effort to address this statutory text and leaves open the question of whether the tax may be imposed at an individual production, gathering, or boosting asset that emits less than 25,000 mtpy CO₂e.

How does tax netting work (or not)?

The IRA expressly allows emissions at one facility that are below the emission threshold to offset emissions at another facility that are above the emission threshold. However, the proposed rule restricts netting by restricting netting “credits” only to “applicable facilities” (that is, facilities with more than 25,000 mtpy CO₂e). That means that facilities with very low methane emission rates (an outcome encouraged by the IRA) cannot create netting credits if they do not emit more than 25,000 mtpy CO₂e. Not only is this approach contrary to the plain statutory netting text, but it also discourages ongoing methane reduction projects at facilities with less than 25,000 mtpy CO₂e.

Is the regulatory compliance exemption real?

The IRA does not impose the WEC at facilities that are subject to NSPS Subparts OOOOb or OOOOc. This exemption has two conditions: (1) that the applicable OOOOb or OOOOc program is “in effect in all States with respect to the applicable facilities”; and (2) the facility must be in compliance with the methane emission requirements of the applicable NSPS. The EPA’s proposed rule takes such a narrow view of these conditions that the regulatory compliance exemption might never provide the intended tax relief. Here’s how.

First, the EPA decided to interpret the first condition to mean that every state must have an approved Subpart OOOOc program before any facility in any state may claim the exemption. This interpretation appears to ignore the phrase “with respect to the applicable facilities” in the statute and might be unlawful. This interpretation also fails to reward states that submit approvable Subpart OOOOc programs, because their oil and gas industry gets no tax benefit until the least timely state submits its program. On the other hand, the interpretation does not punish the late acting state — it collectively punishes all states. As a policy choice, the EPA’s interpretation is lamentable. As a legal matter, the EPA’s interpretation might be unlawful.

Second, the EPA interpreted the second condition to require “no deviations” at a facility during the reporting year, including no deviations with emission standards, work practice standards, and monitoring, reporting, reporting, and recordkeeping requirements. Considering that Subparts OOOOb and OOOOc impose a “no discernible emissions” standard for methane, a single wisp of methane detected using an optical gas imaging camera on one day out of the year will disqualify the facility from the regulatory compliance exemption.

Is the permitting delay exemption real?

The IRA provides partial relief from the aggressive taxation at production facilities that flare instead of selling natural gas if the taxpayer can demonstrate that the necessary gas gathering infrastructure permitting has been delayed. The EPA imposes four conditions of a showing of permitting delay, the most important of which is that the permit must have been delayed for between 30 and 42 months from the date the permitting agency deemed the permit application complete. What this condition means in practice is that the more aggressive tax will be owed for three or four years after a permit application has been filed in a situation that is outside the control of the producer. The EPA has requested — and surely should receive — public comments on whether these conditions are realistic.

How will this rule impact buying and selling taxed assets?

The proposed rule requires the owner of the “applicable facility” on December 31 of a reporting year to pay the WEC. The EPA acknowledges complexities in ownership structure and (to a lesser extent) the effect of mergers and acquisitions in the sector. The EPA’s proposed solution is that multiple owners may designate a representative to make tax filings and pay taxes. That is an adequate solution as far as the EPA is concerned, but it requires WEC owner agreements to be executed that clarify the responsibility for WEC payments. Particularly in a multi-owner situation, owners and operators must be aware of this new obligation to negotiate a designated representative agreement. And in the context of mergers and acquisitions, parties must take great care to assess and negotiate responsibility for the payment of taxes, in addition to considering the WEC impacts on the value of the asset.

This information is provided by Vinson & Elkins LLP for educational and informational purposes only and is not intended, nor should it be construed, as legal advice.