Who is impacted?

• E&P operators with annual CO2 equivalent emissions (not methane) that exceed 25,000 tons/year after an exemption for the first 0.20%
• We estimate, for those producers East of the Mississippi River, anyone with 220 conventional wells (single well per pad) will exceed the exemption threshold. For those west of the Mississippi River, where the factors prescribed are higher, the threshold is lower. For those with multi-well, unconventional pads, the threshold will be much lower regardless of where your wells physically reside.
• Any company with Gathering and Boosting (G&B) operations with an exemption for the first .05% of pipeline throughput.
• Royalty owners, when marginal wells are shut-in due to increased taxes, making the wells uneconomic.
• State severance tax collections, when marginal wells are shut-in due to increased taxes, making the wells uneconomic.
• If we are forced to shut-in wells due to increased taxes, domestic production will decrease, and we will have less energy independence.

What are some of the E&P segment issues?

Pneumatic devices:

• Counting the minutes that devices are in use(i.e. emitting potentially); not 24 hours a day as the math now stands would be more appropriate. Each operator knows the actual periods of usage, as opposed to the EPA’s factors for in-place devices.
• Supply chain issues persist as many companies rush to convert / change their devices over the next 18 months.
• Increased costs are certain as manufacturers seize the opportunity

The 0.20% exemption level is too low:

• This number may derive from the MiQ standards (an international group under the United Nations umbrella that has many large, or multi-national, or national oil companies, as well environmental groups as signatories/members). 2% or higher would be much better.
• The math needs to be codified as methane tons / total production (not methane tons / methane production)

Empirical data should be allowed on every portion of the tax

• Many smaller companies are forced to use the EPA’s equipment count and device emission factors. Without empirical data, the outdated studies result in higher taxes per Operator.
• Compressor methane slip factors, for one example, may be much too high depending on operating conditions.

Facility definition

• The definition of a “facility” in Subpart W is too broad, an entire basin. Not a field, not a pad, but a basin as defined. The definition should be revised specifically for the methane tax to be based upon a well pad, or compressor site, or even a field, so that the exemption opportunities make more sense.

Marginal Wells are not excluded; all well emissions count toward emission thresholds

There is no relief for inevitable production declines. This penalizes ALL legacy well production — since emissions remain relatively stable while production declines, the production exemptions of 0.20% & 0.05% (for E&P & G&B respectively) become less meaningful and make it more cost prohibitive to operate. Ironically, the rule itself is unsustainable.

What are some of the G&B segment issues?

Little to no incentive or method to reduce emissions:

• The tax is most heavily weighted toward miles of pipeline in service. We cannot reduce those miles other than by:
• shutting-in systems
• selling pipeline segments to others, who will then have to pay the tax and charge us higher gathering rates

• We conduct pipeline surveys, identify leaks, and fix those leaks. A tax, if any, should be based upon leaks and emissions data, not on miles of pipeline

Protected vs. Unprotected pipelines:

• The EPA factors are much higher for non-cathodically protected pipelines
• Much of our pipelines are above ground and cannot be cathodically protected
• The definition of “protection” should be expanded to include coated pipe as well other types of protection beyond bare steel

For compressors, methane slip factors are too high. We have empirical data that show actual methane slip is much lower than the EPA factors

Facility definition

• The definition of a “facility” in Subpart W is too broad, an entire basin. The definition should be revised specifically for the methanetax to be based upon a gathering pipeline system so that the exemption opportunities make more sense.

What are some of the timing issues?

• EPA has put forth no rules/regulations for comment. They did pose a series of questions to which IPAA, API, and others submitted comments earlier this year. The last day to submit comments for the second public comment period was 3/13/23.
• The methane tax goes into effect in 2024 and increases punitively every year.
• Methane Tax implementation should be delayed until proposed NSPS OOOOb and OOOOc, and proposed Subpart W factor reviews and revisions are finalized (2 years?). The process has been on-going for quite some time with no end in sight.
• The studies used to establish the current emission factors from EPA rely on old, outdated, and incomplete data. They should engage industry and conduct new, more relevant studies.
• In states that enact the federal standards or stricter standards, there is an opportunity for exemption. However, this takes time and states will need to create processes for implementing the yet-to-be-defined regulations. This is another argument for delay of implementation.

What are implications if revisions are not made to the law as written?

• EPA will have taxing, collection, audit, and enforcement authority for the first time.
• To the extent the methane tax makes marginal wells uneconomic to produce (expenses exceed revenues), the industry will shut-in production to avoid the tax. Is that what this administration, the Senate and Congress, or the country needs right now?
  • Less security and less energy independence
  • Less severance taxes paid
  • Less ad valorem taxes paid
• Increased expenses for wells that are not marginal will mean:
  • Less royalty payments to Lessors whose leases allow for taxes to be deducted
  • Less income taxes paid to state governments based upon the tax reducing net income