Key Takeaways
- Section 60113 of the Inflation Reduction Act adds Section 136 to the Clean Air Act, imposing a first-ever direct “charge” on methane emissions.
- The charge is based on an unworkable comparison between the weight of methane emitted and the volume of the natural gas stream sent to sale.
- In light of West Virginia v. Env’t Prot. Agency, 142 S. Ct. 2587 (2022), EPA likely lacks the authority to cure the statute’s unworkability through substantive rulemaking.
Introduction
Part I of this three-part methane update discussed the state of substantive methane regulation in the United States and touched on the Inflation Reduction Act’s (“IRA” or “the Act”) addition of Section 136 to the Clean Air Act. This Part II covers Section 136’s first-ever federal “charge on methane emissions[.]”[i] Part III will cover currently proposed changes to the substantive regulation of methane emissions.
Section 136’s charge is on the quantity, not on the value, of emitted methane. It is therefore what tax lawyers call a “specific” excise tax.[ii] The tax applies to persons who emit enough greenhouse gases (“GHGs”) to have to report those emissions to the Environmental Protection Agency (“EPA”) under the Clean Air Act. The tax applies to emissions starting in calendar year 2024.[iii] The basic tax formula is this: An operator calculates the number of tons of methane it emits in the year from its “applicable facility.” Note, the calculation is limited to methane—it does not include all GHGs. For example, if a producer is flaring “associated gas” produced with oil and if the flare has a very high “destruction efficiency,” then the methane in the gas is combusted into water and carbon dioxide. Although CO2 is the key GHG, it is not taxed under Section 136.
The formula then subtracts from that tonnage a number called the “waste emissions threshold.” If the operator has emitted more than the threshold, then the excess is assessed what is called the “charge amount.”[iv] A simple illustration might help. For example, assume you own a natural gas producing field and the field is your applicable facility. Assume your facility emits 1,000 metric tons of methane per year. The question, then, is whether those emissions exceed the “waste emissions threshold” for gas production. Section 136 says that for natural gas production facilities, the threshold is “0.20 percent of the natural gas sent to sale from such facility.”
Wait a moment. This is just the Introduction and already Section 136 has brought the reader to a complete stop. For the purpose of the tax, methane is measured by weight—metric tons. But sales of gas are measured by volume (thousands of cubic feet) or by heating content (millions of British thermal units). How much of an apple equals 0.2 percent of an orange?
Furthermore, “natural gas sent to sale” typically includes methane plus a series of heavier gaseous molecules, like ethane, propane, the butanes, the pentanes, and so forth. Methane has a molecular weight of 16 grams, air a molecular weight of 29 grams. Water has a molecular weight of 18 grams, propane a weight of 44 grams. Methane, in short, is the lightest component of gaseous hydrocarbons “sent to sale,” but it is the only component explicitly taxed. How is this tax supposed to work?
To complete the illustration, we ask the reader to suspend disbelief and assume the operator’s volume of methane in gas “sent to sale” equals, when multiplied by 0.2 percent, 5,000 metric tons per year. Here the methane emissions of 1,000 tons are less than the threshold of 5,000 tons, so no tax would be owed.
This article discusses some key issues in how the tax will be implemented. Expect ambiguity.
Overview of Section 136(C) through (h)
As we discussed in Part I, oil and gas operations are not the only, and are not the most significant, source of methane emissions into the atmosphere. But they are uniquely the subject of the methane tax.
The IRA’s basic idea is to tie the tax to the reporting of GHG emissions to the EPA under its “Subpart W” regulations.[v] Some of the concepts in Subpart W of Title 40, Part 98 of the Code of Federal Regulations (“Subpart W”) apply to the tax; some of the tax concepts are new. In total, there are six basic concepts underlying the tax.
First, your activity must be within one of nine “industry segments.” These segments are listed in Section 136(d) and are defined in the regulations in Subpart W. Second, you must own or operate an “applicable facility” within one of those segments. Emissions are reported on the facility level. Third, the facility must be one reporting more than 25,000 metric tons of GHGs measured as carbon dioxide equivalent per year. This is the same threshold as the current reporting threshold under Subpart W.
The tax is not on GHGs emitted, just on methane. Therefore, having to report under Subpart W does not automatically mean you owe any tax. And some methane emissions below a certain minimum amount are not taxed. Thus, the fourth concept is the “waste emissions threshold.” The Act sets three threshold levels: one for production, one for natural gas transmission, and one for “nonproduction” oil and gas “systems.” Fifth, unless the facility is exempted, if the facility’s emissions exceed the threshold, the “charge amount” applies. The charge applies to each metric ton of methane by which the facility exceeds the threshold. The charge is $900/ton for 2024, $1,200/ton for 2025, and thereafter $1,500/ton.[vi] Sixth, a facility can be covered by an exemption. There are three exemptions. We now turn to each of the six concepts.
- Industry Segments
Section 136 is aimed at the petroleum and natural gas “industry segments” that must report under Subpart W. Section 136(d) incorporates the definitions of the industry segments in Subpart W by reference, in addition to listing them explicitly. Those industry segments are[vii]:
(1) Offshore petroleum and natural gas production.
(2) Onshore petroleum and natural gas production.
(3) Onshore natural gas processing.
(4) Onshore natural gas transmission compression.
(5) Underground natural gas storage.
(6) Liquefied natural gas storage.
(7) Liquefied natural gas import and export equipment.
(8) Onshore petroleum and natural gas gathering and
boosting.
(9) Onshore natural gas transmission pipeline.
- Applicable Facilities within the Industry Segment
Although the IRA does not define what constitutes a “facility” within the industry segments, Subpart W does.[viii] Owners and operators of a “facility” that falls within one of these segments must report all the GHGs of the facility.[ix] Therefore, the definition of “facility” determines the reporting scope.
Facilities are defined differently under Subpart W, depending on the industry segment. For example, Subpart W defines “Facility with respect to onshore petroleum and natural gas production” as:
all petroleum or natural gas equipment on a single well-pad or associated with a single well-pad and CO2 EOR operations that are under common ownership or common control including leased, rented, or contracted activities by an onshore petroleum and natural gas production owner or operator and that are located in a single hydrocarbon basin as defined in § 98.238. Where a person or entity owns or operates more than one well in a basin, then all onshore petroleum and natural gas production equipment associated with all wells that the person or entity owns or operates in the basin would be considered one facility.[x]
Separately, Subpart W defines “Facility with respect to the onshore natural gas transmission pipeline segment” as “the total U.S. mileage of natural gas transmission pipelines, as defined in this section, owned and operated by an onshore natural gas transmission pipeline owner or operator as defined in this section.”
However, there are no specific definitions for facilities that fall within the following categories: (1) offshore petroleum and natural gas production, (2) onshore natural gas processing, (3) onshore natural gas transmission compression, (4) underground natural gas storage, (5) liquefied natural gas storage, and (6) liquefied natural gas import and export equipment. Section 98, Subpart A’s definition of “Facility” applies to the six not specifically defined. Subpart A defines “Facility” as:
any physical property, plant, building, structure, source, or stationary equipment located on one or more contiguous or adjacent properties in actual physical contact or separated solely by a public roadway or other public right-of-way and under common ownership or common control, that emits or may emit any greenhouse gas. Operators of military installations may classify such installations as more than a single facility based on distinct and independent functional groupings within contiguous military properties.[xi]
The preamble to the Subpart W reporting rule proposal, published on April 12, 2010, lays out why these were specifically defined. After reviewing relevant comments and industry definitions and deciding “that it was impractical to include each of the over 160 different sources of vented and fugitive CH4 and C02 emissions in the petroleum and natural gas industry,” the EPA settled on basin-level reporting.[xii] It found that the reporting entity would be the operating entity listed on the well drilling permits for all well pads within a single hydrocarbon basin defined by the American Association of Petroleum Geologists’ three-digit Geological Province Code. In contrast, EPA’s guidance has made clear that “offshore petroleum and natural gas production are reported under Subpart W of the GHGRP for each platform.”[xiii]
This difference in treatment illustrates the odd policy consequences that occur when a data reporting law (Subpart W) is used as the basis for a new taxation regime. Onshore, all production well pads within a geologic basin are one facility. Offshore, the production platform (the approximate analog of an onshore multi-well pad) is the facility. As a general matter, then, onshore oil and gas producers could pay more methane taxes than offshore producers, even if an onshore well pad and an offshore platform emit the same amount of methane. This is because the offshore facility is more easily beneath the 25,000 metric ton threshold for reporting than the onshore facility is likely to be.
Most facility owners and operators will already have defined their respective facilities under Subpart W for reporting until this point.[xiv]
- Reporting Threshold
Facilities must analyze two thresholds in determining whether their methane emissions are subject to the charge.
First, facilities are not subject to the charge at all unless they report “more than 25,000 metric tons of carbon dioxide equivalent of greenhouse gases emitted per year pursuant to subpart W . . . regardless of the reporting threshold under that subpart.” Currently, oil and gas facilities must report under Subpart W if they emit 25,000 metric tons or more of carbon dioxide equivalent (“CO2e”) per year.[xv] Therefore, as Subpart W stands now, facilities that report emissions under Subpart W for reporting year 2024 are subject to the charge under the first threshold beginning in 2025. However, if the Subpart W threshold changes, Section 136 makes clear the charge will still apply for emissions reports over 25,000 metric tons of CO2e of GHGs.[xvi]
Unlike the second methane waste threshold, discussed below, the first applicability threshold applies to all GHG emissions.[xvii] Therefore, if a facility reports more than 25,000 metric tons of CO2e, including carbon dioxide, methane, and nitrous oxide combined, it is subject to the charge on just methane emissions.
- Waste Emission Thresholds
The applicable facilities that are subject to the charge under the first threshold are only charged on those methane emissions that exceed a second “waste emission threshold,” defined in Section 136(f). The waste emission thresholds differ for each industry segment defined in Section 136(d). For example, facilities that fall within the petroleum and natural gas production industry segment under Section 136(d) are charged on metric tons of methane that exceed either “(A) 0.20 percent of the natural gas sent to sale from such facility; or (B) 10 metric tons of methane per million barrels of oil sent to sale from such facility, if such facility sent no natural gas to sale.”[xviii] On the other hand, nonproduction petroleum and natural gas systems are charged on metric tons of methane emissions exceeding “0.11 percent of natural gas sent to sale from or through such facility.”[xix]
As the Introduction indicated, there are two unworkable problems: The waste emission threshold is tied to volume, but the tax is tied to weight. And the waste emission threshold is tied to all components of gas sent to sale, but the tax is tied to the methane component alone.[xx]
- The Charge
For applicable facilities, the charge for reporting year 2024 is $900 per metric ton of methane emissions reported over the applicable annual waste emissions threshold.[xxi] In 2025, the charge will be increased to $1,200 per metric ton, and the charge peaks at $1,500 per metric ton in 2026 and “each year thereafter.”[xxii]
- Exemptions
Section 136 carves out a few exemptions for the methane charge. However, further guidance will be needed to implement them.
A. Exemption for meeting performance standards
Section 136(f)(6)(A) excepts facilities from the charge if two conditions are met: (1) Sections 111(b) and (d) of the Clean Air Act (the Performance Standards) “are in effect in all States with respect to the applicable facilities” and (2) compliance with Sections 111(b) and (d) “will result in equivalent or greater emissions reduction as would be achieved by the” proposed rule under those sections “if such rule had been finalized and implemented.”[xxiii] So, although the enforcement of Section 136 does not depend on the implementation of the proposed rule according to its conditional language (“if such rule has been finalized and implemented”), it could cause confusion regarding when the period of exemption starts.
Implementing this exemption will require fleshing out as well. For example, compliance with the proposed rule will only exempt a facility from the charge if compliance results in equivalent or greater emissions reduction than approved state plans . However, it is not clear how the EPA will determine how much the proposed rule or the plans will reduce emissions, to permit a comparison between the two. Because the facilities that are subject to this charge vary in different industry segments, this analysis will look different from facility to facility. What is clear from the rule is that the EPA administrator is the one who will determine whether a facility falls within this exemption.[xxiv]
B. Exemption for “Unreasonable Delay” in Permitting
There is an exemption for emissions that exceed the waste emissions thresholds if there was “unreasonable delay” in permitting of equipment needed for the offtake of gas due to implementation of mitigation efforts for methane emissions.[xxv] Because the EPA administrator is the one deciding what constitutes an unreasonable delay, this exemption will need further clarification before being implemented.
C. Exemption for Plugged Wells
Finally, permanently plugged wells are not subject to the charge starting in the year they were shut in.[xxvi]
Questions Going Forward
- How will the EPA implement the charge?
Although Subpart W can provide the data collection aspect of assessing charges owed, the EPA currently does not collect charges and there has never been a direct tax on methane emissions. Therefore, assuming EPA even has rulemaking authority to implement the charge,[xxvii] it will have to create regulations addressing the procedure for collection of the tax and implementation of exemptions within the next two years.
- What is the meaning of “gas sent to sale”?
Some of the waste emissions thresholds are based on emissions from “gas sent to sale.”[xxviii] However, this term is not defined in Section 136 or Subpart W. We have not found this phrase used anywhere in EPA’s regulations in Title 40 of the Code of Federal Regulations. This is another place where, if EPA even has the authority to issue regulations, regulations will be needed to determine what amount of the emissions are charged.
- What does this mean for carbon offsets?
The charge focuses on raw output emission data without considering any of the GHG offsets that oil and gas companies have purchased. Therefore, the tax disincentivizes persons subject to the tax from obtaining offsets. Offsets on a large scale are essential to achieving the administration’s goals of net zero emissions, so this feature of the tax directly contradicts the administration’s ultimate objectives.
- Can the tax threshold change through manipulation of the CO2 multiplier?
Although the charge’s initial threshold is more than 25,000 metric tons of CO2e regardless of what the Subpart W threshold is, there is room for manipulation of the actual output of GHGs needed to meet the threshold if the CO2e multiplier is changed. As discussed in Part I of this series, methane is assigned a CO2e multiplier because it is more effective at trapping heat than CO2 is. In other words, if a smaller or larger amount of methane equals one metric ton of CO2e, the amount of emissions that will qualify a facility for the charge could change while the actual threshold does not.
Revenue to Be Generated
To give an idea of the impact of the tax, in 2021 alone, around 470 onshore production facilities reported emissions under Subpart W, and those facilities reported 89,769,507.5 metric tons of CO2e.[xxix] Because the initial threshold to be subject to the tax is the current reporting threshold, currently all the facilities reporting are potentially subject to the tax.[xxx]
The Congressional Budget Office released a detailed estimate of revenue derived from the methane charge: $850 million in net revenue in FY 2026 (the first year after the tax is imposed), peaking at a net $1.4 billion in FY 2028 and coming back down to $500 million in FY 2031.[xxxi]
[i] Inflation Reduction Act of 2022, Pub. L. No. 117-169, § 60113 (2022), enacting Clean Air Act § 136, to be codified at 42 U.S.C. § 7436.
[ii] “An excise tax, because it is based on a particular transaction or activity, can be imposed only once per act, whereas an ad valorem property tax can be imposed annually, as is typical of property taxes.” United States v. 4,432 Mastercases of Cigarettes, More or Less, 448 F.3d 1168, 1185 (9th Cir. 2006); Tax, Black’s Law Dictionary (11th ed. 2019) (“excise tax. . . A tax imposed on the manufacture, sale, or use of goods (such as a cigarette tax), or on an occupation or activity (such as a license tax or an attorney occupation fee). . . . specific tax . . . A tax imposed as a fixed sum on each article or item of property of a given class or kind without regard to its value.”); see also An Overview of Excise Tax, Internal Revenue Service (Oct. 7, 2020), https://www.irs.gov/newsroom/an-overview-of-excise-tax#:~:text=In%20general%2C%20an%20excise%20tax,and%20other%20goods%20and%20services.
[iii] Clean Air Act § 136(g).
[iv] Clean Air Act § 136(e)–(f).
[v] 40 C.F.R. §§ 98.230–98.238 (2010) (codifying 40 C.F.R. Part 98, Subpart W).
[vi] Inflation Reduction Act § 136(e).
[vii] The one exception is that the “natural gas distribution” industry segment under Subpart W is not listed as an industry segment in the IRA.
[viii] The IRA states that “the term ‘applicable facility’ means a facility within the industry segments, as defined in subpart W of part 98 of title 40.” Inflation Reduction Act § 60113. The EPA website for Subpart W reporters includes a diagram of the industry segments included under Subpart W. The diagram’s legend explains which “facilities” must report for each segment. For example, for the segment “Onshore Petroleum & Natural Gas Production,” the legend states, “Each owner or operator of onshore petroleum and natural gas production wells and related equipment reports under subpart W the combined emissions for all wells that they own or operate within each hydrocarbon basin. Emissions from stationary and portable fuel combustion equipment are reported under ‘Subpart W’ of the GHGRP.” GHGRP and the Oil and Gas Industry, Env’t Prot. Agency (May 12, 2022), https://www.epa.gov/ghgreporting/ghgrp-and-oil-and-gas-industry.
[ix] 40 C.F.R. § 98, Subpart A defines facility as “any physical property, plant, building, structure, source, or stationary equipment located on one or more contiguous or adjacent properties in actual physical contact or separated solely by a public roadway or other public right-of-way and under common ownership or common control, that emits or may emit any greenhouse gas.”
[x] Inflation Reduction Act of 2022 § 60113.
[xii] Mandatory Reporting of Greenhouse Gases: Petroleum and Natural Gas Systems; New Rule, 75 Fed. Reg. 18608, 18614 (April 12, 2010).
[xiv]See the Subpart W reporters’ website for guidance to owners/operators of facilities on whether they need to report. Subpart W Facility Registration, Env’t Prot. Agency, https://ccdsupport.com/confluence/display/help/Subpart+W+Facility+Registration#SubpartWFacilityRegistration-FacilityNamingConventionforSubpartWReporters (last accessed Nov. 20, 2022) (explaining how to name facilities). When the EPA published Subpart W, multiple commenters expressed concern regarding the inconsistency among the industry definition of “facility,” the definition of “Facility” in Subpart A, and the definition of “Facility” in Subpart W. For example, there was much concern around the definition of “facility” within the Onshore Petroleum and Natural Gas Production industry segment, as it covers all wells in a hydrocarbon basin. The EPA thinks basin-level reporting is the “least complex of all facility definition options given the well-defined facility definition and minimal impact on small and medium businesses.” For now, the guidance given through comment responses and online resources for reporting under Subpart W seems to be the most helpful for determining which facilities will be taxed under Section 136. See Env’t Prot. Agency, Mandatory Greenhouse Gas Reporting Rule Subpart W – Petroleum and Natural Gas: EPA’s Response to Public Comments 117.
[xv] 40 C.F.R. § 98.231 (Subpart W reporting thresholds).
[xvi] Clean Air Act § 136(c) (“The Administrator shall impose and collect a charge on methane emissions . . . from . . . an applicable facility that reports more than 25,000 metric tons of carbon dioxide equivalent of greenhouse gases emitted per year pursuant to subpart W . . . regardless of the reporting threshold under that subpart.” (Emphasis added.))
[xvii] Clean Air Act § 136(i). Section 136(i) defines “greenhouse gas” as including “carbon dioxide, hydrofluorocarbons, methane, nitrous oxide, perfluorocarbons, and sulfur hexafluoride.” Subpart W requires reporting of carbon dioxide, methane, and nitrous oxide. 40 C.F.R. § 98.232.
[xix] Clean Air Act § 136(f)(3) (emphasis added).
[xx] Clean Air Act § 136(e)(1) directs the taxpayer to use “the number of metric tons of methane emissions reported pursuant to subpart W . . . .” Subpart W draws a clear distinction between methane and other components of a natural gas stream. By definition, “methane” is CH4. 40 C.F.R. § 98.6. And the regulations on reporting methane draw a clear distinction between methane and the other components in a “hydrocarbon product stream,” such as “ethane, propane, butane, pentane-plus, and mixed light hydrocarbons.” 40 C.F.R. § 98.233(n)(2)(iii).
[xxi] Clean Air Act § 136(f).
[xxii] Clean Air Act § 136(f).
[xxiv] Clean Air Act § 136(f)(6) (stating exemption will apply “upon a determination of the Administrator” that the requirements are met).
[xxv] Clean Air Act § 136(f)(5).
[xxvi] Clean Air Act § 136(f)(7).
[xxvii] The authors find it doubtful, after West Virginia v. Env’t Prot. Agency, 142 S. Ct. 2587 (2022), that the EPA has the authority to issue substantive regulations to implement the tax or resolve inconsistencies in the statutory language. Only Section 136(h) alludes to rulemaking, and it is limited to assuring that the calculation of methane emissions under Subpart W is based “on empirical data[.]” The general statutory authority for Subpart W’s regulations is Section 114(a)(1) of the Clean Air Act, 42 U.S.C. § 7414(a)(1). See Mandatory Reporting of Greenhouse Gases: Petroleum and Natural Gas Systems, 75 Fed. Reg. 74458, 74460–61 (Nov. 30, 2010) (final rule). That authority concerns the collection of information, not the determination, for example, of what gas is “sent to sale.”
[xxix] Env’t Prot. Agency, GHGP Data 2020 (Aug. 7, 2021), www.epa.gov/ghgreporting/data-sets.
[xxx] Indep. Petroleum Ass’n Am., Inflation Reduction Act: IPAA Analysis on Methane Charge Provisions (Aug. 2022).
[xxxi] Estimated Budgetary Effects of Title VI, Committee on Environment and Public Works, of H.R. 5376, the Inflation Reduction Act of 2022, as Amended in the Nature of a Substitute (ERN22335) and Posted on the Website of the Senate Majority Leader on July 27, 2022, Congressional Budget Office (July 27, 2022) (relevant information at Table 6 on page 32), https://www.cbo.gov/publication/58366.
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