US oil sector seeks flexibility on methane fee

  • Market: Crude oil, Emissions, Natural gas
  • 25/01/23

The oil and gas sector is pressing President Joe Biden's administration to provide exceptions and flexibility on a first-time federal fee on methane waste that will begin to apply in 2024.

Large oil and gas facilities on 1 January 2024 will begin paying $900 for each metric tonne (t) of methane emitted above a minimum emissions intensity, under part of the Inflation Reduction Act that will start to impose a penalty on leaks of the greenhouse gas. The fee will be $1,200/t in 2025 and rise to $1,500/t in all subsequent years.

But it will fall to the US Environmental Protection Agency (EPA) to figure out exactly how to collect the "waste emission charge" through regulations it aims to propose by March. Oil industry officials ahead of that have raised questions into how the charge will work, while asking for changes such as not imposing a charge on methane that escapes unburned from flares.

The Inflation Reduction Act bases the methane charge off "Subpart W" emissions data that oil and gas facilities emitting at least 25,000 t/yr of greenhouse gasses have been required to report to EPA for the last decade. The nearly 2,400 oil and gas facilities covered by the program in 2021 collectively estimated releasing 2.8mn t of methane that year, according to federal data.

But rather than putting a fee on all methane emissions, the law carves out an exception for methane emissions equivalent to up to 0.2pc of natural gas "sent to sale" from each facility, alongside with a different exception for oil wells. The natural gas sales threshold has puzzled industry officials, who see a mismatch between the $900/t weight-based fee and how producers structure gas sales.

"Natural gas is sold by volume," the Independent Petroleum Association of America wrote to EPA this month. "To calculate the mass requires a density volume but it is not routinely determined."

Oil industry officials say EPA needs to provide clear guidance on how to calculate the emission thresholds — including any potential calculations on converting volume to weight — because they say ambiguity could be grounds for potential fines and audits by federal officials.

Experts say EPA may have difficulty coming up with a legally defensible way to calculate what qualifies for the fee exception, since the composition and density of natural gas can vary at different wells, and can even change throughout the day. A court reviewing EPA's rules might eventually find "it's a violation of some form of due process to pass a law that no one can comply with," said BakerHostetler attorney Poe Leggette, who has represented the oil industry in past litigation.

Other industry groups are seeking to change which emissions should count toward the methane fee. The American Petroleum Institute, in comments sent last week, asked EPA to revise Subpart W to omit methane released from incomplete combustion, which it says should not be considered waste. The American Exploration and Production Council asked EPA to develop an emissions threshold that accounts for wells with "varying combinations of natural gas and oil," rather calculating the threshold based either on natural gas sales or oil sales.

Environmental groups are pushing EPA to write rules to crack down on what they see as chronic under-reporting of greenhouse gas emissions by the oil industry. The Clean Air Task Force, in comments filed this month, said some operators are claiming high flaring combustion efficiency that is "clearly not possible," while others are reporting very low emissions from pneumatic controllers that leak constantly by claiming the equipment is only technically "operating" for 1pc of the year.

Oil companies have the potential to reduce or eliminate future methane fees if they cut their emissions below the 0.2pc threshold, a step some producers are taking. ExxonMobil said today it had eliminated all "routine" flaring in the Permian basin, and also reduced non-routine flaring, as part of company goals to reduce greenhouse gas emissions.


Sharelinkedin-sharetwitter-sharefacebook-shareemail-share

Related news posts

Argus illuminates the markets by putting a lens on the areas that matter most to you. The market news and commentary we publish reveals vital insights that enable you to make stronger, well-informed decisions. Explore a selection of news stories related to this one.

News

Q&A: Shell Oman to balance upstream with renewables


24/05/24
News
24/05/24

Q&A: Shell Oman to balance upstream with renewables

Dubai, 24 May (Argus) — Shell has been in Oman for decades now and had a front row seat to its energy evolution from primarily an oil producing nation to now a very gas-rich and gas-leaning hydrocarbons producer. Argus spoke to Shell Oman's country chairman Walid Hadi about the company's energy strategy in the sultanate. Edited highlights follow: How would you characterize Oman's energy sector today, and where do new energies fit into that? Oman is one of the countries where there is quite a bit of overlap between how we see the energy transition and how the country sees it. Oman is clear that hydrocarbons will continue to play a role in its energy system for a long period of time. But it is also looking to decrease the carbon intensity to the most extent which is viable. We need to work on creating new energy systems or new components of energy system like hydrogen and EV charging to facilitate that. It is what we would like to call a 'just transition' because you think about it from macroeconomic perspective of the country and its economic health. Shell is involved across the energy spectrum in Oman – from upstream gas to alternative, clean energies. What is Shell's overall strategy for the country? In Oman, our strategic foundation has three main pillars. The first is around oil and liquids and our ambition is to sustain oil and liquids production. At the same time, we aim to significantly reduce carbon intensity from the oil production coming from PDO. The second strategic pillar is gas, and our ambition here is to grow the amount of gas we are producing in Oman and also to help Oman grow its LNG export capabilities. The more committed we are in unlocking the gas reserves in the country, the more we can support Oman's growth, diversification, and the resilience of its economy through investments and LNG revenue. Gas also offers a very logical and nice link into blue and green hydrogen, whether in sequence or as a stepping stone to scale the hydrogen economy in the country. The last strategic pillar is to establish low-carbon value chains, predominantly centered around hydrogen, more likely blue hydrogen in the short term and very likely material green in the long term, which is subject to regulations and markets developing. How would you view Oman's potential to be a major exporter of green hydrogen? When examining the foundational aspects of green hydrogen manufacturing, such as the quality of solar and wind resources and their onshore complementarity, Oman emerges as a highly competitive country in terms of its capabilities. But where we are in technology and where we are in global markets and on policy frameworks — the demand centers for green hydrogen are maturing but not yet matured. I think there will be a period of discovery for green hydrogen globally, not just for Oman, in the way LNG started 20-30 years ago. When it does, Oman will be well-positioned to play global role in the global hydrogen economy. But the question is, how much time it is going to take us and what kind of multi-collaboration needs to be in place to enable that? The realisation of this potential hinges on several factors: the policies of the Omani government, its bilateral ties with Japan, Korea, and the EU, and the technological advancements within the industry. Shell has also been looking at developing CCUS opportunities in the country. How big a role can CCUS play in the region's energy transition? CCUS is going to be an important tool in decarbonising the global energy system. We have several projects globally that we are pursuing for own scope 1, scope 2 emissions reductions, as well as to enable scope 3 emissions with the customers and partners In Oman, we are pursuing a blue hydrogen project where CCUS is a clear component. This initiative serves as a demonstrative case, helping us gauge the country's potential for CCUS implementation. We are using that as a proof point to understand the potential for CCUS in the country. At this stage, it's too early to gauge the scale of CCUS adoption in Oman or our specific role within it. However, we are among the pioneers in establishing the initial proof point through our Blue Hydrogen initiative. You were able to kick off production in block 10 in just over a year after signing the agreement. How are things progressing there? We have started producing at the plateau levels that we agreed with the government, which is just above 500mn ft³/d. Block 10 gas is sold to the government, through the government-owned Integrated Gas Company (IGC), which so far has been the entity that purchases gas from various operators in Oman like us, Shell. IGC then allocates that gas on a certain policy and value criteria across different sectors. We will require new gas if we are going to expand LNG in Oman. There is active gas exploration happening there in Block 10. We know there is more potential in the block. We still don't know at what scale it can be produce gas or the reservoir's characteristics. But blocks 10 and 11 are a combination of undiscovered and discovered resources. We are aiming to significantly increase gas production through a substantial boost. However, the exact scale and timing of this expansion will only be discernible upon the conclusion of our two-year exploration campaign in the block. We expect to understand the full growth potential by around mid to late 2025. Do you have any updates on block 11? Has exploration work there begun? We did have a material gas discovery which is being appraised this year, but it is a bit too early to draw conclusions at this stage. So, after the appraisal campaign is completed, we will be able to talk more confidently about the production potential. Exploration is a very uncertain business. You must go after a lot of things and only a few will end up working. We have a very aggressive exploration campaign at the moment. We also expect by the end of 2025, we would be in a much better position to determine the next wave of growth and where it is going to come from. Shell is set to become the largest off taker from Oman LNG, how do you view the LNG markets this year and next? As a company, we are convinced, that the demand for LNG will grow and it needs to grow if the world is going to achieve the energy transition Gas must play a role, it has to play a bigger role globally over the time, mainly to replace coal in power generation and given its higher efficiency and lower carbon intensity fuel in the energy mix. While Oman may not be the largest LNG exporter globally or hold the most significant gas reserves, it is a niche player in the gas sector with a sophisticated and high-quality gas infrastructure. Oman's resource base remains robust, driving ongoing exploration and investment efforts. This growth trajectory includes catering to domestic needs and servicing industrial hubs like Duqm and Sohar, alongside allocating resources for export purpose. We have the ambition to grow gas for domestic purpose and for gas for eventual exports Have you identified any international markets to export LNG? We have been historically and predominantly focused on east and we continue to see east as core LNG market with focus on Japan, Korea, and China. Europe has also emerged on the back of the Ukraine-Russia crisis as growing demand center for LNG. Over time we might focus on different markets to a certain extent. It will be driven on maximising value for the country. By Rithika Krishna Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

News

Indonesia plans 15mn electric vehicles on roads by 2030


24/05/24
News
24/05/24

Indonesia plans 15mn electric vehicles on roads by 2030

London, 24 May (Argus) — The Indonesian government aims to have 2mn four-wheeled electric vehicles (EVs) and 13mn two-wheeled EVs on its roads by 2030, to cut emissions and save energy. This will bring about energy savings of 29.79mn bl of oil equivalent (boe) and cut exhaust emissions by 7.23mn t of CO2 in 2030, according to special staff to the minister of energy and mineral resources (ESDM) Agus Tjahjana. Indonesia's transport sector makes up around a third of the country's energy consumption and the 11mn cars on Indonesian roads produce more than 35mn t/yr of CO2, while trucks emit more than 50mn t/yr, according to ESDM secretary general Dadan Kusdiana. The country's vehicle fleet is likely to grow in coming years because of its economic development, so decarbonising the transport sector is critical to achieving net zero emissions by 2060, said the ESDM. Greater electrification of transport will also allow Indonesia to reduce its fossil fuel imports. Indonesia is keen to develop the EV battery supply chain from upstream to downstream, in view of its large nickel resources that can support the development of the industry, said Agus. Indonesia currently has nine facilities processing nickel ore into nickel and cobalt sulphate, which is one of the materials used in making EV batteries. Out of these, four are already operational while three are in the construction stage, and the remaining two are still undergoing feasibility studies. The next step is to promote the manufacture of battery precursors, cathodes, battery cells and batteries, considering that the electric charging and battery recycling industries already exist, said Agus. But there is still a large price gap between EVs and conventional vehicles, said Dadan. The Indonesian government is hence providing tax incentives and subsidies for electric cars, hybrid cars and electric motorbikes to cover this gap. "Indonesia has prepared $455mn to subsidise the sale of electric motorbikes," said Dadan, adding that the subsidy covers the sale of 800,000 new electric motorbikes and the conversion of 200,000 combustion engine motorbikes. The government estimates that 32,000 charging stations will be needed to meet demand by 2030. The total number of charging stations available was 1,566 as of April, said Agus, adding that the government aims to add up to 48,118 charging stations by 2030. The ESDM has just approved 204 nickel mining work plans for exploration and production. The country produced 175.6mn t of nickel ore output in 2023. By Prethika Nair Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

News

Opec+ to take June meetings online


24/05/24
News
24/05/24

Opec+ to take June meetings online

Dubai, 24 May (Argus) — Meetings to discuss Opec+ crude output policy that had been scheduled to take place in Vienna at the start of June have been pushed back by a day and will now be held online. The meetings — one involving Opec ministers, another involving the wider Opec+ coalition and a third consisting of the group's Joint Ministerial Monitoring Committee (JMMC) — will "convene via videoconference on Sunday 2 June 2024", the Opec secretariat said on Friday. The original schedule was for Opec+ ministers to meet in person on 1 June. The announcement puts to bed more than a week of rumours and delegate chatter about whether or not the meeting would take place in person as speculation mounts around what policy decision the group would need, or be prepared, to take. Effectively, the only thing up for debate at these meetings is the fate of the 2.2mn b/d supply cut that eight member countries, led by Saudi Arabia and Russia, committed to after the Opec+ group's last meeting in late November. That cut was originally due to last for just three months, but it was later extended for another three months until the end of June. Several weeks ago, when oil prices were under sustained upward pressure in the face of tightening fundamentals and rising geopolitical tensions, expectations were high that the group would agree to begin unwinding at least part of the 2.2mn b/d from July. But a relative easing of tensions in the Middle East, coupled with signs of continued restrictive monetary policy by the US Federal Reserve and other major central banks, has since led to a softening of oil prices and with that a change in sentiment among Opec+ delegates about what the group should do next. Delegates today argue that the market is on the whole well-supplied and in no need of additional supply from the group, particularly given the uncertainty around the outlook for oil demand, highlighted by the wide range of growth projections for 2024. At one end of the spectrum, Opec sees oil demand growth of 2.25mn b/d this year. At the other end, the IEA recently revised down its 2024 growth forecast for a second consecutive month. It now stands at 1.06mn b/d. Two Opec+ delegates said earlier this week that they expect the eight countries to extend the 2.2mn b/d cut in its entirety beyond the second quarter. One said they could extend it through to the end of the year. Compensation plans A renewed emphasis by Opec+ in recent weeks on the need for those member countries producing above their targets to not only scale back but also compensate fully for their past overproduction could be interpreted as acknowledgement by the group that the market is indeed well-supplied. Iraq and Kazakhstan, the group's biggest overproducers this year, this month issued detailed programmes outlining how they plan to compensate , while Russia this week acknowledged it had exceeded its Opec+ target for April and said it would soon submit a plan to the Opec secretariat detailing how it will make up it. Although all eyes will be on the fate of the 2.2mn b/d cut at the upcoming meetings, the fact it is a voluntary pledge and one agreed by only a handful of countries means, in theory, a decision need not happen at the ministerial meeting. As the eight countries participating in that cut are all members of the JMMC, there is a good chance the decision gets announced at the committee's meeting instead. By Nader Itayim Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

News

Sumitomo, Reti to develop CCS project in Canada


24/05/24
News
24/05/24

Sumitomo, Reti to develop CCS project in Canada

Osaka, 24 May (Argus) — Japanese trading house Sumitomo and Canadian low-carbon energy developer Reconciliation Energy Transition (Reti) have agreed to jointly develop a carbon capture and storage (CCS) project in Alberta, Canada. The firms are targeting to start operations in the April 2026-March 2027 fiscal year and store up to 10mn t/yr of CO2 in east Calgary of Alberta. The project is expected to involve building compression capacity, a CO2 pipeline network, as well as injection and monitoring wells to support permanent CCS in deep saline aquifers. The project is currently only looking at CO2 emitted by Canadian firms, and not considering CO2 exports from Japan, Sumitomo told Argus . Sumitomo will mainly take on the role of seeking Japanese partners and arranging financing for the project. The project also envisions injecting CO2 captured from potential sustainable aviation fuel and direct air capture projects in the Calgary region, which are currently under feasibility studies by Sumitomo and Reti. Fellow Japanese trading house Marubeni is also participating in developing a CCS project in Alberta with Canadian private-sector firm Bison Low Carbon Ventures. Bison is developing the Meadowbrook CCS project near Edmonton and targeting a CO2 storage capacity of 3mn t/yr. By Motoko Hasegawa Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Generic Hero Banner

Business intelligence reports

Get concise, trustworthy and unbiased analysis of the latest trends and developments in oil and energy markets. These reports are specially created for decision makers who don’t have time to track markets day-by-day, minute-by-minute.

Learn more