The environmental credentials of liquified natural gas (LNG) are under increasing scrutiny. Despite emitting about half the CO2 of coal when combusted, the LNG value chain remains highly carbon intensive and plagued by methane losses. 

In response, LNG players are actively working to reduce the greenhouse gas (GHG) footprint of their projects. This all comes at a cost, however, and buyers’ reluctance to pay a premium for lower-emission LNG has so far curbed sellers’ appetite to commit to major investment to reduce carbon intensity. 

This could be about to change. With the European Union (EU) extending its Emission Trading Scheme (ETS) to shipping, LNG cargoes into Europe will be subject to a carbon tax from 2024. The EU has further agreed to start monitoring methane emissions of countries and companies and to define acceptable limits for fossil-fuel imports across the value chain. For now, the first draft only refers to new LNG import contracts, but a methane tax on all LNG imports exceeding defined limits cannot be ruled out. The bloc could go further and include LNG in its Carbon Border Adjustment Mechanism (CBAM), setting an import duty at prevailing ETS carbon prices.  

Such a move will push up European gas prices, bifurcating the global LNG market and creating a European premium, as prices in markets without taxes will be lower. If taxes were limited to the EU, or even extended to Japan and South Korea, trade flows would likely be optimised to mitigate the impact. 

This does not mean that the EU’s moves can be ignored, however. US projects, in particular, will be motivated to reduce their methane emissions as they target higher European prices. But emissions taxes limited to Europe and the mature LNG markets of Northeast Asia alone will be insufficient to motivate LNG players to act decisively to reduce all GHG emissions. Only if widened to the emerging markets of Asia would a substantial tax provide the economic incentive for the industry to invest in more costly abatement options.  

In this month’s Horizons, we assess the carbon intensity of LNG projects around the world and the effects of LNG emission tax scenarios. With the lure of higher margins in premium markets, LNG suppliers must be ready to act. 

We have used Wood Mackenzie’s new LNG Carbon Emissions Tool to assess carbon and methane emissions by project and across the value chain, from the wellhead to regasification. Our analysis shows that upstream production, and the amount of methane and reservoir CO2 vented, generates the lion’s share of emissions. It also reveals a wide variance in levels of methane emissions. Measured in kgCO2 equivalent, methane only accounts for 5% to 15% of overall carbon intensity in LNG projects outside the US. But for LNG projects in the US, methane can account for as much as 25% to 40%, due to higher levels of methane losses largely because of the extensive use of pneumatic devices and compressors associated with shale gas production. 

The overall carbon intensity of LNG projects also varies significantly by region. Russia and the Middle East are home to some of the least carbon-intensive LNG projects. Construction vintage weighs on emissions in Africa and Asia Pacific. However, with a range of 800 to 1400 kg CO2e/t LNG, the US has some of the world’s highest-emitting projects, with upstream reservoir type and pipeline distance to LNG plants adding to their high methane intensity. 

The impact of these emissions on the future delivered cost of LNG projects will depend on how much methane and/or CO2 is taxed. The EU ETS carbon price, used as the reference price in those sectors that already fall within the CBAM, makes it a plausible reference for how the bloc might consider taxing both methane and carbon emissions. The EU ETS price is extremely volatile, though. It traded above US$100/t for much of the last year before dropping to US$50/t recently, partly due to warmer temperatures moderating energy demand. And a future EU ETS price of US$200/t cannot be ruled out as Europe sets increasingly ambitious carbon-emission reduction targets. 

The following chart illustrates changes to the LNG cost curve to Europe based on our understanding of current project emissions and assuming a carbon-equivalent tax of US$50/t, US$100/t and US$200/t applied to methane only and to overall GHG emissions. Some measures to reduce GHG emissions are likely to be applied over time, helping reduce emissions intensity from current levels. However, these varying scenarios help frame a clear picture of how taxes on emissions would affect the economics of LNG projects.  

The optimal abatement options broadly fall into four categories:  

Methane abatement: US gas producers are already reducing methane emissions from their operations, largely focusing on pneumatic devices and compressors. In line with certification frameworks (such as MiQ), supply from some of the country's most prolific basins has shown dramatic reductions in levels of associated methane loss and, thus, carbon intensity. In some instances, this has resulted in reductions of up to 40% of upstream emissions (wellhead to transmission) and is one of the most cost-effective options for tackling emissions. With the Inflation Reduction Act’s methane charge applying a tax escalating to US$1,500/tCH4 (equivalent to a CO2e tax of US$53/t) by 2026 for emissions above certain thresholds from the wellhead to the LNG plant, considerable further emission reductions are expected, even without considering an import tax in Europe.  

Carbon capture and storage (CCS) of reservoir CO2: For LNG projects with high reservoir CO2 content, venting can be the key driver of emissions intensity and result in some of the highest-emission LNG projects in the world (for example, more than 55% of emissions from the wellhead to LNG loading for Tangguh LNG stems from CO2 venting). However, with costs of US$50 to US$120 per tonne, the viability of CCS depends on the availability of proximate injection sites along with some level of regulatory support (such as the 45Q tax credit for carbon sequestration in the US). 

The impact of CCS on projects with high CO2, such as Gorgon and Snohvit, has been considerable, reducing total pre-shipping emissions by around 30%. Future projects that are planning or have proposed CCS – such as Qatar’s North Field East, Tangguh, MLNG 9 and Barossa – could see emissions reductions by around one-third on average. 

Electrification: Emissions from the liquefaction process can be reduced by using electric drive turbines powered by low-carbon power supplies from a proximate power grid, providing up to an 80% reduction in liquefaction emissions. In the US, existing grid-connected electric drive projects include Freeport and Elba Island LNG, while new-build projects include Corpus Christi Stage 3 and Cameron Phase 2 LNG projects. 

Several existing and proposed electric-drive LNG projects are not grid-connected (Ichthys, Papua LNG). Powered by dedicated gas-fired combined-cycle gas turbines, these projects are highly efficient. But they lack the supply of low-carbon grid power that can make electrifying liquefaction attractive from an emissions reduction standpoint. 

Retrofitting electric drives at existing projects is also under consideration. However, with significant costs already sunk in existing gas-fired turbines, this is a less economic proposition. 

Other options: Several other options that operators are pursuing have a smaller impact or are higher cost. 

Post-combustion CCS (that is, from the turbine exhaust gases) has been proposed in the US, where the 45Q tax credit is available. Worth up to US$85/t, the credit still falls well short of the cost of most post-combustion CCS developments. Combining this with an import tax on carbon would be a further boost.  

Operators are also proposing to use renewables to reduce gas combustion. In Australia, Pluto LNG has announced plans to purchase solar power, while Queensland Curtis LNG (QCLNG) is proposing a dedicated 120-MW solar farm to support power needs at the plant. Qatar’s North Field East (NFE) project may use solar power for ancillary functions, and batteries are being touted to reduce the spinning reserve at Wheatstone and Darwin LNG in Australia. 

Taxes on LNG emissions will redesign LNG trade flows, recalibrate prices and force LNG players to reassess trading strategies and investment options to decarbonise across the value chain. But the implications will vary for different LNG players and for governments of importing and exporting countries. 

• A bifurcated LNG market  

Governments imposing a tax on the carbon emissions of imported LNG will see gas prices increase in their internal market. Europe, and potentially markets in Northeast Asia, might be amenable to this to accelerate the shift to lower-carbon alternatives. However, buyers in emerging Asian markets will remain wary of higher LNG prices and be reluctant to follow suit. A bifurcated LNG market is the most likely outcome, one for premium LNG and one for tax-free countries. However, declining LNG demand in premium markets means their importance will fade over time, limiting their influence in driving investments in decarbonisation. 

• Low-carbon LNG suppliers benefit most 

Projects with the lowest carbon emissions will gain from an import tax on emissions. Targeting premium markets will boost trading profitability, with some buyers amenable to paying a premium for long-term contracts. Russia and Canada will be the most advantaged, given their proximity to premium LNG markets. Qatar and Mozambique require higher carbon prices to be lured away from proximate tax-free markets in emerging Asia. 

An import tax on emissions is also good news for those suppliers where governments are tightening environmental regulations, such as Australia’s safeguard mechanism and the Inflation Reduction Act’s methane charge in the US. An import tax on emissions that waives taxes already paid at source might become the only hope to help compensate for higher domestic costs to reduce emissions. 

• High carbon taxes needed to decarbonise LNG 

A tax on methane emissions of US$100/t CO2e will be effective in achieving its goal. Methane reduction remains the low-hanging fruit in emissions, with progress being made in different countries, supported by tightening domestic methane regulations. A methane import tax will help provide additional economic incentives while limiting LNG price upside. In this scenario, exporting countries will also be encouraged to introduce domestic levies and retain taxed revenues. 

For the global LNG market to decarbonise at scale, an import tax of US$100/t CO2e will not be sufficient. It can certainly act as an incentive for pre-final investment decision (pre-FID) projects close to premium markets to deploy electric drives in LNG plants and reservoir CCS to limit CO2 emissions from upstream. However, a carbon price closer to US$200/t CO2e will be required for post-FID LNG projects to deploy these technologies.