Gas pricing and the LNG market

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Gas pricing and the LNG market

Global gas demand has returned to growth after the supply shock of 2022-23, but geopolitical tensions and short supply in LNG markets continue to affect pricing.

Natural gas continues to be a major energy source for the world, representing about one quarter of all energy demand in 2024, and particularly for the ammonia and methanol industries, where gas feedstock accounts for about 70% of all ammonia production and around 65% of all methanol production. Gas pricing remains a key determinant of ammonia and methanol profitability. In addition, while coal and oil are seen as fossil fuels whose demand is on the wane, gas is a cleaner burning fuel and seen by many as a key transition fuel alongside renewables over the coming decades.

The past few years have been a highly volatile time for gas markets, with the coronavirus pandemic and the surge in demand caused by easing of restrictions leading to a gas price spike, exacerbated in early 2022 by the Russian invasion of Ukraine and the gradual restriction of gas supply to Europe, resulting in a price spike that has been followed by an easing in markets as gas flows were redirected around the world, and now gradual tightening again as demand recovers.

Global natural gas consumption increased by 2.8%, or 115 bcm year on year in 2024, above the 2% average growth rate between 2010-20. Natural gas met around 40% of the increase in global energy demand in 2024 – a greater share than any other fuel. This relatively strong growth was mainly due to the Asia Pacific region, which accounted for almost 45% of incremental gas demand in 2024 on the back of continued economic expansion.

Europe

The European gas market continues to suffer as a result of the Russian invasion of Ukraine and the reduction of Russian pipeline gas flows to Europe. The last pipeline supplies across Ukraine ended in December 2024, and Russian gas is now only reaching Europe via Turkey (ca 13 bcm) and as LNG shipped from Yamal. The attempt to replace the loss of 160 bcm of Russian gas supply by opening new LNG terminals and running existing ones to capacity has been remarkable; European LNG imports went from 108 bcm in 2021 to 170 bcm in 2023, and actually dropped in 2024 due to lower gas demand. While LNG, particularly from the US, has kept the lights on in Europe, perhaps as big a story over the past three years has been one of demand destruction, both due to increased use of renewables for electricity generation, a return in some cases to coal-based power, and lower use of gas overall, particularly for industrial uses, where high prices have forced reduced running rates and idling of plants. While European gas prices have stabilised since the 2022 price shock, they have done so at an elevated level. Overall, European gas prices based on the Dutch TTF benchmark have risen from an average of around $5-10/ MMBtu prior to 2022 to around $10-15/ MMBtu in 2024-25.

The ammonia industry has been a particular casualty, and the continued elevated levels of gas pricing compared to the levels of a few years ago pose an ongoing threat to European ammonia competitiveness. A number of plants are now operating on imported ammonia and more may switch, though the Carbon Border Adjustment Mechanism may provide some relief over the coming years. Europe’s reliance on LNG imports means that wholesale gas prices are generally determined by global LNG rates now, which tend to be higher than the pipeline gas that Europe has traditionally relied upon, especially given competition between Europe and various Asian economies for LNG cargoes.

Other notable features of Europe’s gas picture include the rapid ramp up in production of biomethane and biogas, reaching 22 bcm in 2023, up from 17 bcm in 2022, and forecast to reach 35 bcm by 2030. There is also increased gasification of biomass and domestic waste, which is targeted to supply 37 bcm of gas equivalent by 2040. Green hydrogen targets remain unmet for now, however, mostly due to cost.

North America

US natural gas production continues to increase, with steady demand coming from new LNG facilities. Natural gas demand in the US is forecast to rise by 4% in 2025, with a significant portion attributed to a 18% increase in exports, including both pipeline and LNG shipments. The expansion of LNG export facilities, like Plaquemines LNG Phase 1, will contribute to a notable increase in U.S. LNG exports, but growth in the power sector as US power generation continues to shift away from coal, and increasing demand due to investment in data centres and other industries, will contribute to higher natural gas demand. The US Energy Information Administration (EIA) forecasts that the US gas market – not taking into account weather related fluctuations – will tighten somewhat this year, with the Henry Hub price likely to average around $4.30/MMBtu in 2025 and nearly $4.60/MMBtu in 2026, compared to an average of $2.20/MMBtu in 2024 and $2.50/MMBtu in 2023, but these prices remain low by global standards.

South America

The South American natural gas market is characterised by a widening deficit and growing LNG imports, with a focus on regional integration and infrastructure development. While the region holds substantial gas reserves, particularly in Brazil and Argentina, challenges in production and distribution, along with potential geopolitical factors, could hinder its full development. Colombia’s natural gas reserves are declining, and the country faces challenges in meeting its projected consumption needs, while Argentina’s oil and gas sector requires significant investment to develop its Vaca Muerta shale gas resources. Trinidad & Tobago continues to face challenges in mitigating a decline in natural gas production. South American gas demand for power production is expected to grow significantly, with a CAGR of 17.2% from 2024 to 2030. In order to meet this, the LNG market in Latin America is expected to grow by an annual average of 6.7% from 2021 to 2030.

Africa

Africa’s gas production has stagnated since 2021, rising only incrementally from 267 bcm to 268 bcm in 2023, and forecast to reach 272 bcm in 2025. At issue has been a lack of investment in new production and falling production from older fields. This has been a particular issue for Egypt, where production has dropped from 68 bcm to around 43 bcm. However, there are signs that this trend may be belatedly reversing, with investment in the African oil and gas sector increasing by 23% in 2024 according to the African Energy Chamber. In North Africa, Egypt recently signed a deal with Cyprus to import gas from the Cronos block to feed LNG production at Damietta, and is seeing new wells drilled in the West Nile Delta area by Shell and others. ExxonMobil has made a gas find in the Herodotus basin, and Eni is Eni begins drilling this year at the Zohr field. There are also prospects for the domestic Badr Petroleum Company. Further west, Morocco is due to tender in 2025 for the Moroccan section of the proposed Nigeria-Morocco Gas Pipeline (NMGP), which is planned to eventually connect 16 countries, primarily along the Atlantic coast and eventually to Europe. The first phase will involve Morocco, Mauritania, and Senegal, with additional agreements for gas transport expected to be signed in 2025. BP has also begun gas flows from offshore Mauritania to a floating production and storage vessel, and subsequently to a floating LNG vessel for onward transit to Mauritania and Senegal, totalling around 2.3 million t/a.

In Sub-Saharan Africa, Mozambique and Tanzania are increasing gas production, with LNG export planned from Mozambique. Nigeria continues to develop projects to utilise flared gas from its offshore production; a 2.8 million t/a LNG facility is scheduled for production to begin in 2029. Angola is also developing its Quiluma and Maboqueiro gas fields to supply 5.2 million t/a of gas to the Angola LNG plant and the Soyo Combined Cycle Power Plant.

African domestic consumption remains relatively low, and much of the new African gas is destined for export, mainly to Europe via Algeria and Egypt, as well as via an increasing number of new LNG projects.

Asia

Gas demand continues to rise in China, with increasing use of LNG as a vehicle fuel, particularly for heavy duty vehicles, where around 10% of the truck market is now accounted for by LNG-powered vehicles. Electricity generation via natural gas is projected to amount to 232 terawatt hours in 2025, with an average annual growth rate of 6.12% for the period from 2025 to 2029, as China tries to pivot away from coal towards lower carbon forms of energy. By 2030, China’s natural gas consumption is expected to reach 570 bcm and plateau at around 620 bcm between 2035 and 2040. Energy-related carbon emissions are expected to peak before 2030 at between 10.8 billion and 11.1 billion t/a as gasoline and diesel fuel is converted to natural gas and the region sees strong growth of renewable energy.

Elsewhere, Japan’s Ministry of Economy, Trade and Industry (METI) unveiled a draft of its revised Basic Energy Plan in December 2024, which acknowledges that LNG-fired power is a necessary means of energy transition to cleaner energy and says that the government needs to work with private companies to secure the long-term LNG contracts to enhance energy security and invest in upstream natural gas infrastructure. South Korea, conversely, is aiming to meet its future energy needs using nuclear power. By 2038, the country plans to increase its nuclear fleet from 26 to 30 reactors. This will affect the country’s imports of LNG; South Korea aims to cut its fossil fuel imports from 81.8% of its energy requirements in 2021 to 60% by 2030. Currently, South Korea is the third largest market for LNG after China and Japan, importing 60.6 bcm of the fuel in 2023, equivalent to 11% of the global market.

India’s domestic gas production, which met 50% of demand in 2023, is projected to grow gradually, reaching just under 38 bcm by 2030. This would put it around 8% above 2023 levels. The limited growth in domestic supply means India’s LNG imports will need to more than double to around 65 bcm a year by 2030 to meet rising demand.

Middle East

The Middle East gas market is predicted to experience significant growth in both production and consumption, driven by increasing demand for cleaner energy sources and industrial expansion. The Middle East is experiencing substantial growth in energy demand, particularly for electricity, which is expected to triple by 2050. LNG exports from the Middle East, particularly from Qatar, are projected to remain strong, with Qatar being the world’s third-largest LNG exporter. The expansion of Qatar’s North Field, the world’s largest gas field, will be a key driver of increased production and export capacity. However, rising domestic demand within the Middle East could potentially strain supply and impact export volumes if not managed effectively.

LNG

Most of the foregoing has emphasised the increasing role that LNG is playing in the global gas market. Production and consumption of liquefied natural gas reached 562 bcm in 2024, representing 14% of the global gas market, and 60% of internationally traded gas. LNG trade has increased by 70% over the past decade, and growth continues, as we have discussed above. Europe and Japan in particular will continue to require LNG to fill a widening gap between energy diversification ambitions and actual investment levels. The global trade in LNG is set to rise significantly by 2040, driven by Asian economic growth, the need to decarbonise heavy industry and transport and the emerging growth in the energy-intense tech sector. It is also becoming a cost-effective fuel for shipping and road transport that can bring down emissions. LNG vessels represent the bulk of lower carbon emission fuelled vessel orders at present. Overall, more than 230 bcm of new LNG supply is forecast to come on stream by 2030, although there is uncertainty over the timing of particular projects. There is also likely to be an increasing use of liquefied biomethane, production of which is seeing 13% growth year on year. Tanker capacity is plentiful at present, keeping shipping rates low in spite of canal bottlenecks.

LNG growth is particularly strong in the US, with over 120 bcm of exports already in place and that much again already under construction or closing on a final investment decision. The US became the largest LNG exporter in 2023, just surpassing Qatar and Australia, but this could take the country to 1/3 of all LNG exports by 2035, and together with Qatar’s planned expansions, the two nations could represent 60% of all LNG supply. But even in spite of all of this construction, there is a potential forecast gap between supply and demand after about 2033 if more new investment does not materialise soon.

LNG’s continued rise is also continuing to change the LNG market away from the traditional long-term oil indexed contracts that it relied upon in its earlier days to justify the costs of liquefaction and regasification terminals. The decoupling of LNG and oil prices is still not complete and varies across regions, but the rise of spot markets and unconventional energy sources like shale gas in the US have contributed to this decoupling, especially in Europe. However, oil-indexed pricing still influences some long-term LNG contracts, particularly in Asia. Overall, around 40% of LNG is now bought on a spot basis.

Gas pricing

Natural gas is priced in different ways. The International Gas Union, in its annual survey of wholesale gas price fixing mechanisms, distinguishes between: ‘GOG’ – gas-on-gas competition – where there are multiple producers selling into a price unregulated market via trading hubs; OPE – oil price escalation – where the price of gas contracts is tied to oil prices by an escalation factor; and various forms of regulated prices: regulated cost of service (RCS), where a company is allowed to make back costs plus a fixed increment; regulated social and political (RSP) and regulated below cost (RBC), where a company, usually state-owned, sells gas below the cost of delivery for political or other reasons.

At present, North America (including Mexico) and Europe, Australasia and Argentina, Nigeria, Colombia and Morocco are categorised as gas on gas markets. India, China, Brazil, most of northeast and southeast Asia are classed as working on an oil price escalator method, while Russia, Central Asia, the Middle East and North Africa, as well as much of sub-Saharan Africa and the rest of South America are all regulated gas markets. LNG varies, with around half traded on a gas on gas basis, and the rest on oil-indexed pricing.

A tighter gas market this year means that prices will rise in gas on gas regions, with US gas costs up around 40% year on year and European costs up about 25%. By contrast, the average Indian pooled gas price, as it remains tied to oil pricing, is forecast to be slightly lower as the crude oil market remains sufficiently supplied, thereby keeping oil prices partly subdued. As such, the $50/t or so gap between the European average cost per tonne of producing ammonia and South Asia’s is likely to be completely eroded in 2025, and may instead see Europe incurring a premium over South Asian costs instead.