LNG

Bearish shoulder-season fundamentals have made prompt gas prices at Henry Hub fall to their lowest level in five months at just above $3/MMBtu. Appalachia production stayed robust, despite seasonal maintenance, while Haynesville basin output is set to rise by 1 bcf/d year-on-year, weighing on prompt prices.

Fundamentals are largely influencing price discovery at Henry Hub, the most liquid gas trading point in the United States.

Modelling by Energy Aspects indicates that gas production in the Lower 48 States exceeded 107 bcf/d over the past weekend, with gas flows from the Appalachia Basin remaining strong despite maintenance activities and lower regional consumption. Appalachia production notched up 0.3 bcf/d and averaged 34 bcf/d, offsetting the decline in associated gas production from the Permian Basin caused by maintenance on the Permian Highway pipeline which lowered flows by 0.9 bcf/d over the past few days.

Profitable regional economics – despite Henry Hub’s recent selloff – has led to robust Appalachia production in March and April. According to US government figures, regional flows averaged 33.5 bcf/d in March and 33.9 bcf/d in April, up from 32.8 bcf/d over the previous two months. Maintenance works since early March seem to have a "minimal effect on flows," analysts noted.

Appalachia gas volumes, in fact, reached a higher baseline and higher flows. The latest surge in production comes from MarkWest Liberty Midstream and DT Midstream, as per pipeline data.

Energy Aspect’s fundamental outlook for the remainder of the shoulder season is for the year-on-year storage gap to close considerably in the second quarter of 2025, with an estimated injection of 342 bcf for April and 438 bcf for May. Rising upstream gas supply would increase Lower 48 storage levels to about 2.60 trillion cubic feet, still 284 bcf lower year-on-year.

Haynesville flows stay tepid

Gas flows from the Haynesville basin, in contrast, stay subdued as producers were cautiously slow to respond to higher price at the start of the year. As of 17 April, the Haynesville rig count stands at 31 rigs, three rigs lower year-on-year.

Energy Aspects anticipates a modest increase in rig activity by the third quarter of 2025, averaging 33 rigs, two rigs higher quarter-on-quarter. This expectation is based on recent producer guidance indicating production growth for winter 2025–26 to support weather-induced demand and LNG feedgas expansion. Core Haynesville activity in Louisiana will likely contribute most of this growth, reaching 27 rigs by December, nine rigs higher than current levels.

Upstream investment drives further growth: Comstock in its Q4-24 earnings call announced plans to spend $130–150 million on Western Haynesville infrastructure in 2025. Funding will come from their partner, Quantum Capital Solutions. Comstock said it will operate four rigs in Western Haynesville in 2025 on average and intends to drill 20 further wells in the near future.

Aethon Energy, another major producer in Western Haynesville, earlier this year announced it would need Henry Hub prices to reach $5/MMBtu to incentivise investment to grow output. Analysts estimate the company’s rig count in Texas Haynesville will reach seven rigs by December, six rigs below current levels.

LNG export exposure

Latest US government data indicates Western Haynesville production reached 0.71 bcf/d in February, with Comstock averaging 0.32 bcf/d (45% of sub-basin production). Currently, Haynesville's production averages 11.5 bcf/d month-to-date, 0.1 bcf/d lower month-on-month.

“Yet, incremental production from new activity remains elusive due to producer discipline,” analysts commented.

Expand Energy announced estimates that its Q1 25 Haynesville production will average 2.6 bcf/d, some 0.2 bcf/d higher quarter-on-quarter, while operating seven regional rigs, one less than the first quarter. The company’s Haynesville portfolio has approximately 2 bcf/d of exposure to LNG export facilities, with an additional 2.5 bcf/d in deliverability expected by the end of 2025, including 1 bcf/d of Gillis volumes that will come to market via the new NG3 pipeline.

Costly investment programmes to facilitate Europe’s green energy transition are weakening the credit metrics of regulated gas and electricity networks. Moody’s Ratings hence changed the outlook of European TSOs to ‘negative’ from ‘stable’.

Transparent and established regulation still supports credit quality, but regulators struggle to facilitate infrastructure investment at an affordable cost. “If shareholders consider allowed returns or cost recovery mechanisms to be insufficient, then support will fall short of maintaining credit quality,” analysts commented.

Europe's power grids and gas network operators are hard pressed to handle the substantial growth in load-related Capex required, and planned investments, said Phil Cope, senior credit officer at Moody’s Ratings.“Pressing demands arise from the need to grid-connect more renewables and accommodate rising volumes of electricity demand other sectors, e.g. heating (heat pumps), transport (electric vehicles), and data centres, where demands for capacity will intensify to support the growth in AI,” he explained.

Capital spending has grown significantly in recent years: Five-year Capex guidance for many networks – especially electricity transmission – is at least double that of five years ago. The current regulatory framework allows many gas and power network operators to recover investment over 20 to 50 years. But analysts warn the surge in Capex dwarfs the rise to network companies’ operating cash flow and this, in turn, weakens cash-flow based credit metrics.

TenneT, the TSO handling the power grid in the Netherlands and part of Germany, has seen its five-year Capex guidance soar from €40 billion in 2023 to over €62 billion this year – with no end in sight. The Belgian/German network operator Elia, meanwhile, has seen the same Capex metric almost double from around €16 billion to €30 billion over the same period.

The French and Spanish utilities ENGIE and Iberdrola have either increased or stated their intention to rise their exposure to regulated electricity networks. Moody’s reckons this is because they aim to improve their risk profile by benefitting from the “growth in higher quality earnings” as these networks carry out their investment programs. Others, notably SSE of Scotland and the German regional utility EnBW have reduced their exposure by selling their minority stakes in their power transmission businesses in recent years.

Though Germany must phase out fossil gas by 2045 to become climate neutral, there is no clear roadmap for exiting natural gas in the power sector and the future role of LNG, the International Energy Agency (IEA) criticises. The German ‘LNG Acceleration Act,’ for once, stipulates an end of LNG imports by 2043 when terminals should be converted to hydrogen.

To meet that timeline, substantial investment in Germany’s traditional gas infrastructure would be required, analysts pointed out.

For repurposing LNG regas terminals to accommodate hydrogen, the key question is temperature. Methane liquefies at −160°C and hydrogen −253°C. The European Network of Transmission System Operators for Gas (ENTSOG) recommends terminal operators to carry out a risk assessment of LNG in order to analyse the impact on the process conditions, properties of mixtures and consequences.

As for storage, Germany has the largest gas storage capacity in the EU with around 40 gas storage facilities holding more than 24 bcm. Up to 1% hydrogen per volume can be blended into an average gas storage facility – while a pipeline that currently carries mainly natural gas can transport about three times as many cubic meters of hydrogen, an ENTSOG-G study finds.

Key gas pipelines in Germany include Nord Stream 1, which used to transport Russian gas through the Baltic Sea; the Yamal-Europe Pipeline, now primarily used to transport natural gas from Germany to Poland; the Trans Europa Naturgas Pipeline, connecting the German and Dutch gas grids; and the Europipe I and II pipelines, which import natural gas from Norway’s North Sea fields into Germany.

Clear timeframe needed for gas-to-H2 conversions

Looking at the power sector, there is currently no roadmap for exiting natural gas in the power sector. Unlike coal, no timeframe has been set out, though the target of 100% fossil-free generation by 2035 indicated the need for speedy gas-to-hydrogen conversions – or utilities face the risk of plant closures.

Uncertainty about tenders for hydrogen-ready power stations or a future capacity market is has made Germany’s largest utilities to withhold investment in new power stations, which, in turn, risks to push up wholesale power prices.

The IEA hence urges the incoming coalition government to clarify the timing of a future gas exit. Timeframes for mandated hydrogen conversions would provide industry with the certainty needed to invest in the required import infrastructure (for both natural gas and hydrogen) and industrial clusters.

Electrification in focus first, hydrogen and CCUS second

The industry in Germany is struggling to stay competitive in the face of rising fuel costs and high electricity prices. To mitigate the risk of deindustrialisation, IEA analysts recommend policymakers in Berlin should concentrate efforts on promoting energy efficiency and electrification” in the short run. The rising adoption of hydrogen and post-combustion carbon capture utilisation and storage (CCUS) are seen as e viable pathways in the longer term.

For now, Germany’s dependency on natural gas continues “without a clear end in sight,” analysts criticise the government’s failure to set out clear policies on how to enact the clean energy transition. The outgoing government’s Power Plant Strategy attempted to tender 12.5 GW of new natural gas-fired power plant capacity that could later run on hydrogen.

“In this way, the construction of new hydrogen-ready gas-fired capacity could avoid a fossil fuel lock-in that is not at odds with the electricity generation target, as long as the fuel switch takes place on time,” analysts acknowledged but called for more clarity around the viability of hydrogen-ready gas plants.

Gas peaking plants are believed to keep playing a vital role in grid balancing beyond 2035. But other flexibility options, notably industrial demand response, storage and interconnections, should be encouraged as these “may displace the need for additional generation capacity,” analysts argue. The IEA hence urges the German government to “move ahead with the future electricity market design proposals, including a capacity mechanism.”

Financial close on US LNG export projects could be at risk by a stable peace deal between Russian and Ukraine, analysts warn. Europe would subsequently rush to accommodate more Russian pipeline gas imports of up to 50 bcm per year, while the lifting of sanctions on Russian LNG would raise exports to 12 mtpa – undermining the economics of US LNG.

In the event of a ‘stable peace’, Wood Mackenzie expects European gas prices at the TTF trading hub to fall well below the US$8-9 per mmbtu that are forecast for 2028/29.

A collapse in TTF prices, in return, would lead to years of US LNG capacity underutilisation and delays to several expected FIDs on well-advanced LNG export projects.

US LNG projects may become collateral damage

As a knock effect, Henry Hub gas prices would plunge since the lower-than-expected LNG exports create a length in gas supply in the United States. This oversupply supports greater gas-burn for power generation and may well reduce wholesale electricity prices to the benefit of American households and industries.

But Wood Mac’s vice president of Gas and LNG research, Massimo Di-Odoardo warned that with an average of 25 mtpa of liquefaction capacity in the United States and Mexico at risk of underutilisation over the next five years, “US LNG would be the collateral damage,”

More shipments needed in event of no peace

On the other hand, a failure to reach an agreement would results in "stronger for longer" gas prices as even less Russian supply comes to market.

“A continuation of the war could see the EU double down on sanctions, pushing even harder to achieve its ambition of independence from Russian energy - banning LNG imports from the Yamal LNG project and the 15 bcm a year TurkStream pipeline,” Di-Odoardo noted.

This scenario strengthens the need for more LNG supply, with US and Qatar capitalising on more investment opportunities.

"The outcome of ongoing negotiations for a peace agreement between Russia and Ukraine remains highly uncertain,” he said, concluding: “All scenarios are possible, including potential combinations of them, however, recent development suggest a peace agreement where the US and EU take different approaches to lifting sanctions, appears more likely.”

Though India has not yet mandated the dispatch of gas peaking power stations, analysts see upside risk to LNG-burn following a government tender to purchase 1.8 Gigawatt of gas-fuelled generation between April and October. Torrent Power was awarded 1.35 GW, with Kashipur Gama and Kondapalli Lanco taking the rest of the tendered capacity.

Energy Aspects understands the three power producers will receive a fuel price linked to the CME west India LNG prices.

“This power tender alone translates to LNG demand of 0.12 million tons per month over the second quarter of 2025, assuming a 50% load factor and 50% thermal efficiency,” analysts explained, stressing:

“This demand will be price insensitive, as LNG is effectively subsidised by the government.”

Early heatwaves have propelled up electricity demand in India to record levels. The average load factor in March reached 211.3 GW, the highest level ever recorded and a 12.4 GW rise year-on-year. The amount of cooling degree days was 9% above the 10-year norm, but analysts anticipate Indian CCDs will be a staggering 19% above the 10-year average over the next two weeks.

Should this prolonged heatwave materialise, India’s power load jump to new record highs averaging 227 GW over the second quarter, up by 8 GW compared to Q2-23.

Though the LNG tenders are bound to increase gas-burn, coal and solar generation will continue to meet most incremental power demand. In March, coal and solar generation increased by 8.2 GW y/y and 4.9 GW y/y, respectively, while gas generation dropped by 1.3 GW y/y due to peaking power demand.

Upholding a bullish view, analysts said: “We see some upside risks to our Indian LNG demand forecast if the government mandates gas fired plants to run to prevent load shedding and ensure an uninterrupted power supply.”

US investment firm Stonepeak has agreed to acquire a 40% shareholding in Woodside Energy’s Louisiana LNG export project and contribute $5.7 billion towards the project’s capital expenditure. Woodside CEO Meg O’Neill called the transaction a material step towards readiness for FID.

The head of the German energy regulator BNetzA, Klaus Müller, disagrees with the proposal of the European Union to extend gas storage target until 2027. The mandated 90% filling level of storages by November seens to distort seasonal pricing pattern while a build-out in LNG import infrastructure offers alternatives to gas storage.

Since late 2024, gas prices for summer delivery have been trading at a premium to winter – a reversal of typical seasonal pricing. Critics blame this on the mandatory storage goals, arguing they reduce market flexibility and are skewing market signals.

Speculative long positions at the Dutch TTF gas trading hub have increased recently, fuelling concerns that traders are betting on government support for storage refills.

BNetzA President Müller find this trend worrying: “It makes me nervous. It doesn’t inspire confidence that everyone is acting responsibly,” he said, arguing the EU storage goal incentives are misaligned, costly and distort the behaviour of free markets.

The EU had introduced the 90% gas storage filling mandates prior to the winter season in 2022 when Russian gas imports collapsed, but critics say the rules are no longer adapt to today’s market dynamics. As Germany’s coalition talks continue, Müller wants to raise the issue directly with the country’s next energy minister.

EU Regulators uphold storage mandates

Over in Brussels, policymakers have a different view: Amending EU Regulation, published on Wednesday last week, proposes to extend the gas storage requirements by another two years, arguing this would be needed to deliver on the REPowerEU plan which focusses on expanding underground storage capacity of gas, upgrading and extending LNG infrastructure; and diversifying both sources and routes of pipeline gas.

"To deliver on these objectives, the extension of some of the measures, mainly the November gas storage filling target, adopted previously for a limited period of time, is necessary," the regulatory document reads.

Gas-storage facilities provide for 30% of the Union’s gas consumption during the winter months, and EU policymakers are convinced the 90% filling rate is a “necessary and appropriate level" to ensure security of supply.

“The European gas market remains tight. The competition for global LNG supplies has increased and exposure to price volatility is stronger than before.”

“The gas price development during the 2024/2025 winter may confirm the trend,” EU policymakers argue, underlining: “In such situation, the role of gas storages remains paramount.”

Peace between Ukraine and Russia – if and when agreed – will unlikely lead to large additional volumes of Russian gas returning to Europe beyond current LNG and Turkstream flows. According to Fitch Ratings, the resulting implications for the TTF gas price range from "negligible to a decrease of 50 to 60 percent."

A full return of Russian gas supplies to pre-war levels is highly unlikely as the EU has nearly fully replaced it with alternative sources, says Angelina Valavina, head of EMEA Natural Resources and Commodities at Fitch Ratings. The remaining small volumes of natural gas from Russia that are currently delivered to Europe supplement LNG and other imports. "While a peace agreement could see partial resumption of additional volumes, they would likely be limited by geopolitical considerations, affecting the chosen routes," she explained. 

New LNG projects coming to market in the medium term will create a surplus that will further diminish demand for cheap Russian gas. “We forecast new large LNG supply from Qatar and the US to come onstream in 2027-2028, putting pressure on gas prices,” Valavina said in a market note.

The US has become an important LNG exporter, while Europe offers a competitive market. QatarEnergy is expanding LNG production capacity to 126 million tonnes per annum (mtpa) by 2028 from 77 mtpa currently. US government analysts estimate the country’s LNG export capacity will grow by 100 bcm between this year and 2028.

Sanctions on Russia have limited Gazprom’s supply routed to the EU to the Turkstream pipeline and LNG. Together they account for just 13 percent of imports year-to-date.

Flows via the Nord Stream, Ukraine, and Yamal pipelines have been halted. Russian pipeline gas supplies to the EU fell to 33 bcm in 2024 – split evenly between Turkstream and Ukraine pipelines – down from 153 bcm four years earlier. This equates to a fall from 41% to 11% as a share of total EU imports, or to 18% if including LNG.

Russian oil headed elsewhere

Sanctions have slightly reduced Russian oil exports, though this has not hurt state-owned enterprises much given that discounted Russian oil is being redirected to China, India, and Turkey. According to Fitch findings, Russian oil and product exports fell by 0.5 million barrels of oil equivalent per day (MMboepd) in 2024 from 2022. Despite a 2.8 MMboepd drop in EU exports, exports to China, India, and Turkey increased by 1.8 MMboepd.

Oil production in Russia has not been significantly impacted by sanctions, Fitch analysts find, pointing at an oversupplied global oil market with OPEC+ spare capacity of 5.6 MMbpd. “Russian oil production and exports account for 10% and 5% of global demand respectively, which is insufficient to tighten the oversupplied market," Valavina concluded.

LNG as a marine fuel is gaining traction, notably in the very large crude carrier (VLCC) segment where 21 vessels are in service and 14 on order, Lloyds Register finds. Four of these VLCCs were built by Hanwha Ocean, as part of the ‘Neptune project’, on behalf of Advantage Tankers.

Deutsche ReGas has succeeded in gaining permission to restart reloading LNG tankers at its Mukran floating regas and storage unit (FSRU). The environmental ministry had forbidden the practice in the autumn, arguing reloading was not covered by the terminal’s original permit.