The UK gas and power markets has depreciated across the curve with the front seasonal contract shedding 40% value since the start of October 2023. These are levels last observed in Winter 2021 due to a looser supply and demand balance in the near-term that has shifted the structure forward curve into a Contango out to Win-25. Fluctuations in global weather patterns will remain a key driver in tandem with potential risk of supply disruptions at the Red Sea that has sparked recent volatility in the wider energy market.
The same price trend has also emerged in the European market with the rate of gas price declines outstripping losses in coal prices. The TTF gas market currently trades below the average coal switching price, meaning that gas-fired power stations would financially outperform most coal-fired power stations till the end of summer. Interestingly, this lower price environment is impacting operating margins especially in Germany, linked to strong renewables and lower demand for thermal plants. Furthermore, the lightest French nuclear maintenance schedule since January 2018 pushed French power exports to an all-time high above 20GW in early January that has been a major contributor in removing risk premiums.
DEMAND SECTION
Demand reduction continues to remain a key driver in the lower price environment. Price resistance has been linked to strong declines in gas demand across Europe. UK gas demand is currently 1% below the 6-month rolling average with the strongest declines in LDZ demand that have kept below the 5-year average as mild temperatures remained for the most of the winter period. The second largest declines were linked to weakness in gas-for-power demand due to healthy renewable output followed by minimal fluctuations in UK industrial demand. Gas consumption in Europe also continues to remain subdued with consumption levels dropping below previous years in December, particularly in Germany’s non-LDZ demand.
Europe is expected to compete with Asia as a premium market for LNG until the second half of 2025 when significant volume of supply is expected to enter the market. In the meantime, European LNG imports have gradually grown month-on-month this winter from 13bcm in October-23 to over 16bcm in December-23. This is also a trend in the UK as imports increased by 59% from October to December due to an open arbitrage to Europe, creating favourable LNG netbacks for U.S shipments. The Northeast Asian spot LNG price fell to an 8-month low assessed at $9.50/MMBtu with high storage levels and increased nuclear output, which reduced near-term competition against China although long-term contract volumes remain robust at 100bcm till 2029.
Out of the 92 days of Q4-23, the UK has experienced above seasonal normal temperatures on 58% of the days. This, in tandem with strong renewables has helped to supress demand that led to the lowest monthly Day-Ahead electricity price of the year in December averaging £69.48/MWh. Looking ahead the latest weather forecast points to above seasonal normal temperatures in the UK till February before consolidating below seasonal normal into March that could add some stability in prompt prices. Based on latest balances for February UK LDZ consumption is expected at 182mcm/d vs 170mcm/d last year, while the European weather outlook also points to the same trend.
SUPPLY
Strong Norwegian gas flows and LNG arrivals have kept supply and storages well supported this winter. The US has emerged as the top exporter of LNG in 2023, exporting over 120bcm thanks to the return of Freeport LNG and startup of Calcasieu Pass LNG. 63% of these exports arrived into European terminals, despite Asian hub prices sitting at a premium to Europe for most of the winter. Shipping costs meant Europe was still the favoured destination for US LNG and this is likely to remain the case due to current Red Sea shipping route issues.
If we see longer-term disruption, LNG companies could begin working together to rearrange flows and increase efficiency. For example, a Middle Eastern company delivering a cargo to Europe could swap with a US cargo destined for Asia. Both customers would receive their cargo with neither exporter using the Suez Canal. This activity is already the norm internally for global LNG players, but cargos swaps between majors could be a possibility.
US LNG exports are set to grow to 38% of global supply by 2030, from 22% last year. 2025 will see a burst of new global liquefaction capacity beginning to come online. Currently, post-FID projects total over 131bcm. 61.3 bcm of this will come from North America. Qatar’s North Field Expansion project will see first gas in 2025, before completion in 2027, adding some 44bcm of additional capacity. Over 80 bcm of new LNG projects are expected to hit FID in 2024, as appetite remains globally, however, with compound annual growth rates for projects falling rapidly from 2028, the window of opportunity could be closing for investment. After a heavy summer of maintenance, Norwegian exit flows ramped up from November to reach their highest level since Oct-20. Flows in Nov, Dec and Jan have exceeded levels seen during equivalent months since Winter 2020.
A steady stream of maintenance is planned on Norwegian infrastructure between Feb-24 and Jul-24, with heavier maintenance expected from late-Aug to early October. When compared with the 2023 season, total 2024 capacity impact is reduced by 200 mcm/day. Heavier maintenance in late summer could present additional risk if we see warmer than average summer emerge following the strong El Nino event seen in Autumn/Winter 23/24. In recent years, heatwaves have caused issues with nuclear output and river levels on the continent, thus increasing gas demand for power generation during storage injection season. NWE storage levels are on course to end the winter around 54% full, based on central weather scenarios, increasing the likelihood of European storages hitting the mandated 90% ahead of the 1st Nov target date.
After reaching record low capacity in 2022, French nuclear capacity improved significantly in 2023. Over 60% of capacity has remained consistently online since early November with as much as 87% of capacity online in mid-January. We expect online capacity to gradually decrease in the coming weeks as we enter maintenance season, but current forecasts put online capacity consistently above 70% for 2024. France reinforced its commitment to nuclear power at the COP28 summit recently and plans at least six new reactors.
Japan’s nuclear comeback saw generation increase by 50% in 2023, a post-Fukushima high, but forecast growth of 17% in 2024 could be at risk due to several potential delays to reactor restarts. Delays would lead to increased LNG demand as gas-fired generation would bridge gaps left by delayed nuclear returns.
WIDER MARKETS
Dec-24 EUA over 20% down on the highs seen in Q1-2023. The equivalent UKA contract fell a staggering 61% from highs in Feb-23 to trade at record lows in Dec-23. A brief rally saw prices recover during 2023’s last trading days, however, both contracts have since shed over 15% from 2024’s open. Demand for permits has fallen due to increased renewable output, lower gas prices and continued lower industrial demand post-2022 crisis. Falling gas prices have incentivised gas, over coal burn, for power generation, which requires less permits.
Looking ahead, further downside could be provided by largely negative spark and dark spreads to 2027. Negative margins mean thermals plants are less incentivised to forward hedge volume and thus demand for permits falls. In addition, whilst economic growth is forecast in 2024, demand destruction is likely to persist. Looking more specifically at EUAs, 86mt of additional supply will be auctioned to raise funds for the REPowerEU plan. With demand from power generators falling, it will be hard for the market to absorb these additional volumes. Market movement stemming from position covering will also change in 2024 as the compliance deadline moves from April to September. Auction volumes have previously halved in August, due to holiday season, but this will no longer be the case in an attempt to curb volatility during the new peak demand period.
On Feb 6, the EU commission is expected to recommend a target of 90% emissions reduction by 2040, this could challenge recent bearish sentiment. In addition, the maritime sector is now included in the EU-ETS with the % of emissions requiring permits rising from 40% to 100% by 2026. We expect the UK-ETS to include the domestic maritime sector by 2026. In the coming years both ETS’s will introduce a Carbon Border Adjustment Mechanism’s and we could start to see demand from international companies as they begin to manage exposure to this. The UK government is also considering implementing a Supply Adjustment Mechanism, much like the EU-ETS MSR, to deal will surplus allowances as the UK-ETS does not currently have a balancing mechanism to manage demand shift risks.
Brent has depreciated by 19% since October 2023 with the Mar-24 contract now trading below $80/bbl. The market dropped to six-month lows in mid-December as concerns around a weak commitment to output cuts from OPEC+ and higher output elsewhere, including record levels in the U.S were weighing heavily. Since then, price support emerged as the escalating conflict at the Red Sea drove risk sentiment higher as 12% of global oil trade could potentially have been disrupted.
The conflict has led to freight rates for tankers have risen by 30% since mid-December although weak economic growth, global surplus and diverting ships has kept some price resistance. Further price support was also driven by latest demand growth forecasts by the EIA, IEA and OPEC for 2024 which are in a wide range between 1.24mbpd and 2.2mbpd, citing economic growth and tighter crude market in Q4-24, though all three organisations expect demand growth to slow in 2025.