Turkey may purchase more LNG in fourth quarter

: Natural gas
25/09/03

Turkey may need to seek 36-48 spot LNG deliveries in the fourth-quarter of 2025 if consumption continues to hold above 2024 in the remainder of this year.

Turkey consumed a total of 34.2bn m³ of gas in the first six months of the year according to the latest data from the Turkish regulator EPDK. This figure is a roughly 21pc increase from the 28.6bn m³ used in the first half of 2024. The Turkish energy ministry provides more up-to-date daily usage figures, but Turkish market participants consider the regulator's data more reliable.

Turkey's total gas demand was 33.2bn m³ in the six months of this year, according to energy ministry data. This is a 20pc increase from 26.7bn m³ in the first half of 2024, according to the ministry. This data is based on daily figures, and the ministry notes historic values may change.

Turkey's total gas demand was 40.7bn m³ on 1 January-24 August, based on the latest energy ministry data. And end-users consumed around 746mn m³ during the remaining days of August, according to grid operator Botas and Epias transparency platform data. This suggests Turkey's total consumption for the first eight months of 2025 could reach 42.7bn m³ in the regulator's forthcoming dataset, indicating the 21pc year-on-year increase may have continued through the summer. The country consumed 35.3bn m³ in the same period last year, EPDK data show.

How to meet demand in the last quarter

Turkey may have to rely more heavily on LNG to meet demand in the final quarter of this year if consumption continues to hold above a year earlier.

Turkey consumed 53.2bn m³ of gas in total last year, with 15bn m³ in the final quarter. If the trend so far this year continues, consumption could reach 18.1bn m³ in October-December, creating an additional demand of 3.15bn m³ from a year earlier.

The only change in Turkey's pipeline supply mix from last year is the 1.3bn m³ of Turkmen gas arriving through Iran since March. Turkmen deliveries remained largely unchanged at 3.8mn m³/d between March and June, with 465mn m³ delivered so far. Assuming the same pace continues, Turkey may have purchased another 350mn m³ by October, leaving around 485mn m³ of Turkmen gas available for the final quarter.

Last year, domestic production totalled 693mn m³ in the final quarter, but this year production has accelerated and could total 874mn m³, based on August production figures. The combination of additional Turkmen gas and domestic output would only provide 666mn m³ of extra available gas in the final quarter.

Last year, private importers Akfel, Bosphorus and Kibar imported 2.6bn m³ of gas in the final quarter through the 15.75bn m³/yr Turkish Stream pipeline, out of 5.75bn m³/yr of their contracted capacity. This year they have already imported 1.75bn m³ collectively, leaving 4bn m³ available to be imported. Even if they import this, a 1.1bn m³ gas shortfall would still remain in the final quarter relative to last year.

Turkey imported 4.6bn m³ of pipeline equivalent through 49 LNG deliveries, averaging 94mn m³ per delivery, in the final quarter of 2024. Of these, 13 came from Algeria under a long-term contract, while the remaining 36 were spot purchases.

And Turkey may need to meet this potential 1.1bn shortfall through LNG imports. This would require around 12 more LNG deliveries than a year earlier.

Botas signed a 10-year LNG supply deal with Oman LNG starting in early 2025, for 1.4bn m³/yr. Oman has so far delivered only 90mn m³ of pipeline equivalent under this agreement.

Botas may plan to cover the final quarter shortfall with LNG from Oman. However, even in that case, Turkey could still need 36 spot purchases in October–December, similar to last year. In addition, firms have imported 20-21pc more strongly so far this year under pipeline contracts, which may limit available contracted pipeline supply in the fourth quarter, and increase the need for LNG imports, even if Oman LNG delivers at full capacity.

By Ugur Yildirim

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25/12/05

US LNG margins tighten on higher Henry Hub prices

Houston, 5 December (Argus) — A narrowing spread between US and European LNG prices and high freight rates in the Atlantic basin have pushed the front-month indicative long-term LNG contract cost above the spot Gulf coast fob price for the first time in two years. But the premium over the spot price will likely be brief, and limited flexibility in annual delivery plans will likely leave export schedules unchanged, with the impact solely on profit margins rather than fundamentals. A steeper backwardation in the US' Henry Hub forward curve compared to the northwest European LNG forward curve beyond February, as well as a steep backwardation in charter rates, means US LNG offtakers likely will not need to alter export plans. Liquefaction fees are also considered a sunk cost, and the Henry Hub remains comfortably below European LNG prices to more than cover the shipping cost between the two markets. This means there is still a strong financial incentive to maximise US LNG export volumes. The indicative long-term LNG contract price — 115pc of Henry Hub plus a $3/mn Btu liquefaction fee — has exceeded the Argus Gulf coast (AGC) spot fob price since 28 November, climbing to a premium of 69¢/mn Btu on 4 December. That premium came with the front-month Henry Hub price at a nearly three-year high of $5.06/mn Btu on forecasts for cold weather and US LNG exports at a record high. At the same time, the front-month NW Europe LNG des price was at $8.83/mn Btu, the lowest since May 2024, with warmer-than-normal weather forecast in Europe and EU underground storage well-supplied. A surge in freight rates, primarily driven by higher Atlantic basin loading demand, including at the 27.2mn t/yr Plaquemines plant, widened the spread between the AGC fob price and delivered spot prices in northwest Europe. The spread grew to 96¢/mn btu on 24 November, near the peak of the freight rally, up from 28¢/mn Btu in mid-October (see spread chart) . The wider spread pushed the AGC fob price for January loading below the indicative long-term LNG contract price for the same month. Forward freight rates are in steep backwardation in the first quarter of 2026, which is reflected in a tighter AGC-NW Europe spread over that span, as are Henry Hub futures contracts. This puts AGC prices above the indicative long-term contract prices from March through June (see forwards chart) . Although exports are unaffected because of liquefaction costs being considered sunk, the dynamic highlights the tightening margins for US LNG as a supply wave brings more liquefaction capacity on line through the end of the decade. The AGC fob's premium over the long-term indicative contract averaged $4.11/mn Btu through 4 December this year, down from $4.63/mn Btu, $5.37/mn Btu and $20.13/mn Btu in 2024, 2023 and 2022, respectively (see margins chart) . By Tray Swanson AGC-NWE spread and freight rates Tighter margins for US LNG $/mn Btu Indicative long-term contract forwards vs LNG spot prices $/mn Btu Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Golden Pass LNG approved to receive cool-down cargo

25/12/04

Golden Pass LNG approved to receive cool-down cargo

Houston, 4 December (Argus) — QatarEnergy and ExxonMobil's 18.1mn t/yr (2.4bn ft³/d) Golden Pass LNG export terminal in Texas received federal approval today to unload a cool-down cargo, a key step in commissioning the plant. The Federal Energy Regulatory Commission granted the project's request to introduce hazardous fluids into various systems and receive the cool-down cargo. The 174,000m³ Imsaikah has been holding offshore Texas' Port Arthur since 29 November after departing QatarEnergy's 77mn t/yr Ras Laffan export terminal with a cargo on 27 October. The vessel's LNG will be used to cool down Golden Pass' equipment for its start-up process. The three-train project also has federal approval to introduce fuel gas to train 1 and train 1's gas turbine. Feedgas flows to Golden Pass have yet to materially rise. Pipeline nominations on 4 December were just over 8mn ft³, in line with daily flows since mid-October. Flows to LNG plants can be revised later in the day. The project's developers anticipate the facility will start production by the end of the year or in early 2026, with each of its three trains coming on line in six-month intervals. By Tray Swanson Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

LNG to fill the gap as Seoul pledges faster coal exit

25/12/03

LNG to fill the gap as Seoul pledges faster coal exit

South Korea is scrambling for alternatives to coal-fired power to maintain sufficient base-load capacity, writes Evelyn Lee London, 3 December (Argus) — South Korea's pledge to phase out coal-fired power generation by 2040 has thrown its energy strategy into sharp focus, exposing a looming 40GW capacity gap. With nuclear expansion stalling and renewables facing infrastructure hurdles, LNG has become the most likely bridge to fill the potential shortfall. South Korea has formally confirmed its plan to retire 40 out of its 61 existing coal-fired units by 2040, following its declaration during the UN Cop 30 climate summit in Brazil last month to join the Powering Past Coal Alliance (PPCA) — a coalition of countries committed to ending coal use for power generation. The phase out timeline for the country's remaining 21 units — some of which were built relatively recently — will be determined through public consultation taking into account economic and environmental feasibility, and a detailed phase-out strategy is expected to be finalised next year, the PPCA says. This aligns with Seoul's intention to establish its 2026-40 long-term power plan by the end of next year. The firm phase-out pledge leaves South Korea scrambling for alternatives to maintain sufficient base-load power capacity. Its current long-term power plan covering 2024-39 was established in February under the previous administration of then-president Yoon Suk-Yeol. It earmarked 28 aging coal-fired units with a combined 14.1GW of capacity for conversion to LNG, and 12 units with 6.8GW of capacity to transition to carbon-free generation, such as pumped storage, hydrogen or ammonia co-firing, all by 2038. The current administration under President Lee Jae-Myung has indicated it does not intend to allow plants to switch to ammonia co-firing , signalling a decisive break from earlier strategies that sought to keep coal in the mix under a low-carbon guise. In line with this, Lee's administration in October cancelled the second round of a clean hydrogen power generation bidding market, which would have subsidised hydrogen and ammonia co-firing under 15-year contracts. Seoul searching An accelerated coal phase-out alongside a ban on approving new nuclear reactors has led to growing expectations that South Korea will lean more heavily on gas-fired plants to maintain its power system at least until renewables capacity catches up. The current electricity plan stipulates building two new 1.4GW reactors and continued use of expiring reactors, resulting in nuclear capacity rising to 35.2GW in 2038 from 26.1GW in 2025. But the Lee administration has ruled out building new reactors, although construction of reactors already under development can proceed as planned. The government has approved the restart of the 650MW Kori reactor 2, in line with the president's stance that expiring reactors may continue operating if safety standards are met. But even with these measures, Seoul must identify more than 40GW of replacement capacity by 2040, based on information currently available. This is roughly equivalent to the country's entire coal-fired fleet, which has accounted for around 28pc of total power output this year. The government aims to expand South Korea's renewable energy capacity to 100GW by 2030 from a previous target of 80.9GW and current capacity of 37.9GW, but its renewables rollout continues to be constrained by insufficient transmission capacity upgrades, mainly driven by local opposition. A law to accelerate grid projects came into force on 26 September, but progress is now being held up by local governments, which are reluctant to approve project permits in a bid to maintain positive public opinion ahead of municipal elections in June next year. Persistent grid bottlenecks have increased the country's reliance on gas-fired generation in recent years, as these plants are located close to the main demand centre around Seoul. Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

UK gas output continues to defy forecast decline

25/12/03

UK gas output continues to defy forecast decline

London, 3 December (Argus) — Production from the UK continental shelf (UKCS) inched up on the year in September, in contrast to the North Sea Transition authority's (NSTA) projected fall in output this year from last production. Gas output on the UKCS was 71.24mn m³/d in September, NSTA data show, up marginally from 71.17mn m³/d a year earlier. Output was varied across the country's largest production hubs, with higher production at Britannia and Arran balancing the decline at other fields. Production rose significantly on the year at Arran to 2.1mn m³/d in September, up from 0.1mn m³/d a year earlier. Similarly, there was sharp increase at Britannia to 2.1mn m³/d from 0.2mn m³/d a year earlier, because of heavy works in September 2024 at the two fields. Harbour Energy, the operator of the Britannia, experienced an "unusually high number of planned shutdowns" in 2024 . Meanwhile, production declined at the UK's largest fields — Culzean, Elgin, Franklin, Cygnus, Bruce and Tolmount — with the biggest production decrease at Bruce. Bruce production fell to 2.8mn m³/d from 4.4mn m³/d a year earlier. Marginally higher production coupled with lower domestic consumption on the year meant that UKCS output met a larger share of demand than in September 2024. UK demand fell to 107.4mn m³/d in September, from 116.4mn m³/d a year earlier. UK output in September met 66pc of demand, including exports to Ireland at Moffat, up from 61pc a year earlier. Production in 2025 revised up The NSTA increased its projection for production for 2025 and 2026 in its biannual forecast released in November. The NSTA forecast that net gas production will continue its decline, but remain higher than previously forecast in 2025 and 2026. The regulator expects net production of 24.6bn m³ — or 67.4mn m³/d — this year. This is up from its estimation of 24.5bn m³ in March, equivalent to 67.1mn m³/d. The NSTA also revised its net gas production figure for 2026 to 21.3bn m³, up from 21.2bn m³ in the previous forecast (see forecast table) . The NSTA revised its expected decline on the year in 2025 to 9.6pc from the previously projected 10pc. But the decline rate remains unchanged at 12pc for 2026-50. And the NSTA's projections for production in 2025-30 fall by an average of 2.3bn m³/yr. The regulator projects that the average unit cost of gas and crude oil together will increase to £19.80 barrels of oil equivalent (boe) this year, from £19.50/boe in 2025. And it expects this cost to increase in the following years, moving up to £20.80/boe by 2030. In its Autumn Budget, the UK government retained the energy profits levy on oil and gas profits until its scheduled end date of 31 March 2030 . Alongside the budget, the government published its North Sea Future Plan, which outlined that the government will not issue new oil and gas exploration licences in the North Sea, but it will encourage firms to produce gas from areas adjacent to operating fields . Production may surpass 2025 forecast Implied production data suggest that UK production may decline even lower than the revised NSTA forecast states. UKCS production totalled 21bn m³ in January-September. And based on the NSTA's projection of a total production of 24.6bn m³, this leaves 3.6bn m³ to be produced in October-December, or 39.1mn m³/d, based on NSTA data. But implied production — based on gas delivered to the national transmission system — was 79.8mn m³/d in October-November, or 4.87bn m³, already surpassing the projected annual figure for 2025. And if the 9.6pc production decline rate is applied to actual average output of 85.43mn m³/d in October-December 2024, this would equate to an output of 77.23mn m³/d during this period, which also suggests higher total annual production of 28.1bn m³. Operators expect strong production at certain hubs in December, further suggesting potential for production to surpass the NSTA projections. UK North Sea producer Ithaca Energy expects strong production in December on the back of new wells coming on line. An infill campaign at its Cygnus field is continuing, Ithaca said in its third-quarter results earlier this month, with the first of four wells expected to achieve production early this month . Similarly, the operator of the Bruce hub, Serica Energy, said in its third-quarter results last month that it expects strong output from Bruce in the last two months of the year . By Aleksandra Godlewska UK production forecast bn m³ November forecast March forecast October 2024 2024 27.4 27.2 26.3 2025 24.6 24.5 23.6 2026 21.3 21.2 20.3 2027 18.4 18.4 17.5 2028 16.2 15.9 15.6 2029 13.9 13.8 13.7 2030 12.2 11.9 12.1 2031 10.7 10.4 10.8 2032 9.4 9.2 9.7 2033 8.2 8.1 8.7 2034 7.1 6.9 7.5 2035 6.0 5.9 6.5 — NSTA Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Saudi Arabia brings giant Jafurah gas project onstream

25/12/03

Saudi Arabia brings giant Jafurah gas project onstream

Dubai, 3 December (Argus) — Saudi state-controlled Aramco has begun production from the first phase of the giant Jafurah natural gas project, the finance ministry said late on Tuesday. In its 2026 budget statement, the finance ministry listed the phase one start-up as one of Saudi Arabia's achievements in 2025. It didn't specify a date, but it is likely to have been in the past few days. It said production began at 450mn ft³/d, which is two and a half times the rate at which Aramco had long projected. With in-place reserves of 229 trillion ft³ (6.87 trillion m³) of raw gas and 75bn bl of condensate, Jafurah is the largest unconventional gas field in the Mideast Gulf and represents a major pillar of Aramco's ambitious gas expansion plans. Aramco has yet to announce the start up. It previously said it expects to lift sales gas output ꟷ or net production ꟷ to 650mn ft³/d by the end of 2026 in phase one. It is unclear if this stronger-than-anticipated start-up rate could translate into a higher end-2026 target. A second phase is scheduled to come on stream in 2027, to lift production to 2bn ft³/d by the end of the decade, Aramco has said. Aramco has an ambitious programme to expand gas production by more than 80pc by the end of the decade, relative to a 2021 baseline of 9.2bn ft³/d. This implies output of at least 14.7bn ft³/d by 2030, with Jafurah delivering more than one-third of the increase. Jafurah will also produce about 420mn ft³/d of ethane and 630,000 b/d of NGLs and condensate as by-products by 2030. The ethane and NGLs will be sent to the Riyas fractionation plant, which is being built as part of the phase two development. The condensate will be sent to the Juaymah terminal, where Aramco is expanding its storage and export facilities. By Nader Itayim Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

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Turkey may purchase more LNG in fourth quarter

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