Australia's Beetaloo gets approval to sell NT shale gas

: Natural gas
25/12/09

Australian shale gas developer Beetaloo Energy, formerly Empire Energy, has received Northern Territory (NT) government authorisation to sell appraisal gas from its 25 TJ/d (668,000 m³/d) Carpentaria pilot project in the Beetaloo subbasin.

Reconstruction of the 42 TJ/d former Rosalind Park gas plant, bought last year from domestic utility AGL Energy for A$2.5mn ($1.66mn), can now begin, Beetaloo said on 9 December.

Carpentaria holds a gas supply agreement with the NT government signed in 2024 but the project is yet to reach a final investment decision. The company previously said it was targeting first gas by mid-2026.

A vast, underpopulated region of northern Australia, the NT is hoping to drive a new wave of investment on the back of extensive shale gas reserves, which have yet to be commercially proven.

Fellow Beetaloo subbasin developer Tamboran Resources expects first appraisal gas from its 40 TJ/d Shenandoah South pilot project in mid-2026.

The NT hosts the 3.7mn t/yr Santos-operated Darwin LNG terminal and 9.3mn t/yr Ichthys LNG terminal run by Japan's Inpex, which both use offshore-sourced gas as feedstock.

By Tom Major

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25/12/08

Brazil's Lula eyes draft to step away from fossil fuels

Sao Paulo, 8 December (Argus) — Brazil's president Luiz Inacio Lula da Silva called for the country's own draft roadmap for a "just and planned" energy transition, focusing on the move away from fossil fuels, after leading efforts for such an international plan. Brazil's energy, environment and finance ministries, as well as the chief of staff, must draft a resolution by 60 days from 5 December, or by 3 February, according to a presidential decree published in the official gazette on 8 December. Lula called for the creation of an international roadmap to move away from fossil fuels during a leaders' summit only a few days before the UN Cop 30 climate summit. That led to over 80 countries supporting a call for a roadmap to be included in final agreements at Cop 30. But the proposal did not make it to the summit's final decision. Instead, the Cop 30 presidency pledged to create a roadmap on the issue outside of official negotiations. Cop 30 president Andre Correa do Lago said recently that an initial draft of roadmap could be ready by April , when Colombia is set to host a global summit on the topic . Energy transition fund Lula also requested the creation of a draft resolution to "propose financing mechanisms to implement an energy transition policy", which would include creating an energy transition fund financed "by a portion of government revenues from oil and gas exploration". The ministries and chief of staff will also have 60 days from 5 December to draft this resolution. Lula had also asked oil and mining firms to pay their fair share of climate financing during a speech at Cop 30. This comes after similar efforts at previous climate summits. An initiative from the Cop 29 presidency called for a climate fund, capitalized with voluntary contributions from oil, coal and gas-producing countries and companies, to support developing economies in addressing climate change. But the fund was never set up and the topic slid from the agenda. Brazilian state-controlled oil firm Petrobras did not answer Argus ' requests for comments on the topic. Mining giant Vale declined to comment. But Brazil's oil, gas and biofuels institute IBP "recognizes the importance of creating a fund to finance energy transition and climate change projects and understands that the oil and gas sector can and should be part of the solution for this process", it told Argus . Brazil's oil and gas sector contributes with R325bn ($60.85bn)/yr in taxes and "part of this amount should be directed towards climate finance and a fair and efficient energy transition process", IBP said. But for that it is necessary to maintain oil and gas production, it said. Brazil has been steadily increasing its oil production. It produced 4.03mn b/d of crude in October , a 23pc increase from the same month in 2024, data from hydrocarbons regulator ANP show. The country has plans to expand oil production to 5.3mn b/d by 2030, according to energy research bureau Epe, hinging on new exploratory frontiers such as the southern Pelotas basin and the environmentally sensitive equatorial margin. IBP also argues that Brazil's oil sector already faces a large tax burden, with 66pc of all crude destined for the payment of taxes, fees and royalties. "We want to and will contribute, but it's necessary to point out that there's no way to create more burdens on the sector's supply chain", it said. The group argues that the fund's financing should come from the redistribution of current government oil and gas revenues. "Increasing taxation on oil and gas exploration and production could make future projects unfeasible," it said. By Lucas Parolin Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

US LNG margins tighten on higher Henry Hub prices

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.

Eni and BP plan deepwater well in Libya in 1Q

25/12/05

Eni and BP plan deepwater well in Libya in 1Q

London, 5 December (Argus) — BP and Italy's Eni will drill a long-planned deepwater exploration well offshore Libya in the first quarter of 2026, a source at state-owned NOC told Argus . It is the most anticipated well since international oil companies, also including Spain's Repsol, Austria's OMV and Algerian state-owned Sonatrach, resumed exploration efforts late in 2024. "The first ultra-deepwater exploration well in Area C is scheduled in 2026," block operator Eni told Argus . NOC said the well is scheduled for January. The planned well is offshore Libya's Sirte Basin oil and gas heartland and targets a gas prospect. Eni and BP started a three-well exploration campaign in late 2024. The first well was drilled on their Area B in the Ghadames basin, but the NOC source said this yielded no commercial quantities of oil and gas. Eni and BP plan another exploration well on Area B in 2026, the source said. Any discoveries could be tied into Eni's nearby facilities. The two firms also hold the close by Area A. Eni is Libya's largest oil and gas producer by volume and is leading the country's exploration revival. It is currently drilling an offshore exploration well in Area D, close to its existing offshore production facilities. It will drill another after this is completed, the source said. IOCs were forced to abandon their exploration efforts in 2014 as the Libya's security situation deteriorated. Firms are returning because NOC lifted force majeure on these plans in 2024. "The companies are genuinely eager to explore," the source said. "This isn't just about them having to fulfill their contractual commitments." Repsol is drilling the third of a nine-well exploration campaign in the onshore Murzuq basin. So far, one of these has proven "successful", the source said. Discoveries will be tied into the Repsol-led 300,000 b/d El Sharara field. NOC has announced six new onshore discoveries this year, including one from OMV and one from Sonatrach . Exploration revival Libya has said it will announce winners of its first upstream licensing round in almost two decades in the first quarter of 2026. Firms including ExxonMobil, Chevron, Shell, BP, TotalEnergies and Eni have been shortlisted to participate in the licensing round. ExxonMobil , Chevron , Shell and BP have also signed bilateral preliminary agreements with NOC that could see them explore new areas and even develop existing onshore fields. The exploration programmes and licensing round are primarily aimed at boosting reserves and extending plateau production once Libya reaches its output goals, but discoveries could surprise to the upside. Libya aims to boost crude production from about 1.4mn b/d to 2mn b/d and gas production from about 1.2bn ft³/d (12.4bn m³/yr) to 4bn ft³/d over the next few years. By Aydin Calik 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.

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