Panama Canal LNG congestion may become structural

  • Spanish Market: Natural gas
  • 04/02/21

Congestion at the Panama Canal, which has been hampering US LNG deliveries to Asia in recent months, may be a recurring feature in the LNG market in the coming years.

With the third train of the 15mn t/yr Corpus Christi facility still in the commissioning phase, the US is already producing about three LNG cargoes daily (see graph). But no more than one LNG carrier a day can take the quickest route through the Panama Canal to typical global premium markets in northeast Asia. The Canal Authority normally allows no more than two LNG carriers a day to transit the waterway, either both heading to the Gulf of Mexico or one in each direction, although it has occasionally allowed some extra crossings. When Asian prices are high enough to attract Atlantic basin cargoes, LNG tankers coming from the US may also have to compete with Trinidadian cargoes to secure the limited number of Panama slots on offer.

Asia taking a portion of US exports in line with the historical average would already be sufficient to create congestion at Panama. Since the US began exporting LNG, eastern Asia has received on average 35pc of total US production, against 30pc that instead found a buyer in Europe or the Middle East. That said, while eastern Asian markets absorbed the largest share of US cargoes in 2017-18, a tighter arbitrage between the two main markets led to Europe taking a larger share in the past two years (see graph). But LNG demand in the two regions is of a fundamentally different nature — with the largest Asian economies relying heavily on seaborne imports, while most European markets only buy LNG when prices are competitive with other supply sources.

The limited Panama capacity has already forced a large share of US cargoes to take a longer route to Asia in recent months, either through the Suez Canal or the Cape of Good Hope. The US sent a total of 265 cargoes to northeast and southeast Asia last year, but only 219 laden vessels from the US crossed Panama, suggesting at least 21pc of US flows to Asia had to take a longer and more expensive route. US deliveries to eastern Asia were 152 in 2019, accounting for 85pc of the 178 Panama crossings by US cargoes. That said, Asian demand for US cargoes was particularly strong in the fourth quarter of 2020, which was likely to have exacerbated congestions and bolstered use of alternative routes (see graph).

A sharp increase in northeast Asian demand coupled with slower regional production, particularly from Australia, resulted in LNG prices reaching an all-time high in recent weeks. Regional demand continuing to rise at the pace seen in recent years may increasingly require brisk imports from outside the basin. Northeast Asian demand grew at an average of nearly 7pc/yr over the past five years and the region absorbed about 8.2mn t more than a year earlier in 2020. The third 3.8mn t/yr train at the Tangguh facility in Indonesia, expected to start in September this year, is the only new liquefaction facility under construction in the Asia-Pacific basin at present. The addition of the 3.4mn t/yr Coral South FLNG in Mozambique may also be insufficient to dent the regional imbalance, suggesting Asian markets may continue to absorb the vast majority of Qatari supplies, while needing to open an ample premium to European markets to cover the additional costs of US deliveries through Suez or the Cape of Good Hope.

The 5.4mn t/yr Papua LNG project and the planned 2.7mn t/yr third liquefaction train of PNG LNG have yet to reach a final investment decision and are not expected to come on stream before 2024. The 13.1mn t/yr Mozambique LNG project, Mexico's 2.5mn t/yr Energia Costa Azul — which is located on the country's Pacific coast — and the first new train of Qatar's planned Ras Laffan expansion are not expected to be completed before 2024-25.

Total US exports Cargoes

US exports by region Cargoes

US exports, by destination Cargoes

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24/04/24

EU adopts sustainability due diligence rules

EU adopts sustainability due diligence rules

Brussels, 24 April (Argus) — The European parliament has formally approved a Corporate Sustainability Due Diligence Directive (CSDDD), which will require large EU companies to make "best efforts" for climate change mitigation. The law will mean that relevant companies will have to adopt a transition plan to make their business model compatible with the 1.5°C temperature limit set by the Paris climate agreement. It will apply to EU firms with over 1,000 employees and turnover above €450mn ($481mn). It will also apply to some companies with franchising or licensing agreements in the EU. The directive requires transposition into different EU national laws. It obliges member states to ensure relevant firms adopt and put into effect a transition plan for climate change mitigation. Transition plans must aim to "ensure, through best efforts" that business models and company strategies are compatible with transition to a sustainable economy, limiting global warming to 1.5°C and achieving climate neutrality by 2050. Where "relevant", the plans should limit "exposure of the company to coal-, oil- and gas-related activities". Despite a provisional agreement, EU states initially failed to formally approve the provisional agreement reached with parliament in December, after some member states blocked the deal. Parliament's adoption — at its last session before breaking for EU elections — paves the way for entry into force later in the year. Industry has obtained clarification, in the non-legal introduction, that the directive's requirements are an "obligation of means and not of results" with "due account" being given to progress that firms make as well as the "complexity and evolving" nature of climate transitioning. Still, firms' climate transition plans need to contain "time-bound" targets for 2030 and in five-year intervals until 2050 based on "conclusive scientific" evidence and, where appropriate, absolute reduction targets for greenhouse gas (GHG) for direct scope 1 emissions as well as scope 2 and scope 3 emissions. Scope 1 refers to emissions directly stemming from an organisation's activity, while scope 2 refers to indirect emissions from purchased energy. Scope 3 refers to end-use emissions. "It is alarming to see how member states weakened the law in the final negotiations. And the law lacks an effective mechanism to force companies to reduce their climate emissions," said Paul de Clerck, campaigner at non-governmental organisation Friends of the Earth Europe, pointing to "gaping" loopholes in the adopted text. By Dafydd ab Iago Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Oman latest to insist that oil, gas is 'here to stay'


24/04/24
24/04/24

Oman latest to insist that oil, gas is 'here to stay'

Muscat, 24 April (Argus) — Omani and Oman-focused energy officials this week joined a growing chorus of voices to reiterate the pivotal role that hydrocarbons have in the energy mix, even as state-owned companies scramble to increase their share of renewables production. Some producers cite the risk of leaving costly, stranded oil and gas assets as renewable energy alternatives become more favoured. "This is a common concern among producers who are focusing on short-term developments to maximize cash flow — [but] if we continue to do that, with the clean energy transition, will we be left with stranded assets in the long-term", state-controlled PDO's technical director Sami Baqi told the Oman Petroleum and Crude Show conference in Muscat this week. "We need to redefine and revamp our operation model to produce in a sustainable manner." "We are in an era where most of the production does not come from the easy oil but comes from difficult oil," Oman's energy ministry undersecretary Mohsin Al Hadhrami said. "It requires more improved and enhanced oil recovery (EOR) type technologies to extract it." Oman is heavily reliant on tertiary extraction technologies like EOR given its maturing asset base and complicated geology. "We know that most of the oil fields [in the region] are maturing and costs are going to escalate, so we need to be mindful of it while discussing cleaner solutions going forward," Hadhrami said. PDO, Oman's largest hydrocarbon producer, aims for 19pc of its output to come from EOR projects by 2025, and has said it is looking at 'cleaner' ways to implement the technology. PDO in November started a pilot project to inject captured CO2 for EOR at its oil reservoirs. Baqi's concerns were echoed by PDO's carbon capture, utilisation and storage (CCUS) manager Nabil Al-Bulushi, who said even solutions like CCUS can be expensive and come with their own challenges. There is a need for a proper ecosystem or regulatory policies to avoid delays in executing such projects, he said. When it comes to challenges associated with commercialising green hydrogen, Saudi state-controlled Aramco's head of upstream Yousef Al-Tahan said higher costs already make hydrogen more expensive than any other energy sources. "Not only should the costs go down, but the market has to be matured to take in the hydrogen," he said. "We also need pipelines and facilities that are able to handle hydrogen, especially when it gets converted to ammonia." Gas here to stay Oman, like many of its neighbors in the Mideast Gulf, insists gas needs to be part of the global journey towards cleaner energies. "Asia-Pacific is still heavily reliant on coal, this is an area where gas can play an important role," Shell Oman's development manager Salim Al Amri said at the event. "I think there is no doubt that gas is here to stay." Oman is a particularly interesting case as it "has moved from a position of gas shortage to surplus", Al Amri said, enabled by key developments in tight gas. "Output from fields like Khazzan and Mabrouk will continue to produce nearly 50pc of output even by 2025, which is indicative of how important tight gas developments are," he said. The Khazzan tight gas field has 10.5 trillion ft³ of recoverable gas reserves. Mabrouk North East is due to reach 500mn ft³/d by mid-2024. But even as natural gas is touted as the transition fuel, executives from major producers like state-owned OQ and PDO warned there are technical risks associated with extracting the fuel, including encountering complex tight reservoirs, water production and difficult geology. By Rithika Krishna Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Australia’s Woodside pledges extra domestic gas in 2025


24/04/24
24/04/24

Australia’s Woodside pledges extra domestic gas in 2025

Sydney, 24 April (Argus) — Australian independent Woodside Energy has promised to increase gas flows to domestic customers with a predicted national shortfall. The firm promises to make an extra 32PJ (854mn m³) available to the Western Australia (WA) domestic market by the end of 2025, Woodside chief executive Meg O'Neill said at its annual meeting in Perth on 24 April, following criticism of the state's LNG projects' contribution to WA supplies . Woodside produced 76PJ for the WA market in 2023. The company has initiated an expression of interest process for an additional 50PJ of gas from its Bass Strait fields offshore Victoria state for supply in 2025 and 2026 when a tight market is expected for east Australia . Woodside also said its Sangomar oil project offshore Senegal is 96pc complete with 19 of 23 initial wells complete. WA's Scarborough project is 62pc complete with trunkline installation and well drilling having started in the offshore Carnarvon basin. It last month awarded the sub-sea marine installation contract for its 100,000 b/d Trion project offshore Mexico, which is targeting its first oil in 2028. Woodside's 2023 operating revenue was $14bn , resulting in a profit of $1.7bn. Climate tensions Woodside's climate transition action plan saw 58.36pc opposition from shareholders at the annual meeting but is non-binding on the company. Woodside's 2021 climate report also faced significant opposition with 48.97pc voting against its adoption. The company did not put its 2022 climate report up for vote at last year's annual meeting. Its new emissions abatement target aims to reduce Woodside's customers' scope 1 and 2 emissions by 5mn t/yr by 2030, along with a $5bn investment in new energy projects by the same date. Net equity scope 1 and 2 greenhouse gas emissions rose to 5.53mn t carbon dioxide equivalent (CO2e) in 2023 from 4.61mn t CO2e in 2022 because of its merger with BHP Petroleum in mid-2022. Several major institutional shareholders including large domestic and international pension funds had already flagged their vote against Woodside's climate report, citing an insufficient urgency to reduce the firm's emissions. By Tom Major Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

US oil and gas deals slowing after record 1Q: Enverus


23/04/24
23/04/24

US oil and gas deals slowing after record 1Q: Enverus

New York, 23 April (Argus) — US oil and gas sector mergers will likely slow for the rest of the year following a record $51bn in deal in the first quarter, according to consultancy Enverus. Transactions slowed in March and the second quarter appears to have already lost momentum, according to Enverus, following the year-end 2023 surge in consolidation that spurred an unprecedented $192bn of upstream deals last year. The Permian shale basin of west Texas and southeastern New Mexico continued to dominate mergers and acquisitions, as companies competed for the remaining high-quality inventory on offer. Acquisitions were led by Diamondback Energy's $26bn takeover of closely-held Endeavor Energy Resources . Others include APA buying Callon Petroleum for $4.5bn in stock and Chesapeake Energy's $7.4bn takeover of Southwestern Energy . The deal cast a spotlight on the remaining private family-owned operators, such as Mewbourne Oil and Fasken Oil & Ranch, which would be highly sought after if they decided to put themselves up for sale. "However, there are no indications these closely held companies are looking to exit any time soon," said Andrew Dittmar, principal analyst at Enverus. "That leaves public explorers and producers (E&P) looking to scoop up the increasingly thin list of private E&Ps backed by institutional capital and built with a sale in mind — or figuring out ways to merge with each other." Deals including ExxonMobil's $59.5bn takeover of Pioneer Natural Resources, as well as Chevron's $53bn deal for Hess, have attracted the attention of anti-trust regulators. The Federal Trade Commission has also sought more information on the Chesapeake/Southwestern deal. "The most likely outcome is all these deals get approved but federal regulatory oversight may pose a headwind to additional consolidation within a single play," said Dittmar. "That may force buyers to broaden their focus by acquiring assets in multiple plays." By Stephen Cunningham Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

USGC LNG-VLSFO discount to steady itself


23/04/24
23/04/24

USGC LNG-VLSFO discount to steady itself

New York, 23 April (Argus) — The premium for US Gulf coast (USGC) very low-sulphur fuel oil (VLSFO) to LNG is expected to linger but not widen this spring, maintaining interest in LNG as a bunkering fuel. US Gulf coast LNG prices slipped from a premium to a discount to VLSFO in March 2023 and have remained there since. The discount surpassed 200/t VLSFO-equivalent in January (see chart). Both LNG and VLSFO prices are expected to remain under downward pressure due to high inventories, which could keep the current LNG discount steady. The US winter natural gas withdrawal season ended with 39pc more natural gas in storage compared with the five-year average, according to the US Energy Information Administration (EIA). Henry Hub natural gas monthly average prices dropped below $2/mmBtu in February, for the first time since September 2020, Argus data showed. The EIA expects the US will produce less natural gas on average in the second and third quarter of 2024 compared with the first quarter of 2024. Despite lower production, the US will have the most natural gas in storage on record when the winter withdrawal season begins in November, says the EIA. As a result, the agency forecasts the Henry Hub spot price to average less than $2/mmBtu in the second quarter before "increasing slightly" in the third quarter. EIA's forecast for all of 2024 averages about $2.20/mmBtu. US Gulf coast VLSFO is facing downward price pressure as demand falls and increased refinery activity signals a potential supply build . Rising Gulf coast refinery activity was likely behind some of the drop in prices. Gulf coast refinery utilization last week rose to 91.4pc, the highest in 12 weeks and up by 0.9 percentage points from the prior week. US Gulf coast suppliers are also eyeing strong fuel oil price competition from eastern hemisphere ports such as Singapore and Zhoushan, China, importing cheap Russian residual fuel oil. In general, LNG's substantial discount to VLSFO has kept interest in LNG for bunkering from ship owners with LNG-burning vessels high. The EIA discontinued publishing US bunker sales statistics with the last data available for 2020. But data from the Singapore Maritime & Port Authority, where the LNG–VLSFO discount widened to over $200/t VLSFOe in February, showed Singapore LNG for bunkering demand increase 11.4 times to 75,900t in the first quarter compared with 6,700t in the first quarter of 2023 and 110,900t for full year 2022. By Stefka Wechsler US Gulf coast LNG vs VLSFO $/t VLSFOe Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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