Algeria unveils encouraging bid round results

Spanish Market: Natural gas
20/06/25

Algiers aims to build further on its successful return to upstream licensing, writes Aydin Calik

Algeria revealed the results of its first upstream licensing round in over a decade this week. The outcome is encouraging with five out of six blocks on offer awarded. Key winners include Italy's Eni, France's TotalEnergies and China's Sinopec, all of which are already present in the country. But Qatar's state-owned QatarEnergy (QE) marks a notable new entry (see table).

The licensing round marks a huge milestone in the country's efforts to cultivate investment in its oil and gas sector, and is the first under an oil law that came into force in 2021. Mourad Beldjehem, president of upstream regulator Alnaft, tells Argus that the awards will lead to around $1bn of mainly exploration investments. Development spending would bring in much more. Algeria needs it.

State-owned Sonatrach wants to capitalise on Europe's energy security challenges and replace some of the lost gas flows from Russia following the latter's invasion of Ukraine in 2022. But this is a work in progress. Algeria's gas exports have been squeezed in recent years by natural decline at producing fields and strong domestic consumption. Gas output and exports fell by 7pc to 98.3bn m³ and 48.5bn m³, respectively, in 2024.

Of the six onshore blocks on offer, the only one that was left unawarded was Grand M'Zaid, which contains a producing oil field. A source told Argus there was a bid for this block but it was not awarded because of a procedural issue. The other five contain undeveloped gas discoveries and lie close to existing facilities, potentially allowing tie-ins that could cut development costs and time.

For example, Eni and Thai firm PTTEP's new Reggane II block is located close to the Touat gas field in the Ahnet basin. TotalEnergies and QE's Ahara block is within reach of the French major's TFT gas production facilities that lie in the Illizi basin. Beldjehem says the awards could unlock 20bn m³/yr of new gas production in the medium term — equal to about 40pc of current exports — with first output potentially on line within three years. And there could be more, with exploration drilling expected to start next year.

The results are far better than the previous licensing round in 2014, which saw only four of 31 blocks awarded. But there is room for improvement. Ultimately, only seven bids came in for five blocks, despite 37 companies officially expressing interest. "I know where the problem was and we will fix that for the next one. We had a lot of lessons learned from this one," Beldjehem says. Another onshore bidding round is planned for the fourth quarter, and will offer 4-6 blocks. This will also be gas focused. "That is the demand today," Beldjehem adds. After this, three more rounds are planned each year up to 2028.

Competitive advantage

The time is ripe for an investment boom. European firms are refocusing on their traditional oil and gas businesses as climate-change-related shareholder concerns take a back seat. Algeria faces some tough regional competition, however, particularly from Libya, Egypt and the wider eastern Mediterranean. But its existing gas export potential into Europe, strong resource base and political stability should give it a significant competitive advantage over its neighbours.

The licensing rounds are only one part of the country's plan to boost investment. Algeria has signed more than $8bn worth of bilateral upstream contracts with companies such as Eni, TotalEnergies and Occidental since 2021. But it must do more. Sonatrach is holding talks with several companies. The most important of those are with US firms ExxonMobil and Chevron over their potential entry into the country to explore its shale potential. If these contracts go through, they could lead to a substantial upgrade to Algeria's production outlook.

Algeria licensing round results
Block	Bids	Winners	Block type

Toual II	1	Zangas-Filada	Gas
Ahara	1	TotalEnergies-QatarEnergy	Wet Gas
Zerafa II	3	ZPEC	Gas
Guern El Guessa II	1	Sinopec	Gas
Reggane II	1	Eni-PTTEP	Gas
Grand M'Zaid	0	Not awarded	Oil
SOURCE: ALNAFT.

Algeria gas infrastructure

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11/07/25

Brazil advances oil, gas decarbonization strategy

Sao Paulo, 11 July (Argus) — Brazil is implementing a roadmap to increase crude output without boosting net emissions from the sector, a key argument for its claim to leadership on climate issues ahead of the Cop 30 UN summit. Although Brazil does not plan to phase out fossil fuel use, it is working to reach net zero emissions by 2050, and slashing greenhouse gases from its hydrocarbons production is part of this strategy. Brazil's oil industry already has a carbon footprint at 14.88kg CO2 equivalent (C02e)/bl of oil equivalent (boe), which is well below the global average of 20kg CO2e/boe, according to the hydrocarbons regulator ANP. But with oil and gas production slated to increase steadily over the next decade, Brazil's government and producers are eyeing a range of options to further slash emissions. "Brazil can double oil output without increasing net emissions by employing existing technologies," Heloisa Borges, the director of oil, gas and biofuels at the government energy planning and research agency (Epe) said. As part of these efforts, the government called on Epe, ANP and state-owned company Pre-Sal Petroleo to present a roadmap to decarbonize the sector. The plan presented in late June outlines options including adopting new technologies and expanding existing emissions reductions techniques, such as leak detection and reducing flaring. "Expanding methane capture not only reduces emissions, but it allows companies to use this gas to substitute other fuels, such as diesel in their operations," Borges said. Other fuel substitution operations include using natural gas as fuel for drilling rigs and electrification of production operations, the study said. State-controlled Petrobras is already advancing its decarbonization strategy. The company's most recent five-year plan earmarks R5.3bn ($950mn) for emissions reductions in its operations as well as $1bn for research and development of new technologies. Carbon capture, utilization and storage (CCUS) is a key element, according to Lilian Melo, executive director of the Petrobras' research, development and innovation center Cenpes. The company uses high-pressure separation technology to remove CO2 from oil at the mouth of a reservoir and inject it back into the reservoir after the fluids are separated. This technology significantly reduces emissions, especially because crude produced from pre-salt blocks has high CO2 content, Melo said. The CCUS is used on 23 of Petrobras' offshore platforms in the pre-salt. Petrobras is also working to expand electrification of its on and offshore platforms. Power generation is responsible for 65pc of Petrobras' production-related emissions, according to Melo. The company announced this week a contract with Hitachi Energy to assess electrification of its offshore oil operations. Catch and keep Other oil producers are working to reduce the carbon footprint of their operations, including Eneva, which is also weighing investments in carbon capture and storage. The company is conducting a preliminary study to assess the technical viability of injecting CO2 into fields in the Parnaiba basin in Maranhao state. The Gaviao Real field has been operating for more than 10 years and is expected to become depleted in coming years, when it could potentially be converted to store CO2. Eneva is also weighing investments in carbon storage in the Parana basin, where the company has four exploratory blocks. Preliminary seismic data indicates that these blocks also have salt caverns and the company believes that there is significant potential to offer carbon storage to ethanol mills in areas adjacent to the blocks. Despite Brazil's ambitious emissions reduction plan, it has no intention of pulling back on exploration and production. With few exceptions, the Brazilian government is aligned on developing oil and gas reserves to boost economic growth and energy security and holds that the aim does not hurt its role in climate leadership. Brazil's energy sector GHG emissions mn t CO2e Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Trump threatens 35pc tariff on Canada by 1 August

11/07/25

Trump threatens 35pc tariff on Canada by 1 August

Houston, 10 July (Argus) — The US will impose a 35pc tariff on all imports from Canada effective on 1 August, President Donald Trump said in a letter to Canadian prime minister Mark Carney. The 10 July letter that Trump posted on social media late Thursday noted that Canada previously planned retaliatory tariffs in response to the US' first tariff threats in the spring. He repeated his earliest justification for the tariffs - the illegal smuggling of fentanyl into the US from Canada - and said he would consider "an adjustment" to the tariffs if Canada worked with him to stop that flow. The 35pc tariff would be separate from tariffs set for specific sectors, which include a 50pc tariff on copper imports . It is not clear if any imports currently covered by the US-Mexico- Canada trade agreement (USMCA) would be affected by the new tariff threats. The Trump administration since 5 April has been charging a 10pc extra "Liberation Day" tariff on most imports — energy commodities and critical minerals are exceptions — from nearly every foreign trade partner. Trump on 9 April imposed even higher tariffs on key trading partners, only to delay them the same day until 9 July. On 7 July, Trump signed an executive order further delaying the implementation of higher rates until 12:01am ET (04:01 GMT) on 1 August. Earlier this week he threatened 50pc tariffs against Brazil for its ongoing criminal prosecution of former president Jair Bolsonaro. Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

EQT to report $720mn gain on gas derivatives

10/07/25

EQT to report $720mn gain on gas derivatives

New York, 10 July (Argus) — US natural gas producer EQT expects to report a $720mn gain on its derivative contracts for the second quarter of 2025, more than wiping out the $679mn derivatives loss it reported in the first quarter, the company said Thursday in a regulatory filing. EQT, the second-largest US gas producer by volume, as of 16 April had 3.7 Bcf/d of its second-quarter gas output covered by derivatives, according to a financial disclosure on its website. This is equivalent to more than half of its total production capacity. Prices for those volumes appear to have been locked in before 19 July 2024, as the company had 3.7 Bcf/d hedged by that date. The derivatives gain reflects a drop in US gas prices in recent months as resilient production flipped US gas inventories from undersupply at the end of winter to oversupply in recent months. US gas inventories at the end of February were at a 224 Bcf deficit to the five-year average, according to the US Energy Information Administration. After a string of weekly storage reports showing very large net injections into storage, suggesting producers had returned wells to production that had previously been sidelined by last year's lower prices, inventories last week were at a 173 Bcf surplus, or 6.1pc higher than the five-year average. EQT plans to hedge less of its output going forward, in part because it has increased the amount of gas it can move to consumers outside of its core operating area in Appalachia, where gas prices are comparatively low. The company would need to have "conviction" on its US gas price outlook for it to raise its hedged volumes to even 50pc, which would be "a limit," EQT chief executive told Argus in an interview in June. EQT lost about $8bn on derivatives in the 2020-2022 period, in part from a US gas price spike in 2022 which EQT and other producers were not fully able to exploit as they had already locked in sales at lower prices. EQT plans to release full first-quarter financial results after US market close on 22 July. EQT reported a $242mn profit in 2024, down from $1.74bn in 2023. By Julian Hast Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Q&A: Titan on the future of LNG and bio-LNG bunkering

10/07/25

Q&A: Titan on the future of LNG and bio-LNG bunkering

London, 10 July (Argus) — Titan is a leading supplier of LNG and bio-LNG as a bunker fuel, mostly supplying volumes in northwest Europe. Argus spoke to Titan's commercial director, Michael Schaap, about the future of LNG and bio-LNG bunkering. How has the demand for LNG as a marine fuel evolved over the past year, and what factors are driving this growth besides FuelEU Maritime? Demand for LNG as a marine fuel has grown significantly over the past year, driven not only by regulatory developments like FuelEU Maritime but also by the growth of the LNG dual-fuel fleet. According to DNV's Alternative Fuels Insights platform, 642 LNG-powered vessels are currently in operation, excluding LNG carriers. Of these, 169 were delivered in 2024, setting a record. The growth in demand is expected to continue — 264 new orders for LNG-fuelled vessels were placed in 2024, also a record and more than double the number of orders placed in 2023. Essentially, the total addressable market for LNG pathway fuels in 2028 will be enormous. The LNG pathway uses LNG (and its established infrastructure), bio-LNG and e-methane (derived from renewable hydrogen). All of these fuels can be blended at any ratio and ‘dropped into' infrastructure and vessels with little to no modification required. It is increasingly recognised as a practical route to take the shipping industry to net zero greenhouse gas emissions. What are the current challenges in scaling LNG bunkering infrastructure to meet the needs of the growing fleet of LNG dual-fuel vessels? A key challenge is ensuring timely investment in bunkering infrastructure to keep pace with the growing number of LNG-fuelled vessels. Take LNG bunkering vessels, for example. According to the DNV, about 64 LNG bunkering vessels are in operation worldwide today, with a further 16 on order. While this far exceeds other alternative fuels, continued investment and expansion will be important. To maintain safe, timely and efficient LNG deliveries that meet demand, it is also important to maintain a suitable number of LNG loading slots. The increased demand for LNG and bio-LNG could alter the dynamics between buyers and sellers in the market. The spot market may become more challenging and expensive for shipowners and operators going forwards. As a result, those that can plan should book capacity well in advance and sign long-term offtake agreements. A good balance of pre-booked business also allows suppliers to reinvest in infrastructure such as bunkering vessels, shifting the market back towards the buyers. Where is Titan looking to expand — beyond northwest Europe? Titan supplies and bunkers LNG and increasingly bio-LNG around the world, partnering with local companies to support if needed. Titan's base, the Zara (Zeebrugge, Amsterdam, Rotterdam, Antwerp) region, is a key hub for LNG, bio-LNG and in the future, e-methane bunkering, and this is not expected to change. Having said this, the Mediterranean is recognised as a key strategic market for expansion. The Mediterranean became an Emission Control Area (ECA) on 1 May, so we expect this to escalate the need for LNG and bio-LNG in the region. Compared with heavy fuel oil, LNG pathway fuels can reduce nitrogen oxide emissions by up to 80pc and almost eliminate sulphur oxide and particulate matter emissions, offering ECA compliance. How is Titan positioning itself to meet the expected boom in bio-LNG demand growth over the coming years and decades? Titan is leading the way in supplying bio-LNG. We have been bunkering nearly all of [Norwegian shipping line] UECC's LNG-powered car carriers with bio-LNG since mid-2024, offering over-compliance with FuelEU Maritime, which presents financial rewards through pooling or banking. The partnership has now been extended through 2025. In 2024, we completed the world's largest ship-to-ship bio-LNG bunkering. We bunkered 2,200t of mass balanced bio-LNG to a Hapag-Lloyd containership in Rotterdam. The bio-LNG was ISSC-certified and recognised under the EU's Renewable Energy Directive known as Red II, marking a major milestone in the clean marine fuels transition. Going forwards, we hope to continue pioneering bio-LNG bunkering across more ports, and we feel it is important for us to further scale our bio-LNG offering as customers increasingly look to focus on regulatory compliance. We will also continue to closely monitor demand and supply signals for other clean marine fuels and will implement them into our portfolio as necessary. What do you see as the main challenges to bio-LNG growth, both in Europe and globally? High production costs remain a challenge for bio-LNG, but processes such as mass balancing are helping to lower supply-side costs. Mass balancing is a system in which biomethane is injected into the gas network and transported to liquefaction plants and LNG terminals using the existing infrastructure. It is expected to feature on many alternative fuel pathways and is a practical way of delivering clean molecules. The best analogy is when domestic energy companies provide consumers with renewable energy in a very similar way. Co-ordinated and consistent public-sector support for biomethane production will also support continued growth in the sector. The EU REPowerEU plan has ambitious biomethane usage targets of 35bn m³ by 2030. In 2023, the EU produced 22bn m³ of biogas, with biomethane being a key component. There is still plenty of work to do. Public-sector support is not only in the interest of end-users, but also of governments. This is because bio-LNG provides energy security, reducing dependency on any other nation's gas supplies. Bio-LNG can be produced locally, anywhere where waste feedstocks are available. At a time of geopolitical instability, the independence and resilience that lots of smaller suppliers can offer is a powerful incentive to invest. Gas prices have been very volatile since the start of this decade. Do you see this as a limiting factor to LNG and bio-LNG bunkering growth? While price fluctuations are a consideration, they do not fundamentally limit growth. LNG and bio-LNG remain cost-competitive compared with other alternative fuels. As LNG and bio-LNG are produced differently, factors that affect the price of one will not necessarily affect the other. To mitigate against market volatility, building in optionality is key. Shipowners and operators have this through their dual-fuel engines, switching to fuel oil if needed. Our bunkering assets are similarly flexible. Using our specialist skill set, we are also open to delivering any fuel that can substantially decarbonise shipping, which will further diversify our operations and build resilience. By Martin Senior and Natalia Coelho Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

LNG imports feasible, New Zealand utilities say

10/07/25

LNG imports feasible, New Zealand utilities say

Sydney, 10 July (Argus) — Importing LNG to cover New Zealand's shortfall of gas is technically feasible but more challenging than expected, according to two new reports commissioned by five energy companies. Conventional-scale LNG imports would help meet power demand in years when hydroelectric inflows are low, but the total cost to end users is estimated at NZ$170-210mn/yr ($102-126mn/yr) including costs of $10.12-10.37/MMBtu on a landed basis — or approximately NZ$17.83-18.27/GJ, based on a forward exchange rate of NZ$1.67:$1 — according to reports sponsored by New Zealand utilities Clarus, Contact Energy, Genesis Energy, Meridian Energy, and Mercury. Major works to establish infrastructure such as port or pipeline upgrades have been estimated at NZ$190mn-1bn, a level of investment that holds risks given uncertainty about the country's future energy mix and need for imports. Smaller-scale options using existing ports and involving imports from Australia via 15,000m³ vessels could provide an additional 7-10 PJ/yr (187mn-267mn m³/yr) or about one month's supply, but this could cost 25pc more than the large-scale option at about $11.41-11.92/MMBtu, or NZ$20.10-21/GJ . Smaller-scale LNG infrastructure capital costs could be NZ$140mn-295mn, but securing offtake and a solution for storing imported LNG would need to be finalised first, the study said. New Zealand's gas supply has plummeted after years of underinvestment in the Taranaki basin, the country's main source. Just 25.93PJ was produced in January-March, down by 19pc on the year, according to government data. High prices are impacting the production of fertilizers and other industries . Wellington is looking to lure upstream producers via a NZ$200mn co-investment to buy stakes in new gas fields, while also working towards potential LNG import plans . By Tom Major Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

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Algeria unveils encouraging bid round results

Competitive advantage

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Q&A: Titan on the future of LNG and bio-LNG bunkering

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