Speak to a specialist

Register and we will customize a solution that meets your exact needs. When you speak to one of our experts, you may be qualified to sample our industry-leading products on a no-cost basis.

You can unsubscribe from these updates at any time. We manage your personal data in accordance with our privacy policy.
Generic Hero BannerGeneric Hero Banner
Latest market news

Brazil estimates gas-fired operating costs, spending

  • Market: Electricity, LPG, Natural gas
  • 07/03/22

Brazil expects its natural gas-fired power plants will have operating costs between R215-600/MWh ($42.36-118.21/MWh) for the next 10 years.

The country's 10-year plan for the energy sector, PDE 2031, sets expected operating costs (CVU) depending on factors such as plant flexibility and energy cycles utilized.

State-run energy research bureau Epe, which helps the government plan for power auctions, publishes a preliminary version of the plan each year. Epe estimates a R215/MWh CVU for natural gas at completely inflexible thermal plants, a R259/MWh CVU for natural gas utilized at plants with 30pc inflexibility and a R600/MWh CVU for natural gas burned by simple cycle thermal plants. A plant's flexibility is the level of contractual obligation to generate energy, or the amount of power that must be dispatched regardless of the cost for the system.

The PDE 2031 also sets the estimated CVU for LNG at R385/MWh for completely flexible plants and at R303/MWh for plants with 30pc inflexibility.

Epe's calculations are based on 2021 Henry Hub prices.

The document also foresees increases in capital expenditure related to natural gas, compared with the previous year's estimates. The PDE 2031 sets the expected spending for simple cycle natural gas at R3,600/kW, a 5.9pc increase, and at R5,300/kW for combined cycle natural gas, a 3.9pc growth. LNG capital expenditure is estimated at R4,300/kW, up by 4.9pc compared with the previous year, and sugarcane-sourced biogas' spending was set at R8,000/kW, a 6.7pc increase.

By Rebecca Gompertz

Sharelinkedin-sharetwitter-sharefacebook-shareemail-share

Related news posts

Argus illuminates the markets by putting a lens on the areas that matter most to you. The market news and commentary we publish reveals vital insights that enable you to make stronger, well-informed decisions. Explore a selection of news stories related to this one.

News
18/12/25

Ithaca first to try new UK North Sea regime

Ithaca first to try new UK North Sea regime

London, 18 December (Argus) — UK-listed upstream producer Ithaca Energy has begun the approval process for a development in the North Sea, the first since the government softened its approach to the region. Ithaca has submitted a development summary and environmental statement for the Fotla field to the offshore regulator Opred. It outlines a two-well tie-back to the Britannia platform, which processes liquids from the Greater Britannia Area, including Ithaca's Alder field. Ithaca indicates that if the process is successful, drilling will begin in the first half of 2027, with first oil in the final quarter of that year. This is the first submission of an offshore proposal since the UK government published its 'North Sea Future Plan' alongside its budget in late November. That enables "limited oil and gas production in areas that are already part of an existing field, or in areas adjacent to already licensed fields, linked via a tieback, to help ensure they remain economically viable". Developers are not permitted to explore for oil and gas at these sites, and a ban remains on new oil and gas licensing. London's stance on North Sea development has delayed the Rosebank project, in which Ithaca holds a 20pc stake, and the company's west of Shetland Cambo project. Ithaca expects its production to average 119,000-125,000 b/d of oil equivalent (boe/d) this year. By Ben Winkley Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Find out more
News

BP appoints Woodside’s O’Neill as next CEO

17/12/25
News
17/12/25

BP appoints Woodside’s O’Neill as next CEO

New York, 17 December (Argus) — BP appointed Woodside Energy chief executive officer Meg O'Neill as its next chief executive effective from next April. O'Neill will replace Murray Auchincloss, who has decided to step down on 18 December after more than three decades with the London-based oil major. O'Neill transformed Woodside into the biggest energy company listed on the Australian Securities Exchange after taking over as chief executive in 2021, according to BP. While at Woodside, she also oversaw the acquisition of BHP Petroleum International. O'Neill also spent more than two decades at ExxonMobil earlier in her career. "Her proven track record of driving transformation, growth, and disciplined capital allocation makes her the right leader for BP," said Albert Manifold, chairman of the company's board of directors. Carol Howle, executive vice president, supply, trading & shipping of BP, will serve as interim chief executive until O'Neill takes over. Auchincloss will also serve in an advisory role until December 2026 to ensure a smooth transition. BP scaled back ambitious low-carbon goals earlier this year with Auchincloss conceding that the company had been "optimistic for a fast [energy] transition but that optimism was misplaced." The company raised its 2030 target for oil and gas production as part of a "fundamental reset" of strategy that also entailed a cut in renewable energy investments. O'Neill's appointment follows a search process overseen by the board, with the help of an independent recruitment firm, as part of the company's long-term succession planning. By Stephen Cunningham Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

News

LNG supply growth outstrips carrier orderbook to 2030

17/12/25
News
17/12/25

LNG supply growth outstrips carrier orderbook to 2030

With the acceleration of scrapping of LNG carriers, the number of newbuilds is insufficient to keep pace with supply growth, writes Cerys Edwards London, 17 December (Argus) — The number of newbuild LNG carriers scheduled to deliver by 2030 will not be enough to transport the planned growth in global liquefaction capacity, particularly if the retirement of older vessels accelerates compared with recent years. But the balance in the freight market will depend heavily on the configuration of LNG trade flows over the rest of the decade. Some 234 newbuild LNG carriers are scheduled to be delivered over 2026-2030, according to data from the International Maritime Organisation (IMO), with deliveries in 2026 set to be the quickest year on record. Typically, around 1½ ships are needed to transport 1mn t of new liquefaction supply to Europe, and three ships for the equivalent journey to Asia, Capital Clean Energy Carriers chief executive Jerry Kalogiratos said at the World LNG Summit in Istanbul in December. Applying this basic assumption, the 234 newbuild carriers could transport some 158mn t/yr of new liquefaction capacity were the supply to deliver solely to Europe. But the newbuilds provide scope for just 78mn t/yr of new loading demand should the vessels deliver to Asia, which Kalogiratos considers the more probable scenario, given that buyers in southeast Asia are likely to consume more LNG in the forthcoming years. "There definitely looks like there is going to be a shortage", he says. Both scenarios indicate that the present LNG carrier orderbook is not large enough to accommodate the 229mn t/yr of new export capacity scheduled to come on line by 2030, judging by the projects that have already reached a final investment decision (FID). And the LNG carrier market could tighten further if more projects reach FID. Even the roughly 80mn t/yr of additional production capacity that was sanctioned this year are "not yet covered," according to David Colson, vice president at French engineering firm GTT, which supplies nearly all of the membrane containment systems used in LNG vessel tanks. The golden age of steam coming to an end? The LNG freight market balance over the coming years will also largely depend on the number of older vessels being scrapped, which rose sharply this year. A record 14 steam turbines have been sold for scrap so far in 2025, up from eight in the whole of 2024 and an average of five over 2020-24. And the pace of scrapping is likely to accelerate over the next few years, as vessels roll off long-term charter agreements, Kalogiratos says. Steam turbine carriers are "obsolete" as their high boil-off costs and smaller cargo capacity sizes do not provide the "flexibility that the current LNG trading environment requires", he added. There are 29 operational LNG carriers that are 25 years old or older, including the 137,000m³ Puteri Nilam and same-sized Al Jasra which have in recent months idled in the strait of Malacca and Bay of Brunei, according to shiptracking data from Kpler. The oldest LNG carrier still in operation is the 128,000m³ LNG Maleo , which was built in 1989 and is controlled by Indonesia's state-owned Pertamina. As well as these vessels, there are a further 47 built in 2000-2005, including 11 idling in either Malacca or Brunei Bay. These are likely to be retired by 2030, given the average age of the vessels sold for scrap in 2025 was 26, Norwegian shipping firm Flex LNG said in its third-quarter earnings call last month. Were all 76 vessels built before 2005 scrapped by 2030, it would limit the fleet growth to a total of just 158 LNG carriers. Under the scenario outlined above this number of vessels could transport 105mn t/yr of supply to Europe and just 53mn t/yr to Asia — both far below the planned capacity buildout. The LNG carrier orderbook could still grow in the coming years however, given slots for late 2028 delivery are still available at some South Korean shipyards. Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

News

UK government eyes gas market regulatory push in 2026

17/12/25
News
17/12/25

UK government eyes gas market regulatory push in 2026

Momentum is growing in the UK for regulatory changes aimed at reshaping the country's gas system, writes Isabel Valverde Sala London, 17 December (Argus) — Natural gas has climbed up the UK government agenda in recent months, with regulation processes unfolding and culminating in 2026 likely to be pivotal for the future of the UK gas market. The country's department for energy security and net zero (Desnz) launched a consultation in late November aimed at reviewing the UK's security of gas supply , including proposals aimed at ensuring infrastructure capacity, preparing the system for unplanned outages and ensuring a viable commercial model for the UK gas market. This is the latest of a series of consultations held by the ministry in recent months, with a view of gathering information and views from the market before laying down any proposals for market reforms. The government had first announced its intention to address the challenges facing the country's gas system in a policy paper published in June, which minister of state for energy Michael Shanks described as "the first major publication on the gas system in many years". The document sets three core objectives for the coming years — preserving energy security in a context of declining production, ensuring continued investment in infrastructure, and managing a sustainable transition of the gas network "towards other uses in a context of declining production", the paper says. Market participants can send their comments to the latest consultation until 18 February, and Desnz intends to publish a response to the feedback in the spring of 2026. The ministry is also set to launch a call for evidence on network investment and affordability before the end of this year as part of this programme. And next year, the department plans to issue another call for evidence on transitioning the gas network, according to the market update. Separately, an ongoing parliamentary enquiry is at present gathering views from market participants on how to manage a declining gas domestic market. Overall gas consumption across the UK has fallen at an average 8pc rate over the past three years, figures from system operator National Gas show. The call for evidence closes on 7 January and could eventually lead the Energy Security and Net Zero Committee to put forward its own proposals for debate in Parliament. Small steps to move faster The update to the market was the "first step in a long-term programme" aimed at transforming the country's gas system, and it may take years until the initiative turns into policy. But other government measures — including the North Sea Future Plan — may begin influencing the market sooner. The plan, published as part of the government's 2025 budget, announced a new system of "transitional energy certificates" to encourage firms to produce gas from areas adjacent to operating fields as a means to maximise output from tapped-in resources. This would enable faster production compared with traditional licences, according to the government. And ongoing efforts by the North Sea Transition Authority (NSTA) to retrieve as much gas as possible from active wells could slow down the decline in domestic gas production. The NSTA expects UK gas production to halve by 2030, compared with 2025 levels. The authority has worked with different well operators since 2024 to identify and reactivate shut-in wells, and it will continue to do so by engaging with new companies in the forthcoming months, it said in November. After years in the making, UK energy market regulator Ofgem is also set to complete a regulatory impact assessment on the introduction of a single tariff for all entry and exit points into the country's gas grid by the first quarter of 2026, with the aim of making the UK a more attractive hub for gas transiting to Europe — particularly LNG supplies. If approved, the new tariff system could be implemented before the beginning of the 2026-27 gas year. On the demand side, the government's £15bn ($20bn) warm homes plan is poised to add to the downward trend in gas demand by supporting households in implementing energy-efficiency measures. These include the extension of the boiler upgrade scheme (BUS) until the financial year 2029-30, and further funding for home insulation and solar panel installations, among other measures. The publication of the plan has been delayed to January from an expected release in December, Desnz told Argus on 15 December. Regulatory changes affecting the power grid will also have an important impact on gas demand. UK power grid operator Neso earlier this month confirmed a major reordering of the country's electricity grid connection queue to speed up renewable energy projects and connection from demand sites. A quicker and easier access to the grid could incentivise operators of data centres, which are poised to be one of the most important drivers of electricity demand in the coming years, to connect to the electricity grid instead of building on-site gas-fired plants . But even if that was the case, a large part of that electricity could still come from gas even if renewables and storage are deployed in line with expectations. In July, energy minister Ed Miliband asked Neso in a letter to keep 40.1GW of power generation in the country's capacity market by 2029-30 to assure energy security on days of limited renewable generation, a decision that clearly favours investment in flexible gas-fired generation. The Labour government has not disclosed specific targets on new gas-fired generation capacity. The Conservative government, in charge until last year, had said that the country needed to build a minimum of 5GW of new gas-fired capacity to partly offset the 15GW gas-fired capacity closures in the coming years — a third of the total fleet of 34.5GW in operation. Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

News

Viewpoint: French power in slump

17/12/25
News
17/12/25

Viewpoint: French power in slump

London, 17 December (Argus) — France enters 2026 with power prices in a slump, as stagnant demand meets strong nuclear availability and ever-increasing renewables output. Forward prices are well below spot delivery in recent years, with the Cal-26 contract assessed at €49.75/MWh on Tuesday, compared with spot delivery of about €60/MWh in 2024 and 2025. Lower gas prices explain some of the low forward prices, as does increased renewables capacity, but French hydro reserves are well below previous years, and EdF expects to produce less nuclear power year on year because of further planned long maintenance shutdowns. If low spot delivery confirms that these forward prices were correct as to how fundamentals would play out, it could limit any potential for upside risk. And the course of any potential demand recovery over the next few years will determine whether the contango shape of the French forward years is justified by fundamentals. The French yearly contracts are unusual with Europe being in contango, rising out to the end of the decade, compared with most other countries which are in backwardation. Fundamentals arguments put forward to explain this include expectations of increased interconnection to more expensive markets, or an uptick in demand, especially from industry and data centres. But demand has remained stubbornly flat over recent years. Industrial, data centre and hydrogen projects with a total demand of 30GW have grid capacity reserved for them. If all of these projects came to light and used their full capacity, demand would leap by 180TWh by 2030, or about 40pc. Not all of these projects will be built, and those that are will not use their full capacity all the time. Grid operator RTE's high estimate is for 60pc of projects to be completed, which will then use only 20-60pc of their grid capacity. But even if only some of them are built, this could push demand growth to 1-3pc/yr. RTE's low estimate for the incremental demand from these projects by 2030, as well as additional electric vehicles, comes to 2.7GW, while its high estimate is for 6.3GW of incremental demand. A rapid increase in demand could outpace supply gains from the several GW/yr of solar capacity likely to come on line in the coming years, mechanically tightening France's balance, if it is met and there is not a fall in demand from other sectors. France may be reaching a crunch point on renewables. The ambition of governments of recent years to advance on renewables and nuclear has hit the buffers, as the lack of any demand growth removes justification for increasing capacity. Low market prices are an indication that France does not particularly need any extra renewables capacity in the short term. Capture rates for solar have fallen year on year, while lower market prices mean the bill for public subsidy for renewables grows ever higher. Some increases are locked in over the next few years, but appetite may be lacking to continue growth beyond that. And political obstacles could make a low-renewables strategy easier. Right-wing parties are firmly opposed to renewables, and the government relies on their tacit support to remain in office. The government intends to publish the PPE3 10-year energy strategy by the end of the year, which in this draft includes cuts to renewables targets, it has said. The other big dossier of French energy is the new nuclear programme. EdF has already started preparatory works to build two 1.6GW reactors at Penly, and plans to build a further four, with eight more on the drawing board. But the experience of the Flamanville 3 reactor — entering service more than a decade late and many billions over budget — could make any government hesitate before offering EdF funding for more reactors. This is all the more true if prices remain low in the coming years, which would cut EdF's ability to fund large investments and require more government support. The mooted €100/MWh price point of the new nuclear, more than twice the current market price, is a further impediment. And the programme is not expected to come into service until the late 2030s at the earliest, meaning a government which holds fire can spare itself large costs without incurring any power shortage during its term in office. By Rhys Talbot Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Related Products

Argus Carbon

Argus Carbon

Carbon price benchmarks, policy and project news, and deep analysis, on a daily basis.
Find out more

Argus Low Carbon Hydrogen Strategy Report

Argus Low Carbon Hydrogen Strategy Report

Part Three: Americas. An in-depth analysis of the key sectors, countries and policies enabling hydrogen growth. 
Find out more

Argus Hydrogen and Future Fuels

Costs, prices, news and analysis for the hydrogen and P2X sectors

Find out more

Argus Russian Generation Fuels and Power

Independent analysis, trusted benchmarks, and data analytics to help manage margins and risks for coal markets.
Find out more

Argus LNG Daily

Access the latest LNG spot price assessments, market news and independent analysis.
Find out more
Generic Hero Banner

Business intelligence reports

Get concise, trustworthy and unbiased analysis of the latest trends and developments in oil and energy markets. These reports are specially created for decision makers who don’t have time to track markets day-by-day, minute-by-minute.

Learn more