Energy Transfer to supply gas to planned data center

: Electricity, Natural gas
25/02/10

US energy infrastructure company Energy Transfer has reached a long-term agreement to supply natural gas to an artificial intelligence data center in central Texas.

Under that agreement — Energy Transfer's first direct supply contract with a data center — the company will provide about 450mn cf/d (13mn m³/d) to Denver, Colorado-based CloudBurst Data Center's planned data center campus near San Marcos, Texas, for at least 10 years.

That deal is contingent on CloudBurst reaching a final investment decision, which is expected later this year. The data center is scheduled to begin operations in the third quarter of 2026, Energy Transfer said.

New energy-intensive data centers that run artificial intelligence software will be a key source of power demand growth in the coming years. Data centers were forecast to drive power demand in the commercial sector 2pc higher this year and lead to another 2pc increase in 2026, according to the US Energy Information Administration.

Those additional power needs could lift gas demand by 3 Bcf/d or more by the end of this decade, according to some analyst estimates.

Energy Transfer will provide the gas via the Oasis pipeline, a 1.2 Bcf/d line that connects gas supplies from the Permian basin of west Texas to demand centers on the Texas coast. That supply will be used to generate 1.2GW of power exclusively for the data center.

Energy Transfer is in talks to supply other data centers along its network of natural gas pipelines. It expects the CloudBurst agreement to be "the first of many," the company said.

By Jason Womack

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25/03/13

Lower Rio Tinto Al output cuts New Zealand power demand

Sydney, 13 March (Argus) — New Zealand's industrial electricity demand fell on the year in October-December 2024, after Rio Tinto cut production at its Tiwai Point aluminium smelter in the previous quarter. The country's industrial electricity demand was down by 9pc compared with a year earlier, data from the Ministry of Business, Innovation, and Employment show ( see table ). Rio Tinto cut production at Tiwai Point in late-July 2024, after New Zealand utility Meridian Energy requested that it reduce its energy use by 205 MW. Many of the plant's potlines remained off line until late-September 2024, when Rio Tinto began restarting production at a reduced level. The Tiwai Point Aluminium Smelter is New Zealand's largest industrial energy user, consuming 572MW of power, often accounting for 12-13pc of national electricity demand, according to New Zealand's Electricity Authority. But it only accounted for about 10pc of total demand in October-December because of its lower production level. Rio Tinto's decreased power use and the country's rising geothermal generation in October-December pushed New Zealand's coal- and gas-fired generation to their lowest levels since late-2022. Utilities produced 2.1PJ from coal- and gas-fired generation, down by 73pc on the quarter and by 42pc on the year ( see table ). Coal- and gas-fired plants accounted for just 6pc of total generation in the fourth quarter of 2024, down from 19pc in July-September and 10pc a year earlier. Meanwhile, New Zealand's renewable power generation grew in importance over October-December, even as the government continued taking steps to promote coal- and gas-fired generation. The share of renewable electricity rose to 94.3pc, the highest level since December 2022 and the fourth highest on record. The New Zealand government is eager to promote oil, gas and petroleum generation, resources minister Shane Jones told Argus in December 2024. New Zealand's government has rolled back a ban on offshore gas exploration and has been fast-tracking coal developments since taking office in 2023. The country's largest utility, Meridian Energy, also warned of a structural gas shortage in late February, calling for new gas exploration. By Avinash Govind New Zealand Energy Quarterly Oct-Dec '24 Jul-Sep '24 Oct-Dec '23 q-o-q ± % y-o-y ± % Electricity Consumption (PJ) Industrial 11.0 10.1 12.1 8.7 -9.0 Total 33.7 38.1 35.2 -11.4 -4.3 Electricity Production (PJ) Coal 0.5 3.2 1.3 -84.9 -64.2 Gas 1.7 4.6 2.4 -63.8 -29.8 Geothermal 7.6 8.5 7.1 -10.9 6.6 Total 37.7 41.5 38.2 -9.3 -1.4 Source: Ministry of Business, Innovation, and Employment (MBIE) Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

US gas producers gear up for return to growth

25/03/12

US gas producers gear up for return to growth

Firms have changed their tune since the start of the winter, as weather-related factors have increased the appeal of boosting output, writes Julian Hast New York, 12 March (Argus) — Some large US natural gas-focused producers plan to boost their output in the coming years, in response to higher prices and booming US LNG export capacity. This would reverse a years-long trend among US producers of holding output steady to avoid oversupply, which drags down prices. The largest producer of US gas by volume, Expand Energy, aims to lift production by 3.4pc from last year to 7.1bn ft³/d (201mn m³/d) in 2025 and to boost drilling to bring on line 300mn ft³/d of sidelined production capacity that could hit the market in 2026. Fellow US gas producer Comstock Resources plans to add drilling rigs in the Haynesville shale of east Texas and northern Louisiana this year in a bid to offset output declines triggered by low prices in 2024 and bring new output on line when needed. US firm Range Resources, which operates in the Appalachian region, expects to boost production by 19pc from 2024 to 2.6bn ft³/d by 2027, with most of this growth set to take place in 2026-27, when the majority of the planned new LNG export terminals on the US Gulf coast are slated to begin operations. Range's sharp upward growth trajectory represents a break from its recent past, given that its 2024 output was just 2.5pc higher than in 2020. US gas producers appear poised to raise output by about 2bn ft³/d combined over the next 12-24 months, to refill inventories that have been depleted by a cold 2024-25 winter season and to keep up with booming LNG exports, according to investment bank RBC Capital Markets. But if every US gas producer grows at same the rate that Range Resources envisages, "the macro backdrop could quickly deteriorate", US bank Tudor Pickering Holt said in a note to clients last month. US gas inventories were at an 80bn ft³ deficit to the five-year average at the end of February, compared with a 215bn ft³ surplus on 1 November, according to US government agency the EIA. US gas prices now have now climbed above the marginal breakeven price of the industry, Expand Energy chief executive Nick Dell'Osso says, putting the US breakeven US gas price at about $3.50/mn Btu. This means "supply will ultimately show up and compete", he says. Expand Energy and fellow US producer EQT, which made the same estimation of the industry breakeven price early last year, say their own breakeven figures are lower because of their ample acreage in the Marcellus and Utica shale formations of Pennsylvania, Ohio and West Virginia, where production costs are lower. Nymex gas futures prices at the US benchmark Henry Hub in Louisiana for delivery in 2026 settled at $4.38/mn Btu on 7 March, up from $3.91/mn Btu at the start of this year. Fair-weather friend The recent growth plans of US producers stand in contrast with many producers' reluctance to boost output earlier this winter, in response to weather-driven shifts in supply and demand. "You don't want to grow for a season" but rather "grow for something that is durable over several years", Dell'Osso said in January. And the production plans of gas-focused firms may end up being overshadowed by those of crude-focused players in the Permian basin of west Texas and southeast New Mexico. These are set to remain the main drivers of production growth in the coming months, thanks to new gas pipeline infrastructure connecting associated gas supply to end markets near the US Gulf coast. Total US marketed gas production is forecast to increase to 114.7bn ft³/d this year and 117.9bn ft³/d in 2026, from 113.1bn ft³/d in 2024, the EIA says. Permian basin output is expected to account for 75pc, or 3.6bn ft³/d, of the additional production by 2026, with output from the basin increasing by 7pc/yr in 2025-26. This would be slower than the 14pc/yr recorded in 2022-24 but would still make it the US' fastest-growing production area. Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Brazil's Marquise Ambiental invests in 6 RNG plants

25/03/12

Brazil's Marquise Ambiental invests in 6 RNG plants

Sao Paulo, 12 March (Argus) — Brazilian landfill company Marquise Ambiental will invest R400mn ($68mn) in six biogas plants with an estimated total output of around 40.8mn m³/yr. The six plants will be in southeastern Sao Paulo state, northeastern Ceara and Rio Grande do Norte states, and northern Rondonia and Amazonas states, the company said. The Amazonas state plant, in the capital Manaus, is set to produce up to 18mn m³/yr of biogas and should prevent 300,000 metric tonnes (t) of CO2 equivalent (CO2e) from being released into the atmosphere. The Sao Paulo plant is forecast to produce 4.6mn m³/yr, while the Ceara plant is set to produce 2.8mn m³/yr. Meanwhile, the Rio Grande do Norte state plants, Braseco and Potiguar, are forecast to have output of 9mn m³/yr and 4mn m³/yr, respectively. The Rondonia plant is set to have an output of 2.1mn m³/yr, according to the company. The investment will happen in the next three years, but the company did not disclose when operations at each plant will begin. Marquise Ambiental has one 36.5mn m³/yr plant operating in Ceara , dubbed GNR Fortaleza. It is a joint venture between the firm and gas company Ecometano. By Maria Frazatto Planned Marquise biogas plants m³/yr Name State Capacity Osasco Sao Paulo 4,687,000 Braseco Rio Grande do Norte 9,007,000 Potiguar Rio Grande do Norte 4,097,000 Aquiraz Ceara 2,853,000 Manaus Amazonas 18,092,000 Porto Velho Rondonia 2,160,000 Total 40,896,000 Marquise Ambiental Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Low gas storage bookings may drive German stockdraw

25/03/12

Low gas storage bookings may drive German stockdraw

London, 12 March (Argus) — Low gas storage bookings for gas year 2025-26 may already be driving withdrawals and may continue to do so in the coming months. German stocks were at about 79.8TWh on Tuesday morning, filling 31.8pc of capacity. That was well below the 131TWh three-year average for this date and the 171TWh in storage a year earlier. Stronger withdrawals this winter were at least partly driven by higher heating demand as well as slower European imports of LNG and Russian pipeline gas compared with a year earlier. But market dynamics for upcoming storage years may also be encouraging withdrawals. A backwardated forward curve, with prompt prices holding substantially higher than contracts in winter 2025-26 and further along the curve, has incentivised the stockdraw over maintaining stocks. That said, prices for the summer quarters have risen above the prompt recently, so some firms could have a slight incentive to keep gas in storage past the end of this storage year. But the inverted THE summer-winter spread has disincentivised capacity bookings for the upcoming storage year. Summer prices holding above winter prices removes the commercial incentive to inject or book storage space profitably. And storage operators have struggled to sell space in recent months, with many auctions closing unsuccessfully as bidders cannot profitably hedge injections for the contract period. In the prevailing environment, only about 55pc of all German storage space has been booked for the 2025-26 storage year, leaving at least 103.5TWh of capacity unallocated, data show ( see data and download ). By contrast, firms had booked 99.7pc of German capacity for the 2024-25 storage year. Storage sites with low or no bookings might be driving withdrawals, as firms near the end of some storage contracts. At sites where some capacity is booked for the next storage year, firms could sell their stocks to other capacity holders if there is no financial incentive for withdrawing it. But at the six sites with no 2025-26 bookings yet — Rehden, Wolfersberg, Harsefeld, Frankenthal, the VNG-operated Jemgum caverns and SEFE's Speicherzone Nord — firms cannot sell gas in-store as there are no available buyers to transfer gas-in-store to, incentivising firms to empty stocks ahead of the summer 2025 filling season. Consequently, sites with no booked capacity for the upcoming storage year currently are filled less than most other German sites ( see graph ). The remaining sites suggests a correlation between 2025-26 bookings and stocks, as sites with a lower proportion of capacity booked for the next storage year tend to be less full, following stronger withdrawals this winter ( see withdrawals trajectory graph ). Stock dilemma Before the 2024-25 storage year ends on 31 March, any capacity holder left with stocks must decide either to withdraw that gas or sell it to a company holding 2025-26 capacity, if there is sufficient storage space booked at the individual site. Barring additional capacity sales, that suggests that about 7TWh may need to be withdrawn on contractual grounds alone, not accounting for weather or withdrawals from fully-booked sites. About 5.6TWh of that is stored at Rehden, Germany's largest storage site, whose operator SEFE Storage allows capacity holders to withdraw 10pc of their stocks up to two months after the storage year ends . Rehden was filled to 12.1pc of capacity on Tuesday morning, leaving about 1TWh to be withdrawn even if all capacity holders utilise that 10pc allowance. Four of the six sites with no 2025-26 bookings are depleted fields or aquifers, which have lower withdrawal and injection rates than salt caverns and offer capacity holders less flexibility to react to unusual price spreads. Caverns often offer faster injection and withdrawal speeds, so could still be used economically in summer by, for example, reacting to price volatility rather than seasonal spreads. Faster cycling also allows cavern capacity holders to wait longer before starting pre-winter injections, potentially allowing them to wait until the summer-winter spread normalises before injecting. Slower-cycling sites such as aquifers and depleted fields are usually drawn down more consistently in winter as their slower injections and withdrawals reduce their flexibility. That said, some operators might need to inject into caverns to maintain their structural integrity. This might stop withdrawals or possibly support a minimum of injections ahead of or early in the filling season. German storage operator Uniper Energy Storage bought some gas to store as de-facto cushion gas at its Etzel EGL and Etzel ESE sites last week to comply with German law. Restrictions on minimum pressure are enforced by mining authorities and can differ by site, storage operators have told Argus . By Lucas Waelbroeck Boix and Till Stehr Storage bookings next year vs current fill level % Fill level trajectories grouped by site type % Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

US gas CEOs declare victory over energy transition

25/03/12

US gas CEOs declare victory over energy transition

Houston, 12 March (Argus) — The energy industry is finally recognizing that more renewable resources will not deter demand growth for natural gas anytime soon, the chief executives of major US natural gas and LNG producers said today. Two years ago, renewables were the principle talking point of the energy industry, said Michael Smith, chief executive of Freeport LNG, at the CERAWeek by S&P Global conference in Houston, Texas. "That has completely changed," Smith said. "There is a recognition within the industry that the energy transition is not going to be using natural gas just as a bridge fuel." That recognition comes from growing overseas demand for US LNG, the desire by countries to convert coal-fired power generation to gas-fired generation, and more recently, booming power demand by planned data centers to run artificial intelligence software, said Toby Rice, chief executive of EQT, the second-largest US gas producer by volume. But despite growing demand, environmental and local opposition to the construction of new US interstate gas pipelines poses a challenge to the industry's ability to produce and transport enough gas to fulfill that demand, Rice said. "The biggest challenge that's facing our industry is this pipeline cancellation movement," Rice said. Construction of interstate gas pipelines in the US has become difficult in recent years as environmentalists and landowners pressure state governments to withhold air and water quality permits needed for those projects. Rice's controversial 2 Bcf/d (57mn m³/d) Mountain Valley Pipeline (MVP), which connects gas fields in West Virginia with markets 300 miles away in Virginia, is the only major greenfield interstate gas pipeline project in the eastern US that has overcome legal opposition in recent years. It was allowed to bypass federal permitting hurdles through an agreement in 2023 between former President Joe Biden and Republicans to raise the limit on the federal debt, provoking outrage from environmental groups and some Democrats. The pipeline began service in June 2024, six years behind schedule and with a price tag of $7.85bn, compared to an original estimate of $3.5bn. MVP "is a piece of infrastructure that they said was not needed", even though the pipeline was operating at maximum capacity this winter, Rice said. "Everybody should be incredibly concerned that it takes an act of Congress to get a pipeline built in this country." By Julian Hast Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

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