CenterPoint upgrades grid to serve Freeport LNG

Market: Coal, Electricity, Natural gas
24/02/15

Electricity transmission and distribution company CenterPoint Energy will spend $80mn to upgrade the coastal Texas transmission grid to supply 656MW of electricity to the Freeport LNG export project on Quintana Island about 70 miles (113km) southwest of Houston.

CenterPoint Energy will build a new 345kV Jones Creek substation and upgrade and reconfigure the 138kV network in the Freeport area by mid-2017 to meet sizable new load from the LNG export facility expected to start service in 2018.

The 656MW increase in power demand from the facility is the equivalent of the projected load growth for all of New England in the next three years. The projected load equals the consumption of 328,000 new Texas homes during mild weather.

While other proposed LNG export projects plan to use pipeline gas to fuel on-site operations, a majority of the power needed to supply Freeport LNG will come from the power grid to comply with Houston-area emission restrictions.

GE Oil & Gas is supplying electric-drive compressors and six, 75MW motors, along with other electric equipment for two of the project's liquefaction trains.

The board of the Electric Reliability Council of Texas (ERCOT) endorsed the plan earlier this month without discussion.

Freeport LNG started construction for two initial liquefaction and loading facilities in late November. Freeport said the first of three export trains from the $14bn facility will be on line in September 2018, with more trains following five and 10 months later.

The export terminal also will require 146MW to serve a gas pre-treatment facility off Quintana Island. About 82MW of that will be self-supplied.

Round-the-clock Houston power assessments average $36/MWh for Calendar 2018, a 10pc increase from 2016. Spark spreads at the Houston hub in the same period increase by 4pc.

More infrastructure and generation may be needed along the Gulf coast to serve industrial demand from LNG facilities and chemical manufacturers seeking to take advantage of soaring US natural gas production from shale formations.

CenterPoint officials said new load created by Freeport LNG underscores a need for investment in a new 345kV line, called the Houston Import Project, to move additional power from north Texas to the Houston area.

NRG Energy and Calpine, two of the state's largest power producers with generation in Houston, oppose the $590mn transmission line project, which has also been supported by ERCOT.

The US Department of Energy has authorized Freeport LNG to export up to 13.2mn t/yr of LNG, equivalent to 1.8 Bcf/d (51mn m³/d) of gas, to all international markets.

Freeport expects to export more gas to customers in countries that have free trade agreements with the US, including South Korean utility SK E&S. The 2.2mn t/yr of capacity owned by SK E&S could be exported under a license valid only for export to countries that have preferential trade terms with the US in natural gas trade, for total exports of 15.4mn t/yr.

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16/04/25

Japan to develop geothermal power under net zero plan

Osaka, 16 April (Argus) — The Japanese government is gearing up to develop geothermal energy, as the clean power can help to decarbonise the power sector with stable output, unlike weather-dependent renewables such as solar and wind. The trade and industry ministry Meti on 14 April launched a public-private council to discuss the development of next-generation geothermal energy, aiming to formulate a draft guideline, including capacity and cost targets, by around October this year. The new technology could lift the country's potential geothermal capacity to at least 77GW, compared with 23.5GW based on conventional methods, according to the council. The draft plan aims to establish the next-generation geothermal technology as early as the 2030s, to expand the use of the clean energy with competitive prices toward 2040, while tacking geological challenges, such as fault and complex geology, in Japan. Should the next-generation technology, such as closed-loop and supercritical geothermal, prove practical, Japan could utilise its potential, said Meti minister Yoji Muto on 15 April. Japan could consider exporting the next-generation technology globally, as it has around 70pc global share in conventional geothermal turbines, he added. The geothermal strategy is in line with the country's new strategic energy plan (SEP) , which was published in February, as well as prime minister Shigeru Ishiba's push to develop geothermal capacity. Ishiba had focused on less-utilised and high potential geothermal, as well as micro-hydropower, during his [campaign for the ruling Liberal Democratic Party presidential election](https://direct.argusmedia.com/newsandanalysis/article/2608517) last year. The SEP assumes geothermal will account for 1-2pc of Japan's power mix in the April 2040-March 2041 fiscal year, which is relatively marginal compared with other renewables such as solar at 23-29pc, wind at 4-8pc, hydroelectric at 8-10pc and biomass at 5-6pc. But even the small share would be much higher compared with its actual share of 0.3pc of total power generation in 2023-24. Diversification of renewable power sources would be necessary to achieve Japan's plan to reduce its greenhouse gas emissions by 60pc in 2035-36 and by 73pc in 2040-41, respectively, against the 2013-14 level, before achieving its net zero goal in 2050. Under the SEP, Tokyo aims to reduce its dependence on thermal power to 30-40pc in 2040-41 from 71pc in 2024. Japanese private firms are already involved in further developing domestic and overseas geothermal projects. Japanese utility Hokkaido Electric Power and construction firm Obayashi said on 16 April that they will study potential geothermal resources in Hokkaido during April 2025-February 2026, taking advantage of subsidies provided by state-owned energy agency Jogmec. Japanese battery maker Panasonic Energy said on 8 April that it has signed a power purchase agreement with regional utility Kyushu Electric Power's renewable arm Kyushu Mirai Energy to secure around 50GWh/yr of geothermal-based electricity from 1 April. The stable geothermal supplies, unaffected by weather, could double a renewable ratio in its domestic power consumption to around 30pc, Panasonic said. By Motoko Hasegawa Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

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Dozens of US coal plants eligible for MATS extension

15/04/25

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15/04/25

Dozens of US coal plants eligible for MATS extension

Cheyenne, 15 April (Argus) — The White House has identified more than 60 fossil fuel-fired power plants that will have two extra years to comply with the more stringent mercury and air toxics standards (MATS) finalized in 2024. Under a proclamation signed by US president Donald Trump last week, the plants on the list will be able to operate under whatever existing mercury and air toxics standards they currently are subject to until 8 July 2029. That is two years after the compliance deadline put in place in May 2024. The Environmental Protection Agency (EPA) rules finalized last year tightened mercury and air toxics standards for coal- and oil-fired units by 67pc, included new emissions-monitoring requirements and added standards for lignite-fired coal plants that put them in line with those for other coal plants. EPA in March said it was reviewing the new standards and said companies could seek exemptions to the mercury rule and other emissions rules. Trump followed that up last week with a proclamation that certain generating facilities would be given a two-year exemption in complying with the 2024 rule. The White House released the list of exempt power plants late on 14 April. Most of the plants on the list are coal-fired generators, some of which were scheduled for retirement by the end of 2027. These include Tennessee Valley Authority's Kingston plant and one unit of its Cumberland plant, as well as Vistra Energy's Kincaid, Baldwin and Newton plants and two coal units of Vistra's Miami Fort plant. The two coal units at Southern Company's Victor J Daniel plant in Mississippi also have been exempted from the new mercury and air toxics rules for two years. Southern had planned on retiring those units by the end of 2027, but in February, the Mississippi Public Service Commission approved two special contracts that were expected to need unit 2 of the Daniel plant and possibly a unit of a natural gas plant to run into the 2030s. Some other coal plant units owned by Southern, TVA and Vistra also are now exempt from the July 2027 mercury and air toxics compliance deadline. So are some plant units owned by East Kentucky Power Cooperative (EKPC), NRG, Ameren and Entergy. At least two natural gas plant units — unit 5 of Southern's Plant Barry and City Utilities of Springfield's John Twitty Energy Center, which has coal and natural gas generation — are exempt from the July 2027 deadline. So is unit 5 of Entergy's RS Nelson plant, which runs on petroleum coke. Essentially all of the other units in the White House's list are coal units, including Otter Tail Power's Big Stone and Coyote Station plants in North Dakota. Otter Tail said it had requested the exemptions "to avoid making unnecessary expenditures" if EPA decides to roll back the 2024 rule. EKPC said it was "grateful" its request to exempt the Spurlock and Cooper coal-fired power plants in Kentucky was granted and that the company "will continue to operate the plants in accordance with all market and environmental rules." NRG said it was still reviewing the order, but did not expect it to have any effect on its plans. TVA, Southern, Vistra and owners of other power plants given compliance extensions did not respond to requests for comment. By Courtney Schlisserman Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

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Australian coal methane emissions under-reported: Ember

15/04/25

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15/04/25

Australian coal methane emissions under-reported: Ember

London, 15 April (Argus) — Australian coal miners emitted 40pc more methane in 2020 than they reported, energy think-tank Ember said in a review of satellite data released today. The organisation, along with energy intelligence company Kayrros, analysed methane emissions from four mining "clusters" in Queensland in 2020, which account for roughly three fourths of the state's thermal coal and almost all of its coking coal production. The investigators found "a total of 1.42 ± 0.19 million tonnes of methane released from coal mines" in that year. Miners in the state reported 1.01mnt of methane emissions during the same period. The difference between reported and actual emissions was much larger in New South Wales, Ember said. "While the state reported 379,000t of methane in 2020, our satellite study identified 721,000t of methane that year, while only accounting for approximately 61pc of the state's coal production," the organisation said. If all coal mines in New South Wales followed the same trend, this would suggest total methane emissions of 1.2mn t, more than three times the figure producers reported to the government. Ember are not the only organisation criticising Australia's official numbers. Climate Trace and Open Methane, two organisations monitoring greenhouse gas emissions by satellite, suggest that Australian coal miners are only reporting half of their methane emissions. Academics supported by the UN Environment Programme (UNEP), writing in the American Chemical Society, published an article this year saying that trading company Glencore's Hail Creek mine was emitting four to five times more methane than it reported. Glencore sharply criticised the Hail Creek report, saying the study's aerial surveys lacked credibility because they were based on very limited samples and did not consider "inherent mining variability." The firm said that the report "failed to detect methane emissions" that it had reported itself. The producer, one of the country's largest, has repeatedly criticised satellite measures of methane emissions. The method, the firm said in a 2022 statement, is vulnerable to "atmospheric contaminants such as dust, water vapour or smoke" and cannot reliably detect the amount of greenhouse gases coming from mines. The Australian government launched a review of their methane reporting last year in light of the new satellite techniques used by researchers. The UK and EU are both planning a carbon tax on imported goods called the Carbon Border Adjustment Mechanism (CBAM) in the next two years. If either government were to accept Ember's figures, they could theoretically raise taxes on imported steel made with Australian coking coal. Neither government plans on taxing coal imports directly under CBAM. By Austin Barnes Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

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VG begins contracted LNG deliveries at Calcasieu Pass

15/04/25

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15/04/25

VG begins contracted LNG deliveries at Calcasieu Pass

Houston, 15 April (Argus) — US LNG exporter Venture Global began deliveries of long-term contractual cargoes at its 12.4mn t/yr Calcasieu Pass terminal in Louisiana today after the facility started commercial operations, more than three years after producing its first LNG. "We are excited to reach this milestone and are grateful for our regulators and supply chain partners who have worked with our team to reach commercial operations as efficiently and safely as possible," said Venture Global chief executive Mike Sabel. But the long-delayed and highly contested start comes amid ongoing arbitration proceedings against Venture Global, which some customers including Shell, BP, Italian utility Edison and Spanish company Repsol argue was unjustified in deferring the contracted supplies (see offtakers table) . The LNG exporter originally sought to begin commercial operations in 2022 but cited impacts from Covid-19, two hurricanes and "major unforeseen manufacturing issues" related to one of the plant's heat recovery steam generators, equipment that helps power the facility. Because several of the plant's facilities, including the power island, were not officially placed in service with federal authorization, Venture Global maintained that the plant was not commercially operating — despite producing 444 cargoes totaling 28.2mn t of LNG (about 1.28 trillion cubic feet of natural gas) since its first in March 2022, according to Vortexa data. The start-up Tuesday comes on the final day before Venture Global could have lost control of the project. The company said in a December filing with the US Securities and Exchange Commission (SEC) that the agreement under which it had financed debt requires commercial operations to be completed by 1 June 2025. Should commercial operations have not begun 45 days prior to this date — which is Tuesday — then the agreement defaults, allowing "certain investors" to exercise control over the project. Before Tuesday, the company instead sold cargoes on the spot market for prices much higher than the terms of its offtake agreements. Calcasieu Pass produced its first LNG in January 2022 and exported its first cargo on 1 March 2022 — less than a week after Russia, then a key supplier of gas to Europe, invaded Ukraine. The facility produced its first LNG just 29 months after reaching a final investment decision (FID) on the project, compared with the industry average of four to five years. The timing of the project's start dovetailed with the war-driven volatility in the European gas market, helping Venture Global realize much larger profits than it would have under contracted volumes. The firm's liquefaction fees in 2023 and 2024 averaged $12.23/mn Btu and $7.28/mn Btu, respectively, compared with the average $1.97/mn Btu in its long-term deals, according to a company presentation in March. The lengthy commissioning process generated $19.6bn in revenue by the end of September 2024, Venture Global said in the December SEC filing. Shell estimated that Venture Global sold cargoes in 2023 at an average of $48.8mn per shipment, "raking in billions of dollars while shirking its contractual obligations", according to a filing with US energy regulator FERC in March 2024. Venture Global said in March that the customer arbitration cases are not likely to be resolved until after 2025. LNG facilities usually produce commissioning cargoes for a few months before beginning long-term contracts. But Venture Global has said its unique plant design, which uses a higher number of smaller, modular liquefaction trains compared with traditional trains, requires a longer start-up process. Calcasieu Pass LNG consists of 18 trains paired in nine blocks, and a similarly long commissioning period is expected at the first two phases of Venture Global's 27.2mn t/yr Plaquemines facility consisting of 36 trains. The company also has plans for an 18.1mn t/yr expansion at Plaquemines. An FID is expected in mid-2027, with first LNG production 18-24 months later. Venture Global estimated that its third LNG facility, the 28mn t/yr CP2 facility adjacent to Calcasieu Pass, could export up to 550 commissioning cargoes . The company expects to make an investment decision on the first phase of CP2 this year. By Tray Swanson Calcasieu Pass offtake deals Offtaker Volume, mn t/yr Contract length, yrs Shell 2.0 20 Galp 1.0 20 Sinopec 1.0 3 CNOOC 0.5 5 Edison 1.0 20 Repsol 1.0 20 PGNiG 1.5 20 BP 2.0 20 — US DOE Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

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Indonesian coal producer Bukit Asam to raise 2025 capex

15/04/25

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15/04/25

Indonesian coal producer Bukit Asam to raise 2025 capex

Manila, 15 April (Argus) — Indonesian state-owned coal producer Bukit Asam has increased its 2025 capital expenditure (capex) plan from a year earlier, as it focuses on completing key projects to support its expansion plans. The company said it has earmarked 7.2 trillion Indonesian rupiah ($428mn) as the capital expenditure (capex) plan for this year, a more than three-fold increase from last year's Rp2.35 trillion. Bukit Asam will fund around 80pc of the capex via loans while the remainder will be from the company's own coffers. The company said that it is able to be more aggressive with loans since it has a healthy debt-to-equity ratio of 0.6. The bulk of the capex will be used for the completion of the Tanjung Enim-Kramasan coal railway system, a key infrastructure project to allow the company to increase its coal production. The commercial operation of the railway project will boost the company's transportation capacity by another 20mn t/yr of coal. Construction of the railway project started in 2023 with a target to operationalise the line in 2025, but the project ran into delays. Bukit Asam is now targeting to open the line by the third quarter of 2026. This will be in line with the company's long-term plan of boosting output to 100mn t/yr by 2030. Bukit Asam is also increasing investments in its downstream project, in line with the government's push to develop the downstream coal industry. It has already partnered with Indonesia's National Research and Innovation Agency to develop artificial graphite sheets using Bukit Asam's coal. The pilot project has seen moderate success, but improvements are still needed to reach economic feasibility. Additional funds would help to improve conductivity and density to reach international standards, with the goal of commercial operations by 2028. The project is important for Bukit Asam, as it sees an increase in usage for artificial graphite sheets, ahead with the rising popularity of electric vehicles that would make Li-ion battery parts manufacturing an attractive coal downstream avenue. By Antonio delos Reyes Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

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