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Bitcoin miners help US oil producers cut flaring

  • Market: Crude oil, Emissions, Natural gas
  • 08/10/21

US oil producers are turning to an unexpected source to help solve the environmental problem of excess natural gas — cryptocurrency miners.

On remote well pads dotted across the Bakken shale play of North Dakota and Montana, shipping container-sized data centers packed with computers power energy-intensive operations of Bitcoin miners. Their computers, running around the clock to earn crypto tokens by authenticating digital transactions, are powered by natural gas-fired generators, running on gas from the oil wells that would otherwise be flared on site.

Mining for virtual currencies has attracted widespread criticism — from environmental groups to tech entrepreneur Elon Musk — because it uses vast quantities of energy, more than some nations use in a year. That has led crypto miners to try and cut down on their energy use, or at least find ways to shrink their carbon footprint.

In the Bakken, they are able to capitalize on an abundance of surplus natural gas — a common byproduct of oil production — that would otherwise be burned off given a lack of pipeline infrastructure to take it to market. The environmentally harmful practice of flaring has come under intense scrutiny from regulators, climate campaigners and investors, including fund manager Blackrock.

Companies tapping surplus gas to run their cypto-mining computer banks see a double benefit — reducing the negative impacts of gas flaring and cutting their carbon footprint.

Denver-based Crusoe Energy operates 44 data centers in Montana, North Dakota, Wyoming and Colorado, and was due to deploy another 16 units by the end of September. Plans are afoot to start an initial project in the top oil producing Permian basin of Texas and New Mexico later this year before ramping up there in 2022.

"Our systems reduce greenhouse gas emissions by the equivalent of hundreds of thousands of cars in the process, primarily by reducing the amount of methane escaping into the atmosphere from incomplete combustion in flares," company president and co-founder Cully Cavness said.

Crusoe expected to reduce flaring in areas where it is operating by almost 10mn cf/d by the end of September. Its technology lowers CO2-equivalent emissions by as much as 63pc compared with continued flaring.

The company's digital flare mitigation system is also used to support other computing intensive processes, such as artificial intelligence.

The prices of crypto currencies including Bitcoin have fluctuated wildly this year with China banning all related transactions and mining. The Chinese crackdown "plays greatly into the advantage of US-based operators as it makes available hardware for domestic projects and increases the competitiveness of American operations," Cavness said.

Equinor, Devon among crypto-miner customers

Before divesting its Bakken acreage earlier this year, Norway's state-controlled Equinor was one of the producers that sold excess gas to Crusoe and provided the company with space on a well pad for its equipment. Other clients have included Devon Energy, private-equity backed Kraken Oil & Gas, and Canadian oil firm Enerplus.

North Dakota has had targets to curb flaring since 2014, with the industry spending billions trying to solve the problem. While flaring eliminates most methane — a potent greenhouse gas — the process still emits CO2. Flaring rose to 10pc of all gas produced in July, above the current 9pc limit allowed in North Dakota, due to several natural gas processing plants being offline.

As an incentive to curb the practice, North Dakota lawmakers passed legislation earlier this year that offered operators a tax credit for installing gas flaring mitigation systems like those Crusoe operates. Crusoe qualifies for emissions reduction credits because it uses waste gas to generate electricity that would otherwise have come from the grid.

Texas regulators also have adopted a tougher stance against flaring in recent months, after previously taking a largely hands-off approach.

Jim Wright, one of three Republican commissioners on the Texas Railroad Commission, said recently that companies stuck with unwanted gas should reach out to third parties — including crypto currency miners — who can "eliminate the vast majority of emissions that flaring produces and even pay the operator for the gas."


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13/09/24

About 42pc of US Gulf oil output still shut on Francine

About 42pc of US Gulf oil output still shut on Francine

New York, 13 September (Argus) — About 42pc of oil output in the Gulf of Mexico was still shut-in on Friday, just days after Hurricane Francine passed through the region. Around 732,316 b/d of offshore oil output was off line as of 12:30pm ET Friday, according to the Bureau of Safety and Environmental Enforcement (BSEE), while 973.20mn cf/d of natural gas production, or 52pc of the region's output, was also off line. The volume of crude production shut in rose slightly from yesterday, by about 2,000 b/d, while curtailed gas output fell. Operators evacuated workers from 144 platforms this week ahead of the storm. Shell said today it is ramping up production at its Appomattox, Mars, Vito, Ursa and Olympus platforms after resolving downstream issues. However, the company's Perdido, Auger and Enchilada/Salsa assets remain shut-in due to other downstream issues. And drilling remains on hold at its Whale asset, which is scheduled to begin operations later this year. The port of New Orleans resumed all normal operations Thursday evening. Preliminary damage assessments showed no significant damage to facilities or infrastructure, port officials said, while onshore refinery operational issues appear to be minor . By Stephen Cunningham and Tray Swanson Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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Fulcrum Bioenergy files for Chapter 11 relief


13/09/24
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13/09/24

Fulcrum Bioenergy files for Chapter 11 relief

New York, 13 September (Argus) — A US company that had set ambitious plans to convert garbage into sustainable aviation fuel (SAF) and attracted investments from major airlines and energy companies filed for Chapter 11 bankruptcy protection this week. Fulcrum Bioenergy and subsidiaries filed for relief before the US Bankruptcy Court for the District of Delaware on Monday, estimating outstanding obligations to over 200 creditors at more than $456mn. A lawyer representing Fulcrum, Robert Dehney, said at a Thursday hearing that the company was on the verge of declaring Chapter 7 bankruptcy, which typically involves liquidation of assets, before a late-breaking bid from an interested company prompted a change in plans. Fulcrum chief restructuring officer Mark Smith said in a declaration to the court that the company wants to initiate the sales process and move through the chapter 11 process on an "expeditious timeline." Judge Thomas Horan on Thursday preliminarily approved various first-day motions, including a request to continue paying Fulcrum's handful of remaining employees. Fulcrum began initial operations at its flagship Nevada facility in 2022, becoming the first company to commercialize a clean fuels pathway based on gasifying garbage and signing offtake agreements with BP, United Airlines, and others. The process at the Nevada site involved receiving and sorting landfill waste, converting that to a synthetic crude oil through a gasification process, and then sending that feedstock to a Marathon Petroleum refinery to be processed into a usable low-carbon fuel. Fulcrum eventually wanted to be able to upgrade the synthetic crude into SAF on site. An archived version of the Fulcrum website, which is no longer online, also set plans for eventual biorefineries and feedstock processing facilities in Indiana, along the US Gulf coast, and in the UK and said its suite of facilities could ultimately support 400mn USG/yr of production capacity. But Fulcrum has reported few updates on its progress more recently, and there were signs of financial struggles. Multiple contractors have filed lawsuits alleging missed payments, while UMB Bank indicated in October last year that Fulcrum had defaulted on debt obligations. The Nevada site ceased operations in May and plans for other US facilities are apparently on hold, though filings indicate that Fulcrum has not yet determined whether to begin restructuring proceedings for any subsidiaries outside the US. Fulcrum's business "represents a revolutionary idea," Smith said in his declaration, but "as with all cutting-edge businesses, the cost of innovation has been born through delays in operations and the inability to anticipate issues based on prior ventures and experiences." There were necessary equipment changes after initial operations begun, but these were expensive and affected by supply chain delays, he said. It is unclear how much feedstock was successfully delivered to Marathon, which declined to comment. The Hong Kong-based airline Cathay Pacific, which had signed an offtake agreement with Fulcrum, told Argus that it never received any SAF. Other companies that had signed offtake agreements did not immediately respond to requests for comment or declined to comment. Fulcrum had been soliciting interest from potential buyers for months and finalized an agreement with a company called Switch LTD, which agreed this month to offer a "stalking horse" bid to purchase Fulcrum's assets for $15mn and issue a loan of up to $5mn to fund Fulcrum's bankruptcy cases. A stalking horse bidding method is a way to arrive at a minimum bid price that other prospective buyers then must exceed. Filings before the court this week did not elaborate on the nature of Switch's business or its reasons for wanting to acquire Fulcrum's assets. Dehney described Switch as a "disinterested third party" and said that Fulcrum has received other interest from prospective buyers, some eyeing all of Fulcrum's assets and some just looking at physical property, intellectual property, or the UK subsidiary specifically. Failure to launch The idea of gasifying waste to produce fuel has long been attractive, since feedstock costs would be low and the Fischer-Tropsch chemical process to convert synthetic gas to liquids has been known for decades. Demand for low-carbon alternatives to jet fuel is high among major airlines, some of which have government mandates to meet or voluntary goals to rapidly scale up SAF consumption by 2030. While Fulcrum's Chapter 11 filing "was not really a surprise" given its recent financial troubles, it could give investors pause about future projects aiming to use similar technology, according to BloombergNEF renewable fuels senior associate Jade Patterson. The large majority of SAF capacity currently and the bulk of planned capacity additions through 2030 come from the more established method of hydroprocessing non-petroleum feedstocks like fats, oils, and greases, Patterson said. Efforts to build gas-to-liquids facilities, by comparison, have faced delays and financial challenges. Red Rock Biofuels had aimed for a refinery converting forest waste to begin operations in 2020 , but the company that later acquired the Oregon site at auction is now targeting a 2026 launch for its clean fuels facility. And Fulcrum's plans for converting waste into fuel go back more than a decade, having inked its first deal with a municipal solid waste supplier in 2008. Kickstarting a market for a novel fuel pathway has also not been helped by a dip over the last year for prices of US federal and state environmental credits, which function as a crucial source of revenue for biofuel producers. There is also uncertainty about how much federal subsidy certain fuels will earn when an Inflation Reduction Act tax credit for low-carbon fuels kicks off next year. But other gas-to-liquids companies are marching on — including DG Fuels, whose president told Argus last month that the company plans to reach a final investment decision by the first quarter next year on a potentially 178mn USG/yr SAF plant in Louisiana that will gasify biomass. The company has earlier-stage plans for similar facilities in Maine and Nebraska. By Cole Martin Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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US oil exports: WTI mixed while TMX rises


13/09/24
News
13/09/24

US oil exports: WTI mixed while TMX rises

Houston, 13 September (Argus) — US light sweet waterborne spot crude prices were mixed over the week as Asian buying interest firms. WTI loading 15-45 days forward at the US Gulf coast narrowed its discount to December Ice Brent by 50¢/bl to 93¢/bl. The free-on-board (fob) value weakened by 4¢/bl against the secondary coastal crude benchmark WTI Houston to a 26¢/bl midpoint premium as October-loading differentials were mostly unchanged due to a major industry event happening in Singapore this week. Demand for WTI climbed a bit earlier in the week as Asia-Pacific refiners stepped up their purchases of October-loading WTI prior to the start of S&P's Asia Pacific Petroleum Conference (APPEC) conference this week in Singapore. It was unclear whether the pace of Asian buying would continue after this week. Asian buyers typically seek WTI supplies around two weeks earlier than European customers. Prior to the spike in Asian buying of WTI, Chinese demand had been relatively weak, although delegates at the Singapore conference said this demand weakness was overstated. Chinese oil demand growth is slowing but has not yet peaked, while growth in the use of naphtha and jet fuel is offsetting declines in motor fuel consumption, delegates heard at the Argus Asia-Pacific Oil Markets Forum on 10 September. The growth in the use of naphtha and jet fuel is offsetting declines in motor fuel consumption. The slowdown in oil demand growth is attributed to signs of weakness in the Chinese economy and the country's push for electric vehicles. Despite the slowdown, some experts believe that the weakness in Chinese oil demand is being exaggerated, and they view China as a maturing market with lower growth like other OECD countries. Elsewhere, tanker freight rates are expected to increase in the coming months due to a recovery in demand for dirty tankers, according to delegates at the Appec conference in Singapore. The rates for clean tanker freight fell in the third quarter due to competition from dirty tankers, but there has been a recent increase in demand for dirty tankers, hinting at a general recovery in the fourth-quarter rates. Americas Pacific coast Values for Canadian crude exported via the 590,000 b/d Trans Mountain Expansion (TMX) pipeline strengthened amid volatility in the underlying futures market. Free-on-board (fob) High-tan crude exported from Vancouver strengthened 10¢/bl to a $10.53/bl discount to January Ice Brent, while Cold Lake fob Vancouver rose 20¢/bl to a $9.55/bl discount against the benchmark. Ice Brent crude futures prices fell below $70/bl during the week, the first time since late 2021. This decline came after low Chinese crude imports in July and the delay by OPEC+ alliance members to increase output. Despite disruptions to Libyan crude output, the prices continued to fall. OPEC's research arm remains bullish on oil demand, while some trading firm executives suggested that prices may need to fall further to stimulate demand. Analysts and traders are factoring in the softness in China, the impending Federal Reserve easing cycle in the US, and mixed messages from OPEC. Elsewhere, sections of the 622,000 b/d Keystone crude pipeline remain at reduced pressure since a spill nearly two years ago, but its operator is making strides to have those restrictions potentially removed. TC Energy's Keystone pipeline is a major thoroughfare for Canadian heavy crude destined for the US midcontinent and Gulf coast, but a rupture in December 2022 took the cross-border pipeline off line for more than three weeks. Service was mostly restored in the months following the incident, but more crude could likely be moved down the line if pressure restrictions are lifted. Canada's west coast now exports more Canadian crude than the US Gulf coast after the startup of the TMX pipeline. Lifted restrictions on the Keystone pipeline could potentially disrupt crude flows through TMX. By Andrea Agee and Rachel McGuire Planned US crude export cargoes Tanker name Size Charterer Destination Laycan Asia-Pacific Front Forth VLCC Phillips 66 China 7-14 September 2024 C. Earnest VLCC Mercuria China 7-14 September 2024 Khurais VLCC Unipec China 10-14 September 2024 Ilma VLCC SK Energy South Korea 15 September 2024 Legio X Equestris VLCC Aramco Trading Singapore 15 September 2024 Plata Glory VLCC Phillips 66 Taiwan and/or South Korea 19 September 2024 Seamajesty Suezmax Shell Singapore 19 September 2024 Dht Sundarabans VLCC ExxonMobil Singapore 24 September 2024 Yasa Scorpion VLCC Unpiec China 25-30 September 2024 Basrah VLCC Unipec China 30 September 2024 New Corolla VLCC Hyundai Oil Bank South Korea 3-5 October 2024 Front Alta VLCC Shell South Korea 5 October 2024 Cosflying Lake VLCC BP Singapore 8 October 224 Celeste Nova VLCC Chevron South Korea 8 October 224 Landbridge Glory VLCC Equinor Asia-Pacific 13 October 2024 Front Tana VLCC SK Energy South Korea 13 October 2024 Hillah VLCC PTT Ningbo, China 15 October 2024 Sinokor TBN VLCC Occidental Petroleum Asia-Pacific 16 October 2024 Europe Andromeda VLCC BP Europe 8-14 September 2024 Seaways Endeavor VLCC ExxonMobil Europe 14 September 2024 Levantine Sea Aframax Chevron Europe 15 September 2024 Seatribute Aframax BP Europe 15 September 2024 Yuan Bei Hai Suezmax Equinor Europe 15 September 2024 Arctic Suezmax BP Europe 18 September, 2024 Aegean Horizon Suezmax Vitol Europe 18-19 September 2024 Morning Hope VLCC ExxonMobil Europe 21 September 2024 Eagle Veracruz VLCC ExxonMobil Europe 27 September 2024 Cobalt Nova VLCC BP Europe 13-17 October 2024 Americas and misc. Front Shanghai Suezmax Energy Transfer Porto Sudeste, Brazil 13-14 September 2024 Green Adventure Aframax Chevron East Coast Canada 15 September 2024 Seaways Frio Suezmax Petrobras Brazil 21 September 2024 Shipping fixture reports Select US crude cargoes in transit Tanker name Size Loading window Destination ETA Asia-Pacific Houston Voyager VLCC 22-24 July 2024 Maoming, China Alongside Seavoice VLCC 20-24 July 2024 Ulsan, South Korea 15 September 2024 Dht Panther VLCC 11-16 July 2024 Kaohsiung, Taiwan 16 September 2024 Arsan VLCC 19-25 July 2024 Daesan, South Korea 16 September 2024 Dht Osprey VLCC 23-27 July 2024 Taoyuan, Taiwan 17 September 2024 Xin Long Yang VLCC 29 July 2024 - 3 August 2024 Paradip, India 20 September 2024 Maxim VLCC 26-29 July 2024 Kaohsiung, Taiwan 22 September 2024 Halcyon VLCC 2-6 August 2024 South Korea 27 September 2024 Cap Victor Suezmax 5-7 August 2024 Mumbai, India 28 September 2024 Advantage Verdict VLCC 12-16 August 2024 Singapore 5 October 2024 Cosnew Lake VLCC 13-18 August 2024 Yeosu, South Korea 9 October 2024 DHT Redwood VLCC 15-18 August 2024 Asia-Pacific 10 October 2024 Maharah VLCC 15-21 August 2024 Daesan, South Korea 12 October 2024 Maran Thaleia VLCC 16-21 August 2024 China 13 October 2024 Vl Brilliant VLCC 21-26 August 2024 Kaohsiung, Taiwan 17 October 2024 Dias I VLCC 23-27 August 2024 Geoje, South Korea 17 October 2024 Amphitrite VLCC 27-31 August 2024 Singapore 19 October 2024 Great Lady VLCC 30 August - 3 September 2024 Singapore 25 October 2024 Dijilah VLCC 3-6 September 2024 Mumbai, India 27 October 2024 Europe Ithaki DF Aframax 27-28 August 2024 Fos, France 16 September 2024 Seagrace Suezmax 29-31 August 2024 Immingham, United Kingdom 17 September 2024 Minerva Nounou Aframax 30-31 August 2024 Rotterdam, The Netherlands 17 September 2024 Achilleas Suezmax 30-31 August 2024 Rotterdam, The Netherlands 18 September, 2024 Eagle Ventura VLCC 28 August - 4 September Rotterdam, The Netherlands 20 September 2024 Nordic Zenith Suezmax 30 August - 2 September Wilhelmshaven, Germany 21 September 2024 Horten VLCC 31 August - 5 September 2024 Rotterdam, The Netherlands 22 September 2024 Drepanos Aframax 3-5 September 2024 Immingham, United Kingdom 23 September 2024 Atlantic Suezmax 29 August - 1 September 2024 Trieste, Italy 23 September 2024 Sola TS Aframax 6-8 September 2024 A Coruña, Spain 24 September 2024 Front Ull Suezmax 5-7 September 2024 Wilhelmshaven, Germany 25 September, 2024 Atlantic Emerald Aframax 7-9 September 2024 Spain 26 September 2024 Crude Zephyrus Suezmax 3-4 September 2024 Ancona, Italy 26 September 2024 Grimstad Aframax 9-11 September 2024 Rotterdam, The Netherlands 29 September 2024 Nordic Vega Suezmax 3-4 September 2024 Porvoo, Finland 29 September 2024 Minerva Libra Aframax 7-9 September 2024 Milazzo, Italy 30 September 2024 Kpler and Vortexa Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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India’s higher LNG regas rates receive customer flak


13/09/24
News
13/09/24

India’s higher LNG regas rates receive customer flak

Mumbai, 13 September (Argus) — Indian LNG terminal developers led by state-run Petronet LNG and Shell are charging some of the highest rates among the world to regasify LNG, prompting consumers to complain, raising concerns over the government's plan to more than double the share of gas in the country's energy mix to 15pc by 2030. Petronet is charging as much as Rs62.91/mn Btu ($0.75/mn Btu) to regasify the fuel received at the 17.5mn t/yr Dahej terminal on the west coast, the country's largest such facility, according to consumers using the import facility. Coupled with the annual escalation in charges, the rates are "unsustainable in the longer-run," a person who did not wish to be identified said. "Going by the 5pc increase in regas rates every year, by 2030, regas rates could become Rs84/mn Btu ($1/mn Btu), which is not justified," the source added. State-run Petronet has lifted regasification rates by 5pc in recent years. "The 5pc hike in regas rates every year may eventually have to stop in the coming years before it reaches a dollar," an equity analyst at a foreign investment bank said. Shell is also charging similar rates at its 5.2mn t/yr Hazira LNG import facility on the west coast at $0.75/mn Btu, industry sources said. Both Dahej and Hazira are well connected to consumption centres by pipelines and operate year-round, unlike many of India's other terminals which suffer from lack of a breakwater facility or weak pipeline connectivity. Higher regas prices account for the lower usage levels in other terminals, because the country's overall LNG imports are lower than major importers like China or Japan, market participants say. India's regasification rates are much higher compared to terminals in the Europe. The 9.2mn t/yr Gate terminal in Netherland charges around $0.35/mn Btu for unloading and regasification, while Spain is much lower. Regasification rates in Japan LNG terminals are around $0.5/mn Btu, while rates at terminals operated by Jera, like the 22.9mn t/yr Futtsu LNG facility, are much lower, according to market participants. Regasification rates in China, however, are also higher, on a par with India as PipeChina's eight LNG terminals, including the largest 12mn t/yr Tianjin terminal in north China, and 6mn t/yr Dalian terminal in Liaoning. These are charging $0.7-1.3/mn Btu for unloading and regasification, sources say. Regas rates across the world are mostly determined by market forces based on demand fundamentals compared with fixed prices charged by Indian terminal operators. But record regasification rates have not stopped city gas utilities and industries from using Petronet and Shell's terminals to import the fuel, enabling Petronet to operate Dahej at around 109pc in April-June, a record for the facility, according to oil ministry data. Hazira, which in the past has operated at over 80pc, operated at 46.5pc in the second quarter. Capacity usage at LNG terminals in Europe, China and Japan are mostly in the range of 30-50pc, and the rest of India's five terminals with a combined 25mn tons a year in capacity operate at 20-40pc of that. Judging by deliveries in January-July this year, India's LNG imports stood at 16mn t, compared to an annual installed import capacity of 47.7mn t. Strategic location Importers in the country have little option of switching to other facilities because of the strategic location of Dahej and Hazira, which are well connected by major pipelines to the country's western region — where consumption is strong. The cost structure breakdown for a customer comes to $11.62/mn Btu at the Dahej terminal, which is calculated based on a delivered LNG price at $10/mn Btu, custom duty of 2.75pc at $0.275/mn Btu, regas price at $0.76/mn Btu, system used gas at $0.07/mn Btu and zone 1 pipeline tariff at $0.51. Tariffs under zone 2 are $0.95/mn btu and zone 3 is at $1.27/mn Btu. The zone 1 tariff is application for pipelines defined as up to 300km from the terminal, followed by between 300-1,200km for zone 2 and zone 3 more than 1,200km. Regulatory scrutiny Weak capacity utilisation levels in India's LNG terminals have attracted the attention of India's Petroleum and Natural Gas Regulatory Board (PNGRB), as it issued a draft proposal for enhanced regulatory control earlier this year. The draft regulations state the PNGRB must approve new facilities or capacity additions, review regasification fees and approve setting up pipeline infrastructure for regasified LNG. Terminal operators are reluctant to share information with the regulator. Total Adani, operator of the 5mn t/yr Dhamra LNG terminal on the east coast, said "requirement to share commercially sensitive information" such as project costs, regasification tariffs and capacity allocation are "not consistent" with the PNGRB Act. "An authorisation regime for LNG terminals may indeed negatively impact healthy competition and create monopolistic behaviour by the existing terminals." Each project would require a certification of registration by PNGRB, and may even face penalties if there are any start-up delays. Developers will also need to publicly disclose their regasification tariffs and other charges for transparency. By Rituparna Ghosh Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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UK High Court rules Cumbria coal mine permit unlawful


13/09/24
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13/09/24

UK High Court rules Cumbria coal mine permit unlawful

London, 13 September (Argus) — The UK's High Court has quashed planning permission granted in 2022 for a coal mine in Cumbria, northwest England, ruling the approval was unlawful. The court judgment found the greenhouse gas (GHG) emissions that would result if the coal was burned — known as scope 3 emissions — were not properly considered during the planning process. The proposed mine's developer, West Cumbria Mining, said it would produce a "net zero coal product", using methane capture and abatement, renewable power, "tree planting… and offset of minor residual emissions". But the judgment found the secretary of state at the time, Michael Gove, acted unlawfully in accepting that claim. The UK's Climate Change Act does not allow reliance on international offsets to meet the country's legally-binding carbon budgets. The then-Conservative UK government granted permission for the mine — set to produce metallurgical coal, used in steel production — in December 2022 to West Cumbria Mining. Environmental groups Friends of the Earth and South Lakes Action on Climate Change sought a judicial review, a challenge to the way in which a decision has been made by a public body, focusing on the procedures followed rather than the conclusion reached. The UK's Labour government, elected in July, said it would not defend the planning decision in court. The government will now have to reconsider the planning application, taking into account the "full climate impact", Friends of the Earth said. "West Cumbria Mining will consider the implications of the High Court judgement and has no comment to make at this time", the company told Argus . Today's ruling referenced a landmark June judgment from the UK's Supreme Court, which found that Surrey County Council's decision to permit an oil development was "unlawful because the end use atmospheric emissions from burning the extracted oil were not assessed as part of the environmental impact assessment". The outcome has prompted the UK government to develop new environmental guidance for oil and gas firms . By Georgia Gratton Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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