Germany's Landwärme declares insolvency
German biomethane supplier Landwärme has today declared insolvency under the country's self-administration procedure and has initiated restructuring measures "to overcome the consequences of the ongoing decline in prices of German greenhouse gas (GHG) emission reduction quota".
Self-administration proceedings are a proven legal framework in German restructuring law analogous to the US' Chapter 11 bankruptcy proceedings. They allow businesses to reorganise structures and financing while operations continue.
Landwärme attributed the price decline of German GHG tickets to an influx of imported, falsely-labelled biodiesel since the start of last year, as well as other alleged fraud cases regarding upstream emission reduction (UER) projects. Fake UER projects have caused the biofuel industry around €4.5bn in damages, according to the company.
Argus' Other GHG credits, GHG certificates which do not fall under caps for crop-based and Annex Part B biofuels, averaged €100/t CO2e in July, down from around €400/t CO2e in January 2023.
Landwärme is also looking to bring a "financially strong partner on board" to regain the necessary stability, it said, and intends to complete the restructuring as quickly as possible.
"This procedure could have been avoided if politicians and authorities had been more consistent in prosecuting and combating the alleged fraud cases in biodiesel and UER projects", managing director Zoltan Elek said.
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Fulcrum Bioenergy files for Chapter 11 relief
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.
India’s higher LNG regas rates receive customer flak
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.
Argentina's big energy hopes face reality
Argentina's big energy hopes face reality
Houston, 13 September (Argus) — Argentina has the reserves, investor interest and now most of the regulatory framework to potentially triple its oil and natural gas output by the early 2030s, but ensuring success will require much more, producers in the country said today. "Argentina has tremendous production potential," said Chevron's general manager of its Argentina upstream unit Jim Navratil, speaking at the 4th Shale in Argentina conference in Houston, Texas. But the country needs to give more assurances that contracts and investment regimes will be honored, and make it easier to move capital, he added. Chevron produces more than 100,000 b/d in Argentina. The South American country is banking mostly on its Vaca Muerta unconventional oil and gas deposit that holds an estimated 308 trillion cf in natural gas and 16bn bl of oil reserves. Output from Vaca Muerta alone could rise to more than 1mn b/d from about 390,000 b/d now by 2030, the government and outside forecasts estimate. This comes after Argentina's overall oil output hit a 20-year high in July of 682,000 b/d and 151.7mn m³/d of gas, a 21-year high. To further that increase, Argentina's government under President Javier Milei has passed massive changes to its financial and energy regulatory framework. The changes are aimed at ending the costly policy of energy sovereignty that "has hurt us" and instead making the system financially self-sustaining and open for investment, Argentina's energy minister Eduardo Rodriguez Chirillo said at the same event. Not quite there Optimism has grown, but more work is pending, producers say. "We are supporting [the government's changes] and cheering, but we are still not quite there yet", Equinor's Vaca Muerta asset manager Max Medina said. Equinor has interest in one exploration license and one producing block in Vaca Muerta, with about 59,000 b/d of production. Argentina should add more incentives for producers and those companies must place more attention on safety, emissions reductions and compliance as the basin expands, Medina said. Workforce development is also a challenge in Neuquen, the province where Vaca Muerta is centered, which has a population of about 700,000. "The challenge to get to 1mn b/d [in Vaca Muerta] is going to be much more difficult, especially on the human resources side," Medina said. Technological and cost constraints also present difficulties, said Pan American Energy's upstream managing director Fausto Caretta. The company hopes to triple its oil production in the Neuquina basin asset and in the Neuquen province in coming years, from 6,000 b/d of oil now. But restrictions in Argentina on importing needed technology have also delayed needed improvements, Caretta said, although rules are easing. This has contributed to well drilling costs in the Vaca Muerta region being about 20pc higher than in the Permian basin in Texas, to which it is often compared, and completion times remain about 30pc more. Financing multiple proposed infrastructure projects will also be key. "The challenge is how to get that oil to markets," said Julian Escuder, country manager for Pluspetrol, which produces about 21,000 b/d of oil in Argentina. "We need infrastructure." Despite the hurdles, Argentinian officials are assuring investors that changes are here to stay, unlike recent abrupt shifts in energy policy in Colombia and Mexico to focus on state-centered models. Neuquen governor Roland Figuero assured attendees that energy policy is stable in his province. "That has been the same for years," he said, adding that Vaca Muerta "is the last big opportunity that Argentinians have to do things well" in energy. By Carla Bass Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
Francine shuts in about 42pc of US Gulf oil: Update 2
Francine shuts in about 42pc of US Gulf oil: Update 2
Adds spot crude pricing information, NOLA port reopening. New York, 12 September (Argus) — Hurricane Francine, which has since weakened to a tropical depression as it passes over central Mississippi, shut in about 42pc of US Gulf of Mexico oil output. About 730,472 b/d of offshore oil output was off line as of 12:30pm ET Thursday, according to the Bureau of Safety and Environmental Enforcement (BSEE), while 991.68mn cf/d of natural gas production, or 53pc of the region's output, was also off line. Operators evacuated workers from 169 platforms this week ahead of the storm. Companies including Chevron, ExxonMobil and Shell relocated offshore workers and suspended some drilling operations ahead of Francine, while a number of ports, including New Orleans, Louisiana, shut down. Shell curtailed output at the Appomattox platform, around 80 miles south east of Louisiana, as well as the Mars, Vito, Ursa, and Olympus platforms because of downstream issues. Today Shell said it has started to redeploy staff to its Perdido facility, located about 190 miles south of Houston, where production is still shut. Operations at Shell's Auger and Enchilada/Salsa assets, about 120 miles south of Vermillion Bay, Louisiana. remain suspended. Drilling is still halted at the Whale platform, which is scheduled to start up later this year. "As conditions continue to improve, we will begin the process of redeploying personnel to Auger and Enchilada/Salsa to bring staffing to normal operating levels," Shell said. Offshore crude spot prices rise Crude from Shell's Appomattox project moves through the offshore Proteus and Endymion pipelines to be marketed as part of the medium sour Thunder Horse stream, which has dedicated underground cavern storage in LOOP's Clovelly, Louisiana, hub. In today's spot market, prompt October Thunder Horse has been trading at a 30¢/bl premium to the US benchmark in Cushing, Oklahoma, today, 20¢/bl higher than in the prior session. Crude from Shell's Mars, Vito, Ursa and Olympus platforms also delivers to LOOP's Clovelly hub, and is sold as Mars crude from there, where the medium sour also has dedicated cavern storage. Mars crude has sold in the spot market today at 70-80¢/bl discounts to the Cushing benchmark, in line with yesterday's 75-80¢/bl discounts. Shell's Auger and Enchilada/Salsa production feeds primarily into the Bonito Sour crude stream, a light sour that is not often seen trading in the spot market. Perdido feeds into ExxonMobil's Hoover Offshore Oil Pipeline System (HOOPS), that delivers the HOOPS Blend to the Texas Gulf coast. HOOPS Blend is a medium sour crude that is not actively traded in the spot market. Competing Texas-delivered medium sour Southern Green Canyon (SGC) was trading at a $1.25/bl discount to Cushing this morning, within yesterday's range of discounts between $1 and $1.30/bl. SGC discounts had tightened to as narrow as 70¢/bl this week — the tightest since mid-August. Ports reopening Conditions at the port of New Orleans were set to normal at 2pm ET today after the port was closed ahead of the storm, according to the US Coast Guard. The mouth of the Mississippi River remained closed to traffic however. The port of Lake Charles reopened to vessel traffic at 11am ET Thursday after closing on Tuesday evening. Francine was about 15 miles north-northeast of Jackson, Mississippi, as of a 12pm ET advisory from the National Hurricane Center, with maximum sustained winds of 35mph. It slammed into the Louisiana coast as a Category 2 hurricane Wednesday evening before weakening. 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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