It’s possible that I shall make an ass of myself. But in that case one can always get out of it with a little dialectic. I have, of course, so worded my proposition as to be right either way (K.Marx, Letter to F.Engels on the Indian Mutiny)
As part of a wave of measures to stimulate demand, China's government has announced new subsidies to incentivize domestic shipowners to renew their fleets with more efficient, green-fueled tonnage. The policy echoes the "scrap-and-build" subsidy program of the 2008 financial crisis, which helped buoy Chinese shipyards during a severe downturn.
China's economy grew at a comparatively sluggish pace of five percent in the first half, meeting government targets but falling below historical patterns. A housing market downturn, weak consumer demand and reduced government spending are weighing on the pace of Chinese economic expansion. To stoke demand, Beijing has rolled out subsidies for consumers and businesses to replace older buses, cars, appliances, farm machinery and more. The incentive for swapping an old car with a new battery-electric model has doubled to nearly $2,800 - about 15 percent of the purchase price for a typical EV in China.
Shipowners and shipyards need not feel left out. China's Ministry of Transport and the National Development and Reform Commission have released a new schedule of subsidies for the demolition and replacement of older domestic vessels. China's coastwise and inland fleet is vast, and replacing these small ships with newbuilds would create industrial-scale demand for steel and skilled labor.
The subsidies apply to domestic vessels of as little as 10 years of age, and vary depending on type (coastal, inland or passenger vessels). The starting-point value for the subsidy is $140 per gross ton, ranging up to $210 for qualifying passenger ships and tankers.
The subsidy applies when the newbuild replacement vessel is powered by LNG (at least 50 percent), or by methanol, hydrogen, ammonia or battery-electric propulsion.
The scrapping subsidy points to the possibility of a future for China's inland waterways that looks more like China's heavy-truck sector, which is already transitioning to LNG single-fuel power. Per unit of energy, LNG is now cheaper than diesel in China, and it has made rapid gains in the Chinese trucking market. Owners of older trucks who wish to make the switch may be eligible for subsidies of up to $19,000, enough to cover up to 20 percent of the price of a new LNG-fueled tractor-trailer. Even before the subsidy, LNG-powered trucks accounted for a third of all Chinese new-truck sales as of the end of 2023 - and China's road diesel demand is dropping, according to Wood Mac.
MOL Looks to Cow Manure to Supply Biomethane Fuel
MOL researches cow manure as source of biomethane fuel (MOL)
A group of Japanese companies is researching cow manure as a source to produce biomethane to fuel the decarbonization of heavy industry and shipping. While methane is viewed as a promising alternative fuel shipping companies such as Maersk continue to cite the shortage of supply while others such as Ørsted cite the weak demand for biomethane.
Mitsui O.S.K. Lines and its MOL Sunflower ferry company along with Hokkaido Gas Co., Takanashi Milk, and others announced they are launching a study on the production and utilization of biomethane. They point out the thriving dairy farming industry in Hamanaka town saying they believe animal manure from local dairy farms could be used in fuel production. MOL in 2023 highlighted that farmers have traditionally used this as a power source saying the biogas produced by cattle farmers is about 60 percent methane and 40 percent carbon dioxide.
Liquefied natural gas (LNG) is currently being used as a low-carbon fuel alternative to conventional fuels such as coal and oil and can reduce carbon dioxide (CO2) emissions by 25 to 40 percent compared to conventional fuels in factories and vessels. In this study, the six organizations will evaluate the feasibility of using all or part of the biomethane produced in Hamanaka Town to fuel factories and vessels.
Among the advantages MOL highlights are that the fuel can be used in current infrastructure for transport and consumption. MOL confirmed this in tests with one of its coastal vessels in 2023.
The Japanese company AirWater is one of the pioneers in commercializing this form of biomethane. In the company’s process, the gas is derived from dairy-owned biogas plants, liquefied at about -160°C, separating and refining its main component, methane. The resulting methane can be compressed to 1/600th of its volume when liquefied, enabling it to be transported on a large scale.
While orders of methane-fueled vessels skyrocketed, costs and the lack of production have raised concerns. Maersk recently admitted that it is looking at LNG-fueled vessels in its current fleet renewal project although those vessels could be transitioned to biofuels when it is available. Yet, citing slow delay for biofuels, Ørsted stopped construction on a prototype biomethane plant it is building. Production was slated to begin in 2025.
CEO interview: “Onshore oil industry must generate cash for well decommissioning”
The UK onshore industry needs to raise money to plug and abandon hundreds of redundant oil wells as part of the energy transition, Angus Energy’s chief executive told DrillOrDrop.
Richard Herbert, chief executive of Angus Energy. Photo: Angus Energy
In an extended interview, Richard Herbert said the onshore industry had to follow the North Sea’s example and invest to decommission old wells.
He said:
“It’s not on the same scale as the North Sea was but the [onshore] industry has hundreds and hundreds of wells to abandon safely, so that they don’t pollute future water courses.
Official data analysed by DrillOrDrop shows there are nearly 500 UK onshore wells that are not classed as operating but have not been fully decommissioned. More detailed article coming soon.
Mr Herbert said:
“[site operators] have sites to demolish and return to open fields and someone has to pay for that. And the government won’t pay for it and nobody else is going to pay for it.
“So the industry has to generate some wealth that can be used to reward its shareholders but also can be used responsibly to end the oil era in onshore UK.”
Mr Herbert, who runs the UK’s biggest onshore gas field at Saltfleetby in Lincolnshire, said the onshore industry was playing “a very important role” in the energy transition “that maybe people don’t’ understand when they look at our business model.”
He said:
“the energy transition doesn’t just involve building a lot of windmills and solar farms and everyone buying electric cars and cooking on those electric things, that I can’t cook on.
“It also involves cleaning up more than 100 years of industrial activity and if you look at all these producing fields in the Weald and in the east midlands, it’s a bit like the North Sea.
“the big [offshore] companies are investing billions of pounds now in taking out the platforms and plugging the wells and making it look like it did before we ever went there. We have to do the same onshore.”
He said the investment tax breaks in the energy profits levy – described by fossil fuel opponents as a loophole – were “critical capital allowances that allow the industry to invest and replenish our domestic production”.
Last month, the new Labour government extended the energy profits levy, also known as windfall tax, by another year. It also increased the rate of tax and removed the investment allowances.
Other key points
Mr Herbert has been Angus Energy’s chief executive since 2023 and was a senior executive at BP. As well as Saltfleetby, his company operates onshore oil sites at Balcombe and Lidsey in West Sussex and Brockham in Surrey.
In his DrillOrDrop interview, he also said:
The oil and gas industry had to lower its climate impact but developing domestic oil and gas fields was in the best interests of the country
“We all recognise that we have to continue to lower the impact of oil and gas because of the climate impacts of it.
“But at the same time, it has to be done in the right way.”
He said:
“we are in the very early days of the energy transition. We still rely significantly on oil and gas for our energy, for transportation, for home heating, for electricity generation, for industry, and importing oil and gas when we have domestic resources does not make any sense.
“I think the whole industry recognises that if we are given a chance to produce and develop domestic oil and gas fields it is in the best interests of the country as we manage our way through what’s going to be a complex energy transition.”
Campaigner Sarah Finch who brought the successful legal challenge at the Supreme Court on downstream carbon emissions. Photo: DrillOrDrop
“The reaction I’ve heard since this case was that people are confused about how this is this is going to be interpreted and what does it really mean.”
The court ‘s majority judgement said Surrey County Council should have taken into account downstream emissions from burning oil produced at UKOG’s Horse Hill site when deciding planning permission.
The decision is expected to have widespread implications for carbon intensive industries, including a new coal mine in Cumbria.
Mr Herbert said it was difficult to know how the judgement would affect Angus Energy and the onshore generally. He said “right now we are waiting to see.
“We have a planning application which has just been submitted to drill additional wells at the Saltfleetby gas field and that approval process could be affected by this. At this stage, we remain optimistic that we will get the right outcome and if this involves more work to be clear about the impact of what we’re trying to do then so be it. We can live with that.”
He described the argument, put forward by the former head of BP, John Browne and others, against issuing new North Sea licences as “an interesting point to debate”.
He said:
“I think in terms of production and opportunities to get as much out of the ground now or in the short term to stop us importing, I find it much harder to find arguments against that because that seems to me to be efficient and logical.
“We still have an electricity system that is very dependent on hydrocarbons. We have home heating that is very largely dependent on hydrocarbons. We don’t have that many electric cars on the road yet and a lot of those that are there the electricity is being generated by gas. So we’ve got a long way to go.”
He said he would be “the first to support” Labour’s plans for investment in alternative energy”.
But he said “it can’t come at the cost of the oil and gas industry”.
The energy transition “has to be done in the right way”, he said.
“What doesn’t work right now is the high levels of taxation that were committed by the last government as a knee-jerk reaction to what happened in Ukraine. And rather than seeing those come down as commodity prices have come down again, we’re actually seeing people trying to push them up.”
Angus Energy in southern England
The Weald – potential in question
Mr Herbert described the Weald oil fields in southern England as “small and complicated”.
Asked whether there was potential for future development of oil and gas in the Weald, he said:
“Probably not.”
He said there was “not much public support from the community” for the industry.
Balcombe – well test, stimulation and wrong location
Balcombe residents challenging the Balcombe well test at the High Court. Photo: DrillOrDrop
At Balcombe, where there were near daily protests during drilling in 2013, local people have delayed a well test by bringing a legal challenge. Angus Energy and the Department of Housing, Communities and Local Government will defend the case at the appeal court in January 2025.
Asked whether the Balcombe oil site, in the High Weald Area of Outstanding Natural Beauty, was in the wrong place, Mr Herbert said:
“If we were starting from scratch today, we would say ‘shall we go and explore for oil in an area of outstanding beauty? Probably too difficult’.”
He acknowledged local opposition to the plans, but said they were “borne out of the fear of fracking”. He said he thought the site could be “developed responsibly without putting at risk the water course and everything that’s in the AONB”.
The well would have to be flowed even if it was going to be abandoned, he said.
“the only way to deal with this is to allow the well to be flowed and then we either make a commercial decision to abandon it and put it back to what it was like before we drilled, or we have some encouragement that says we have an asset here that could be developed and which could generate production, taxes, jobs and all the things that we do this for.”
Asked if Angus Energy planned any form of stimulation of the Balcombe well, Mr Herbert said:
“Not in terms of hydraulic stimulation, no. We have not applied in our planning permission to do that. And if we were to develop the field, I think it is extremely unlikely that we would be looking to do that. I can’t say impossible because I don’t know what the test might tell us about the best way to encourage production from the wells.”
He said high volume hydraulic fracturing “never got off the ground in the UK. I don’t think it ever will”.
But he said the industry had been stimulating wells to deal with formation damage “for decades” and “no one ever made a fuss about it”.
“If we wanted to clean up a well and do a very small job on it, that is something that we would have to apply for permission for. It’s not something we have currently applied for.”
Mr Herbert said Angus had no recent contact with Frack Free Balcombe Residents’ Association, the group bringing the challenge to the Balcombe well test.
Brockham and Lidsey – water injection plans
At Brockham, near Dorking, Angus said it was seeking permission to import formation water from other sites to inject into the reservoir. It currently has permission to inject just water from Brockham.
The company restarted production at Brockham in June 2024, after a break of 18 months. New production levels were 40-50 barrels of crude oil a day, Mr Herbert said. But 60% of the output from the field was formation water.
Mr Herbert said:
“we’ve argued successfully that to maximise the recovery from Brockham we need to replace the fluids we’re taking out. And therefore we would like the ability to bring additional tanker loads of water in to make sure that we’re doing that. We’re in the process of putting that together.”
He said this permission would allow Angus Energy to restart production at its Lidsey field, near Bognor Regis, which has no water disposal facilities.
Lidsey produced about 15-20 barrels a day in 2020. Mr Herbert said even at this level of production the field “would still be economic”.
“we have licences from the government to maximise production from these fields so we will do what we can to achieve that. But we can’t make a decision on that until we’re able to consider the movement of the fluids, particularly the water, to Brockham.”
Official figures show the field contributes about 80% of UK onshore gas production. But this represents less than 1% of total UK gas production.
Mr Herbert said the field was currently constrained to about 11 or 12 million cubic feet per day. He said he hoped new wells, workovers and a £3m project to install a booster compressor, would increase production at Saltfleetby.
The company was revising its reservoir model for the field, Mr Herbert said, to shape decisions on future wells and workovers.
Angus and its partner, Trafigua, are also looking at potential gas storage at Saltfleetby. Mr Herbert said “there could be a role” for market-driven storage at the field, where a trader buys a cargo of cheap liquefied natural gas (LNG) and stores it until prices rise.
He added:
“I believe we should take a serious look at carbon capture at this site. This government has both committed to net zero emissions and at the same time acknowledged the role of gas in the foreseeable future. Onshore sites will have to be an essential part of the new strategy.”
He also said once Saltfleetby’s gas was worked out, the company would “be looking to see if there is anything else around”, including oil.
Acquisitions and hedging
Angus has previously hinted about new areas of interest and Mr Herbert suggested this could include additional UK onshore fields:
“we recognise that the company has the potential to grow and we can take on more opportunities.”
He said:
“as a UK onshore producer, the first place people would expect us to look at is onshore UK and there’s quite a lot of companies that are, if not distressed, then they are struggling.
“There’s a logic to potentially combining or adding assets in onshore UK. But this comes back to the attitude of the new government to the environment in which we would be investing.
“I think we need to have clearer rules and a clearer understanding of government direction before we commit to that.”
At the time of writing, Angus Energy’s share price was 0.25p. This is down from 1.37p when DrillOrDrop last interviewed an Angus Energy chief executive.
Mr Hebert said:
“I believe we’re significantly undervalued. We’ve had to fight to get through some very difficult situations in the last 12-18 months.”
The company hedged Saltfleetby gas during a period of lower prices and before production from the field got underway.
Mr Herbert said the bubble in the gas price “largely coincided with the period when the field was still being developed”. He said the situation was worsened by the need to honour hedges when there was no production. He said: “there was a bit of a lost opportunity there”.
The hedging commitments will continue until summer 2025 and cash flow would be lower, Mr Herbert said.
“we’ve got another 12 months of dealing with those, where for quite a significant part of our production we receive a price that is significantly below the current price. That’s just a legacy position that we have to deal with.
“The good news is that 12 months from now that will be gone and we’re still hedging a percentage of our production but we’re doing it at prices that are much more aligned to current market prices so they give us price protection.”
The company restructured its debt earlier this year and Mr Herbert appeared optimistic for the future. He said:
“We have a very strong asset that has very strong cash generating potential”.
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Sunday, August 18, 2024
CMA CGM Vessel on MV Losses 99 Containers During Storm off South Africa
CMA CGM's brand new containership has lost up to 99 boxes overboard in a storm off South Africa (Hudong-Zhonghua)
For the second time in approximately a month, one of CMA CGM’s large containerships, the newly inaugurated CMA CMG Belem (13,000 TEU) has lost boxes overboard in storms off South Africa. Industry observers had noted that the large boxships would encounter difficult weather on the Cape of Good Hope route as they divert from the normal routing through the Red Sea.
The South Africa Maritime Safety Authority received a report from the containership that it has lost as many as 99 containers off the east coast of South Africa. The incident happened on Thursday, August 15, with SAMSA saying it had also been informed there was a “significant stowage collapse,” and that the vessel was seeking a port of refuge.
“The vessel had initially sought refuge at Maputo Bay. However, after further assessment, the decision was made to redirect the ship to Qheberha (Port Elizabeth). The CMA CGM Belem is currently slow steaming towards Port of Ngqura, with an expected time of arrival on August 18, 2024,” said SAMSA.
Given the size of the vessel, 145,650 dwt with a length of 1,102 feet (336 meters) and a draft of 48.5 feet (14.8 meters), SAMSA said the Port of Ngqura terminal is the only one in local area suitable for the vessel. The vessel’s AIS signal shows that as of late on Sunday she had arrived in the Port Elizabeth anchorage. CMA CGM has not issued a statement, but it is likely undergoing a full damage assessment at the moment.
“Stowage collapses have been confirmed, and the affected containers will need to be discharged at a container port facility upon arrival,” according to SAMSA.
The vessel which is registered in Malta, was delivered to the French company in late June. It is the fifth of six dual-fuel LNG vessels built by CSSC’s Hudong-Zhonghua yard under its latest contract CMA CGM. The vessel sailed from Qingdao, China on July 18, making stops at three additional Chinese ports and Singapore. It is bound for Rio de Janeiro and Santos, Brazil, where it was due at the beginning of September.
A month ago, on July 9, the ultra-large container vessel CMA CGM Benjamin Franklin (18,000 TEU), also reportedly lost up to 40 containers in the same region of the South African Indian Ocean area, while also sailing past the country from Asia to Europe. The vessel put into Algoa Bay and finally resumed its trip on July 16.
South Africa has been experiencing a series of strong later winter storms this year. Industry experts had warned that ships would find the routing around South Africa possibly more challenging in addition to the distances required. The storms have disrupted operations with the bulker Ultra Galaxy also being caught in the July storms. The authorities speculate the vessel’s cargo of bagged fertilizer shifted causing the ship to take on a heavy list. After the crew abandoned the vessel, it capsized and washed ashore north of Cape Town. The vessel broke apart in subsequent storms.
Friday, August 16, 2024
Naval Architecture: The Decarbonization Challenge
The design is the easy part. What to design is the challenge.
Glosten is developing the designs for a hydrogen-hybrid coastal-class research vessel
(Article originally published in May/June 2024 edition.)
While much of the discussion about the future of shipping is centered on big concepts like increasing efficiency, alternate fuel sources and decarbonization, naval architects say there is no one solution to the emerging challenges.
The field is having to respond as technologies rapidly mature and regulatory requirements remain a moving target as they continue to evolve and react to public sentiment.
“Operators are asking which alternative fuel they should consider or if batteries or hybrid solutions are an option,” says Sam Waterhouse, Technical Manager for Naval Architecture at Elliott Bay Design Group. “Our advice is always to start with an analysis of their operation. Every vessel is unique.”
A full-service marine engineering and naval architecture firm with a broad portfolio ranging from fishing boats, barges and tugs to passenger vessels and ferries, Elliott Bay knows the future of ship design will evolve to accommodate the future variety of fuel options. Ten years ago the future vision was to convert more ships to liquified natural gas (LNG). Now it will require a more holistic and inclusive approach.
“One of the biggest challenges is the impact specialization has had on naval architecture,” says Donald MacPherson, Technical Director at HydroComp, a developer of software applications that optimize vessel efficiency, including their propellers. He notes that naval architects want to retain control of the system design in areas such as propeller design, driving significant growth for their focused propeller design tools.
“Successful naval architecture requires a vision of the whole project supported by specific staff providing very focused specialized deliverables,” MacPherson adds.
TrueProp Software, a spin-off and now partner company of HydroComp, offers just such a tool for propeller inspections and tuning to maximize performance. “Customers demand more performance and higher efficiencies,” states Adam Kaplan, TruProp’s Chief Technical Officer. “Fuel and emissions are slowly transforming the way we power (and repower) vessels.”
No One Solution
Decarbonization is one of the biggest challenges.
Glosten, a full-service naval architecture and marine engineering consultancy working on innovative projects such as the first hydrogen-hybrid coastal-class research vessel and battery-hybrid pilot boats for San Francisco, says naval architecture involves a consulting role requiring a complete understanding of the options for clients. It requires they educate their own teams as well as clients and sometimes the entire industry. Today, projects involve working with clients to figure out what will be best for the individual situation.
Whether it be methanol, ammonia, hydrogen or a synthetic fuel, vessel designs require adaptation to accommodate alternate fuels. Many of the fuels come with a lower energy density and some have health and safety concerns.
“As a sector, we’re getting smarter about choosing between alternative fuels and electricity,” says Glosten. “Many of our clients are seeking decarbonization, and there isn’t currently a one-size-fits-all solution.”
Decarbonizing a vessel involves more than simply finding the right energy source and adapting the vessel’s structure and systems to accommodate the necessary equipment. The availability of fuel supply or energy sources, the maturity of the technologies and systems that will process it and the infrastructure needed to deliver it are often harder to guarantee than whether or not the solution will work.
“Everything comes back to a good analysis of the operational profile,” says Elliott Bay’s Waterhouse. The industry is optimistic about batteries but the challenge is for them to become more energy dense.
“Currently, battery designs are limited to roughly two to four hours of operation max before recharging or around 10 to 40 miles depending on the size of the vessels,” he adds, saying for the time being batteries will be the solution for ferries and short-sea shipping. Elliott Bay designed a 599-passenger, 15-vehicle, double-ended hybrid-electric ferry for Casco Bay Lines that’s due to start service this year on a 30-minute run between Portland and Peaks Island, Maine.
Cost Considerations
The transition, however, comes at a cost.
Glosten notes that new fuels, technologies and regulations are cost drivers that are particularly challenging for shipowners and operators “who are trying to balance decarbonization with running a business or marine operation.”
Similarly, Elliott Bay’s Waterhouse notes, “The cost of vessel construction has increased drastically over the last five years, making it very difficult for operators to finance new construction.” He says operators now also face the major challenge of meeting future emissions reduction goals.
As new construction costs mount, Elliott Bay has integrated efficiency and economy as core aspects of its vessel designs. Waterhouse expects there will be a “refocusing on other methods to reduce fuel needs. Options include reducing transit speeds, hull optimization and diversifying the fleet so that smaller vessels are used when there’s less cargo to move.”
Glosten says inflation in the cost of building new ships may make owners less likely to build new vessels in favor of keeping existing vessels in service longer. This, however, comes with the challenge of keeping older vessels in compliance with new regulations.
Owners are also looking to tools such as TrueProp, which is seeing increased demand as a solution to improving the operations of in-service vessels. Kaplan points out that “Even a perfectly manufactured, high-tolerance propeller may need to be adjusted to dial in the performance for a vessel. This means that propeller inspection and tuning tools are a critical part of vessel post-design delivery.”
As shipowners work to respond to the emerging constraints from regulatory agencies, HydroComp’s MacPherson says it becomes attractive to look at adding, modifying or replacing components such as propellers, ducts, bulbs, flow-alerting devices or flow-adapted appendages.
“However, from our perspective, everything is a system problem first and a component problem second,” he adds. “Isolating design considerations to individual components can omit reaching meaningful solutions.” He cites, as an example, that modification to the propeller to reduce noise can require additional power and fuel consumption, meaning it has to be reviewed from a systems’ perspective.
Moving Target
Naval architects are also continuing to learn and refine designs and approaches in response to regulatory challenges.
“The dynamic regulatory environment is a simple fact of naval architecture, but because of the many new fuels and technologies that are emerging, changes are occurring at a faster rate,” says Glosten. They note that in the current fluid environment, there can be unintended consequences, such as when previous regulations have come under more scrutiny and are being interpreted differently, making it more difficult to ensure designs work the first time.
“We’ve spent a lot of time figuring out how our decarb projects are going to be approved,” says Tim Leach, a Glosten principal. “It’s not a well-worn path. Every novel design must go through the regulatory approval process, and even when you start the conversation early, when the rubber meets the road and people have to sign off, things can change.”
Among the examples Glosten highlights are design efforts to develop the world’s first hydrogen-hybrid coastal-class research vessel for Scripps Institution of Oceanography. They note that investigatory studies were critical along with the time required to navigate the relatively uncharted regulatory environment around hydrogen use for a research vessel.
Similarly, for the San Francisco Bar Pilots, they recommended a battery-hybrid system that exceeds California’s current emissions requirements because they recognized the likelihood that California’s emissions restrictions could become stricter in the future.
“We also try to future-proof our designs, thinking through what could be coming and making decisions knowing certain regulations may become more stringent.” Glosten says this is hard for obvious reasons but critical to prevent a vessel design from quickly becoming obsolete.
In a related development, a project to develop the first hydrogen-powered towboat in the U.S., a design developed by Elliott Bay, recently reached a Design Basis Agreement with the U.S. Coast Guard establishing a framework to help speed the review, inspection and eventual certification of the vessel.
More to Come
The industry appears to be on the edge of a big change that goes beyond how vessels are powered. Many are speculating about how emerging technologies such as artificial intelligence (AI) and the early exploration of autonomous operations will impact future designs.
As with any major shift, there are growing pains, says Glosten. “All we can do is educate ourselves on emerging technologies and regulations, continue honing our design processes and learn as much as we can about our clients and their needs so we can deliver a vessel that will serve them well and be able to adapt to the changing regulatory landscape.” – MarEx
Allan Jordan is the magazine’s Associate Editor
The opinions expressed herein are the author's and not necessarily those of The Maritime Executive.
German LNG Terminal Operator Sues EU Over Competitor's Subsidy
FSRU dockedi n Stade where construction has begun on the first onshore LNG import terminal (Deutsche Energy Terminal)
Two years after Germany rushed to launch its first onshore LNG import terminals, the operators are struggling to gain the upper hand in the market as they move from temporary operations toward the future energy markets. The operator of the first terminal opened at Stade confirmed on Thursday that it has filed suit against the European Commission in a move to block government subsidies to one of its competitors.
After the Russian invasion of Ukraine, Germany launched an ambitious plan to gain energy independence ending its massive gas imports from Russia. The government led the efforts and formed partnerships with private companies to develop floating storage and regasification facilities. They entered into multiyear charters with the owners of FSRUs that could be docked in major German ports and linked to the existing gas infrastructure. The government reportedly committed up to €740 million for the development of the LNG import infrastructure and operations.
The first of the terminals was established in Wilhelmshaven with the FSRU Hoegh Esperanza and the FSRU Hoegh Gannet which was placed in Brunsbüttel. The partnership Deutsche Energy Terminal was established with the goal of building a permanent facility in Brunsbüttel with financial support through the German industrial bank KfW. The German federal government has a 50 percent stake in the company along with Dutch pipeline operator Gasunie (40 percent) and German energy group RWE (10 percent).
Another one of the onshore import terminals was started nearby in Stade, Germany as part of the Hanseatic Energy Hub. Participants include Buss Gruppe, a Hamburg port logistics company, Swiss investment firm Partners Group, Spain’s Enagas, and US chemical company Dow. The FSRU Energos Force was stationed in Stade.
Separately, Deutsche Regas also established LNG terminal operations in Lubmin and Mukran in eastern Germany. These projects were privately financed by Deutsche Regas. Deutsche Energy Terminal is also scheduled to position another FSRU, Excelsior from Excelerate Energy at a floating terminal on the Jade at Wilhelmshaven later this year.
The long-term plans called for the construction of permanent facilities both in Brunsbüttel and Stade. Work began in June 2024 in Stade to build what is being billed as Germany's first land-based terminal for liquefied gases. The design includes Europe's two largest LNG tanks, each with a capacity of 240,000 cubic meters, which critically are also being built ready for ammonia. The facility is scheduled to be online in 2027.
RWE developed the infrastructure at Brunsbüttel and as planned transitioned it as of the beginning of 2024 to Deutsche Energy Terminals. The plan calls for the construction of a permanent facility at the site which like its nearby rival in Stade is designed to handle a form of hydrogen derivates.
The German government filed with the European Commission and won approval in 2023 to provide a state subsidy for the development of the Brunsbüttel terminal. The European Commission approved an initial amount of €40 million and under certain circumstances, it could increase to a total of €125 million.
HEH is now seeking to block the subsidy arguing that the work at Brunsbüttel could and should proceed without government support. They contend the subsidy encourages the operators to be less economically efficient. They also said a normal business would have raised prices to customers to pay for its expansion.
Ferries to Demonstrate First Green Corridor Operating for a Week on Biogas
Already eco-friendly, the deluxe ferry Viking Glory and her running mate Viking Grace will demonstrate the Baltic green corridor sailing for one week using only biogas (Viking Line)
Viking Line, the Baltic ferry operator based in Finland, plans to demonstrate the future Baltic Green Corridor with special operations between Turku, Finland and Stockholm, Sweden later this month. For one week, two of the company’s ferries will operate using only liquified biogas resulting in a 90 percent reduction in harmful greenhouse gas emissions.
“This is a historic moment for us, the Baltic Sea, and maritime transport,” said Viking Line’s Sustainability Manager, Dani Lindberg. “Scheduled service has never before been powered solely by biofuel. We have invested 450 million euros in our climate-smart vessels Viking Grace and Viking Glory, and one of their most important features is that they can run on LNG, biofuel, and future synthetic fuels produced from renewable energy.”
The company is involved in the efforts to develop a green sea corridor in the Baltic targeting the routes between Turku and Stockholm as well as between Helsinki, Finland and Tallinn, Estonia. While these efforts are ongoing and the supply of biogas is yet to be expanded, Viking Line plans to kick off a special celebration for Baltic Sea Day by demonstrating the world’s first green corridor.
From August 29 to September 4, Viking Glory (built in 2022 and 65,000 gross tons) and Viking Grace (built in 2013 and 57,500 gross tons) will only be operating on LBG. The vessels are equipped to run on sustainable fuel and have run on it for limited periods instead of their normal LNG fuel. Viking explains that while biogas is already a part of its fuel mix today, availability and the price put a damper on it currently. According to the company, when it is available it currently costs twice as much as LNG.
The biogas for the special week will be supplied by Gasum. It will be made in Europe entirely of food and agricultural waste and fully certified. The vessels make an approximate 11-hour trip between the two destinations as well as offering passengers the option of a 24-hour cruise. Viking estimates a week of biogas operations will generate about 2,600 fewer tonnes of greenhouse gas emissions. They equate that to the annual average carbon dioxide footprint of 270 Finns.
Viking drew attention a year ago when it began offering passengers and cargo shippers the option of paying a surcharge for their travel to be with biofuel. The base fee for a passenger adds SEK 26 (approximately $2.50) to the fare. Viking reports when it began highlighting the option on its booking system the number of trips using biofuel increased 500 percent.
Viking Line, the Ports of Stockholm, and the Port of Turku signed a Memorandum of Understanding in 2024 formalizing the efforts to launch the green corridor. Efforts will phase in with the goal for the corridor to be 100 percent carbon-neutral by 2035.
Renewable energy giant Ørsted further highlighted the problems in the nascent sustainable fuel market for the shipping industry highlighting that it was unable to secure a contract at a reasonable for the offtake from its pioneering plant. The company surprised investors by reporting today that it has decided to defer the program known as FlagshipONE, which was under construction and due to begin production in 2025.
FlagshipONE was hailed as a game-changer in 2022 when Ørsted acquired the project while it was in the design phase from Swedish e-fuels company Liquid Wind. Expected to produce around 50,000 tonnes annually of e-methanol the project was using wind power in northern Sweden along with biogenic carbon from the nearby forestry industry. It was to use renewable energy and captured biogenic carbon dioxide in production while sharing steam, process water, and cooling water with a nearby plant and returning excess heat from production into the regional heating system.
“The liquid e-fuel market in Europe is developing slower than expected, and we have taken the strategic decision to de-prioritize our efforts within the market and cease the development of FlagshipONE,” Mads Nipper, Group President and CEO of Ørsted announced during the company’s half-yearly results announcement.
FlagshipONE's construction began in May 2023 with reports saying the company was expected to invest $175 million in the development of the pilot project. They said at the time it would signal a new era in green shipping.
Nipper said the company however was unable to secure long-term contracts for the e-methanol at a “viable price.” Based on this, Ørsted reports it has shut down the project and is taking an impairment charge of over $220 million this quarter related to ceasing execution of FlagshipONE.
“We will continue our focus and development efforts within renewable hydrogen, which is essential for decarbonizing key industries in Europe and closer to our core business,” Nipper told investors.
There continue to be discussions across the shipping industry and regulators about the challenges of developing a supply of sustainable fuels for the industry. One of the big concerns is the anticipated high prices far above traditional fuels with repeated calls for establishing surcharges and funds to help bridge the gap and build demand for the new fuels. Maersk, a strong proponent of methanol, recently admitted continuing challenges and confirmed it was looking at other biofuels and LNG as it moves forward this year with a fleet renewal effort for as many as 50 to 60 ships.
Ørsted’s decision to cease the methanol project comes as the company continues to execute a revised strategy after recording significant charges in 2023 including the ending of two planned large offshore windfarm projects in the U.S. It took further charges this quarter revising the value of the leases but reversed a charge for the Sunrise Wind project in the U.S. which it has decided to move forward after it was successful in its rebid with New York State.
In a further development which Nipped called “frustrating and unsatisfactory,” the company cited further problems in the “early stage” U.S. offshore wind energy market. While saying Ørsted’s portfolio overall is performing well, he said they are now experiencing delays related to Revolution Wind, a 704 MW project that has started construction offshore between Connecticut and Rhode Island.
“Despite encouraging progress on our U.S. offshore wind project Revolution Wind, the construction of the onshore substation for the project has been delayed,” Nipper announced today. “This means that we have pushed the commercial operation date from 2025 into 2026, which led to an impairment.”
The company recorded a nearly $309 million impairment charge due to the delays at Revolution Wind as part of an overall impairment charge of $470 million this quarter for all parts of its business. Reuters quotes Nipper as saying that it is no longer a supply chain problem in the U.SD. wind sector but a specific challenge with substation. He said offshore work at Revolution Wind was “going according to plan.”
Overall, he told investors that Ørsted’s operations are performing well and particularly the earnings from its offshore wind farms. He highlighted that it was maintaining EBITDA guidance for the full year, and increasing earnings expectations for Ørsted’s offshore wind business.
