Energy News Beat

Back in the summer, there were signs that the consensus around Net Zero policy was starting to crack. The Prime Minister, Rishi Sunak then made his speech that watered down some Net Zero commitments and promised “a more pragmatic, proportionate and realistic approach that eases the burdens on families.” However, in the run-up to Christmas, the Department for Energy Security and Net Zero (DESNZ) made several worrying announcements about hydrogen policy.

Unfortunately, the announcements mark the end of the pragmatic approach to the Net Zero insanity and demonstrate that the Government has no idea about economics, thermodynamics or energy and has gone completely insane. Of course, consumers will pick up the tab.

On December 14th, the Government used the distraction of the COP28 meeting to announce updates to its hydrogen policy. There was a new hydrogen production delivery roadmap, an announcement of the results of a consultation on blending hydrogen into the gas distribution network and a strategic policy decision on the same topic.

The Government has a vision of up to 10 GW of hydrogen production capacity to be delivered by 2030, subject to “affordability and value for money”. This capacity would comprise 6 GW of ‘green hydrogen’ produced from electrolysis powered by renewables and 4 GW of ‘blue hydrogen’ produced from natural gas with the emissions captured (CCUS). The trouble is, its roadmap to 2030 only includes 4 GW of capacity and some of that does not deliver until 2031, so its own roadmap will not achieve its vision.

The Government expects its 10 GW vision to produce 60 TWh per year of hydrogen with 33 TWh of the total being blue hydrogen and the balance being green hydrogen. It is fortunate that its route map does not meet its vision because its estimate of hydrogen demand is only 18-40 TWh – well short of the supply of 60 TWh envisaged.

It recognises this mismatch between supply and demand and suggests that transport and storage infrastructure might be in place by then, so some of the excess could be stored. Although why would we want to store lots of hydrogen if supply is exceeding demand by such a vast amount? In case the storage capacity is insufficient, the Government sees “strategic and economic value in supporting blending” into the natural gas distribution network. It sees the gas network as the “offtaker of last resort”, although it has not yet formally taken the decision to blend hydrogen into our gas.

These announcements will have a significant impact on several areas including electricity demand, the size of our energy bills and the overall efficiency of the energy system.

Given the low efficiency of producing hydrogen using electrolysis, the 26 TWh of ‘green’ hydrogen (powered by renewables) would require about 49 TWh of electricity, which is more than the 45 TWh of electricity produced by the entire offshore wind. Even if it only achieves the 4 GW of total capacity outlined in its roadmap, then it would still need 20 TWh of renewable electricity to make the required amount of green hydrogen. It is clear to see that to make the amount of hydrogen in either the lower roadmap or the higher vision, then we would need more electrical generation capacity.

With renewable energy then being largely occupied with making hydrogen, this likely means we would have to burn more gas to keep the lights on, the heat pumps running and the EVs charged. This would be a bonanza for gas suppliers, but mostly those from overseas as the ban on domestic fracking continues. So much for energy security and the COP28 commitment to transition away from fossil fuels.

Even though the Government has committed to a value-for-money test, its hydrogen plans will increase our energy bills. The announced 11 green hydrogen projects were approved at a weighted average strike price of £241 per MWh (in today’s money). This is more than double the £112 per MWh (in 2020 money) that the Government estimated to produce hydrogen using dedicated offshore wind in its 2021 ‘Hydrogen Production Cost Report‘.

To put this in context, U.K. Natural Gas has recently been trading at the equivalent of around £33 per MWh, which is more than seven times less than the proposed cost of electrolytic hydrogen. Moreover, our gas is already about four times more expensive than U.S. gas. The consumer will lose out massively when this extremely expensive hydrogen is almost certainly blended into the gas network. Of course, the developers will be delighted to receive such high guaranteed prices.

These proposals will also reduce the overall efficiency of our energy system. If hydrogen is produced from natural gas with carbon capture (CCUS), around half of the energy in the gas will be lost in the process. In short, this is a crime against thermodynamics. It makes no sense at all to take methane, use it to produce hydrogen and then blend that hydrogen back into the gas network. It adds cost, reduces efficiency and will increase consumer bills. More natural gas will be used to deliver the same energy from the gas network with blended hydrogen, and of course higher demand for gas means higher prices.

The hydrogen roadmap will fail to achieve even half of the Government’s vision for 10 GW of hydrogen production capacity by 2050. Its vision entails producing 50% more hydrogen than even its most optimistic demand forecast, so it wants to fall back on injecting said hydrogen into the gas network. But this plan has not yet passed the required safety tests and will require legislative change to deliver.

The idea of producing more than half of the hydrogen using methane, losing half of the embedded energy in the process and then injecting much of it back into the gas grid is beyond insane. To avoid any doubt the Government’s insanity, it also proposes to produce the remaining hydrogen at a cost that is more than seven times the current cost of gas. Of course, this is all subject to the fig leaf of a value for money test. If value for money was even a secondary consideration this crackpot idea would have been abandoned long ago.

Taken together, these plans will increase the demand for gas and actually decrease the amount of useful energy we get from it. But because the Government has committed to “transition away” from fossil fuels, there are no plans to increase domestic supplies of gas from fracking. No, we will have to import it at great cost from the world’s despots.

Of course, these plans will be a gold mine for gas suppliers, for gas network operators, electrolyser makers and hydrogen producers. For the rest of us, it means much higher energy costs. It will be the end for heavy industry and a disaster for consumers. So much for a more pragmatic, proportionate and realistic approach that eases the burdens on families.

Source: Dailysceptic.org

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The MV Hallaig, a hybrid electric ferry in Scotland, celebrated for reducing emissions, is now running on diesel due to a lengthy £1.5 million battery replacement. The Daily Record has the story.

The MV Hallaig was the first in the world to use a system which cut carbon emissions by 20% when it was launched in 2012.

But the battery broke on the £10 million vessel in September and bosses have admitted it could be April 2025 before it’s fixed because the replacement part is no longer available.

It’s now the third problem ferry in Scotland after the controversy over the MV Glen Sannox and MV Glen Rosa which are six years overdue and £260 million over budget.

Alfred Baird, formerly Professor of Maritime Business and Director of the Maritime Transport Research Group at Edinburgh Napier University, said he was consulted on the hybrid ferries but advised against them. He claims officials at the Scottish Government then complained to his bosses about his work and tried to stop his research being published.

He said: “The strategy was flawed in that it specified use of earlier battery designs that were much heavier than are now available, and operationally riskier – implying they should have continued with more efficient diesel designs until battery technology had improved sufficiently – as was the general industry practice within the ‘commercial’ ferry industry who were waiting on better technology coming along.

“The main weaknesses were therefore, one, inefficient and costly hull designs developed in-house and/or by insufficiently experienced naval architects. Two, the selection of inefficient/early battery technology which led to three higher costs of shoreside infrastructure.”

He added: “My research paper was submitted to Transport Scotland and ferry agencies at the time, also in my role as an independent Member of the Scottish Government’s Ferry Advisory Group, a Ministerial appointment. However, the officials not only ignored my advice, they complained to my university hierarchy about my research and sought to prevent publication.”

Baird’s report claimed the total running cost of the hybrid ferries would be 259% more than a diesel only equivalent. Sturgeon was described as the ship’s godmother and said at the time it “symbolised everything the Scottish Government is striving to achieve”.

It was built at the now nationalised Ferguson Marine in Port Glasgow following more than £20 million of Scottish Government investment.

Source: Dailysceptic.org

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Energy News Beat
The U.S., Eurozone, and Chinese manufacturing indexes all showed contraction at year-end.
Weakness in manufacturing in China, the EU and the U.S. has been weighing on demand for distillates and will likely continue to weigh on global oil demand early in 2024.
For the time being, U.S. diesel and other distillate inventories are accumulating, although they are still below the five-year average.

Continued weakness in manufacturing activity in the United States, Europe, and China eased demand for diesel and other distillates in the fourth quarter, also easing the diesel markets that were very tight at the beginning of the third quarter.

The U.S., Eurozone, and Chinese manufacturing indexes all showed contraction at year-end as the sector entered 2024 with only slight optimism about regaining momentum this year.

The weak manufacturing activity, which has marked most of 2023 in the United States and Europe, and the uneven Chinese recovery have been weighing on demand for distillates and will likely continue to weigh on global oil demand early in 2024—the period in which oil consumption is typically at its weakest.

The weak manufacturing sector has contributed to the decline in oil prices in recent weeks, despite the OPEC+ cuts and the threat of attacks in the Red Sea, Reuters columnist John Kemp notes.

In the United States, economic activity in the manufacturing sector contracted in December for the 14th consecutive month following a 28-month period of growth, supply executives said in the latest report by the Institute for Supply Management (ISM). The U.S. manufacturing purchasing managers’ index (PMI) rose in December to 47.4%, up by 0.7 percentage point from the 46.7% recorded in November, but still below the 50-point mark separating contraction from growth.

The contraction has been persistent over the past year, but it has been shallow, so strength coming from possible interest rate cuts could result in pick-up in manufacturing activity, boosting demand for distillates later this year.

For the time being, U.S. diesel and other distillate inventories are accumulating, although they are still below the five-year average. In the week ending December 29, 2023, distillate inventories jumped by 10.1 million, which compared with a build of 800,000 barrels for the previous week, according to the latest data from the U.S. Energy Information Administration (EIA). Distillate fuel inventories are now about 6% below the five-year average for this time of year.

The surge in distillate, as well as gasoline, inventories in the last week of 2023 sent oil prices lower at the end of last week and at the start of this week, despite the continued threat of Houthi attacks on vessels in the Red Sea and a force majeure in Libya due to protests at its largest oilfield, the 300,000-barrels-per-day Sharara.

U.S. distillate stocks have increased by a little more than 20 million barrels since the middle of November, although stocks are still trending below the five-year average, ING strategists Warren Patterson and Ewa Manthey said last week, commenting on the EIA inventory report.

“The large product builds were predominantly driven by weaker demand,” they noted, adding that “The large distillates build will do little to help end the broader weakness we have seen in middle distillate cracks in recent months.”

Refined product stocks also rose at the start of 2024 in Europe’s key hub

Amsterdam-Rotterdam-Antwerp (ARA) and in Singapore.

Refining margins for diesel in Northwest Europe ended last year 40% below the levels from the end of 2022, despite the EU ban on seaborne imports of Russian petroleum products that came into effect in February 2023.

Europe has imported more diesel from the Middle East and Asia this year to offset the loss of Russian fuel supply. Import levels were high enough to ease fears of a supply shortage in the first winter without Russian fuels, while an industrial slowdown in Europe weakened demand.

In the Eurozone, manufacturing activity contracted for the 18th month in a row in December, the latest survey compiled by S&P Global showed. In China, the official PMI showed a third consecutive month of manufacturing sector contraction and one that was deeper than expected.

Globally, diesel and other distillate inventories are higher now than they were this time last year, suggesting that the global diesel market has started to ease, in part due to slowing construction and manufacturing activity in the United States and major European economies.

Source: Oilprice.com

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As tensions with Venezuela continue to simmer over President Nicolas Maduro’s attempt to annex oil-rich Essequibo from Guyana, the U.S. is sending a top defense official to Guyana to discuss the situation.

U.S. Deputy Assistant Secretary of Defense for the Western Hemisphere Daniel P. Erikson is visiting Guyana on Monday and Tuesday in what the U.S. Embassy in Guyana referred to as a push for a “bilateral defense and security partnership in support of regional stability”. Erikson will be meeting with the Guyanese government and military leaders, as well as with the regional bloc, the Caribbean Community (CARICOM).

In December, Guyana and Venezuela vowed to avoid the use of force in the dispute, which escalated earlier last month after Maduro held a referendum to annex Essequibo, then vowing to force the exit of foreign oil producers who refused to comply.

The Venezuelan parliament has yet to pass a law establishing Venezuela’s jurisdiction over the Essequibo region, which represents two-thirds of the territory of Guyana and is where its oil riches are concentrated.

Maduro is facing elections this year, and there has been significant speculation that the subject of the rightful ownership of Essequibo–a popular topic among Venezuelans–is being used to create a state-of-emergency situation that could justify the postponing of the elections.

In the meantime, an easing of U.S. sanctions on Venezuela, which remains in place despite Maduro’s moves on Essequibo, where Exxon has made massive discoveries offshore, Venezuela’s oil exports rose 12% last year, reaching nearly 700,000 barrels per day.

However, this pace of increase of crude oil exports remains slower than last year, with gains limited in part by a lack of investment necessary to boost production, Reuters reports.

Source: Oilprice.com

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West Qurna 1, holding over 20 billion barrels of reserves, is a key asset in Iraq’s oil industry, with PetroChina now leading its development.
ExxonMobil’s withdrawal from the Common Seawater Supply Project and other Iraqi energy projects opened the door for Chinese and Russian firms to fill the gap.
The change in leadership at West Qurna 1 reflects a broader trend of increasing Chinese influence in Middle Eastern oil markets and the decline of Western hegemony

The official handover of the lead operator role on one of the world’s biggest oil fields – West Qurna 1 – from the U.S.’s ExxonMobil to China’s PetroChina was completed last week. However, unofficially China took control of the supergiant oil field from the moment at the end of June 2018 that ExxonMobil broke off talks with the Iraqi government about it being the lead partner in the country’s Common Seawater Supply Project (CSSP) and began a strategic withdrawal from all Iraq energy projects, as did other Western energy firms. Chinese and Russian firms were happy to step into the project voids created. As a very high-ranking official from the Kremlin said recently at a meeting with senior government figures from Iran: “By keeping the West out of energy deals in Iraq […] the end of Western hegemony in the Middle East will become the decisive chapter in the West’s final demise,” a senior source who works closely with the European Union’s energy security apparatus exclusively told OilPrice.com.

West Qurna 1 is located around 65 kilometres from southern Iraq’s principal oil and export hub of Basra and holds a considerable portion of the estimated 43 billion barrels of recoverable reserves held in the entire supergiant West Qurna field. Originally, West Qurna 1 was thought to have around 9 billion barrels of these reserves, but early in 2021 Iraq’s Oil Ministry revised its recoverable reserves estimate for the field up to a total of over 20 billion barrels. Given this, the Ministry increased the target for the present phase of development from the previous 500,000 barrels per day (bpd) to 700,000 bpd, with the field currently producing around 550,000 bpd. The Ministry also said at that time that although the original production plateau target of 2.825 million bpd (by the early 2030s) had been negotiated down to 1.6 million bpd during contract discussions with participating oil companies at the time, the plateau target may well be raised again in the coming five years.

The main companies involved in those discussions were PetroChina – the listed arm of the China National Petroleum Corporation (CNPC) – which then completed the purchase of a 32.7 percent stake in West Qurna 1, and ExxonMobil, which also took a 32.7 percent stake. Almost immediately, PetroChina sought to establish itself as the dominant force on the site. As analysed in full in my new book on the new global oil market order, the strategy employed to effectively sideline ExxonMobil is one that China has repeatedly used in similar situations across the Middle East, with a key element being the often surreptitious and gradual acquisition of a range of huge ‘contract-only’ awards made to Chinese companies. The most notable of these early on was the November 2019 US$121 million engineering contract to upgrade the facilities that are used to extract gas during crude oil production to the China Petroleum Engineering & Construction Corp. Similar ‘contract-only’ deals have been done by China across Iraq, including for its supergiant Majnoon oil field, to another hitherto unheard-of Chinese firm – the Hilong Oil Service & Engineering Company.

This incremental loss of influence across the West Qurna 1 project was one of ExxonMobil’s problems. Another potentially far greater one emerged as the U.S. supermajor discussed its other major targeted deal in Iraq – the US$53 billion CSSP. At that time, both projects were to form a new core presence for the U.S. in Iraq based around cooperation in the energy sector with the Iraq authorities, following years of rising military and sectarian tensions across the country. The CSSP is the key to Iraq’s being able to jump from its long-running oil production of around 4-4.5 million bpd to 7 million bpd, then 9 million bpd, and perhaps even 12 million bpd, as also analysed in depth in my new book on the new global oil market order. This would allow it to become the world’s second-biggest crude oil producer, after the U.S. and ahead of Russia and Saudi Arabia. The CSSP involves taking and treating seawater from the Persian Gulf and then transporting it via pipelines to oil production facilities in order to maintain pressure in oil fields to optimise their output and longevity. The basic plan for the Project is that it will be used initially to supply around six million bpd of water to at least five southern Basra fields and one in Maysan Province, and then built out for use in further fields. However, both the longstanding stalwart fields of Kirkuk and Rumaila – the former beginning production in the 1920s and the latter in the 1950s, with both having produced around 80 percent of Iraq’s cumulative oil production – require major ongoing water injection. Although the water requirements for most of Iraq’s oilfields fall between these two cases, the needs for oilfield injection are highest in southern Iraq, in which water resources are also the least available.

ExxonMobil was brought into the CSSP initiative when it was first announced in 2010, to take the lead in co-ordinating initial studies for the plan at a time when Baghdad was looking to raise its oil production capacity to 12 million bpd by 2018, to overtake Saudi Arabia’s output. The U.S. firm was then removed in 2012 when negotiations fell through, and replaced by the state-run South Oil Company. By that time, it had become increasingly clear to the Americans that the Project was infused with massive risks to it that far outweighed the admittedly considerable rewards. Fully detailed in my new book, suffice it to say here that there were three key elements to the risk/reward matrix that formed the basis of those negotiations between ExxonMobil and the Oil Ministry. These were cohesion, security, and streamlining, a senior source who works closely with the Ministry exclusively told OilPrice.com at the time. “Cohesion related to ensuring the facilities that are connected to the CSSP are completed in order and in full, security related to the on-the-ground security of personnel and to the basic soundness of the business and legal practices involved in the agreement, and streamlining meant that any deal should continue as agreed, regardless of any change in government in Iraq,” he said. “The basic problem was that the [Oil] Ministry and other officials connected with the CSSP expected to receive commissions for anything they did, which might look a lot like bribery if they ever came to light, but if the payments weren’t made then the project simply would not have progressed,” he added. “The standard commission here is 15 percent, but it can rise to 30 percent or more, so with the development cost having risen to US$53 billion, Exxon[Mobil] was looking at under-the-counter payments of nearly US$8 billion, and that’s difficult to hide in any accounts, even if it wanted to do so,” he told OilPrice.com.

According to the source (and corroborated to OilPrice.com by two other senior sources connected to Iraq’s Oil Ministry at the time), ExxonMobil tried again in 2015 to reset negotiations with the Ministry back onto a normal business level by insisting that all the contracts relating to the CSSP were designed by independent Western risk experts and lawyers, and administered by independent Western accountants, but such demands came to nothing. “Ultimately, Exxon[Mobil] was not willing to take the risk to its reputation or to that of the U.S. government, and could not move forward with the CSSP, and it was from that point that it also started to look seriously at getting out of West Qurna 1 as well,” the source said.

CNPC then tried to take up the CSSP where ExxonMobil had left off – as part of a broad-based set of deals with Iraq that gave China huge discounts on oil and gas produced, as also analysed in depth in my new book – but made very little progress. Thereafter, no real progress was made until the Oil Ministry eventually agreed to allow France’s TotalEnergies to move ahead with it as part of a four-pronged US$27 billion deal. According to source close to the Ministry, the government again sought to inveigle the French supermajor into similar arrangements that it had tried on ExxonMobil, but TotalEnergies stood firm as well – which was why the deal was postponed repeatedly until it was recently ratified. How this will pan out for the French is uncertain, as the overall drift of Iraq into the China-Russia sphere of influence continues.

Source: Oilprice.com

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America is the world’s largest natural-gas producer, but New Englanders’ capacity to stay warm in winter may hinge on the fate of an expensive, 53-year-old import plant that its owner has threatened to shut down.

Constellation Energy plans to retire a Massachusetts power plant at the end of May. That will eliminate the biggest user of the liquefied natural gas, or LNG, that is imported through the company’s neighboring Everett Marine Terminal. Constellation said it is trying to line up new gas buyers to keep the terminal running. If it cannot, it will likely close the import facility as well.

But New England utilities rely on imported LNG to keep them supplied in winter when demand peaks. Without it, severe cold could leave them, and their customers, in a bind, the utilities have said in public hearings and in letters to regulators.

The situation on the Mystic River shows that despite 25 years since the first shale well was fracked in Texas, the benefits of the American drilling boom remain unevenly distributed. Swaths of the country are flooded with cheap gas, and export facilities have cropped up to sell the excess overseas. Other areas, including New England, are bereft of fuel and pay up for energy.

New England residents paid about 43% more for natural gas in the first quarter of 2023 than the U.S. average, according to the Energy Information Administration.

Weaning off those supplies without shortages during the coldest days is also emblematic of the challenges involved in a smooth transition from fossil fuels to renewable energy.

National Grid, which has more than two million gas customers in Massachusetts and New York, feeds fuel from Everett into its pipelines around Boston and also trucks it to storage tanks across the region ahead of each winter, said James Holodak Jr., the utility’s vice president of energy supply.

“We don’t see any other near-term plausible solution in the event that Everett closes if gas demand does not decline as drastically as some may anticipate,” Holodak told federal regulators at a hearing last year.

A big issue is how to cover the terminal’s overhead, most of which is currently recouped through New England electricity bills tied to the nearby power plant.

Constellation said it would close the Mystic Generating Station at the May 31 expiration of that deal with regulators, a two-year agreement intended to bolster the region’s energy supplies.

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The partners behind the Ksi Lisims floating LNG project in Canada have signed the first long-term offtake deal with a unit of LNG giant Shell.

Under the 20-year SPA, Ksi Lisims will supply 2 million tonnes of LNG per year on a free-on-board basis to Shell Eastern Trading

The partners behind Ksi Lisims LNG are the Nisga’a Nation, Rockies LNG, a limited partnership comprised of Canadian natural gas producers, and Houston-based Western LNG.

Ksi Lisims said in the statement it would continue to work toward reaching a final investment decision, but it did not provide any additional details.

It previously said that construction of the project is expected to take three to four years, and that commercial operations could start in 2028.

In July last year, US-based engineer Black & Veatch and South Korean shipbuilder Samsung Heavy Industries won a contract for the Ksi Lisims LNG nearshore floating production facility in northwest Canada.

Ksi Lisims LNG plans to produce 12 million tonnes per annum of LNG from two floating production and facilities which will have integrated storage with an aggregate capacity of about 450,000 cbm of LNG.

The proposed facility will have an all-electric process technology developed by Black & Veatch and will be located at Wil Milit on the northern point of Pearse Island, British Columbia.

In July 2021, the Nisga’a Nation, Rockies LNG, and Western LNG filed the initial project description for Ksi Lisims LNG with the local and state governments, while in December 2022, the Canada Energy Regulator (CAR) approved an application from Ksi Lisims LNG to export LNG for a period of 40 years.

Ksi Lisims LNG also filed an application with the B.C. government for an environmental certificate on October 16, 2023.

 

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Australia Pacific LNG, the operator of the 9 mtpa LNG export facility on Curtis Island near Gladstone, has signed a deal to supply additional gas to the domestic market.

According to a statement by APLNG, the producer has signed a contract to extend the supply of gas to mining and infrastructure solutions provider Orica to 2025.

Orica produces explosives, blasting systems, and mining chemicals used to mobilize the earth’s resources.

Under the contract, APLNG will supply an additional 2.92PJ of gas in 2025.

APLNG’s CEO Khoa Dao said the agreement was a “further demonstration of Australia Pacific LNG’s commitment to supplying the east coast gas market.”

Orica’s current contract was struck as a result of tenures granted to APLNG that included domestic supply conditions specifically focused on supporting manufacturing.

At the end of 2023, APLNG contributed over 142 PJ of supply to the domestic market and expects to supply a further 151 PJ in 2024.

In 2022, US energy giant ConocoPhillips completed the purchase of an additional 10 percent shareholding interest in APLNG from Origin Energy for about $1.64 billion.

ConocoPhillips has a 47.5 percent share in the project but it also operates the LNG export facility on Curtis Island and the export sales business.

Origin Energy operates APLNG’s gas fields and holds a 27.5 percent share, while China’s Sinopec owns a 25 percent share in APLNG as well.

 

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Finnish state-owned energy firm Gasum will buy e-methane from Nordic Ren-Gas to supply it to its customers in the heavy-duty road transport sector and the maritime industry.

Gasum and Nordic Ren-Gas have signed a long-term sales and purchase agreement whereby Gasum will buy all of the e-methane produced by Nordic Ren-Gas at its Tampere power-to-gas plant from 2026 onwards.

The plant in Tampere will produce annually 160 gigawatt hours (GWh) of e-methane, according to a joint statement.

Moreover, it will produce e-methane using renewable electricity from Finnish wind power and biogenic CO2 captured from existing power plants.

In the power-to-sas process, hydrogen is first produced using renewable electricity and water.

Hydrogen is then further processed into e-methane by combining it with biogenic carbon dioxide.

Gasum said e-methane will replace fossil fuel usage in transportation, maritime, and also industrial sectors.

The firm said the fuel is fully interchangeable with natural gas and biogas. When it is liquefied it is likewise fully interchangeable with liquefied natural gas (LNG) and liquefied biogas (LBG).

This means that it can be transported through already existing infrastructure – trucks, ships, pipelines, Gasum said.

E-methane can be directly used in gas engines currently running on natural gas, biogas, LNG, or LBG/bio-LNG and it can be blended in at any ratio, it said.

Gasum’s strategic goal is to bring 7 TWh of renewable gas yearly to the Nordic market by 2027.

The firm operates a network of LNG filling stations for vehicles. It also supplies LNG to vessels via a fleet of chartered bunkering vessels.

 

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