At current fuel prices, transport work that would cost a fleet operator around ₹85 using 1 kg of LNG would cost roughly ₹146.75 on diesel, making LNG nearly 42 per cent cheaper, and anywhere between ₹96 and ₹110 on CNG depending on the city, giving LNG an additional cost advantage of roughly 12–23 per cent over CNG.

Yet while the government approved ₹4,573 crore in support for ethanol distilleries and helped mobilise nearly ₹40,000 crore in private investment for blending infrastructure, Vadodara-based cryogenic engineering company INOXCVA has approached the Ministry of Petroleum & Natural Gas (MoPNG) seeking ethanol-style support for LNG infrastructure, storage and freight-corridor development.

https://www.thehindubusinessline.com/economy/lng-42-cheaper-than-diesel-for-trucks-as-industry-seeks-ethanol-style-policy-push/article71047011.ece

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Currently, India has government support for ethanol infrastructure, but not for LNG, which is now 42% cheaper than diesel for the freight industry, industry executives told Indian outlet BusinessLine.

“Historically, LNG adoption has been constrained more by infrastructure availability than economics,” Deepak Acharya, Managing Director at cryogenic engineering company INOXCVA, told the publication.

The firm has approached India’s Ministry of Petroleum and Natural Gas with a call for support for LNG infrastructure, storage, and freight-corridor development, similarly to how India is currently backing the ethanol industry.

The recent spikes in diesel and compressed natural gas (CNG) prices due to the oil and gas price rally following the Iran war have made LNG for trucking even more competitive, according to industry executives.

Last week, India’s state-owned energy majors that trade in fuels raised prices at the pump for the fourth time in the space of a month, reflecting the continued effect of the Strait of Hormuz closure on oil and fuel flows.

The cumulative price hike since the start of the month comes in at 8.6% for diesel fuel and 7.8% for gasoline.

The first fuel price hike took place in Mid-May, with refiners including Indian Oil Corp., Bharat Petroleum Corp, and Hindustan Petroleum Corp. hiking their retail prices by over 3% for the first time in four years.

Since the war in the Middle East began and cut off over 40% of India’s crude oil flows, those that passed through the Strait of Hormuz, one of the highest-flying economies in Asia, has seen its oil import bill soar, investors fleeing the capital market, and the local currency plunging to an all-time low against the U.S. dollar.

The Indian government, meanwhile, has called for fuel conservation, including through working from home, carpooling, and using public transport instead of personal vehicles.

https://oilprice.com/Latest-Energy-News/World-News/Indias-LNG-Industry-Pushes-for-Government-Backing-as-Diesel-Costs-Surge.html

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Touraj Dehqani said the platforms had not been damaged. He said production from the three platforms was being routed to other processing plants in the region while repairs continue at damaged facilities, including the Phase 14 refinery.

https://gcaptain.com/three-offshore-platforms-resume-production-at-irans-south-pars-gas-field/

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Eng. Karim Badawi, Minister of Petroleum and Mineral Resources, reviewed the launch of drilling activities aboard the drilling vessel Stena Forth, recently arrived in Egypt to begin operations at the field.

The Minister said that the drilling of the new well is part of the Ministry of Petroleum and Mineral Resources’ strategy to encourage international energy companies to accelerate the development of untapped gas discoveries, including the Nargis Field, and bring them into the development and production portfolio.

The Egyptian government is encouraging investment and incentivising exploration and production to reverse years of decline and reduce energy imports, a drive which is being given additional impetus by the current situation in the Middle East. These efforts seem to be paying off, with a high level of exploration activity and a number of promising discoveries being made.

The most recent is the discovery by Agiba Petroleum Company, the joint venture between the Egyptian General Petroleum Corporation (EGPC) and Eni, in the Western Desert, representing the company’s most significant discovery over the past 15 years.

The Ministry announced that the discovery was achieved through the South Bostan-1X exploratory well, drilled using the EDC-9 rig operated by the Egyptian Drilling Company (EDC). Preliminary estimates indicate reserves of approximately 330 bcf of gas and 10 million bbl of condensates and crude oil, with total estimated recoverable reserves reaching 70 million bbl of oil equivalent.

The significance of the new discovery is further enhanced by its proximity to existing facilities and infrastructure, which will enable its rapid development and swift tie-in to the production network.

The well encountered multiple sandstone and limestone reservoirs, with a net pay thickness of 400 feet, highlighting the discovery’s strong economic potential and production significance.

The new discovery reflects the success of the Ministry of Petroleum and Mineral Resources’ incentives to encourage partners to intensify exploration activities in areas adjacent to existing fields. This approach has facilitated the identification of new discoveries in close proximity to established infrastructure and production facilities, eliminating the need for significant new infrastructure investments. As a result, development costs are reduced, time to first production is accelerated, and operating efficiencies are enhanced

In early May Eni made a new natural gas discovery in the Nile Delta region, with estimated production rates of around 50 Mmcf/d, following its gas and condensate discovery in the Temsah concession in the Eastern Mediterranean in April, with preliminary estimates of about 2 trillion cubic feet of gas and 130 million barrels of associated condensates.

Also this year, Dragon Oil announced a new oil discovery following the successful drilling of the South El Wasl ‘B.B2’ exploration well in the Gulf of Suez, with initial results indicating production rates above 2,000 bpd of oil. While US Apache, in collaboration with the Egyptian General Petroleum Corporation (EGPC), made a new natural gas discovery in the Western Desert, following the drilling of the SKAL-1X exploratory well in the South Kalabsha area, with initial test results indicating a daily production rates of approximately 26 million cubic feet (mmcf) of natural gas and 2,700 barrels of condensate.

https://oilreviewafrica.com/exploration/exploration/chevron-drills-new-well-in-nargis-gas-field-offshore-egypt

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The company said its Port Arthur Pipeline Louisiana Connector project is now complete and in-service, providing additional gas carrying capacity for Gulf Coast regional market and for a forthcoming liquefied natural gas export project.

The Louisiana Connector was built to feed supplies to the Port Arthur LNG Phase 1 export facility, just east of Houston.

Port Arthur LNG Phase 1 is under construction and, when complete, will be able to process and ship up to 13 million tonnes per auum of LNG, according to Port Arthur LNG.

Sempra’s new line also aims to supply additional natural gas storage capacity being built in Louisiana.

The company said the line improves its ability to move gas to customers throughout the region.

“Additionally, the pipeline strengthens domestic energy networks by interconnecting with Sempra Infrastructure’s Gillis Hub Pipeline, a highly connected natural gas pipeline header system in Southwest Louisiana’s energy corridor,” the company said.

The new pipeline’s price tag was put by Sempra at $1 billion. Port Arthur LNG Phase 1 is estimated to cost some $13 billion once completed.

https://www.upstreamonline.com/lng/new-gas-pipeline-ready-to-feed-us-lng-project/2-1-2001692

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The more the pipeline costs, the more its builders will need to charge for gas shipped through it in order to make money. But if the cost of Alaska gas is too high, it isn’t competitive with gas from other sources around the world.

On Tuesday, members of the House Finance Committee met for the second time in a 30-day special session devoted to discussing the tax break.

Nick Fulford of GaffneyCline, the Legislature’s hired analyst for the pipeline project, said previously published financial modeling by the Alaska Department of Revenue remains the best public look at whether the project pencils out financially.

“The main question really is: How much bigger and how much more capital cost can the project support before it becomes uneconomic,” he said.

In 2018, officials with the Alaska Gasline Development Corp. suggested that building a pipeline from the North Slope to Cook Inlet — plus large industrial processing plants on either end — would cost roughly $43.4 billion, including money earmarked for possible cost overruns.

Since then, the official cost has risen only slightly, to $46.2 billion, but many state lawmakers have said they are skeptical of that figure, because it does not seem to account for inflation.

Glenfarne, a multinational corporation that now owns 75% of the pipeline project, has not disclosed an updated figure.

Representative Alyse Galvin, I-Anchorage, said that when she uses the Consumer Price Index to judge how much the cost has grown, it’s significant.

“When I look at cost adjustment, just using CPI, just a straight cut through, that brings us to $57 (billion) to $60 billion,” she said during Tuesday’s hearing.

 “I would say it seems highly likely that it would be more than $46 billion given the general inflation that we’ve seen,” Fulford said.

Publicly available estimates suggest gas could be bought from North Slope producers between $1 and $2 per thousand cubic feet. That’s what’s technically known as the “upstream price.”

In a scenario where the pipeline costs Galvin’s suggested figure, the state’s tax laws don’t change to help the project and the upstream price is $1.50 per thousand cubic feet of gas, the Department of Revenue estimates that an end buyer in Japan could expect to pay more than $11 per thousand cubic feet.

That’s likely a problem for the pipeline project, because according to GaffneyCline’s estimates, the average contract price in Japan over the past 10 years has been $10.41 per thousand cubic feet — less than what the Alaska project would have to charge to earn its expected profit target.

Under a tax change proposed by the governor, the end buyer’s price would drop to about $10.40, using Galvin’s cost estimate and the $1.50 upstream price.

But if the cost of upstream gas rises, or if the cost of the pipeline rises, even the governor’s proposed tax break isn’t enough to keep the project economically competitive.

Fulford, speaking to the House Finance Committee, said he thinks Asian LNG prices will rise in the coming years, possibly offsetting any rising costs and keeping the project viable.

But he also acknowledged that with so many unknowns, it’s not clear where the project becomes uneconomic.

“The question is … if the price of LNG goes up and if the capital cost goes up, then where’s that sort of tipping point where the project can still go ahead, even if it’s a much higher capital cost?” he said.

Under Dunleavy’s proposal, the state’s existing petroleum property tax would be largely replaced by a tax on gas that moves through the pipeline.

Speaking last week in Anchorage, Glenfarne CEO Brendan Duval said the governor’s proposed change is necessary for Glenfarne to get financing for the project.

“It won’t be financeable in the form that we’re trying to do it without the tax stabilization law,” he told the Anchorage Daily News.

Legislators appear favorable to the general idea, but they don’t know what tax rate to use for the “alternative volumetric tax,” as it is formally known.

Dunleavy has proposed 6 cents per thousand cubic feet of gas. House and Senate lawmakers are each considering different, higher rates.

They’re also considering mandatory impact payments to compensate cities and boroughs that collectively would lose out on $14 billion in property taxes through 2063 if the governor’s plan is adopted. A mandatory natural gas spur line to Fairbanks is also being discussed. As currently planned, the pipeline runs to the west of Fairbanks.

Representative Calvin Schrage, speaking Tuesday, said legislators are working with a large amount of uncertainty, and that is slowing their work.

“If we could eliminate some of these variables and have it known, it would really help us in figuring out where this might be going, but we don’t have that right now,” he said. “What this is ultimately showing is that under our current tax structure, there’s a very small window of break-even profitability for a developer.”

https://kiowacountypress.net/content/proposed-alaska-gas-pipeline-has-narrow-window-viability-estimates-suggest

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The deal provides for the purchase of 1 million tonnes of LNG per year for a period of up to 20 years. The agreement, announced on May 27, 2026, is subject to the execution of a definitive sales and purchase agreement.

Deliveries are expected to begin in the early 2030s from the future Ksi Lisims LNG export facility, planned on the Pacific coast of British Columbia, Canada.

SEFE to buy LNG from British Columbia

Ksi Lisims LNG is a project developed by Western LNG, Rockies LNG, and the Nisga’a Nation. The proposed facility will have an export capacity of 12 million tonnes of LNG per year, which would place it among Canada’s largest liquefied natural gas export plants.

According to SEFE, the supply will be contracted on a free on board basis, giving the buyer flexibility to manage the cargo’s destination within the international market.

Canada’s Minister of Energy and Natural Resources, Tim Hodgson, stated that the agreement reflects Canada’s positioning as a reliable energy supplier in a global environment marked by volatility and uncertainty.

Germany seeks to diversify its supply

For Germany, the agreement is part of an energy diversification strategy following the reduction in Russian gas supplies and the geopolitical tensions affecting international energy markets.

SEFE, whose full name is Securing Energy for Europe, already has LNG supply agreements with companies such as Venture Global, Southern Energy, and the Turkish state-owned company BOTAS.

Germany’s Minister for Economic Affairs, Katherina Reiche, noted that cooperation with Canada strengthens a strategic energy partnership and helps make supply chains more resilient to global risks.

Ksi Lisims moves toward a final decision

The agreement with SEFE represents an important step for Ksi Lisims LNG, whose sponsors are working to sign sales and purchase agreements before making a final investment decision.

The project is at a key stage of development and is part of Canada’s efforts to expand its energy exports to markets other than the United States.

Although Asia has historically been considered the natural destination for Canadian LNG due to its proximity from the Pacific coast, European interest has increased amid the need to diversify supply sources.

The project faces regulatory challenges

Canada is seeking to accelerate major energy projects through mechanisms designed to streamline regulatory approvals. However, Ksi Lisims LNG still faces technical, environmental, and social challenges.

Several Indigenous groups have questioned the pipeline infrastructure needed to supply the plant, while environmental organizations have criticized the government’s push for new fossil fuel developments.

Even so, the agreement marks a milestone for Canadian energy policy and for Germany’s supply security strategy.

If it moves forward toward a definitive contract and a final investment decision, Ksi Lisims LNG could become a significant component of energy trade between Canada and Europe over the coming decades.

https://inspenet.com/en/news/canada-signs-its-first-lng-agreement-with-a-european-buyer/

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The decision has been taken after the completion of an open season procedure earlier this year aimed at securing contracts with gas suppliers and traders to deliver LNG to the terminal between 2028 and 2036, the terminal said in a statement on Monday.

The Dutch government has provided EemsEnergyTerminal with a guarantee to cover part of the remaining project risks and thereby ensure the extension of the terminal, it said.

The final investment decision will be taken once necessary permits have been obtained, the terminal said.

With the second FSRU installed, the facility will have a storage capacity of approximately 190,000 cubic metres of LNG and provide customers with direct access to the Dutch TTF gas market, one of Europe’s most liquid marketplaces for natural gas.

A significant part of the offered capacity has been contracted under the open season procedure, the statement said. EemsEnergyTerminal is holding discussions with various parties for the remaining capacity, offered on a first come, first served basis.

The LNG terminal was rapidly developed in 2022 to open up alternative sources of natural gas imports after Russia’s Gazprom halted pipeline gas supplies to Europe, retaliation for sanctions imposed upon Russia and its corporations following the invasion of Ukraine.

The terminal was originally intended to operate until the end of 2027. However Gasunie and Vopak – who each hold a 50% stake in the project — have been in discussions sine 2024 with Belgian infrastructure developer Exmar to extend the FRSU contract.

Capacity growth

The EemsEnergyTerminal currently has an import capacity of 8 billion cubic metres of gas per year. Onсe the second FRSU arrives at Eemshaven, total capacity will rise close to 14 Bcm per annum, according to Exmar.

In April, Exmar said it launched the conversion works for the second FSRU for the terminal.

The move followed the signing of the conditional charter party covering both the extension of the existing Eemshaven LNG FSRU and a newly converted FSRU, according to Exmar.

Exmar said it has secured a second hand LNG carrier for the conversion project, a dual-fuel diesel-electric membrane vessel, however, has withheld its name and the previous owner.

However, Upstream sister title Tradewinds reported in April that the vessel is understood to be the Maran Gas Troy.

Exmar also initiated engineering activities and ordered a 750 million standard cubic feet (about 21.2 million cubic metres) per day LNG regasification plant from Wartsila Gas Solutions of a type that has previously been used in several Exmar-led FSRU and LNG carrier regasification projects.

https://www.upstreamonline.com/lng/dutch-lng-terminal-moves-closer-to-import-capacity-expansion/2-1-1997597

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Ukraine has secured an important energy agreement with Lithuania for the long-term supply of liquefied natural gas (LNG) through the Klaipeda terminal, as announced by Ukraine’s Prime Minister Yulia Svyrydenko during her visit to Lithuania.

Svyrydenko confirmed that the agreement ensures the booking of capacity for continuous LNG supply to Ukraine, with potential imports from both U.S. and Middle Eastern producers. This development strengthens Ukraine’s energy security following intensified Russian assaults on the country’s gas production facilities last year.

At a joint press conference with Lithuanian Prime Minister Inga Ruginiene, Svyrydenko highlighted Ukraine’s offer to use its underground gas storage facilities, signaling an increased cooperation between the nations in tackling energy challenges.

(With inputs from agencies.)

https://www.devdiscourse.com/article/science-environment/3928307-ukraine-secures-long-term-lng-deal-with-lithuania?amp

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The success of this trial hinges on a fully self-developed hydrogen-coal mixed low-nitrogen burner. Deployed on a 40-megawatt coal-fired boiler, the technology achieved a 50 percent heat-ratio hydrogen co-firing, said CHN Energy, the country’s largest coal-fired power generator by capacity.

This achievement directly translates to a staggering 50 percent reduction in both coal consumption and carbon emissions, coupled with highly effective synergistic nitrogen emission reductions, setting a new technical benchmark for clean power generation worldwide, it said.

Industry experts believe that as coal still plays a key role in China’s energy consumption, the green and low-carbon transition of the coal power industry is paramount to realizing the country’s ambitious “dual-carbon” goals.

This technological leap pioneers an effective pathway for massive carbon reductions in existing coal-fired units and stands as a significant milestone for the integration of coal power with renewable energy sources, they say.

Despite the rapid global march of green energy, China Academy of Engineering academician Hao Jiming emphasized that the “ballast stone” role of traditional coal power remains essential for grid stability.

China’s fundamental energy reality is characterized by “abundant coal and scarce oil”, meaning coal will continue playing a key role for the country in the near term, said Hao.

Because wind and solar power are inherently intermittent and subject to weather fluctuations, the reliable baseline generation capacity and flexible regulatory power of traditional coal facilities are temporarily irreplaceable for national energy security, he said.

This reality makes the low-carbon transformation of coal power exceptionally urgent.

Chen Zongfa, chief expert at the China Electricity Council Expert Group, said low-carbon retrofitting is no longer an elective course for coal power enterprises, but a mandatory one.

While acknowledging that green hydrogen co-firing currently faces high short-term costs and relies heavily on regions with abundant renewable resources and stable green ammonia supplies, Chen said targeted investment and technological innovation will lead to widespread application in the mid-to-long term.

China has already sounded the bugle for a new generation of coal power upgrades. Under the action plan for accelerating the construction of a new power system released by the National Energy Administration, upgrading coal power is a central mission.

The policy emphasizes clean and low-carbon operations, efficient regulation, rapid load shifting and deep peak shaving. Implementing zero-carbon fuel co-firing alongside carbon capture, utilization and storage technologies is explicitly highlighted as a crucial strategy to drastically slash coal power emissions, according to the plan.

Pan Yuelong, supervisor of the CEC, said that through ongoing energy-saving, ultra-low emission, and flexibility retrofits, coal power is already providing a vital foundational guarantee to the grid.

“Relying on scientific innovation, industrial optimization, policy support and international cooperation, we will gradually transition coal power from a primary power source to a foundational and regulatory one,” Pan said.

https://www.chinadaily.com.cn/a/202606/10/WS6a28c2bba310d6866eb4d657.html

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