While developing hydrogen pipelines is essential, high costs — 70-80 per cent from materials, labour, and construction — and challenges like securing rights of way make repurposing underutilised pipelines appealing, the report reviewed by Business Standard said. “India’s LNG import terminals could be retrofitted to handle the export of GH2 derivatives such as ammonia. Clear cost advantage arguments are evident for repurposing LNG import terminals,” the report by US-based energy think tank RMI and the IPA pointed out.

Produced using renewable energy (RE) sources, green ammonia is a sustainable form of ammonia (NH₃), and serves as a versatile energy carrier, fertiliser feedstock, and clean fuel alternative. The National Green Hydrogen Mission is currently targeting production of 5 million tonnes of GH2 by 2030 to provide an alternative to imported crude oil for transportation, industrial uses, and energy storage.

According to the study, constructing greenfield ammonia terminals with a capacity of 5 million tonnes per year is estimated to cost ₹20,401-21,209 crore. In contrast, repurposing LNG terminals — either after or before commissioning — would cost approximately ₹14,766-12,581 crore, assuming a 30-year operational lifespan.

Dedicated frameworks for common user infrastructure such as intra-port pipelines, storage units, electricity transmission and distribution, water and CO2 (carbon dioxide) pipelines have also been suggested.

“This will be fundamental in establishing GH2 facilities, enabling ports to become central hubs. Emerging port hubs could serve both domestic and export markets, leveraging their proximity to industrial clusters such as fertiliser producers and refineries, presence of existing infrastructures like storage and distribution systems, access to international trade, and the captive demand from shipping and logistics operations,” the report said.

The report also suggested ports to act as energy aggregators by partnering with distribution companies and independent power producers to pool demand from existing port industries — the scale would allow them to secure RE at lower prices.

Challenges remain

However, retrofitting comes with its own set of challenges. According to the study, hydrogen’s unique properties, such as lower density and the risk of embrittlement, require significant upgrades to materials, equipment, and safety systems.

 “Hydrogen’s higher susceptibility to leaks means that each component of the existing infrastructure must be thoroughly analysed for technical limitations, including pipeline compatibility, leakage risks, and the need for enhanced monitoring systems,” it said.

India currently operates eight LNG terminals run by state-owned companies such as Petronet, NTPC, and Indian Oil, as well as private entities lime Shell, among others. The cost of retrofitting or converting these terminals for ammonia would be around $105 per tonne, the report said.

Existing terminal operators would also need to come on board. “Beyond Petronet’s terminal Dahej, most regasified LNG terminals have struggled with low capacity utilisation due to insufficient pipeline connectivity, a gas market that is still developing, and lack of coordinated planning. But another crucial factor is the limited number of long-term contracts signed between terminals and major offtakers,” an official from a public sector energy major said.

The government wants to position India as an export hub for GH2 and green ammonia. The report suggested that east coast ports like Tuticorin and Paradip are strategically located to serve major Asian demand centres like Japan, Singapore, and South Korea. These countries are expected to require significant green ammonia imports, and 4.4 million tonnes of hydrogen equivalent as part of their decarbonisation goals by 2030. Similarly, west coast ports can service European demand, which has projected a 10-million-tonne hydrogen import by 2030.

https://www.business-standard.com/industry/news/repurpose-lng-infra-to-make-ports-gh2-export-hubs-say-ports-body-125070201075_1.html

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This shift is part of ONGC’s strategy to achieve net-zero targets for scope 1 and scope 2 emissions by 2038. The company has committed an investment of ₹2 trillion by 2038 across multiple decarbonisation initiatives, including energy efficiency, flare reduction, renewables, green hydrogen, green ammonia, compressed biogas, pump storage, and carbon capture units.

Declining crude oil production, ageing oilfields, and the absence of major discoveries in recent decades have posed significant challenges for India’s hydrocarbon sector. Domestic crude oil production dropped from 37.9 million tonnes (mt) in 2010-11 to 28.7 mt in FY25 — a fall of 24 per cent. Natural gas production also fell from 39,753 million standard cubic metres (mscm) to 36,113 mscm in FY25, a drop of 9 per cent.

In recent years, global demand for crude oil has weakened, leading to falling prices (before the recent West Asia crisis). The Paris-based International Energy Agency (IEA) predicts a further decline in crude demand by 2030, driven by sluggish economic growth, global trade tensions, the rise of electric vehicles, and the global shift away from fossil fuels for power generation.

It is in this environment that ONGC is working to reinvent itself, striving to secure its relevance — and India’s energy security — in a rapidly transforming global energy landscape.

“ONGC is purely an exploration and production (E&P) company. E&P is in trouble now as oil prices come down considerably,” Arunangshu Sarkar, ONGC’s director of strategy and corporate affairs, told Business Standard. “There is a glut of oil worldwide — 0.6-0.7 million barrels of oil (per day) is excess now, due to the advent of new energy and low carbon mandates.” The glut, he added, may go up to 10-11 million per day by 2030. “In this scenario, we are thinking of making ONGC a future-ready company. This means we are now going for diversification other than the E&P business.”

ONGC’s LNG import plans are one part of this diversification.

The company aims to source 3 million tonnes per annum (mtpa) of LNG by FY27, exploring long-term, low-priced sourcing deals. It is expected to procure gas from the Henry Hub in the US or from West Asia on spot deals, targeting the city gas distribution (CGD) sector from the fourth quarter of FY26. Henry Hub is a natural gas pipeline hub located in Erath, Louisiana.

This move, the company says, is a strategic intervention to help India achieve its goal of increasing the share of natural gas in its energy mix to 15 per cent by 2030, from around 6.7 per cent now.

 “Domestic production satisfies only about 50 per cent of our demand, with the remainder being bridged by imported LNG,” Sarkar said. “Projections indicate that by 2030, natural gas demand may reach approximately 210 billion cubic metre (bcm), requiring LNG imports of nearly 124 mmtpa to meet the shortfall. In this context, we are actively exploring opportunities in the LNG business,” he explained.

Industry experts also see this as the right move, considering natural gas is expected to remain crucial for India’s energy mix until there is a breakthrough in hydrogen technologies.

Greening the globe

ONGC’s push into renewables mirrors a broader global trend among major oil producers.

Companies like BP, Shell, TotalEnergies, and Equinor have all diversified into renewable energy. Even Saudi Aramco, despite its crude oil reserves of 267 billion barrels, is making aggressive moves toward renewables to align with Saudi Arabia’s goal of generating 50 per cent of its electricity from renewable sources by 2030.

“Unfortunately, our exploratory efforts in India have not yielded much in terms of results. It is not just ONGC, all global majors have ventured into renewables,” said R S Sharma, former ONGC chairman and an independent director of Indian Gas Exchange.

ONGC has established a wholly owned subsidiary called “ONGC Green” to accelerate its green energy initiatives. Through its joint venture, ONGC NTPC Green Pvt Ltd, the company recently acquired a 100 per cent stake in Ayana Renewable Power, which holds 4.1 Gw of operational and under-construction renewable energy assets.

 “We have a plan to have 10 Gw capacity by 2030. We already have around 4 Gw, the remaining is 6 Gw,” Sarkar said. “Apart from renewable energy, wind, and solar, we are also going for pump storage, green hydrogen, and battery storage.”

The strategy includes plans for a 2 mtpa green ammonia plant by 2030, seen as a crucial element of ONGC’s long-term decarbonisation goals. Additionally, ONGC is exploring the potential of small modular reactors (SMRs) for nuclear power generation, aiming to diversify India’s energy mix further. The company is assessing partnerships with firms specialising in SMR technology, focusing on safety standards and navigating the regulatory landscape. “We will start with a pilot project. It will be a floating vessel that will be carrying that SMR,” Sarkar added.

In the bioenergy segment, ONGC is working on establishing 25 compressed biogas plants, including one within its own production facility in Hazira. In green hydrogen, the company is conducting a pilot project that uses wastewater from its Mehsana asset to produce green hydrogen via microbial electrolysis.

ONGC has also acquired 100 per cent of IL&FS’s shares in Mangalore Special Economic Zone, bringing its combined stake in the venture, along with subsidiary Mangalore Refinery and Petrochemicals, to around 76 per cent. To enhance India’s energy security, ONGC is exploring the development of underground natural gas storage systems in collaboration with the Indian Strategic Petroleum Reserve. These storage solutions are crucial for managing supply fluctuations, ensuring stable natural gas availability, and bolstering national energy security.

While ONGC is diversifying aggressively, efforts are ongoing to ramp up production from existing oil and gas blocks and from new blocks acquired in recent bidding rounds.

Asked whether this diversification might dilute the company’s core business, Sharma said, “As a commercial enterprise, the company has to keep looking for growth opportunities. There is opportunity for every player and much more appetite for gas and renewables in the country.”

With a forward-looking approach, the company intends to keep its operations energised.

https://www.business-standard.com/industry/news/fossil-to-future-ongc-charts-a-bold-path-pivots-to-lng-renewables-125062900781_1.html

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 “This electrolyser delivery is more than a shipment—it’s the foundation of a national energy transformation. Our vision blends sustainability with self-reliance, and through this partnership with Greenzo, we’re empowering industries with low-carbon solutions,” said Ratan Bokadia, Managing Director, Oswal Energies.

Greenzo Energy, which designs and manufactures electrolyser systems, currently holds an order book exceeding ₹1,800 crore. The company is engaged in supplying turnkey hydrogen solutions, including Build-Operate-Transfer (BOT) hydrogen plants, to clients across India and the Middle East.

“Our dispatch to Oswal Energies highlights the growing strength of India’s green manufacturing ecosystem. We are proud to support India’s energy goals with cost-effective, locally made hydrogen solutions,” said Sandeep Agarwal, Managing Director, Greenzo Energy.

Oswal Energies, established in 2013 and headquartered in Ahmedabad, provides Engineering, Procurement and Construction (EPC) services in oil and gas, green hydrogen, carbon capture, and compressed biogas. It has executed more than 250 projects in upstream, midstream, and downstream hydrocarbon segments, along with clean energy initiatives.

https://energy.economictimes.indiatimes.com/news/renewable/oswal-energies-launches-320-crore-green-hydrogen-project-with-greenzo-energys-1-mw-electrolyser-delivery/122180296

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He believes that due to critical safety requirements for hydrogen, separate and enhanced safety norms would be necessary for green hydrogen stations. This would require oil marketing companies (OMCs) to establish dedicated infrastructure for retail sales of the fuel.

The playbook is part of Indian Oil’s $30 billion investment plan to achieve net zero by 2046, and involves the refiner to meet its captive demand, followed by catering to mobility requirements and exports. The plan being worked upon by the country’s largest refiner’s strategy group involves setting up these carbon emission-free fuel dispensing stations at new locations, and not at its current network points.

Green hydrogen is used as a clean fuel for vehicles, especially in fuel cell electric vehicles, as a zero-emission alternative to fossil fuels.

Without divulging further detail of its retail plans for green hydrogen, Sahney said: “Everything is on our strategy table.”

The plan involves selling green hydrogen from Indian Oil’s 10,000 tonne per annum green hydrogen generation unit at Panipat refinery to be commissioned by December next year.

Panipat refinery

Referring to the planned green hydrogen plant at its Panipat refinery, Sahney said: “First of all, I am putting up this plant at Panipat, I want to take it to its logical conclusion, that is increased use in mobility. Till the time mobility is there, I can use that in my refineries also. I can replace the grey hydrogen with the green one. Otherwise my ultimate aim will be to use it more and more towards mobility.”

He noted that it would be the largest green hydrogen facility in the country. Recently, Indian Oil discovered the levelized cost of green hydrogen at $4.66 per kg for the proposed green hydrogen plant. This is a key breakthrough as the government has been eyeing green hydrogen prices to come below $5 per kg, with an eventual target of bringing it to $1 per kg. The development assumes significance in the backdrop of India targeting 5 million tonne annual green hydrogen production by 2030.

Noting that technology for use of green hydrogen in automobiles is already available and that the state-run OMC is supplying hydrogen to about 15 fuel cell buses in the national capital, he stressed on the need for having dispensing stations or retail outlets dedicated to supplying new-age fuel to customers.

“We don’t have enough (green hydrogen) dispensing stations in India. I think only three or four dispensing stations are there. Two of them are with us – one in Gujarat and another in Faridabad…But with those four, you can’t run a proper automobile (ecosystem), so it’s a chicken and egg story. If I can develop an ecosystem, if I can develop green hydrogen first and then our number of dispensing stations in a particular area in a particular state in a particular distance, and then encourage people to buy those automobiles there. And then, maybe we can develop an ecosystem there,” he said.

Another state-run major NTPC Ltd runs a green hydrogen refueling station in Leh.

Sahney also said that the company would be open to catering to export opportunities. On being asked if Indian Oil would look at exporting green hydrogen, he said: “Why not? If opportunity comes, why not?” He also said that with the growing energy requirement in India, new energy sources like green hydrogen or renewable energy would only complement the existing fossil fuel sources, rather than competing with the conventional fuels.

Under the National Green Hydrogen Mission, India also aims to become an export hub for the molecule. Other companies which have forayed in this business include Mukesh Ambani-led Reliance Industries, Greenko founders-backed AM Green, Adani Group, Larsen & Toubro, ReNew and Avaada.

In 2023, RIL Chairman Mukesh Ambani announced that it has come up with a roadmap to bring down green hydrogen cost to $1 per kg. Last month, Adani Group commissioned India’s first off-grid 5 megawatt green hydrogen pilot plant in Kutch, Gujarat. AM Green is eyeing the export market and plans to begin production at green ammonia facility in Kakinada, Andhra Pradesh, in the second half of 2026, primarily targeting export markets in Europe.

AM Green has already signed offtake agreements with major buyers including Uniper, Yara, and Keppel, supporting a range of green hydrogen applications.

Last year, Nasdaq-listed ReNew Energy Global plc signed an initial agreement with JERA Co., Inc, Japan’s largest power generation company, to jointly evaluate development of a green ammonia production project in India. In January, Avaada Group announced a partnership with Switzerland’s Casale to build a green ammonia plant in Odisha.

Indian Oil also has a joint venture with L&T and ReNew to develop green hydrogen projects in the country, which they had launched in 2023.

Amid a massive policy push by the government and capex announcements by energy companies both in the public and private sector, cost of green hydrogen has remained a concern for the growth of this emerging space.

In March, Union minister for road transport and highways Nitin Gadkari urged the industry to come up with innovative solution to bring the capital investment required for setting up hydrogen fuel stations.

Noting that currently, the cost of setting up a hydrogen gas station goes to around ₹7 crore, he said: “Indian technology, innovation, and research are crucial for the future and we need to convert knowledge into wealth. To make hydrogen fuel stations widely accessible, the cost of setting up each station must be reduced to a maximum of ₹50 lakh.”

https://www.livemint.com/companies/indian-oil-green-hydrogen-ioc-green-hydrogen-indian-oil-fuel-dispensing-pumps-green-hydrogen-retail-india-11751460817143.html

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The closing date for bid submission is July 31, according to the hydrocarbon regulator Directorate General of Hydrocarbons. Sources indicate that ONGC, which accounts for 70 per cent of India’s domestic crude oil and natural gas production, is expected to show interest in all 25 blocks on offer during the round, while partners may be brought on board for exploration in deep and ultra-deep acreages. Official queries mailed to RIL, ONGC, BP, and Petrobras did not elicit a response.

  “ONGC is keen on all 25 blocks on offer under OALP X — some alone and some with partners. Partners are being brought in because these are difficult areas and require a huge amount of money. We are engaging in talks with almost every company, including Petrobras, BP, and RIL,” said a source aware of the development.

In OALP IX, of the 28 hydrocarbon blocks on offer earlier this year, ONGC secured 15 — four in partnership with other players and 11 independently. Of those, GS-OSHP-2022/2 in the Saurashtra Basin was a joint bid by ONGC (40 per cent participating interest), RIL (30 per cent), and BP Plc (30 per cent). That was the only time the three majors collaborated.

ONGC has also had an association with Petróleo Brasileiro SA, or Petrobras, in the past.

Interestingly, although Petrobras had a 15 per cent stake in KG-DWN-98/2 operated by ONGC, the Brazilian major relinquished it in early 2010 to focus on oil and gas finds back home. In April this year, Brazil’s state-run oil firm’s head of E&P, Sylvia Anjos, confirmed that it had already collected data to assess the potential of offshore areas in deep and ultra-deep waters in India for the upcoming round. In February, Petrobras signed a memorandum of understanding with both ONGC and Oil India Corporation for possible collaborations in India — including in upstream, marketing, decarbonisation, and low-carbon solutions.

“The company has teamed up with an international partner and a private sector entity earlier as well. There is no problem with that. We appreciate foreign entities coming into the E&P space in India,” a petroleum ministry official said, referring to state-run national oil and gas company ONGC.

 The government has been keen on drawing foreign entities into the E&P space for the past few years. However, a glut in global oil supply, combined with weak industrial demand in key markets, has dampened exploratory spirits, another executive pointed out. “It’s also no secret that foreign companies often opt for a local partner to navigate the Indian market. ONGC’s tieups are just the latest reflection of that,” he said.

In a first-of-its-kind move, BP was appointed by a public sector player to boost production in January, when ONGC brought the oil major on board to help ramp up output at the Mumbai High offshore oil field. The following month, both signed a three-year memorandum of understanding to explore collaboration in oil and gas exploration, production, trading, and new energy vectors, both in India and internationally.

One of the world’s six largest ‘supermajors’, BP already has a major partnership with RIL, operating 1,900 fuel retail stations across India and producing oil and gas from a deepwater block in the Krishna-Godavari Basin.

https://www.business-standard.com/industry/news/petrobras-bp-reliance-may-join-ongc-in-india-s-biggest-oil-block-bid-125070600398_1.html

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The Maharashtra State Electricity Distribution Company Ltd (MSEDCL), which is the sole authority for providing power connections to EV charging points, revealed that 151 charging stations have been set up so far across the district and many of them are private and not available to public. Of these, 58 are in urban areas, while 93 lie within the broader city limits.

Among the total stations, 43 have been installed by various fuel providers, while MSEDCL itself installed six. “The charging stations installed by MSEDCL and fuel providers are all available to the public. Many of the remaining ones are also being used by the public, but they are installed by private people, MahaMetro, Nagpur Municipal Corporation (NMC), and others,” said a senior MSEDCL official.

The officer further said although the pace of installation increased recently, many stations remain privately owned and are not accessible to the public, thereby limiting the usability of the city’s overall EV infrastructure.

At present, there are 77,795 registered electric vehicles in the city, spanning all categories, including battery-operated vehicles (BOVs), pure EVs, and strong hybrids. However, with only 151 charging stations available, public access to charging infrastructure remains severely restricted.

According to RTO-wise data, 46,686 EVs are registered at Nagpur East RTO (MH49), followed by 15,805 in Nagpur Rural RTO (MH40), and 15,304 in Nagpur Urban RTO (MH31).

This imbalance has created challenges for EV users, who often struggle to locate reliable charging options — particularly during peak usage hours or long distance travel. Experts warn that this growing gap between vehicle adoption and infrastructure support could jeopardise the broader goals of sustainable mobility and frustrate EV owners.

One such user, Vaibhav Sahare, shared his experience. “In our apartment, there were four or five e-cars, so we went ahead and installed a charging station, but if someday we need to charge a vehicle outside, then we either have to wait for a long time or it gets harder to find a charging station. In other countries, charging stations are installed at short distances. Such steps should be initiated in our country as well. It will not only promote green energy but also provide us with facilities,” said Sahare.

While the city has seen a steady increase in the number of charging points, officials and users agree that the current infrastructure remains inadequate. Unless this gap is urgently addressed, Nagpur’s ambition of becoming a green and sustainable city may face serious hurdles.

https://timesofindia.indiatimes.com/city/nagpur/few-and-far-between-nagpur-has-just-one-charging-station-for-every-515-evs/articleshow/122283526.cms

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In a post on X, the minister said the country is looking to develop a full exploration and production (E&P) deepwater technology ecosystem under the leadership of Prime Minister Narendra Modi.

“As India plans to explore over 2.5 lakh sq kms in Open Acreage Licensing Policy Round 10 in one of the largest offshore exploration bidding rounds globally, we are trying to develop a full E&P deepwater technology ecosystem in India, under the visionary leadership of PM Narendra Modi,” Puri said on X.

Puri participated in a roundtable with representatives of the Offshore Energy Cluster in Bergen, Norway, to discuss a range of technologies for deep-sea hydrocarbon exploration. The discussions covered well services, subsea operations, testing, maintenance operations, drilling tools, drilling submersible rigs, well completion services, high pressure high temperature wells, drillships, and monitoring technologies.

“In a roundtable with representatives of Offshore Energy Cluster in Bergen, Norway we held invigorating discussions on technologies including well services, subsea operations, testing, maintenance operations, drilling tools, drilling submersible rigs, well completion services, high pressure high temperature wells, drillships, monitoring technologies covering the entire gamut of hydrocarbons exploration, particularly deep sea exploration by the Norwegian energy professionals,” Puri stated.

The meeting was attended by representatives from TechnipFMC, Reach Subsea, DNV Group, Odfjell Drilling, CCB Subsea, Shearwater, Innovasjon Norge, and NORWEP. A representative from Equinor India was also present.

Jostein Dahl Karlsen represented the Norwegian Ministry of Foreign Affairs and the Norwegian Ministry of Energy at the discussions.

The government has been expanding OALP rounds to boost exploration and enhance domestic production of oil and gas, especially from frontier areas and deep-sea basins.

https://energy.economictimes.indiatimes.com/news/oil-and-gas/india-seeks-offshore-tech-tie-ups-for-deep-sea-oil-hydrogen-collaboration-with-norway/122319511

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Despite green hydrogen project announcements exceeding 9.2 MTPA, only a few projects have reached the Final Investment Decision (FID) or secured long-term offtake agreements from domestic or international markets. The IESA report notes that under a baseline scenario, if 30 per cent of the announced green hydrogen (GH2) capacity is commissioned within ten years, electrolytic and bio-hydrogen supply can meet approximately 31 per cent of domestic demand in 2032.

The event was inaugurated at IICC Yashobhoomi, New Delhi, in the presence of Dr. Ajay Mathur, Ex-DG, International Solar Alliance and Professor, IIT Delhi; Malini Dutt, Trade and Investment Commissioner – India, NSW Government; Manish Sharma, Chairman, Panasonic; Stephen Fernands, Founder & President, Customized Energy Solutions (CES); Vinayak Walimbe, Managing Director, CES; and Debmalya Sen, President, IESA, along with over 200 global energy leaders.

Addressing the inaugural ceremony, Dr. Ajay Mathur said, “IESW 2025 embodies the collective aspirations of the battery and storage communities, fostering collaboration and knowledge exchange among industry professionals. It serves as a crucial platform where individuals from various sectors, such as battery manufacturing, application, and electricity demand, can come together to learn from one another and advance their understanding of the sector.”

The report stated that for schemes being implemented under the National Green Hydrogen Mission (NGHM), a call for proposals or bids has been issued, winning bidders or proposals announced, or fund disbursement has begun. The largest allocations are for subsidies under the GH2 Tranche 1 and 2, electrolyzer manufacturing (ELY Tranche 1 and 2), and green ammonia (GNH3 aggregation) tenders under the Strategic Initiative for Green Hydrogen Transition (SIGHT).

According to the report, four states account for 82 per cent of the announced GH2 projects — Odisha (38 per cent), Gujarat (26 per cent), Karnataka (12 per cent), and Andhra Pradesh (6 per cent). Around 72 per cent of the announced projects are targeting green hydrogen use for ammonia production, while 20 per cent have not announced end-use applications.

Key cost drivers of the Levelized Cost of Hydrogen (LCOH) produced through water electrolysis include the cost of landed electricity, capital expenditure (CAPEX) for the electrolyzer stack and balance of plant, and capacity utilization of the electrolyzer.

Vinayak Walimbe, Managing Director, CES, said, “Despite various policy interventions and government initiatives to promote the green hydrogen mission, several challenges remain in addressing the urgent issue of decarbonization. The IESA India Hydrogen Report, launched at IESW 2025 today, is crucial in raising awareness among policymakers, industry leaders, and stakeholders in the sector, helping to further accelerate the mission.”

According to the status of India’s green hydrogen transition report, the production cost of hydrogen from fossil fuels in India is nearly twice the cost of $1 per kilogram of hydrogen or even higher. For consumers representing about 6 per cent of the total hydrogen market who obtain hydrogen, the landed cost is even greater due to storage and transportation expenses.

Open-access electricity regulations often restrict the renewable energy offset for commercial and industrial consumers, which can reduce the capacity utilization of electrolysers. The estimated LCOH in the base case is two to four times higher than the production cost of fossil fuel-based hydrogen. In a highly optimistic scenario, the estimate is 1.5 to 2.5 times higher, which is close to the recent first price discovery of green hydrogen in India.

Debmalya Sen, President, IESA, said, “With the support of government initiatives to foster innovation and investment in clean energy technologies, IESW 2025 will bring together industry leaders, government representatives, and global experts to showcase groundbreaking solutions. This gathering will pave the way for India’s transition to a resilient energy system, ensuring we meet our growing energy demands while keeping our target of production capacity of 5 million tonnes per annum (MTPA) of green hydrogen by 2030 in sight.”

IESW 2025 is bringing together ministries, government representatives, and companies from over 20 countries. The three-day event will showcase over 300 product innovations in sectors including electric vehicles, charging infrastructure, solar, green hydrogen, and energy storage. Seven or more new product and factory announcements are expected from Indian manufacturers during the event.

https://energy.economictimes.indiatimes.com/news/oil-and-gas/indias-hydrogen-demand-to-reach-8-8-mtpa-by-2032-few-projects-hit-investment-stage-report/122316790

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This breakthrough comes after CEID’s earlier deployment of MDPE pipeline offtake at the same plant. The steel pipeline marks a new industry benchmark, enabling continuous, real-time and safer CBG distribution. It also lays the groundwork for standardised guidelines on pipeline design, metering, gas quality control, and safety protocols.

“The transition to steel pipeline injection brings unmatched scalability, efficiency, and compliance to India’s CBG ecosystem,” said Prince Gandhi, Founder & CEO, CEID Consultants. “It opens the door for similar nationwide deployments aligned with the SATAT programme.”

The plant serves PNG consumers and CNG retailers while integrating seamlessly with Gujarat Gas’s existing infrastructure, supporting India’s clean energy and gas-based economy goals.

https://www.constructionworld.in/energy-infrastructure/oil-and-gas/india—s-first-cbg-plant-with-steel-pipeline-integration-launched-/76148

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During the meeting, Chief Secretary Ahuja emphasised Odisha’s strategic readiness to lead in the green hydrogen sector, citing its abundant water resources, strong renewable energy integration potential, proactive industrial policies, and a strategic coastal location. These factors, he noted, place Odisha in a unique position to become a global exporter of green hydrogen and its derivatives, including green ammonia and green methanol.

MNRE Secretary Sarangi echoed this view, adding that private sector interest is high in Odisha’s potential for producing green hydrogen-based fuels. Ports such as Paradip and Gopalpur were identified as key enablers for scaling up green hydrogen exports. Special focus was placed on the Gopalpur SEZ, where several developers are exploring investment in large-scale hydrogen and ammonia production projects.

The meeting was attended by representatives from central ministries, state departments, and leading green hydrogen developers, with a focus on resolving infrastructure and regulatory challenges to enable faster deployment and investment.

In parallel, progress under the ‘PM Suryaghar: Muft Bijli Yojana’ — a nationwide rooftop solar initiative — was also reviewed. The MNRE Secretary and Odisha Chief Secretary discussed ways to accelerate rooftop solar adoption across the state, particularly for low-income households.

District Collectors have been instructed to speed up the implementation of rooftop solar installations, while Ahuja stressed the need for regular SLBC meetings, vendor and bank engagement, and swift loan approvals and disbursements. He also called for adopting a Utility-Led Aggregation (ULA) model, especially for residential capacities below 1 kilowatt.

Odisha reaffirmed its commitment to becoming a preferred investment destination for green energy initiatives and to playing a pivotal role in strengthening India’s clean energy ecosystem.

https://ommcomnews.com/odisha-news/odisha-gears-up-for-green-hydrogen-and-rooftop-solar-push/

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The demonstration was conducted following the initial concept proposal by HD Korea Shipbuilding & Offshore Engineering (HD KSOE), and the development of the BOG processing system by HD Hyundai Heavy Industries (HD HHI) and DongHwa Entec.

KR and The Liberian Registry (LISCR) carried out verification of the system’s design, manufacturing, and operation.

The demonstration partners expect the once fully developed technology to recover over 50 tons of boil-off gas per LNG-fueled ship under construction, and support compliance with port environmental regulations, including the broader adoption of alternative maritime power (AMP).

As previously reported, HD HHI and partners set out to conduct the demonstration project in April 2025 to recover the boil-off gas from a 7,900 TEU LNG-fueled containership currently under construction and use it as an energy source at its worksites.

Reducing greenhouse gas (GHG) emissions during the construction of LNG-fueled ships was part of a national task of the South Korean Ministry of Trade, Industry and Energy (MOTIE) in 2023.

Due to the lack of relevant laws and standards for the self-consumption of evaporated gas in Korea’s City Gas Business Act, HD HHI applied for a regulatory sandbox demonstration exemption from MOTIE to carry out this project, and received conditional approval on October 23, 2024.

https://www.offshore-energy.biz/south-korean-partners-conduct-worlds-first-lng-boil-off-gas-recycling-demo/

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The report estimates that imported oil and gas generated 30 million tonnes of CO2 equivalent (CO2e) in methane emissions in 2023, compared with just 1.7 million tonnes from domestic activity. As one of the world’s top five fossil fuel importers, sourcing 98% of its oil and gas from abroad last year, South Korea’s true methane footprint remains largely unaddressed, according to SFOC.

Methane intensities across South Korea’s key suppliers were found to exceed global benchmarks. Oil imports averaged 27.6 kg CO2e per barrel of oil equivalent (BOE), more than five times the US benchmark of 5.9 kg. LNG imports averaged 22.3 kg CO2e per BOE, nearly four times the US threshold.

South Korea’s oil and gas imports come primarily from Saudi Arabia, the US, Qatar, and Australia. The report found wide variations in methane intensity across these exporters, reflecting differences in upstream practices and regulatory enforcement.

The report recommends that South Korea adopt an import standard modelled on the EU’s methane regulation, which requires reporting of emissions across the fossil fuel supply chain and sets intensity limits for new import contracts.

“Like the EU and Japan, South Korea is one of the world’s largest importers of fossil fuels,” said Jinsun Roh, Head of the Methane and HFC Team at SFOC. “By requiring methane emissions data from exporting countries, Korea can not only improve transparency around greenhouse gas emissions but also lay the groundwork for meaningful action to limit global temperature rise.”

The proposed changes, if adopted, would affect LNG producers, oil exporters and industrial gas suppliers involved in upstream production, liquefaction, shipping and terminal operations. Exporters to South Korea could face increased scrutiny over methane intensity throughout the value chain.

“While South Korea may choose an approach that reflects its national priorities, finding common ground with regulations like those in the EU could enhance the impact on global methane reductions,” said Irina Semykina, Senior Consultant at Carbon Limits and lead author of the report.

The International Energy Agency (IEA) has estimated that the global oil and gas sector emitted around 130 million tonnes of methane in 2023. It believes that up to 75% of these emissions could be cut cost-effectively using existing technologies such as leak detection, improved monitoring and bans on routine flaring and venting.

Rapid methane reductions, according to the IEA, are among the most impactful near-term actions available for limiting global temperature rise. However, critics note that enforcing such rules may raise compliance costs, create trade friction, or limit flexibility in long-term LNG contracts.

South Korea signed the Global Methane Pledge in 2021 and introduced a national methane reduction roadmap in 2023. The report’s authors say that an import standard would be a logical next step to align the country’s global commitments with its energy buying practices.

https://www.gasworld.com/story/south-korea-pressed-to-cut-methane-from-lng-and-oil-imports/2161049.article/

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Under the proposal, the company disclosed LNG volumes would be imported and stored at its existing storage tanks and could be either sold outside of the United States as LNG or re-gassified for the domestic market.

https://naturalgasintel.com/news/golden-pass-lng-eyeing-october-train-1-start/

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This will be the first major delivery of Canadian LNG to Japan, which currently depends on Australia and Malaysia for over half of its LNG imports.

With limited domestic energy resources, Japan has been actively working to diversify its LNG supply. Australia, its largest supplier, is projected to face production declines in the coming years. This highlights the need for more stable and reliable sources. Canadian LNG, backed by geographic proximity and political stability, presents a strong alternative. It could play a key role in strengthening Japan’s energy security.

Diversifying Japan’s LNG Supply

LNG is natural gas that has been cooled to a liquid state, reducing its volume to about one-600th and making it much easier to transport by sea.

Japan does produce some natural gas domestically, mainly in areas like Niigata and Chiba, but this supply falls far short of meeting national demand. Like oil, Japan relies almost entirely on imports for its natural gas.

With delays in restarting nuclear power plants, Japan remains heavily dependent on thermal power, which generates around 70% of the country’s electricity. Gas-fired power plants are the largest contributors.

Compared to other fossil fuels, natural gas produces less CO₂, making it a relatively cleaner option. Because of its key role in electricity generation, any disruption in LNG supply could have serious consequences for the economy and daily life. In fiscal 2024, Japan imported 65.87 million tons of LNG, making it the world’s second-largest importer after China.

The LNG Canada Project

The new LNG supply will come from the LNG Canada project in British Columbia, a facility developed with investment from Mitsubishi Corporation, Shell, and other partners. Natural gas is extracted inland and transported via a 670-kilometer pipeline to the coast. There, it is liquefied and shipped overseas by tanker.

The project represents a total investment of about $14 billion USD and has an annual production capacity of 14 million tons. Mitsubishi holds a 15% stake, giving it rights to around 2.1 million tons per year. If all of that were exported to Japan, it would cover roughly a quarter of the country’s projected increase in LNG demand.

Mitsubishi’s LNG Expertise

Mitsubishi was the first major Japanese trading company to enter the LNG business, beginning in the 1960s. Today, it is involved in LNG projects across more than 10 countries. With the addition of Canadian supply, Mitsubishi’s annual LNG production capacity has grown to around 15 million tons, the largest among Japanese companies.

Katsumi Saito, Senior Executive Officer overseeing the fuel business and related operations, commented, “Our strength lies in the knowledge and development capabilities built on more than 50 years of experience.”

One of the key advantages of Canadian LNG is proximity. Shipping LNG from Canada’s west coast to Japan takes about 10 days — much shorter than the roughly 30 days required from the US Gulf Coast via the Panama Canal. That route can take even longer when canal traffic is restricted by drought.

Avoiding Chokepoints and Longer Routes

Other shipping routes, such as around the Cape of Good Hope in South Africa, can take up to 60 days. LNG from the Middle East typically takes about 16 days. In contrast, Canadian LNG avoids major chokepoints like the Strait of Hormuz, offering more stable and reliable delivery.

Canada also has vast natural gas reserves — enough to meet Japan’s current annual LNG demand for about 25 years. Its cold climate makes the liquefaction process more energy-efficient. Canadian LNG has a higher heat content than LNG from the United States. On top of that, there is strong political support in Canada for energy exports, ensuring long-term policy stability.

As of fiscal 2024, Australia supplies 38% of Japan’s LNG. Although shipping times from Australia are similar to those from Canada, slower gas field development — driven by climate change policies — has raised concerns about future supply. To reduce risks, Japan has also prioritized LNG imports from the United States, Qatar, which has massive reserves, and Russia.

The US has significantly increased its LNG exports in recent years. Qatar, however, faces geopolitical risks, especially due to tensions with Iran. Japan continues to import LNG from Russia, but new projects have been put on hold under US sanctions. For instance, Japanese trading firms like Mitsui & Co are currently unable to engage with Russia’s Arctic LNG 2 project.

Growing Electricity Demand

Japan’s electricity demand is expected to grow as the number of data centers increases, driven by the expansion of artificial intelligence technologies. If decarbonization efforts do not progress, the government estimates LNG imports could rise by 12% by 2040, reaching about 74 million tons.

The LNG Canada project marks the first new LNG venture involving Japanese companies in around six years. With global instability highlighting the need for stronger supply chains, Canada’s role as a new supplier is a major win for Japan. Further expansion of production capacity is also eagerly anticipated.

https://japan-forward.com/japan-to-import-canadian-lng-in-bid-to-diversify-energy-supply/

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LNG Canada is the first major LNG facility in North America with direct access to the Pacific Coast. It starts at a time when trade tensions with the United States have heightened Canada’s desire to diversify its export markets.

“This is something Canada really needs right now,” LNG Canada CEO Chris Cooper said in an interview, pointing to those trade tensions.

The LNG Canada project, which is a joint venture between Shell Plc , Petronas (PGAS.KL), opens new tab, PetroChina (601857.SS), opens new tab, Mitsubishi Corp (8058.T), opens new tab and Kogas (KVGG.LJ), opens new tab, cost approximately CDN$40 billion (US$29.4 billion) to construct and has been billed as the largest private-sector investment in Canadian history.

When fully ramped up, it will have the capacity to export 14 million metric tonnes of LNG per year.

Shell and its partners are working towards reaching a final investment decision next year for doubling the project’s capacity, the chief of Shell’s gas business Cedric Cremers told Reuters.

Canada is the world’s fifth-largest producer and fourth-largest exporter of natural gas, but until now virtually all of those exports have gone to the United States.

LNG Canada offers the country’s natural gas producers access to energy-hungry Asian markets for the first time.

Its Pacific coast location offers a direct shipping route to Asia without needing to transit the Panama Canal, something project partners hope will give Canadian LNG an advantage against U.S. competitors whose facilities are located on the other side of the continent along the Gulf coast.

LNG Canada also has a supply cost advantage. Prices for Canadian natural gas — which will be shipped to LNG Canada from the shale fields of northeast British Columbia via the Coastal Gaslink pipeline — currently trade at less than half the price of the U.S. Henry Hub benchmark.

“West coast LNG in Canada competes exceptionally well against anything being developed in the United States,” Petronas Canada CEO Mark Fitzgerald said at a conference in Calgary in June.

The startup of LNG Canada — which was first proposed in 2012 — comes almost 10 years after the United States first began exporting LNG from the lower 48 states. The United States has since become the world’s largest LNG exporter, leaving many in Canada’s energy sector to say that their country has been too slow to develop its own industry.

But Canada has additional LNG projects waiting in the wings. Two smaller Pacific coast LNG facilities — the Cedar LNG and Woodfibre LNG projects — are currently under construction, and LNG Canada itself is considering a second-phase expansion of the project, which would double the facility’s capacity.

While Canadian LNG does have certain beneficial cost elements, it also has negatives, said RJ Johnston, incoming director of energy and natural resource policy at the University of Calgary’s School of Public Policy.

Constructing new Canadian LNG facilities and pipelines along British Columbia’s remote northern coast is more challenging and expensive than along the U.S. Gulf, where the infrastructure to serve the LNG sector is already developed, he said.

Ed Kallio, executive advisor for data analytics and forecasting firm Incorrys, said the business case for expanding Canada’s LNG production is weakened by greenhouse gas regulations that U.S. producers don’t face.

https://www.reuters.com/business/energy/canada-ships-first-lng-export-cargo-pacific-coast-2025-07-01/

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That’s the highest daily level for the plant, historic data shows. Higher natural gas output doesn’t automatically indicate a hike in LNG production, but historically the plant produced more gas when it was able to load cargoes. In December 2023, when it was launched, Arctic LNG 2 pumped an average of 13.7 million cubic meters of gas a day.

The facility located above the Arctic Circle is key for Russia’s ambition to triple LNG production by 2030. Those plans were squeezed by international restrictions after the invasion of Ukraine, but a liquefied gas tanker appeared to load a cargo several days ago, suggesting Russia may be finding ways around the penalties.

Gas output at Arctic LNG 2 averaged 8.9 million cubic meters a day during most of June, compared with 9.4 million cubic meters a day the month before, the person said, asking not to be identified because the information isn’t public.

Novatek, the largest shareholder of Arctic LNG 2, and the plant’s operator didn’t immediately respond to requests for comments.

The Iris tanker — previously known as North Sky and blacklisted by the U.S., the EU and the UK — left the site Sunday. Its draft level, which the crew inputs manually, has increased, potentially indicating the tanker loaded a cargo there, according to ship-tracking data compiled by Bloomberg.

The tanker is heading toward the Arctic port of Murmansk, where it’s expected to arrive July 2.

Novatek uses waters near Murmansk to transfer LNG cargoes from ice-class vessels to conventional tankers. Novatek’s sanctioned Saam floating LNG storage facility, previously used to store cargoes from Arctic LNG 2, is also located there.

https://worldoil.com/news/2025/6/30/russia-s-sanctioned-arctic-lng-2-ramps-up-output-to-record-levels/

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The bid winners will deliver the LNG cargoes—each totaling 3.36 million MMBtu (million British thermal unit)– to Moheshkhali Island in the Bay of Bengal, with the option to discharge at either of the country’s two floating storage and regasification units located there.

The bid submission deadline is July 7.

The South Asian country is expected to buy more spot LNG cargoes in August as the interim government has targeted to procure six additional cargoes from late May and by August to boost the supply of re-gasified natural gas for industrial use, said the official.

Bangladesh procured five spot LNG cargoes in July. The country purchased six spot LNG cargoes in May—the highest number in a single month to date.

RPGCL, a wholly owned subsidiary of state-run Petrobangla, oversees LNG trading in Bangladesh.

Bangladesh previously awarded Vitol Asia Pte Ltd, a spot LNG cargo tender for the July 28-29 delivery at $13.52 per MMBtu, said the RPGCL official.

Bangladesh currently imports LNG under long-term contracts from QatarEnergy and OQ Trading International, supplementing these with spot purchases. The two operational FSRUs at Moheshkhali have a combined regasification capacity of 1,100 million cubic feet per day (mmcfd).

The country continues to face an acute energy crisis, worsened by declining domestic natural gas production.

As a result, gas rationing remains in effect across power plants, industrial units and other major consumers to balance mounting demand against limited supply.

The country’s overall natural gas output – local gas and imported LNG combined—was around 2,869 mmcfd including 1,024 mmcfd of re-gasified LNG, against the demand for over 4,000 mmcfd, according to official data as on July 3, 2025.

https://thefinancialexpress.com.bd/trade/govt-to-buy-two-more-spot-lng-cargoes-by-mid-aug

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