NGS’ NG/LNG SNAPSHOT June 1-15, 2025
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City Gas Distribution & Auto LPG
ONGC & GAIL Begin Direct Natural Gas Supply to Gomati GA
ONGC, in collaboration with our business partner GAIL (India) Limited, is proud to commence the direct supply of Natural Gas from Palatana, Tripura, to the City Gas Distribution (CGD) sector of Gomati GA, as allotted by Petroleum and Natural Gas Regulatory Board
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This milestone marks a significant leap in connecting Palatana, a remote region in Tripura, to the CGD network, reinforcing our commitment to energy accessibility.
A crucial step in advancing the Government of India’s North-East Vision, this achievement brings clean energy closer to the remotest corners of the country.
https://www.psuconnect.in/psu-news/ongc-and-gail-begin-direct-natural-gas-supply-to-gomati-ga
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PM Lays Foundation for Rs 10.1 Billion Gas Project in Bengal
Prime Minister Narendra Modi laid the foundation stone of a City Gas Distribution (CGD) project worth over Rs 10.1 billion in Alipurduar, West Bengal. The project will supply Piped Natural Gas (PNG) to more than 0.25 million households and over 100 commercial and industrial users. Additionally, 19 Compressed Natural Gas (CNG) stations will be set up to cater to vehicular demand.
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The Prime Minister called the project a vital example of doorstep delivery of government services and a key component of India’s move towards a clean, affordable, and accessible energy future. He underscored that Bengal’s development is essential to India’s goal of becoming a developed nation.
Shri Modi noted that while city gas services existed in only 66 districts in 2014, the network now spans over 550 districts. He credited initiatives like the Pradhan Mantri Ujjwala Yojana for driving a gas-based economy and improving the lives of millions.
The CGD initiative will create jobs, reduce pollution, and contribute to the industrial ecosystem in the region. It forms part of broader infrastructure and energy efforts to support Bengal’s growth.
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Incomplete PNG Pipeline in Guwahati Leaves Residents Worried and Confused
After an elaborate round of boasts by Purba Bharati Gas Private Limited (PBGPL), the so-called “first phase” of PNG supply to 101 houses in Guwahati’s Geetanagar area was touted as a major milestone. Among the first connections were flats in Geetanjali Heights, Nabakiran Apartment and some households. But dig a little deeper and the story is not one of progress-it is of pretense, poor planning, and public discontent
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While the connections have indeed started, GPlus learned that this so-called supply is functioning without a full-fledged link to the central Barauni pipeline. Essentially, what is being called the “first phase” is more of a glorified trial run, sustained by a temporary arrangement, rather than a fully commissioned and secure gas distribution system.
Speaking to GPlus, the secretary of Geetanjali Heights said, “We have hardly completed a month… There’s nothing much to complain about. But this early optimism is cautious and not necessarily sustainable. “The bills will be taken after two months and on an average it might be around 1200 bucks,” an official from PBGPL said, showing that even billing has been deferred to cover up the incomplete back-end infrastructure.
The larger concern, however, emerged when a recent incident near Rajgarh link road sparked panic among the public-a suspected pipeline leakage with zero communication from the authorities. There was no signage, no barricading, and certainly no attempt to educate or calm the locals. Instead, people watched in fear as a mysterious hiss rose from beneath the freshly dug road.
Though PBGPL later clarified, “The pipes are filled with air, this helps out to detect leakage and blockage. There is no immediate threat for the public,” the statement did little to placate public concern. Residents questioned: What if there had been gas? Would there have been any warning? Any action plan? Is Guwahati really ready for a city-wide PNG rollout when even a mock line causes panic?
The comparison with other Indian cities lays bare the incompetence. Delhi, Mumbai, and Bengaluru have had successful PNG rollouts over the past decade. Their pipelines are deeply integrated into centralised grids, safety mechanisms are standardised, and public awareness campaigns have preceded every new installation. In Delhi NCR, for example, Indraprastha Gas Limited (IGL) launched extensive door-to-door awareness drives before initiating supply. Regular SMS alerts, detailed bills, emergency hotlines, and coordination with RWAs (Resident Welfare Associations) have ensured trust and a sense of safety.
In contrast, PBGPL’s approach in Guwahati appears rushed, half-baked, and disjointed. Although, there is a hotline, no manual, and no answer to what would happen if a leak occurs when actual gas is not flowing. What protocols will be followed in case of an emergency? Who will take responsibility? None of these questions have received clear answers.
However, speaking to GPlus, an official said, “The area where supply has been commissioned, regular patrolling is done. Before installing, the consumers were given instructions. Moreover, there are all kinds of safety measures kept intact.”
Despite the city being dug up extensively-narrow lanes, arterial roads, and residential neighbourhoods all bearing the scars of endless trenching-there is no concrete timeline for when the Barauni-Guwahati connection will be activated. GAIL’s promise of an interstate pipeline has been floating since 2021. According to media. reports from earlier this year, the much-hyped pipeline that connects Barauni in Bihar to Guwahati remains incomplete, with land acquisition delays and red tape cited as the main culprits. Yet, on the ground, PBGPL has moved ahead with lateral pipelines, street disruptions, and promises of household supply, building a house without a foundation.
Public frustration is growing. “This is worse than the water pipeline works,” said a resident of Geetanagar on condition of anonymity. “The digging doesn’t stop, and they come at odd hours. They don’t inform us whether it’s a test or a connection. We didn’t ask for this chaos.”
Another added, “Even the LPG cylinder delivery was more predictable. With this PNG, we don’t know what we are getting into. What if a child tampers with a leaking valve? What if someone lights a fire too close to an active point?”
These questions are not mere paranoia. They stem from the lack of transparency and accountability from the company and the administration. No ward-level representative, no GMDA or GMC authority has come forward to explain or audit the work. In a state where agencies like Guwahati Jal Board (GJB) are already infamous for erratic and botched pipelines, the trust deficit is real.
And unlike Delhi or Mumbai, where multiple agencies are monitored by safety boards, Guwahati’s administrative oversight seems practically absent. Citizens are left to rely on obscure social media updates or word-of-mouth rumours. There is no dedicated app, no helpline, no real-time update on whether a connection is active or under testing. In Bengaluru, city dwellers can track gas supply status online and even file complaints digitally. Guwahati, in contrast, is still living in the dark ages, where a spark could literally set off panic.
Meanwhile, the long-promised dream project of delivering domestic PNG to every Guwahati household remains in limbo. The GAIL pipeline, which is supposed to be the lifeline of this endeavour, remains a distant promise. Officials suggest another 3-4 months before commissioning-but that promise has been made several times before.
PBGPL has recently expanded operations to select pockets in Upper Assam and towns like Tinsukia and Dibrugarh. But the bigger question remains: is expansion justified without addressing core safety and operational readiness?
Another media report published in April 2024 stated that in cities like Pune and Ahmedabad, PNG adoption surged only after proper public-private partnership models were set up with clear guarantees on safety and service. PNG networks there were backed by field response teams, 24×7 customer care units, and were overseen by state safety boards. In Guwahati, however, there is no clarity on who will answer a distress call if something goes wrong.
Even more concerning is the growing belief among citizens that they are being used as guinea pigs. “We don’t even know what kind of testing is going on under our buildings,” a Rajgarh resident said. “There is no meter yet, no instruction manual. What if there’s a malfunction?”
And the biggest question of all-once the grid is commissioned, and Guwahati officially goes ‘live’ with PNG, will people actually trust it enough to get rid of their LPG cylinders? The transition requires total confidence in safety, pricing transparency, emergency handling and ease of access. At this point, none of those conditions are being met.
Will the average household be willing to throw away their backup cylinder if their entire kitchen depends on an underground line that may or may not work during floods, landslides, or administrative failure? There is no plan for contingency. No mention of pressure regulators in flood-prone zones. No clarity on how PBGPL will handle a breach or a pressure drop. Will cooking grind to a halt if a technician doesn’t show up?
For a city already battling poor infrastructure, relentless construction, and an unresponsive civic system, the PNG promise seems less like a leap into the future and more like a leap into confusion. Guwahati is not asking for the moon-it is asking for basic coordination, public engagement, and reliable service. Without that, this “new flame” might just burn bridges rather than illuminate homes.
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TruAlt gets OMC licence; to launch 100 ethanol-BioCNG fuel stations
New Delhi: TruAlt Bioenergy, India’s largest ethanol producer, has been granted authorisation as an Oil Marketing Company (OMC), enabling it to directly retail ethanol, Bio-CNG, petrol, and diesel across the country, the company said.
With this authorisation, TruAlt becomes one of the first private biofuel firms to enter the fuel retail sector, aligning its operations with India’s evolving clean energy roadmap. The company will offer a mix of renewable and conventional fuels including ethanol (E93), Bio-CNG, petrol, diesel, EV charging, and battery swapping facilities.
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“Securing OMC status marks a defining step in TruAlt Bioenergy’s growth journey. This milestone enables us to directly serve India’s evolving fuel needs while accelerating the shift toward cleaner energy,” said Vijay Nirani, Managing Director, TruAlt Bioenergy.
In the first phase, the company plans to set up over 100 fuel stations in Karnataka and Maharashtra, integrating biofuels and conventional fuels under one retail experience. At least 5% of these outlets will be located in remote regions, adhering to the government’s mandate for inclusive access.
The move is expected to generate employment for over 2,000 people, the company said.
India’s petroleum product consumption rose to 239.5 million metric tonnes (MMT) in FY2024–25, with petrol growing at 7.5% and aviation turbine fuel (ATF) at 8.9%. The diesel-to-petrol ratio has dropped from 3.6 to 2.3 in the past decade, indicating a shift in demand and presenting new opportunities for blended fuel models.
“As India’s appetite for mobility surges, this is our moment to shape a retail network that fuels today’s growth while powering the transition to a cleaner, more intelligent, and purpose-driven mobility ecosystem,” Nirani added.
TruAlt currently holds a 7% market share in molasses-based ethanol and 3.7% in overall ethanol supply. It is also expanding into compressed biogas (CBG) production and plans to become one of India’s largest Bio-CNG producers.
India’s ethanol blending rate has climbed to 18.4% in ethanol supply year 2024–25, with a record 19.7% blending in February 2025. The government is targeting 20% blending by the end of the year.
TruAlt is also planning to establish a Sustainable Aviation Fuel (SAF) production facility with an annual capacity of 10 crore litres. The plant is expected to position it among the world’s largest SAF producers using ethanol as feedstock.
“Our model sources agri-residue and biomass from rural communities, creating a circular economy where we return health to the soil and wealth to the farmer,” Nirani said.
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OIL India starts gas production from DSF-III Bakhritiba block in Rajasthan, to scale up output to 100 MSCMD
New Delhi: Oil India Ltd (OIL) has commenced natural gas production from the Bakhritiba block awarded under the Discovered Small Field (DSF) III bid round in Rajasthan’s Jaisalmer district. The production has begun at a rate of 67,200 standard cubic meters per day (SCMD), which is planned to be enhanced to 100,000 SCMD (100 MSCMD), according to the Ministry of Petroleum and Natural Gas.
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The gas output is being supplied to GAIL (India) Ltd and Rajasthan Rajya Vidyut Utpadan Nigam Ltd (RRVUNL), the ministry stated. The production comes after successful drilling of three MWP wells within the block’s stipulated development period.
Petroleum and Natural Gas Minister Hardeep Singh Puri, in a post on social media platform X, said, “Heartiest congratulations to Oil India Limited (OIL) on setting a benchmark by achieving fast monetization from DSF III block by successfully drilling 3 MWP wells within the development period leading to supply of 67,200 SCMD gas to GAIL/ RRVUNL to be further enhanced to production of 100 MSCMD gas from the Bakhritiba Block in Jaisalmer district in Western Rajasthan.”
Puri said the development “stands as a testimony of OIL’s resilience, resolve, and responsibility – delivering energy in challenging frontier environments.”
The minister also acknowledged the efforts of the company’s operational teams. “I commend the tireless efforts of the OIL team, who brave extreme conditions every day to ensure steady energy flows. Every hydrocarbon molecule produced fuels India’s march towards energy security and self-reliance,” he said.
The Bakhritiba field development is part of India’s broader effort to enhance domestic oil and gas output by monetising smaller hydrocarbon reserves awarded under the DSF policy.
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CGD to drive India’s gas demand, set to become biggest consumer
The city gas distribution (CGD) sector is expected to surpass fertiliser plants this year to become the largest consumer of natural gas in India, thanks to the fast growth of CNG and piped gas networks, industry leaders said on Wednesday. CGD, which encompasses supply of CNG as fuel to automobiles, and piping gas to household kitchens for cooking as well as to industries, accounts for 21.22 per cent of the near 200 million standard cubic meters per day of gas consumption in the country. Natural gas consumption is likely to rise to 300-250 mmscmd in the next 7-10 years, GAIL Director (Marketing) Sanjay Kumar said while speaking at the 11th CGD Conference here.
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“Fertiliser sector consumes 60 mmscmd and this is likely to remain the same as no new fertiliser plants are on the anvil,” he said.
“CGD sector consumption could go up to 100 mmscmd from 41.1 mmscmd usage in February/March 2025.”
Anjani Kumar, Head (Gas Origination & BD), Shell Energy LNG, said, “CGD could very well become the largest consumption sector this year itself.”
The CGD sector will drive India’s ambition to raise the share of natural gas in energy basket to 15 per cent from the current 7 per cent.
But domestic production is insufficient to meet the demand and the country has to necessarily rely on imports of liquefied natural gas (LNG).
Gas demand, he said, has grown 35 mmscmd in the last three years and 80 per cent of this has been met through LNG.
Currently, roughly half of the gas requirement is met through imports.
India’s CGD sector is experiencing rapid growth, driven by government initiatives, increased infrastructure investments, and a shift towards cleaner energy sources. City gas licences have been given out for almost the entire country in the recent auctions. The country now has over 8,000 CNG stations and 1.5 crore households using piped natural gas for cooking purposes.
GAIL’s Kumar said domestic gas production can rise to 130-135 mmscmd in next 4-6 years as per the projections made by the national oil companies. The production will “mature” by then and is unlikely to go up, he said.
Petronet LNG Ltd MD & CEO A K Singh said the peak domestic production would not last long as fields mature. “We will be dependent on imported gas in future.”
Petronet operates two of the eight LNG import facilities in the country. Its Dahej import terminal in Gujarat is being expanded to 22.5 million tonnes per annum capacity from 17.5 million tonnes over the next 3-4 months.
“Dahej is the world’s biggest LNG import terminal,” he said, adding that though capacity-wise it ranks 7th or 8th in the world, but because of full capacity utilisation throughout the year, it is the world’s busiest terminal.
“Dahej handles 270-275 cargoes in a year,” he said.
Besides Dahej, Petronet has a 5 million tonnes a year import facility at Kochi in Kerala that even after 12 years of commissioning operates at only 20-25 per cent of its capacity as not all consumers in the vicinity are connected with pipelines to take the fuel, he said.
Singh said the Kochi to Bengaluru pipeline is likely to be completed by end 2025, which will help maximise utilisation of the import terminal.
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Natural Gas/ Pipelines/ Company News
IBA collaborates with Indian Oil to develop bioenergy, bio-hydrogen sector
IOCL and IBA to create a knowledge centre for backing initiatives mutual to both entities and assign resources to boost biofuels industry in India The Indian Biogas Association (IBA) on Sunday said it has signed an MoU with Indian Oil Corporation Ltd (IOCL) for development of bioenergy and bio-hydrogen sector. This collaboration seeks to develop and expand the bio-energy sector on the basis of synergies between both organisations, a statement said.
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In this association, IOCL and IBA will create a knowledge centre for backing initiatives mutual to both entities and assign resources such as technology, infrastructure, and skilled workforce to boost the expansion of the biofuels industry in India.
The two parties will actively interact with legislators, business executives, industry players, and think tanks to develop knowledge centres.
Programmes for training and capacity-building will be the key focus in order to support the biofuels sector.
“At a policy level, IBA is already working with a number of ministries to create regulations that support the biogas, bio-CNG, and renewable energy sectors. To catalyse biogas development, this partnership will facilitate collaboration between central and state ministries. IOCL and IBA will work to formulate and propose policy incentives for various categories of biofuels,” Gaurav Kedia, Chairman, IBA, said.
The MoU also provides for synergy of R&D work ongoing in the area of biofuels with a special emphasis on industry-institute collaboration.
IBA is the first nationwide and professional biogas association for operators, manufacturers and planners of biogas plants, and representatives from public policy, science and research in India.
The association was established in 2011 and revamped in 2015 to promote a greener future through biogas. The association is working with the German Biogas Association to foster the development of the biogas sector in India.
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Gas Leak In ONGC Pipeline Triggers Panic In Tamil Nadu Village
The residents took to a road roko on Kumbakonam–Mayiladuthurai highway and demanded immediate action in connection with ONGC pipeline gas leak. A gas leak in an Oil and Natural Gas Corporation (ONGC) pipeline in Chethirabalapuram sparked panic among local residents early Saturday. Following this, the residents took to a roadblock on Kumbakonam–Mayiladuthurai highway.
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More than 30 villagers gathered on the road, demanding immediate action from authorities and expressing fear over potential health and safety hazards. The protest led to significant traffic disruption in the region for several hours.
A similar incident last year raised concerns among residents of the Ambedkar Konaseema district, who suspected a gas leak beneath the River Godavari near Dariyalatippa village. The suspected leak caused widespread fear and anxiety in the local community.
To draw attention to the issue, Yanam Congress leaders, along with local residents, set out on a boat to document the suspected leak. They captured video footage showing bubbles rising from the Gowthami Godavari River, accompanied by a strong, unpleasant odor. The visuals were submitted to authorities, intensifying concerns about the possible risks posed by the suspected leak.
In March this year, a gas leak at an ONGC gas collection centre in Kesanapalli, Konaseema district, left nine staff members unwell. The incident occurred around 3 PM due to a pin valve malfunction but was brought under control within 15 minutes. Those affected reportedly experienced suffocation, and among the ill were a four-year-old girl and a 39-year-old woman.
Policy Matters/ Gas Pricing/ Others
Govt cuts APM gas price for first time in 2 yrs
The price of natural gas from legacy fields allocated to state-owned ONGC without auction has been reduced from $6.75 to $6.41 per million British thermal units (mmBtu), according to a notification from the Oil Ministry’s Petroleum Planning and Analy sis Cell (PPAC). New Delhi: For the first time in two years, the government has reduced the price of natural gas used for producing CNG for vehicles and cooking gas, reflecting a decline in benchmark rates.
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The price of natural gas from legacy fields allocated to state-owned ONGC without auction has been reduced from $6.75 to $6.41 per million British thermal units (mmBtu), according to a notification from the Oil Ministry’s Petroleum Planning and Analysis Cell (PPAC).
The reduction, which is the first since the government in April 2023 implemented a new formula to price such gas, will aid city gas retailers like Indraprastha Gas Ltd, Mahanagar Gas Ltd and Adani-Total Gas Ltd who had been reeling under cost pressures from rise in input cost.
In April 2023, the Union Cabinet accepted an expert committee report to price on a monthly basis the gas from legacy fields, called APM gas, at 10 per cent of monthly average import price of crude oil with a floor of $4 and a cap of $6.5 per mmBtu. The cap price was to remain unchanged for two years and rise by $0.25 annually thereafter. In line with this, the cap rose to $6.75 per mmBtu in April.
In the first two years, the price of gas using this formula ranged between $7.29 per mmBtu and $9.12 but the cap ensured that the rate were fixed at $6.50 per mmBtu. In April, the price according to this formula came to $ 7.26 per mmBtu but the final rate was $6.75 in line with higher cap.
In May, the price came to $6.93 but was capped to $6.75 for consumers.
Since there has been a fall in international oil prices in view of uncertain demand outlook, the Indian basket of crude oil averaged around $64 in May. Using this as a benchmark, the APM gas price came to $6.41 per mmBtu on gross calorific value (GCV) basis, according to PPAC.
“For gas produced by Oil and Natural Gas Corporation/Oil India Ltd from their nomination fields, the APM price shall also be $6.41 per mmBtu on GCV basis” for the period June 1, 2025 to June 30, 2025, PPAC said.
The fall in benchmark also means that the price of gas that ONGC produced from new wells in the APM fields would also come down.
The government had allowed ONGC to charge 12 per cent of the oil price for the gas coming from new wells it drills. The higher price was to make up for the capex incurred in drilling new wells.
As much as 5 million standard cubic meters per day of gas or a 10th of all gas produced by ONGC -comes from new wells, according to industry sources.
APM gas is one produced by state-owned firms Oil and Natural Gas Corporation (ONGC) and Oil India Ltd (OIL) from fields that were given to them on nomination basis. This gas is the input that is used in the cooking gas piped to household kitchens as well as turned into CNG for running automobiles, making fertilizers and producing electricity.
Prior to April 2023, the price of gas produced from fields covered under the Administered Price Mechanism (APM) regime which accounts for 70 per cent of domestic gas production — was determined semi-annually based on a formula that benchmarked it to average international prices at four gas trading hubs.
APM gas is provided to city gas distributors for supply to CNG and residential PNG segments, which together accounts for 60 per cent of their sales volume.
Subsequent to the April 2023 decision, APM gas prices are revised on a monthly basis but subject to ceiling and floor price. The ceiling price now is $6.75 per mmBtu and will rise by another $0.25 per mmBtu in April next year.
APM gas prices had seen wide fluctuations in the years running up to the April 2023 decision. From a low of $1.79 per mmBtu in 2021, to a high of $8.57 for the 6-month period ended March 2023.
The rate for difficult fields like KG-D6 of Reliance Industries has been set at $10.04 per mmBtu for six months beginning April 1 as compared to $10.16 in the preceding six months period, according to PPAC.
https://www.deccanherald.com/india/govt-cuts-apm-gas-price-for-first-time-in-2-yrs-3566472
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PNGRB rolls out LNG Terminal Regulations 2025; mandatory charge disclosure, pre-FID filings now required
The move is aimed at integrating terminal planning with gas market needs, improving transparency, and resolving inefficiencies that have led to poor infrastructure utilisation.
New Delhi: With capacity utilisation at newer LNG terminals stuck around 28 per cent and concerns over uncoordinated infrastructure build-up rising, the Petroleum and Natural Gas Regulatory Board (PNGRB) has notified the LNG Terminal Regulations 2025—a sweeping framework that mandates registration, public disclosure of terminal charges, and pre-investment submissions for all entities setting up or operating LNG terminals in India.
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The regulations, finalised in May 2025 after public consultations in August 2024, are applicable to all LNG terminals established on or after October 1, 2007. The move is aimed at integrating terminal planning with gas market needs, improving transparency, and resolving inefficiencies that have led to poor infrastructure utilisation.
Under the new framework, LNG terminal operators must now submit a pre-investment intimation before making a final investment decision (FID). This must be accompanied by a detailed feasibility report, business and evacuation plans, and a performance bank guarantee of ₹25 crore or 1 per cent of the project cost, whichever is lower. Upon PNGRB approval, the entity will receive a certificate of registration valid for 30 years.
Utilisation challenge and planning gap
A key trigger for the regulation has been the poor capacity utilisation of newer LNG terminals. Data from FY16 to FY25 shows that apart from the two legacy terminals at Dahej and Hazira, other terminals have operated at an average utilisation of just 28 per cent. Several of these terminals have been promoted by state-owned companies.
Currently, LNG terminals often come up with limited regulatory oversight during the early stages, and connectivity with gas pipelines is sought post-construction. This has led to creation of underutilised pipeline assets and higher tariffs, which are eventually passed on to end consumers.
To address this, the regulations require terminal developers to inform PNGRB prior to final investment, enabling the regulator to assess gas demand, location suitability, and connectivity requirements before issuing pipeline authorisations.
“The regulator will ensure an integrated development through a well-coordinated plan that aligns with the overall gas sector’s objective,” the regulations state.
Transparency provisions introduced
In a major move towards commercial transparency, the new rules require operators to disclose key charges—such as regasification fees, truck loading rates, and boil-off gas (BOG) charges—on their websites. These charges will also be accessible to PNGRB. Unlike natural gas pipelines where tariffs are regulated and published, LNG terminal charges have remained opaque until now.
While PNGRB does not intend to regulate terminal tariffs, the regulations aim to empower downstream consumers by enabling informed decisions and ensuring fair market access.
“Mandating public disclosure of regasification and related tariffs, granting PNGRB access to terminal charges, and promoting equitable access to gas for all market participants” are central objectives of the new framework.
Monitoring, compliance and penalties
Operators will be required to submit operational data every six months—in April and October. Provisions have been made to accommodate capacity expansion and change in ownership. Non-compliance could lead to suspension, penalties, or cancellation of registration, with due process guaranteed.
Impact on CGD and industrial consumers
The reforms are also significant for City Gas Distribution (CGD) companies, which are increasingly reliant on LNG amid limited domestic gas supply. Following the 12th bidding round, CGD coverage now spans the entire country, excluding islands.
Several CGD players have reached a point where they require nearly one LNG cargo per month and have the capacity to source gas from international suppliers. Industrial users in other sectors are also expected to seek better pricing terms and clearer access conditions in the years ahead.
“Several such customers in other sectors of industry are also coming up which would look for better pricing slopes for LNG contracts in the future. This would require not only competitive sourcing, but transparent access to re-gas slots, clearly disclosed tariffs, and robust downstream connectivity,” PNGRB stated.
Way forward
The regulations represent a shift toward a coordinated and demand-driven gas infrastructure ecosystem. While pipeline development has followed sectoral planning, regasification terminals have largely developed independently. By integrating LNG terminal development into the broader planning framework, the PNGRB aims to optimise infrastructure, reduce tariff burdens, and promote India’s long-term energy security vision.
The PNGRB, under the 2006 Act, had previously issued rules for LNG terminal registration in 2012. The 2025 regulations now reinforce and update that framework, incorporating the need for upstream-downstream alignment, better data collection, and consumer-focused transparency in a rapidly evolving gas economy.
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PNG connection: Gas discoms to be fined for missing targets
City gas companies may face penalties. The PNGRB is concerned about the slow pace of household connections. Many firms missed their PNG connection targets. Some achieved as little as 2% of their goals. CNG infrastructure expanded rapidly. Companies focused on CNG due to higher profits. State-run firms performed better than private companies. The government aims to connect millions of homes. New Delhi: The PNGRB is set to penalise city gas distribution companies for falling significantly short of their targets-achieving, in some cases, as little as 2% of cumulative goals-for connecting households with piped natural gas (PNG), according to people familiar with the matter.
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Companies that secured licences during the 9th, 10th, 11th and 11A bidding rounds-the four largest city gas licensing rounds-have especially underperformed on their home connection commitments. These companies had won licences based on number of households they pledged to connect each year.
Data published by the Petroleum and Natural Gas Regulatory Board (PNGRB) shows that, on average, winners of these four rounds had achieved less than 12% of their cumulative targets as of March 2025.
Conducted from 2018 to 2022, these four rounds awarded two-thirds of India’s city gas distribution licences, with a combined target of connecting 112.9 million households-about 90% of the national goal of 126.3 million homes.
These targets were staggered over multiple years, with cumulative target up to March 2025 set at 19.1 million connections. However, actual connections achieved stand at just 2.24 million – accounting for less than 12%.
Major winners
IndianOil, BPCL, HPCL, Adani Total Gas, Think Gas, Torrent Gas, Indraprastha Gas and others were among the winners in these rounds, with some companies submitting aggressively high connection targets to secure licences.
Considering all city gas licensing rounds to date, companies have achieved about 50% of their cumulative household connection targets. Older licensees have performed better. Private firms are the weakest performers, achieving just 15% of their cumulative targets as of March 2025.
State-run cos better
In contrast, state-run firms have achieved 35%, while joint ventures involving state companies have exceeded their targets, reaching 128% Some of these joint ventures have been operating for nearly two decades.
In stark contrast to the lag in household connections, city gas companies have rapidly expanded compressed natural gas (CNG) infrastructure. They have commissioned 8,067 CNG stations across the country – 165% of their cumulative targets up to March 2025.
“CNG is an extremely profitable business while connecting homes is difficult and offers thin margins,” according to a city gas executive, who explained the gap in expansion between the two business segments.
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UP govt plans green aviation fuel policy to link farming with clean energy
India’s top agricultural producer is developing a plan to increase its portfolio of clean energy such as compressed biogas. The Yogi Adityanath government is creating “Uttar Pradesh Sustainable Aviation Fuel Manufacturing Promotion Policy 2025” in an effort to integrate the farm economy with green energy. By using biomass and grain-based feedstock for the production of aviation fuel, the policy will promote rural income. The feedstock includes rice husks, wheat straw, excess food grains, and sugarcane bagasse.
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India’s top agricultural producer is developing a plan to increase its portfolio of clean energy such as compressed biogas, in order to reduce fossil fuel consumption amid rising energy demand.
The state has already received 18 investment proposals worth ₹3,000 crore from companies
textagagain
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Every Assam town to get CNG pumps & electric vehicle charging stations
Guwahati: During an awareness campaign on World Environment Day here on Thursday, state transport department announced its plan to install CNG pumps and electric vehicle charging stations at all towns of the state. The initiative amis to enhance focus on sustainable transport, complementing its current green infrastructure, which includes more than 6,000 registered electric vehicles across the state and a public transport system comprising 257 electric buses and 100 CNG-operated buses in the city.
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Deputy commissioner of transport, Gautam Das, said, “Our vision is to create a comprehensive network of clean-energy infrastructure that will make sustainable transportation accessible to every citizen of Assam. The govt is looking towards establishing CNG pumps and electric vehicle charging stations in every town of Assam.”
The event, which included a tree plantation drive, was jointly organised by Kamrup Metro’s District Transport Office, the Pollution Control Board of Assam, and S B Deorah College, showcasing a unified approach towards environmental conservation in the state.
Notable Assamese actors Pranjal Saikia and Chetana Das attended the event to support the environmental initiative. Saikia said, “It is a great initiative taken by the transport department involving the younger generation because they are our future, and they should be aware of environmental threats and ways to protect the environment.”
The students of S B Deorah College contributed to the awareness campaign by presenting mime performances that illustrated various environmental concerns, effectively conveying the importance of ecological preservation to those in attendance.
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Govt targets at least 1,000 hydrogen trucks, buses on roads by 2030
After electric vehicles (EVs), hydrogen-powered cars have emerged as a viable alternative to conventional internal combustion engine vehicles to curb road transport emissions The central government plans to put at least 1,000 hydrogen-powered trucks and buses on the road by 2030, an official said. After electric vehicles (EVs), hydrogen-powered cars have emerged as a viable alternative to conventional internal combustion engine vehicles to curb road transport emissions.
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“Almost 50 trucks and buses should be running on hydrogen within this year, and from next year, we’ll need to scale up. We expect more than 1,000 trucks or buses to be in commercial use across the country by 2030,” Abhay Bakre, mission director of the National Green Hydrogen Mission (NGHM), said on Thursday at a Society of Indian Automobile Manufacturers event on revolutionising mobility.
But the availability of green hydrogen will be a challenge, he said. “That’s because most of the hydrogen we aim to produce is meant for a wider market, given the high capital investment required.”
Refineries need large renewable energy inputs, big plants, vast land, and water to produce green hydrogen.
The government also plans to install fuel stations every 200 kilometres (km) and produce biogas-based or decentralised hydrogen at affordable rates. Pilots have been cleared for 10 short-distance corridors, though longer routes like Delhi-Mumbai may also be explored.
The ease of charging an EV at home doesn’t apply to hydrogen vehicles.
“At this stage, it’s risky to produce hydrogen and charge your vehicle at home. Maybe someday, we’ll produce hydrogen on rooftops for cooking and transport, but that’s still far off. So, we’re building a network of hydrogen refilling stations,” Bakre said.
“Our first step is to run pilots across various mobility levels. We plan to set up roadside fuel stations using biogas-based or decentralised hydrogen. We’ve already cleared pilots in 10 corridors,” he added.
“These are short stretches, 100 to 200 km. But we might even try longer corridors like Delhi-Mumbai or others, where fuelling stations could be set up every 200 km. The idea is to produce decentralised hydrogen at a much lower cost.”
A hydrogen fuel cell vehicle runs on hydrogen gas as its main fuel source.
Currently, no hydrogen cars are available for purchase in India, though several manufacturers have announced plans to introduce them.
After targeting road transport, the government now aims to extend hydrogen use to other sectors such as aviation and shipping, as outlined in the NGHM guidelines.
With an outlay of ₹19,744 crore, NGHM was launched in January 2023 for the period up to 2029–30 to reduce dependence on fossil fuel imports. The budget for mobility pilot projects in 2025–26 is ₹496 crore.
Pilot projects under the mission also include those for steel, shipping, decentralised energy, hydrogen from biomass, and hydrogen storage.
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LNG Use / LNG Development and Shipping
India emerges as key market for LNG, ranks fourth globally in 2024: TotalEnergies CEO
India is becoming an increasingly important market for liquefied natural gas (LNG) and ranked number four in the world in 2024, said Patrick Pouyanne, Chairman and CEO of TotalEnergies.
Paris [France], 2 June (ANI): India is becoming an increasingly important market for liquefied natural gas (LNG) and was ranked number four in the world in 2024, said Patrick Pouyanne, Chairman and CEO of TotalEnergies.
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He made these remarks during an exclusive conversation with ANI in Paris, France.
Pouyanne shared insights into the French energy giant’s expanding presence in India, highlighting that TotalEnergies has invested nearly USD 5 billion in the country over the last five years.
He said, “India is becoming an important market for LNG, number four in the world in 2024. So developing this gas for us, finding customers, long-term customers in India is good”.
These investments span across gas, natural gas imports, city gas distribution, development of gas infrastructure, as well as renewable energy projects such as solar and wind.
“We have invested almost USD 5 billion in the last five years, in particular in gas, natural gas, importing energy, city gas, development of gas infrastructure in India, as well as renewables. We invest a lot in solar and wind in India,” Pouyanne said.
Responding to a question about the progress on the MoU signed during India Energy Week with GSPC (Gujarat State Petroleum Corporation) venture in India, Pouyanne said, “It’s going very well. We have signed some contracts in the last year for providing energy to India. GSPC is one, IOCL is another. These are long-term, 10-year contracts.”
He added that the MoU would be converted into a Sales and Purchase Framework (SPF) soon, marking a significant step in strengthening the LNG supply chain to India.
He also spoke about his meeting with Union Commerce Minister Piyush Goyal, who encouraged the company to expand its operations further in India.
He said, “We discussed TotalEnergies’ investments in India….And so we discussed our plans, what we’ve done and what we intend to do for the future. And of course, Mr. Goyal encouraged me to do more in India”.
The meeting took place in Paris during Goyal’s official visit to France, which is part of his ongoing trip to France and Italy from June 1 to 5.
Goyal is also scheduled to meet with key French ministers, including Minister of Economy Eric Lombard and Trade Minister Laurent Saint-Martin.
The developments highlight India’s growing role in the global energy market and its strong partnership with global energy players like TotalEnergies. (ANI)
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Torrent Power signs LNG supply pact with BP Singapore
The deal comes amid a government push to boost power generation from gas-based plants. Last month, the Centre directed such plants to increase output in anticipation of surging electricity demand.
New Delhi: Gujarat-based Torrent Power Ltd (TPL) has signed a long-term sale and purchase agreement with BP Singapore Pte. Ltd, a subsidiary of global energy major bp, for the supply of up to 0.41 million metric tonnes per annum (MMTPA) of liquefied natural gas (LNG) from 2027 to 2036.
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The LNG will be strategically used by TPL to operate its 2,730 MW combined cycle gas-based power plants (GBPPs) across India, helping meet the country’s growing electricity demand and support the grid during peak consumption periods, the company said in a statement.
The agreement will also support Torrent Gas Ltd (TGL), the group’s city gas distribution (CGD) arm, by catering to its rising LNG requirements. The fuel will be used to ensure reliable gas supply for households, commercial and industrial consumers, as well as compressed natural gas (CNG) vehicles, the statement added.
“Taking advantage of softness in LNG prices, TPL along with TGL further intends to explore medium- and long-term LNG procurement in response to the growing demand from its GBPPs and CGD networks respectively, aiming to enhance its portfolio diversity and reliably to meet energy supply needs of customers,” the statement said.
The deal comes amid a government push to boost power generation from gas-based plants. Last month, the Centre directed such plants to increase output in anticipation of surging electricity demand. India’s peak power demand is projected to hit 270 GW in FY26, up from the record 250 GW seen last year.
As part of India’s broader energy transition, natural gas—considered a cleaner alternative to crude oil—is being promoted across sectors, including domestic cooking and transportation. The ministry of petroleum has set a target to raise natural gas’s share in India’s energy mix to 15% by 2030, up from the current 6%.
A part of the Torrent Group, TPL has an installed generation capacity of 4,838 MWp, comprising 2,730 MW of gas-based, 1,746 MWp of renewable, and 362 MW of coal-based capacity. Another 3,154 MWp of renewable projects and 3,000 MW of pumped storage capacity are under development.
This brings TPL’s total planned generation and storage capacity to 7,992 MWp and 3,000 MW, respectively.
Under its power distribution business, TPL supplies nearly 31 billion units of electricity to over 4.21 million customers across Ahmedabad, Gandhinagar, Surat, Dahej SEZ and Dholera SIR in Gujarat; Dadra and Nagar Haveli and Daman and Diu; and Bhiwandi, Shil, Mumbra, Kalwa in Maharashtra; as well as Agra in Uttar Pradesh.
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GAIL Discharges LNG Cargo at Dabhol Terminal
GAIL (India) Limited marked a major milestone in India’s energy infrastructure with the successful berthing and discharge of its first LNG vessel at the Dabhol LNG Terminal following the completion of the landmark Breakwater Project.
‘GAIL Bhuwan’ Makes Historic First Call
On June 2, 2025, Sandeep Kumar Gupta, Chairman and Managing Director, and Sanjay Kumar, Director (Marketing), GAIL, received the LNG vessel ‘GAIL Bhuwan’. The event marked the start of seamless, all-weather operations at the terminal, a transformative development for India’s gas import capacity.
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Breakwater Project Transforms Dabhol into All-Weather Port
With the commissioning of the island breakwater structure and receipt of all necessary statutory approvals, the Dabhol LNG Terminal is now classified as an all-weather port. This is a crucial upgrade that allows uninterrupted operations throughout the year, including during the challenging Southwest monsoon, which has historically disrupted marine logistics along India’s west coast.
Unlike conventional land-connected breakwaters, the Dabhol breakwater is an island-type structure, reflecting a significant feat of advanced marine engineering. Multiple stakeholders realized this complex infrastructure through innovative solutions and deep collaboration, overcoming numerous technical hurdles.
Vital Link in India’s Natural Gas Network
Strategically located on the Maharashtra coastline, the Dabhol LNG Terminal has a regasification capacity of 5.0 million metric tonnes per annum (MMTPA). It plays a key role in India’s energy distribution system, feeding into major pipelines such as the Dabhol-Bangalore and Dabhol-Panvel corridors. The new breakwater is set to significantly improve vessel accessibility, enhance operational efficiency, and increase capacity utilization, thereby strengthening GAIL’s LNG handling capabilities.
Capacity Expansion to 6.3 MMTPA Underway
As part of its forward-looking strategy, GAIL is now preparing to expand the terminal’s capacity from 5.0 to 6.3 MMTPA in the first phase over the next three years. Once expanded, the terminal will be capable of handling up to 100 LNG cargoes annually, reinforcing its role as a critical node in India’s energy supply chain.
Driving Energy Security with Resilient Infrastructure
The achievement comes at a pivotal time, as India accelerates efforts to ensure energy access, reliability, and security. As reported by msn.com, by transforming Dabhol into a monsoon-resilient LNG hub, GAIL is not only addressing seasonal operational challenges but also laying the groundwork for a more robust and flexible energy future.
https://chemindigest.com/gail-discharges-lng-cargo-at-dabhol-terminal/
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GAIL’s Dabhol LNG Terminal soars to new heights with All-Weather Port triumph
DABHOL : In an electrifying leap toward a brighter, more resilient energy future, GAIL (India) Limited has etched a historic milestone by transforming its Dabhol LNG Terminal into a vibrant all-weather port.
Jubilant moment was celebrated on June 2, 2025, as the first LNG vessel, GAIL Bhuwan, gracefully berthed and discharged its cargo during the monsoon season. The occasion was graced by Shri Sandeep Kumar Gupta, Chairman & Managing Director, and Shri Sanjay Kumar, Director (Marketing), GAIL, igniting a wave of optimism for year-round LNG operations that promise to power India’s energy security.
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The crowning achievement of the Breakwater Project, a dazzling feat of marine engineering, has paved the way for this transformation. With all statutory approvals proudly secured, the terminal now stands as a beacon of reliability, undeterred by the fierce Southwest monsoon that once challenged marine logistics along India’s West coast. The pioneering island breakwater, a bold departure from conventional designs, radiates technological brilliance and the power of collaborative spirit, turning complex challenges into a symphony of innovative solutions.
Nestled along Maharashtra’s scenic coastline, the Dabhol LNG Terminal, boasting a robust 5.0 MMTPA regasification capacity, is a vital artery in India’s natural gas network, fueling the Dabhol-Bangalore and Dabhol-Panvel pipelines. The breakwater’s success has unlocked seamless vessel access, supercharging capacity utilization and ensuring a steady stream of clean energy to energize communities and industries. This milestone is a vibrant step toward India’s energy transition, amplifying the nation’s commitment to a sustainable, low-carbon tomorrow.
With eyes set on a bold future, GAIL is charging toward expanding the terminal’s capacity to an impressive 6.3 MMTPA within three years, with plans to handle up to 100 LNG cargoes annually. This ambitious vision is set to elevate Dabhol as a cornerstone of India’s energy infrastructure, sparking economic prosperity and strengthening regional connectivity.Brimming with stakeholder synergy and cutting-edge innovation, this achievement showcases GAIL’s unwavering dedication to building a dynamic, future-ready energy ecosystem. As green energy and sustainable infrastructure light up global discussions, Dabhol’s radiant transformation stands as an inspiring testament to what passion, ingenuity, and ambition can achieve, setting a golden standard for progressive energy solutions.
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BP shakes hands on multi-year LNG offtake with India’s Torrent Power
BP Singapore, a subsidiary of the UK-headquartered energy giant BP, has signed on the dotted line with India’s Torrent Power, part of Torrent Group, to supply liquefied natural gas (LNG) for the latter’s 2,730 MW combined cycle gas-based power plants in line with India’s push to up the natural gas ante in its energy mix to around 15% by the end of the decade.
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Torrent Power’s move to secure fuel for its increasing power and city gas distribution businesses has led to a long-term sales and purchase agreement (SPA) with BP for the supply of up to 0.41 million metric tonne per annum (mtpa) of LNG, beginning in 2027 and continuing through 2036.
While the 2,730 MW combined cycle gas-based power plants are said to play a key role in meeting peak power demand and balancing renewables in India’s energy grid, this is also expected to cater to the growing requirements of Torrent Gas’ distribution network.
As India’s player is interested in leveraging the current state of play in global LNG prices to lock in favorable terms for energy supply, it is actively evaluating additional medium- and long-term LNG sourcing options to support the expansion of its generation and gas distribution operations.
With an installed generation capacity of 4,838 MWp, Torrent Power has 2,730 MW of gas-based, 1,746 MWp of renewables, and 362 MW of coal-based capacity, while projects under development entail 3,154 MWp of renewables and 3,000 MW of pumped storage.
BP has been a busy bee lately across many regions, including Azerbaijan, where the firm confirmed final investment decisions for multiple projects.
This encompasses the development of the next stage of a natural gas field in the Caspian Sea, seen as the firm’s largest gas discovery.
https://www.offshore-energy.biz/bp-shakes-hands-on-multi-year-lng-offtake-with-indias-torrent-power/
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Electric Mobility/ Hydrogen/Bio-Methane
IndianOil finalises India’s largest Green Hydrogen project at Panipat
In a major step towards promoting clean energy in India, IndianOil has finalised the Levelized Cost of Hydrogen (LCOH) for setting up a 10,000 Tonnes Per Annum Green Hydrogen Generation Unit at its Panipat Refinery & Petrochemical Complex.
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In a major step towards promoting clean energy in India, IndianOil has finalised the Levelized Cost of Hydrogen (LCOH) for setting up a 10,000 Tonnes Per Annum Green Hydrogen Generation Unit at its Panipat Refinery & Petrochemical Complex.
This project marks IndianOil’s entry into the green hydrogen sector and will be the largest green hydrogen initiative in India to date.
The company in a statement on Friday, stated that “Slated for commissioning by December 2027, the Green Hydrogen produced will replace fossil-derived Hydrogen in refinery operations, resulting in substantial reduction in Carbon emissions”.
The plant is expected to be commissioned by December 2027. The green hydrogen produced at this facility will replace the fossil-fuel-based hydrogen currently used in the refinery’s operations.
This transition is expected to significantly cut down carbon emissions, helping IndianOil move towards a more sustainable and environment-friendly model.
The company also added that this initiative is in line with Prime Minister Narendra Modi’s vision under the National Green Hydrogen Mission and forms a critical part of IndianOil’s larger decarbonization strategy.
The project also supports the company’s Net Zero target and demonstrates its commitment to leading India’s shift towards a cleaner and greener energy future.
Earlier, Arvinder Singh Sahney, Chairman of IOC, during an exclusive conversation with at the World Economic Forum 2025 in Davos, Switzerland, stated that the plant, with a production capacity of 10,000 tons per annum, had made substantial progress.
“Green hydrogen plant is now alive. We have got very good bids for it. And now the tenders are under evaluation. And within a month or so, we will be able to award the job, and within two years, that green hydrogen, the 10,000 tons per annum plant at Panipat (Haryana) will be commissioned” he said.
The plant aims to bolster India’s green energy mission, contributing to a sustainable and carbon-neutral future.
With this landmark project, IndianOil further strengthens its leadership in the country’s energy transformation journey.
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Green hydrogen projects on the slow lane on unviable project economics, lack of pricing clarity
Govt has set an ambitious production target of 5 million tonnes by 2030
India’s green hydrogen plans are making slow progress with not much clarity on the global demand for green ammonia, as the cost of producing green hydrogen makes it economically unviable, resulting in uncertainty over its pricing. The government is making a huge push for green hydrogen. Under the Strategic Interventions for Green Hydrogen Transition (SIGHT) scheme, the government has set an ambitious production target of 5 million tonnes by 2030, with an outlay of ₹17,500 crore up to FY30, offering incentives for the production of electrolysers and green hydrogen.
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While all leading energy companies, including state-owned enterprises such as Indian Oil Corporation, Oil India, NTPC, GAIL, and private sector conglomerates such as Reliance Industries have announced ambitious plans, it is yet to be called a success story.
It is still at a very nascent stage, as there is no clear reference point to derive price, multiple sources said.
Also, there is wide price differential between cost of production of green and grey hydrogen, and the incentives under the government schemes are not adequate to bridge that gap. At around ₹300 per kg, the cost of producing green hydrogen is double that of grey hydrogen.
While large players such as Reliance Industries’s Mukesh Ambani and Adani Group’s Gautam Adani have been talking about bringing down the cost of hydrogen to $1 per kg, the road to achieving that is a long way off.
One of the major components in the cost of production is power, followed by operational expenditure. For the cost of power to go down, the government will have to step in to provide incentives. At present, most of the solar energy capacity that companies are setting up is going toward captive consumption rather than towards production of green hydrogen, sources said.
The costs of setting up a green hydrogen plant in India can vary depending on factors, such as production capacity and chosen electrolyser technology. However, a self-investment range of ₹10 crore to 15 crore can be considered a starting point, sources said. Additional investments may be necessary based on specific project requirements, those into the business said.
Projects
IOC, Bharat Petroleum, and RIL currently have green hydrogen pilots under construction. NTPC is blending green hydrogen with PNG, while Honeywell plans to set up India’s first green ammonia plant.
Last week, IOC said it has finalised the Levelised Cost of Hydrogen (LCoH) for setting up a 10,000 tonne per annum green hydrogen generation unit at its Panipat Refinery & Petrochemical Complex, marking its entry into the green hydrogen space.
GAIL has commissioned a 10 MW green hydrogen unit at its plant at Vijaipur, Guna Distt. M.P in April 2024.
Despite all this it still has to become popular in the retail market. Till price issue is not addressed.
Electricity costs can be reduced through dedicated solar parks, allowing unlimited power banks and waiving open-access charges for captive renewable energy for green hydrogen, according to a note by SBI Caps.
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Saudi energy firm Alfanar lines up India green hydrogen play, awaits clear policy signals
However, India still lacks assured offtake agreements, says its India CEO
Mumbai: Saudi Arabia-based energy giant, Alfanar Group, is preparing to enter India’s green hydrogen segment once the country’s policy and regulatory framework becomes clearer, Mohammed Irfan, chief executive officer, Alfanar Global Development – India, told ETEnergyWorld.
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The company has an annual revenue of Rs 620 crore. At present, it has wind power capacity of 506.5 MW operational in Gujarat and while 50 MW is under construction, he said.
“Our focus is on a mix of wind and solar hybrid projects, along with energy storage… We are preparing to enter the hydrogen segment once India’s policy framework becomes clearer. Leveraging our international expertise, especially from Egypt and Chile, we aim to replicate successful models in India,” he said in an exclusive interview.
He, however, added that while there was growing interest, India still lacked assured green hydrogen offtake agreements.
“Once India’s hydrogen market matures in terms of regulatory and policy adaptation or guaranteed offtake emerges, we will definitely be a part of it. In contrast, India’s renewable sector benefits from long-term PPAs with entities like NTPC, SECI, and others,” said Irfan.
Apart from this, he added that their Saudi team is also working on developing green hydrogen projects in Egypt and green ammonia in Chile.
The company is actively positioning itself as a key player in the global renewable energy transition and has developed a portfolio of about 1.7 GW of renewable energy projects across Spain, India, and Egypt.
“In Spain, we operate both wind and solar projects. In Egypt, we have a solar project, and in India, we have about 600 MW of wind projects operational,” said Irfan.
The company is also developing a sustainable aviation fuel project in the United Kingdom.
On the challenge of grid evacuation, Irfan said that power evacuation and grid connectivity at CTU/PGCIL substations are already constrained, as multiple independent power producers and land brokers have secured access through land acquisitions and bank guarantees for substations scheduled for commissioning up to 2030. As a result, the earliest available connectivity that can currently be applied for at the CTU level is for the year 2031.
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Hydrogen-powered Drone: Paras Defence Bets On Next-gen UAV Tech
In an interview with BW Businessworld, Amit Mahajan, Director of Paras Defence & Space Technologies, outlined the company’s pivotal role in India’s defence manufacturing ecosystem, highlighting indigenous capabilities in optics, electronics, and anti-drone systems. The company is bringing hydrogen-powered drones—offering 12-hour endurance and quick refuelling—into local production through partnerships with Israeli firms. With a strong focus on R&D and collaborations with DRDO and global players, Paras is poised to support emergency procurements and exports. While exports currently account for 10 per cent of revenue, the company expects growth as global demand rises. Excerpts:
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Paras Defence has emerged as a key player in India’s defence sector. How do you see your company’s role in indigenous defence manufacturing today?
Paras Defence has been an Indian manufacturer for both defence and space applications for many years. Our core offerings include optics, optronic systems, defence electronics, electromagnetic pulse protection, and mechanical systems. Additionally, through our subsidiary, we offer anti-drone solutions. We have partnered with Israeli companies to bring hydrogen-powered drones and electro-optic payloads to armoured vehicles and drone platforms. These Make in India solutions are not just contributing to the current programmes but are also ready for deployment in emergency procurements and fast-tracked defence initiatives.
Can you explain how hydrogen-powered drones differ from conventional battery-powered drones and those already in use globally?
Certainly. Instead of using batteries, these drones are powered by hydrogen fuel cells, which significantly increases endurance. While typical battery-powered drones can fly for about 30 minutes, hydrogen-powered drones can stay airborne for up to 12 hours with a payload capacity of 22 kg. Refuelling is quick, and the drones are quieter. It is similar to hydrogen-fuelled cars—Hyundai already makes one, for instance. If we talk about use. Yes, our Israeli partner has already field-proven this technology. We are bringing that to India for local manufacturing under Make in India.
Apart from Israel, do you have any other international collaborations?
We have partnered with two Israeli companies—CONTROP Precision Technologies (a government company) and HEVEN Drones. We are forming joint ventures with both. Additionally, we work with CERBAIR, a French anti-drone solutions firm that uses our technologies. These partnerships ensure that advanced technologies are developed or manufactured in India, and some Paras technologies are also being exported.
What is Paras Defence’s role in research and development, particularly in missile systems, avionics and drones?
R&D is at the core of our organisation. For 50 years, we have developed technologies across mechanical systems, electronics, software (particularly embedded systems), optics, RF and microwave technologies, and drone platforms. This focus ensures that we deliver world-class, technically superior products.
With the current conflicts involving drones, from Armenia-Azerbaijan to Israel-Palestine and even Russia and Ukraine. How can India reduce dependence on imported drones?
The Indian government has mandated a minimum of 50 per cent indigenous content in defence equipment, regardless of the source country. This means that even when Israel or others supply us, manufacturing must happen in India. This approach strengthens the domestic manufacturing ecosystem and ensures we are prepared to meet any urgent demand.
During the recent conflict with India, Pakistan was reportedly using Turkish drones. How do Indian drones compare?
I prefer not to compare. Every country develops technologies suited to its needs. India has its strengths. Our systems have proven their mettle by defending our skies, and that is what matters.
Does Paras Defence work directly with the Indian Army, Navy, or Air Force?
We work with the entire Ministry of Defence ecosystem—DRDO, Ordnance Factories, and Defence Public Sector Undertakings. About 30–40 per cent of our revenue comes from technologies developed in collaboration with DRDO. We co-develop and contribute to cutting-edge defence solutions.
Is Paras currently exporting defence products? How do you see the global market?
Yes, we are exporting to Israel, parts of Europe, South Korea, and now the US. Indian defence technologies have proven their field-worthiness, and this will create global demand. We expect a rise in export enquiries in both the defence and space sectors.
Among Israel, the EU, South Korea, and the US, which is your most promising market?
Export is our Plan B. Our Plan A is the domestic market, where we enjoy top priority as an IDDM (Indigenously Designed, Developed, and Manufactured) company. Currently, exports make up about 10 per cent of our business, but we expect this to grow to 25 per cent as global demand increases.
The Defence Minister has set an ambitious export target of Rs 50,000 crore by 2029 and wants India to become a top exporter by 2047. Are these goals achievable?
Absolutely. Even before recent geopolitical developments, our technologies were already on par with global standards. What is needed now is repetitive production to refine development-quality systems into production-quality systems. Once achieved, we will be export-ready, not just in capability but in price competitiveness as well. Our systems will be more affordable than their European or American counterparts.
In the last couple of years, private sector participation in defence has increased significantly. How do you see the future of private defence companies?
Both the public and private sectors bring unique strengths. Large government firms, like HAL, have the infrastructure to develop massive platforms like Tejas. Yes, speed needs improvement, but they are indispensable. On the other hand, private firms offer agility, cutting-edge tech and rapid development cycles. Together, they form a robust ecosystem. Private players complement government entities, and this collaborative model is key to building scalable, high-quality defence solutions.
Do you face significant competition from other Indian defence companies?
Paras Defence typically focuses on niche technologies, so we do not have many direct competitors. Today, the Indian defence ecosystem is more collaborative than competitive. Each company contributes based on its strengths, and we collectively support our armed forces.
Defence stocks are surging and investor optimism is high. What are your future plans—investments, acquisitions, or new partnerships?
We have always responded proactively to market and customer needs. Our partnerships with CONTROP and HEVEN reflect that. When your customer is the national defence, business becomes a matter of patriotism. We will do whatever it takes—whether that means raising funds, acquiring firms, or forming tech partnerships—to strengthen India’s self-reliance in defence.
Could you elaborate on your manufacturing footprint?
Our main manufacturing bases are in Navi Mumbai, specifically in Nerul and Ambernath. We also have facilities in Bengaluru (two locations), Hyderabad and Delhi. We are well equipped with space, assets, and talent to scale up operations in response to emergency procurement needs or sectoral growth.
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First biogas plant for waste management unveiled on World Environment Day in Maharashtra’s Ulhasnagar
ULHASNAGAR: On the occasion of World Environment Day today, the first Waste Management Bio Gas Plant in Ulhasnagar city was unveiled by the city’s BJP MLA, Kumar Ailani, and BJP Ulhasnagar District President, Rajesh Vadhrya.
This bio gas plant was built by the developer in a private Regency Antilia complex. The waste from hundreds of flat holders living in the complex will no longer go to the municipal corporation’s dumping site.
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Instead, it will be processed in this bio gas plant built within the complex. Through this process, bio gas and electricity will be produced, which will be used to operate the plant and meet the electricity needs for other utility services installed in the complex.
Mahesh Agrawal, Chairman of Regency Group, said that this plant is the first bio gas plant in Ulhasnagar city. Through it, they will collect the wet waste from the houses in their complex, where thousands of people live, and process it to make bio gas and electricity.
Vadhrya stated that this plant can process 4,000 kg of waste per day. The gas generated will run the entire plant, and 200 to 250 units of electricity will be generated daily, allowing the utilities inside the complex to run efficiently. Additionally, cow shed dung located in the complex will also be used to produce gas in this plant.
BJP MLA Kumar Ailani appealed to other housing complexes in the city to come forward and install such plants to save the environment.
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ACME Group confirms green hydrogen project in Odisha
The project will be located within the Tata SEZ and aims to support India’s transition to alternative energy sources.
ACME Group has reaffirmed its plan to establish its first green hydrogen project in India at Gopalpur, Odisha. The announcement was made at the Groundbreaking and Inauguration Ceremony for five industrial projects at the Tata Steel Special Economic Zone (Tata SEZ) in Gopalpur Industrial Estate. The event was attended by Odisha Chief Minister Mohan Charan Majhi, state officials, business representatives and ACME Group executives.
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The project will be located within the Tata SEZ and aims to support India’s transition to alternative energy sources. Anil Kumar Taparia, Chief Operating Officer of ACME Green Hydrogen SBU, said, “ACME Group is privileged to associate with Tata Steel Special Economic Zone to establish our first Green Hydrogen project in India. The rapid industrialisation of Odisha under the leadership of Chief Minister and the sustainability-focused ecosystem being developed empowers us to pursue our mission of providing innovation solutions to decarbonise various sectors for a greener future. The implementation of our project is on course to meet the stipulated timelines.”
Employment and international collaboration
The project will produce 400,000 tonnes of green ammonia annually and is expected to create over 1,000 direct and indirect jobs. ACME Group has also partnered with a Japanese corporation to supply the entire output from the Odisha facility starting in 2029.
The company stated that the collaboration aligns with both Japan’s net zero goals and India’s National Green Hydrogen Mission.
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INTERNATIONAL NEWS
Natural Gas / Transnational Pipelines/ Others
US: Gas pipelines eye return to New York
ALBANY, N.Y. (NEXSTAR) — Plans to revive two controversial natural gas pipelines previously blocked in New York renewed the debate between fossil fuelers, utilities, state officials, and environmentalists. Potentially at issue are the Constitution and Northeast Supply Enhancement pipelines, long-defeated projects that could move forward with support from the Trump administration and mixed signals from Governor Kathy Hochul.
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This follows talks between Hochul and President Donald Trump that also resulted in federal reapproval for the Empire Wind project. In a May 19 statement on Trump greenlighting the offshore wind farm, Hochul said she “reaffirmed that New York will work with the Administration and private entities on new energy projects that meet the legal requirements under New York law.”
Indeed, “They will have to follow our laws,” Hochul said on Thursday of any company wanting to build pipelines or other energy projects in New York. “But we can look at this expansively, also consider the benefits at a time when energy prices are through the roof.”
In response, environmental groups called on Hochul to oppose the pipelines. They pointed out that New York previously stopped both pipelines by denying necessary Clean Water Act permits.
Food & Water Watch said the Constitution and NESE pipelines “posed serious threats to our environment, climate, and communities across the state,” and told Hochul to reject any new applications for those projects. Laura Shindell, New York State Director at FWW, called reviving the Constitution Pipeline a “reckless and unacceptable capitulation to President Trump and the polluting fossil fuel interests backing him.”
Mark Izeman, senior strategist and attorney at the Natural Resources Defense Council, warned that reviving either pipeline “will once again be met with stiff and deep resistance” and could lead to prolonged legal battles. He said the pipelines would increase dependence on fossil fuels.
And the New York Public Interest Research Group pointed out that the Constitution pipeline was denied under the Clean Water Act and that the decision was upheld by the U.S. Court of Appeals and left in place by the U.S. Supreme Court. Eric Wood, Senior Environmental Program Coordinator for NYPIRG, urged Hochul to “stand strong with the [Department of Environmental Conservation] and the Supreme Court in prioritizing the health and safety of her constituents.”
Tulsa, Oklahoma-based pipeline operator Williams Companies filed paperwork with federal regulators in May to restart both projects, which would carry fracked gas from Pennsylvania’s Marcellus Shale into New York and New England, as first reported by The New York Times. The Constitution pipeline would span over 100 miles from northeast Pennsylvania to Albany, while NESE would run mostly underwater between New Jersey and New York City.
Energy officials and industry advocates argue the pipelines could lower utility bills in the region where natural gas prices are among the highest in the country. A recent S&P Global study, as reported by the New York Times, found that more pipelines could cut natural gas prices in the Northeast by 20% to 30%.
Natural gas currently supplies nearly half of all electricity in New York. In their public filing, Williams said the proposed pipelines are “essential to address persistent natural gas supply constraints in the Northeast, constraints that have led to higher energy costs for consumers and increased reliance on higher-emission fuels like fuel oil.” The company told the Federal Energy Regulatory Commission that it hopes to begin operating NESE by late 2027, according to the Times.
The revival of the pipeline projects, estimated to cost nearly $1 billion each, faces hurdles, including securing enough long-term customers to finance construction and potential legal challenges. Meanwhile, the Trump administration has made expansion of fossil fuel infrastructure a top priority.
The governor’s office denied making any specific deal on pipelines in exchange for the wind project’s federal reapproval. But U.S. Interior Secretary Doug Burgum tweeted that Hochul signaled a “willingness to move forward on critical pipeline capacity.”
The renewed debate coincides with the New York State Senate advancing the New York Home Energy Affordable Transition Act, sweeping reform targeting energy costs and gas system expansion. The State Senate Rules Committee just cleared the bill, which supporters say would modernize outdated utility laws and promote cleaner fuel sources by ending a requirement that utilities supply gas to new customers and removing subsidies for new gas hookups.
Liz Moran, New York Policy Advocate with Earthjustice, said, “The NY HEAT Act is the only policy before Albany lawmakers to put an end to out-of-control utility rate hikes while standing up to the Trump administration gutting energy affordability and climate programs.”
The Climate Can’t Wait coalition has also pushed for the NY HEAT Act and other climate bills, citing concerns about federal actions supporting fossil fuel projects, including “previously stopped gas pipelines, including the Constitution pipeline in New York.”
As of early 2025, more than 1.2 million New York households were behind on utility bills, collectively owing nearly $1.8 billion. The nonprofit AGREE reported that every major gas utility in the state has raised heating costs since 2022. For example, average monthly gas bills rose by $48 for Con Edison customers and $62 for National Grid customers in New York City.
Supporters say the HEAT Act would save struggling households an average of $136 monthly and cut billions in long-term fossil fuel infrastructure costs. A Siena poll found that 58% of New Yorkers surveyed support the bill, including majorities across party lines, regions, and income levels.
Opposition to the NY HEAT Act has come from those and other utility companies, including National Fuel Gas, the only major utility in the state that engages in fracking. The Alliance for a Green Economy, promoting a report from the think tank Switchbox, accused National Fuel of generating almost 90% “of its profits from fracking-related businesses in Pennsylvania rather than delivering energy to New York households.”
While it serves a relatively small portion of New York customers, it raised residential delivery rates by 40% over three years and plans to invest $362 million in new gas infrastructure. As of August 2024, more than 54,000 National Fuel customers were in arrears and facing shutoffs. The report identified National Fuel as one of the top 25 fracking companies nationwide.
Jessica Azulay, executive director of Alliance for a Green Economy, said, “This report makes it obvious why National Fuel is opposing this transition, in particular why they are opposing the NY HEAT Act, which will reduce our reliance on the product they sell.”
Reiterating her commitment to climate goals on Thursday, Hochul said she was focused on New York City’s energy demands and open to exploring “all the options that could work for New Yorkers.” Facing reelection next year, she said, “I have to look at this in a different lens and will continue being committed to our climate goals. I believe in them, but also the realization that we need to be more open-minded.”
Hochul added, “I am open to nuclear. That may be a radical thought to people, but I need to power this state, take the economic burden and the cost off my citizens and my residents, but also be able to prepare for the innovation and the jobs that are coming here.”
https://www.rochesterfirst.com/news/gas-pipelines-eye-return-to-new-york/
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Monongalia : Hope Gas Morgantown pipeline makes progress: A visit to construction sites
MORGANTOWN – Hope Gas is making steady progress on its Morgantown Connector Project – a new 30-mile pipeline from Wadestown to Morgantown – and took The Dominion Post on a visit to several sites along the route last week. Brittany McDaniel, Hope’s director of Engineering Project Management, and Colin Mitchell, project manager for contractor Apex Pipeline Services, led the tour. Jonell Carver, Hope’s chief operating office, Chris Hendrick, Hope vice president for Reliability, and Jason Barnette, with Hope’s land department, also joined.
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Nitro-based Apex is the contractor for the 10-mile “spread” leading into Morgantown. Charleston-based Ace Pipeline won the contracts for the two other 10-mile spreads.
Apex started cutting trees in January, McDaniel said, and expects to be nearly done with its work by the end of July into August – ahead of schedule. Ace is also ruining ahead of schedule. The line is planned to go into service Nov. 1, at the start of winter heating season when demand picks up. Additional restoration and cleanup will continue into 2026.
Hope is building the pipeline to meet increased demand for natural gas in the Morgantown area. A second line will also provide redundancy – should there ever be an issue with the existing line. But Hope also said during our Wednesday tour that one of its missions it to create West Virginia jobs.
Mitchell said Apex is employing about 150 people for its spread, while Ace has about 300 on its two sections. McDaniel said each spread also requires 20-30 Hope inspectors and support staff.
And that doesn’t count service jobs – dump trucks and delivery trucks – and indirect jobs for hotels, restaurants and the various suppliers, Mitchell said.
We visited three sites in various stages of development. At one, outside Westover, two big yellow shovels sat at the bottom of a hill. A line of 16-inch pipe ran down the cleared right of way. Metal support structures keep the pipe off the ground.
At the next site, also outside Westover, the right of way runs up and down more hills and the pipe is buried. Mitchell said the line must have a minimum of 3 feet of coverage, but there’s usually more. And the original ground goes back on top of that, so the line is generally about 6-7 feet below the surface.
McDaniel noted that laying pipeline is different from running it along flatland. As West Virginia companies, both contractors have an advantage. “They know how to handle this mountainous terrain.”
The third site, out Fairmont Road and up Little Indian Creek Road near the Arkwright Mine, is already reclaimed. Grass is growing on the right of way running down the hill. They work with landowners, McDaniel said, to meet their needs and demand for specific types of grass, fencing, property line posts and so on.
And while the original design ran as straight as possible, she said, they’ve adjusted the course for the realities on the ground – including the residents along the way. The second site was moved several hundred yards to avoid a new subdivision under construction.
McDaniel estimated that the project right of way involved about 243 landowners. We’ve reported several times that Hope filed 31 condemnation suits – seeking eminent domain – in Monongalia County Circuit Court, and spoken with landowners unhappy with Hope’s negotiations for compensation. A look at court records on Thursday showed 23 cases open and eight settled and closed.
We asked McDaniel about those holdouts. “We’re working on that,” she said. Some are in the process of resolution and will be settled while some will be resolved by the court.
Along with compensation for loss of land use, some landowners raised pipeline safety concerns to The Dominion Post.
We also asked McDaniel about that. She said, “As far as I’m concerned, pipelines are the safest form of [gas] transportation that there is.” She has lines across her land, she said, and described some of the safety measures they employ, including X-raying all the pipe welds and testing the lines to 1.5 times their operating pressure.
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Azerbaijan: Exxon signs agreement with Azerbaijan’s SOCAR to explore onshore oil production
BAKU, June 2 (Reuters) – Exxon Mobil (XOM.N), opens new tab and Azeri state energy company SOCAR said on Monday they signed a deal agreeing to explore onshore oil and gas production in Azerbaijan, while BP (BP.L), opens new tab is expected to buy into new Azeri offshore fields, according to three sources. Azerbaijan’s production mainly relies on mature oil fields in the Caspian Sea and the country is aiming to maintain its oil output at around 582,000 barrels per day over the next five years with investment from Western energy companies.
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At the Baku Energy Week conference, SOCAR and Exxon signed a memorandum of understanding for the exploration, development, and production of unconventional onshore oil reserves in Azerbaijan.
Exxon’s experience in developing unconventional oil could help Azerbaijan boost its onshore output, which currently accounts for just 5% of the country’s total oil production, and open a new chapter in its oil industry.
Unconventional oil and gas resources often refer to hydrocarbons trapped in porous rock, requiring specialised extraction technologies such as fracking.
“In the years to come, we’ll be able to talk about the potential size of the resource and what the economics might look like,” said John Ardill, Exxon vice president of global exploration.
Arzu Javadova, vice president for geology at SOCAR, said the agreement was focused on assessing options for the project and the companies were not planning to drill exploration wells at this stage.
Exxon already holds stakes in Azerbaijan’s largest oil development project, Azeri-Chirag-Gunashli, and the Baku-Tbilisi-Ceyhan pipeline, which transports Caspian crude to Turkey and onward to Europe.
Separately, SOCAR is expected to announce on Tuesday the sale of interests in the Karabakh and Ashrafi-Dan Ulduzu-Aypara offshore oil and gas fields to BP, with BP set to become the operator of the Karabakh development project, according to three sources familiar with the matter.
Last year, BP signed a memorandum of understanding with SOCAR on potentially joining these two projects.
SOCAR previously had a contract with Norway’s Equinor on the Karabakh and Ashrafi-Dan Ulduzu-Aypara fields, but Equinor decided to withdraw from the project in 2017 as it refocused on core assets.
Azerbaijan plans to increase natural gas exports by 8 billion cubic metres by 2030, President Ilham Aliyev said at the conference on Monday. Azerbaijan exported 25 bcm of natural gas in 2024.
BP also announced on Monday it had taken a final investment decision on its 240-megawatt Shafag solar plant project in the Jabrayil district of Azerbaijan. The company’s solar unit Lightsource bp is building the project with joint-venture partners SOCAR and the Azerbaijan Business Development Fund.
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Evonik paves the way for climate-neutral hydrogen to Marl – 50 km pipeline completed
Marl. A significant step towards hydrogen supply in Germany has been successfully completed: Experts from the Essen-based chemical company Evonik have made a pipeline more than 50 kilometers long operational. The pipeline connection extends in several sections from Legden in northern North Rhine-Westphalia through the Marl Chemical Park to the Gelsenkirchen refinery site. Climate-neutrally produced hydrogen is considered key to the energy transition in Germany. The pipeline creates the technical prerequisites for this: It is one of the first connecting lines to the nationwide hydrogen core network, which is being gradually built up. The now completed connection also includes a section through which the fossil fuel natural gas previously flowed. A team from Evonik Pipelines has converted this section to the transport of hydrogen over the past few months.
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The pipeline is part of the GET H2 Nukleus project, which aims to connect the climate-neutral production of green hydrogen in northern Germany with industrial customers in North Rhine-Westphalia and Lower Saxony. Evonik is driving this forward together with other companies from across the entire value chain of the hydrogen economy. GET H2 is an initiative of companies, municipalities, and institutions. Its overarching goal is to actively contribute to the development of an integrated hydrogen economy.
In almost two years of intensive project work, we and our partners have successfully converted a natural gas pipeline for hydrogen operation and built new sections.
“This is a success we are all very pleased about. The dedicated collaboration of all those involved made this possible. It is a special achievement that also underscores our innovative strength in the field of hydrogen infrastructure,”
For the Marl Chemical Park, the pipeline provides a new opportunity to increasingly use climate-neutrally produced hydrogen in the future.
Thomas Basten, Head of the Chemical Park, says:
The Marl Chemical Park is one of the largest chemical sites in Germany.
“The direct integration into the hydrogen pipeline is a great addition to the site’s already extensive hydrogen infrastructure and represents future-oriented, sustainable development,”
Evonik has completed work on the entire pipeline route from Legden via Marl to Gelsenkirchen on schedule, completing three tasks in the process: A former natural gas pipeline, approximately 41 kilometers long, has been converted to hydrogen. A new, approximately three-kilometer-long pipeline crosses the Marl Chemical Park. At the property boundary, it is connected to a new, approximately ten-kilometer-long hydrogen pipeline to the refinery in Gelsenkirchen-Scholven. The hydrogen pipeline enables the transport of green hydrogen, the production of which is based on several hundred megawatts of electrolysis capacity in northern Germany. The electricity required for this comes from renewable energy sources.
Basten emphasizes the dual role of hydrogen in the chemical industry, said:
Hydrogen has always played an important role for chemical companies in the production of fertilizers, paints, and disinfectants.
“In the future, it will also play an increasingly important role as an energy carrier, which can also be stored in this form. This will become increasingly important with the further expansion of renewable energy generation. With our commitment, we are resolutely driving forward the expansion of the nationwide climate-neutral hydrogen infrastructure.”
Currently, climate-neutrally produced hydrogen is only available in comparatively small quantities and is not yet price-competitive. The majority of the hydrogen required nationwide is still produced using processes that utilize fossil energy sources such as coal, petroleum, or natural gas. Projects, plans, and initiatives aim to create more capacity for competitively produced and climate-neutrally produced hydrogen. Ultimately, a significant price reduction can only be achieved by scaling the volume and the resulting imports.
The pipeline further strengthens the Marl Chemical Park’s role as a hub for hydrogen activities. Evonik recently announced the establishment of a new start-up: a new facility will combine CO₂ captured from the air with 200 tons of green hydrogen per year in an integrated process to produce green methanol. Evonik’s Rheticus research project is also based at the Chemical Park. It uses hydrogen in artificial photosynthesis to produce specialty chemicals from CO₂ with the help of bacteria in a pilot plant. The company is also investing a low double-digit million euro amount in Marl to build a pilot plant for the production of its proprietary anion exchange membrane, DURAION®. The membrane is a key component of AEM water electrolysis and has the potential to enable cost-effective production of green hydrogen. A hydrogen filling station is also located at the Chemical Park.
Evonik can contribute extensive expertise to the development of a nationwide hydrogen supply network. A team of experts is responsible for the planning, construction, operation, and monitoring of pipeline networks. The more than 170 employees at Evonik Pipelines currently manage pipelines with a total length of approximately 3,000 kilometers, through which gases and liquids flow for customers in the chemical and energy industries. As a company, Evonik has been involved in several hydrogen initiatives for years.
Hydrogen has played an important role in production at the Marl Chemical Park for 85 years. The site currently processes approximately 25,000 cubic meters of hydrogen per hour and is engaged in further potential development projects. These involve producing basic chemicals from hydrogen and CO2 in order to become less dependent on crude oil-based raw materials.
The comprehensive know-how and extensive experience in handling hydrogen are available.
“We want to utilize all of this for the future-oriented and sustainable development of the site,”
Evonik: Leading beyond chemistry
Evonik, combining innovative strength with leading technological expertise, transcends the boundaries of chemistry. The Essen-based chemical company, active in more than 100 countries, generated sales of €15.2 billion and adjusted EBITDA of €2.1 billion in 2024. The common drive of its approximately 32,000 employees: to provide customers with a decisive competitive advantage with tailored products and solutions as a superpower for industry – and thereby improve people’s lives. In all markets, every day.
Legal notice
To the extent that we express forecasts or expectations in this communication, or our statements relate to the future, these forecasts or expectations of the statements may involve known or unknown risks and uncertainties. Actual results or developments may vary depending on changes in general conditions. Neither Evonik Industries AG nor its affiliated companies assume any obligation to update any forecasts, expectations, or statements contained in this communication.
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Abuja Seeks Investors for $25 Billion Morocco-Nigeria Gas Pipeline Project
The ambitious pipeline project, which spans 5,660 kilometers, aims to deliver Nigerian gas through an undersea route along the West African coast to Morocco and eventually to European markets. Doha – Nigeria’s government is actively courting international investors for the $25 billion Nigeria-Morocco gas pipeline project, a key infrastructure initiative to supply natural gas to European markets. According to Nigerian media, Vice President Kashim Shettima met with representatives from Vitol Group, the world’s largest independent energy trader based in Switzerland, at the Presidential Villa in Abuja on Monday.
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During the meeting, Shettima stressed President Bola Tinubu’s commitment to economic reforms aimed at making Nigeria an attractive investment destination in the energy sector.
The vice president noted the president’s “courage to take far-reaching decisions,” including the removal of fuel subsidies, unification of multiple exchange rates, and implementation of tax reforms.
The ambitious pipeline project, which spans 5,660 kilometers, aims to deliver Nigerian gas through an undersea route along the West African coast to Morocco and eventually to European markets.
The infrastructure is designed to supply energy to approximately 400 million people across 13 African countries with an annual gas capacity between 15 and 30 billion cubic meters.
“We are seriously exploring the option of taking our gas to Europe. It is an expensive venture requiring about $25 billion and, of course, the technical expertise,” Shettima stated during the meeting. He added that Nigeria values Vitol’s technical expertise as much as potential financial investment.
Shettima described Nigeria’s gas sector as “a beacon of stability and transparency” and noted the country possesses the eighth-largest gas reserves in the world. He urged Vitol to participate in Nigeria’s energy transition program and leverage their dominance in the Liquefied Natural Gas (LNG) and Associated Petroleum Gas (APG) sub-sectors.
The gas pipeline tops President Tinubu’s priorities
The project has been identified as a priority by President Tinubu’s administration. Senator Jimoh Ibrahim announced this commitment during the executive session of the African Parliament Union in Casablanca last month.
According to Ibrahim, the project is expected to create thousands of jobs, boost industrial and digital development, and contribute to a sustainable energy future for participating countries.
Morocco’s Energy Transition Minister Leila Benali confirmed in mid-May that feasibility and preliminary engineering studies have been completed and the optimal route determined.
“A special-purpose company is currently being established between Morocco and Nigeria to make the final investment decision by the end of the current year,” Benali told Morocco’s Upper House.
The project has attracted major international interest. The United Arab Emirates (UAE), European Investment Bank, Islamic Development Bank, and OPEC Fund have agreed to contribute funding.
China’s Jingye Steel Group has secured a contract to supply pipes for construction. The United States has also expressed interest in investing in the initiative, particularly given Nigeria’s vast gas reserves.
The pipeline project originated during King Mohammed VI’s state visit to Nigeria in December 2016. Though the Final Investment Decision was initially planned for 2023, it has been postponed to 2025, reflecting the project’s complexity and scale.
Morocco will host 1,672 kilometers of the pipeline, which will pass through Nigeria, Benin, Togo, Ghana, Ivory Coast, Liberia, Sierra Leone, Guinea, Guinea-Bissau, Gambia, Senegal, and Mauritania before reaching Morocco.
The North African country has already launched a tender to develop national natural gas infrastructure connecting Nador port to Kenitra and Mohammedia, extending to Dakhla to link with the Africa-Atlantic Gas Pipeline.
Jeffrey Dellapina, Chief Financial Officer of Vitol Group, voiced his company’s long-term commitment to Nigeria during the meeting with the vice president. “This has been an incredibly close and important country for Vitol for a very long time,” Dellapina said, continuing that Vitol is “committed to this country” and wants to “evolve with you.”
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Russia: Power of Siberia Gas Deliveries to CNPC Reach 3.5 Tcf
Gazprom PJSC has fulfilled 100 billion cubic meters (3.53 trillion cubic feet) of the 1.14 trillion cubic meters of natural gas it committed to China National Petroleum Corp. (CNPC) under a 30-year deal signed 2014, the Russian state-owned company said. Shipments to CNPC under the Power of Siberia pipeline supply agreement began late 2019 when the pipeline stretching over 3,000 kilometers (1,864.11 miles) went onstream. The unified gas transmission system, which carries gas from Irkutsk and Yakutia fields to Russia’s Far East and China, has exceeded its annual contractual obligation of 38 Bcm to CNPC since 2020 according to Gazprom.
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Daily export via the route reached a new record high in March 2025, Gazprom said without disclosing the volume. Recently China requested for supply to continue even as the pipeline underwent scheduled maintenance. That maintenance was completed April 4, 2025, and supplies since resumed their maximum level according to Gazprom.
“Throughout 2024, Gazprom’s pipeline gas supplies grew by more than 35 percent and covered about a quarter of China’s additional demand for gas”, Gazprom said in an online statement announcing the 100 Bcm milestone.
Meanwhile Gazprom chair Alexey Miller reaffirmed, “In 2027, Russian gas will start to be supplied to China via the second, i.e. Far Eastern, pipeline route”.
“As our Chinese colleagues say, the longer the friendship is the stronger it is. The projects like Power of Siberia and the Far Eastern route mean more than supplies of clean energy. They mean a strong bond between our countries and people, as well as a mutually beneficial cooperation for many years to come”, Miller added.
In 2022 Gazprom and CNPC penned a long-term agreement for gas supply for China via the Far Eastern pipeline. “As soon as the project reaches its full capacity, the amount of Russian pipeline gas supplies to China is going to grow by 10 billion cubic meters, totaling 48 billion cubic meters per year (including deliveries via the Power of Siberia gas trunkline)”, Gazprom said in a press release February 4, 2022.
In November 2023, Gazprom, CNPC and China Oil & Gas Pipeline Network Corp. signed an agreement that governs cooperation between the parties on the construction of the trans-border section of the Far Eastern pipeline to cross the Ussuri River near Dalnerechensk, Russia and Hulin, China.
Earlier in 2023 Gazprom achieved its maiden delivery of liquefied natural gas using the Northern Sea Route in the Arctic Ocean, meant for China. The Arctic shortcut between Europe and Asia allows for faster shipping compared to the traditional routes through Egypt’s Suez Canal and South Africa’s Cape of Good Hope.
Gazprom’s private competitor Novatek PJSC has already been using the Northern Sea Route to deliver gas to China. Novatek completed its first gas delivery to China via the route September 2010. The cargo for state-owned China National Offshore Oil Corp. took 22 days from the Russian port city of Murmansk near the border with Finland to its destination, the port of Ningbo, a city on the eastern coast of mainland China. The voyage was about half the time it would have taken through the Suez Canal, Novatek at the time.
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Canadian regulator says Prince Rupert Gas Transmission pipeline project has started
June 5 (Reuters) – British Columbia’s Environmental Assessment Office has determined that work on the Prince Rupert Gas Transmission natural gas pipeline project has been substantially started, the provincial government said on Thursday.
The decision means a 2014 environmental assessment certificate for the project will remain in effect indefinitely, unless suspended or cancelled under the Environmental Assessment Act, the B.C. government said in a press release.
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The 900-kilometre PRGT project will run from Hudson’s Hope in northeastern B.C. to Lelu Island near Prince Rupert on Canada’s Pacific Coast.
It was acquired from TC Energy (TRP.TO), opens new tab by the Nisga’a First Nation and the Western LNG in March 2024 to supply natural gas to the proposed 12 million tonneS per annum Ksi Lisims liquefied natural facility.
The 2014 environmental assessment certificate required that the project show substantial progress by November 25, 2024.
The B.C. Environmental Assessment Office launched a review process late last year to examine whether work had started, considering site inspections, documentation from PRGT and input from local First Nations.
The government statement said compliance and enforcement officers will continue to monitor the PRGT project throughout construction and operation to ensure it meets all environmental requirements.
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Paraguay Pitches Argentina, Brazil on Natural Gas Pipeline Plan
Paraguay is lobbying Argentina and Brazil to sign agreements signaling their political support for a proposed natural gas pipeline linking the three countries, according to a senior official in the landlocked South American nation. Mauricio Bejarano, deputy minister of mines and energy, is optimistic that memorandums of understanding can be signed this year and a task force created to formally study Paraguay’s plan for a 1,050-kilometer (652 mile) conduit.
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“We think this is a crucial year to move this proposal forward,” Bejarano said in an interview from Asuncion. Bolivia’s declining exports of locally produced gas to Brazil have created a sense of urgency for the project, he added.
Argentina is keen to sell more gas from its Vaca Muerta shale fields to Brazil by upgrading pipelines that run through Bolivia or building a new line directly to Brazil, or through Paraguay. Bolivia might not have any surplus gas to sell before the end of the decade due to falling output from its depleted fields, and Brazil started importing Argentine gas through Bolivia for the first time in April.
President Santiago Peña is trying to convince his neighbors to back a pipeline that would use the right of way along the Ruta Bioceanica highway currently under construction in Paraguay’s sparsely populated Chaco region. Almost half of the $1.9 billion project would be built in Argentina and Brazil, where it would connect with existing pipelines, according to a study commissioned by Paraguay.
Paraguay could eventually use some of the gas to generate electricity as growing domestic energy demand threatens to deplete its surplus of hydroelectric power in the 2030s, Bejarano said. “We need to introduce a new energy source in our power matrix that today isn’t present,” he said.
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Natural Gas / LNG Utilization / Bio-LNG
Guinea : FG targets $1bn annual investments in CNG conversion projects
The Presidential Compressed Natural Gas Initiative (PCNGi) has announced that the Federal Government is aiming for a billion-dollar annual investment in compressed natural gas (CNG) conversion projects. Programme Director/CEO of the initiative, Michael Oluwagbemi, disclosed this at the launch of a CNG conversion centre at Commercial Parks, Mile 2, Lagos, in collaboration with the National Union of Road Transport Workers (NURTW).
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According to Oluwagbemi, there has been a rapid growth in investment over the past year.
He said, “In the last one year, we’ve invested over $500 million, and more is still coming. Our target this year is a billion-dollar investment. I think we’re already close to $175 million.
“We’ve seen Greenville, NIPCO, and AYM Shafa investing stations. Femadec Energy is investing, and even the federal government, through the Midstream and Downstream Gas Infrastructure Fund (MDGIF), is investing.”
He explained that PCNGi is also investing projects to extend gas supply across northern Nigeria, not just the south.
“Our food comes from the north, and we want cheap food in the south. If we want cheap food in the south, then we must provide gas to the north so that they can transport the food cheaply to the south, and vice versa,” he added.
He said the development of the refueling stations is being fast-tracked through the private sector.
Oluwagbemi added, “There was no infrastructure for CNG in the country then. But the reality is that progress happens, it might be slow, but it will happen surely. When we first got GSM in this country, we did not have towers everywhere. We had to go a little distance, sometimes we even climbed on top of a tree to make a call. It’s no longer the case and it’s getting better because the private sector is investing.”
State Secretary, NURTW, Comr. Usman Teslim, described the initiative as a positive development for the union.
He recalled that the federal government launched the CNG Conversion Centre around this time last year, which has been embraced by union members.
“Time is of utmost importance to drivers. It has been challenging for our members to leave their vehicles parked for one or two days for conversion.
“Now, with PCNGi introducing this new approach, after a day’s work, drivers can have their vehicles checked, and if everything is in order, the conversion can be completed within three to four hours. This is a significant improvement for our organisation,” Teslim said.
https://dailytrust.com/fg-targets-1bn-annual-investments-in-cng-conversion-projects/
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Georgia: Chart and Flowserve see chance in LNG and nuclear
Alongside conventional industrial gas synergies and opportunities, a key reason behind the $19bn merger of Chart Industries and Flowserve is that it provides potential growth in diverse end-markets. These include a raft of LNG and nuclear openings, encompassing the ‘full lifecycle’ of design, engineering, construction and installation, performance, and aftermarket services. Essentially, as with most mergers, the union allows both companies to fill in important portfolio gaps.
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In terms of LNG system configurations, while Chart offers a range of compressors, vaporisers and LNG condensers, Flowserve’s portfolio includes sea water pumps and high-pressure pumps.
And with nuclear, Flowserve’s circulation, feed water and recirculation pumps are now complemented by Chart’s steam turbines, air-cooled steam condensers and reactor pressure vessels.
When you look at the combined portfolio – Flowserve’s pumps, valves, actuation, flow systems and seals, complemented by Chart’s thermal portfolio comprising compressors, turboexpanders, fans, air cooled heat exchangers, cold boxes, mobile equipment and cryogenic bulk storage tanks – it does look a comprehensive offering.
Chart signed a global master goods and services agreement in January to supply oil and gas major ExxonMobil with LNG equipment, technology, and services.
Chart and Exxon are developing an initial LNG project design and will build several follow-up concepts to optimise global facilities.
One notable LNG contract secured by Chart in 2024 was the Rovuma LNG Project in Mozambique, operated by a joint venture between ExxonMobil, Eni, and China National Petroleum Corporation (CNPC), in which Chart is building 12 liquefaction modules.
Another highlight was the opening of its Teddy 2 facility, Chart’s second manufacturing facility in Theodore, Alabama, in March 2024.
The plant manufactures the world’s largest shop-built cryogenic tanks, with capacities up to 1,700 cbm, serving industries such as energy, aerospace, marine, and power.
Last year Flowserve bought the intellectual property and in-process R&D related to cryogenic LNG submerged pump technology, systems and packaging from NexGen Cryogenic Solutions, a privately held, Arizona-based company specialising in the engineering, design and testing of LNG pumps and turbines.
Scott Rowe, Flowserve’s President and CEO, said, “LNG provides a resilient pathway to energy transition. As we continue advancing our 3D growth strategy to diversify, decarbonise and digitise, this technology acquisition will strengthen our decarbonisation offerings across the LNG value chain.”
https://www.gasworld.com/story/chart-and-flowserve-see-chance-in-lng-and-nuclear/2159807.article/
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South Korea: Thumbs-up for MOL and Samsung Heavy Industries’ SOFC tech-endowed LNG carrier design
Japan’s shipping giant Mitsui O.S.K. Lines (MOL) and South Korea’s Samsung Heavy Industries (SHI) have received approval in principle (AiP) from Lloyd’s Register for the design of a 174,000-cubic meter (cbm) liquefied natural gas (LNG) carrier (LNGC) equipped with Solid Oxide Fuel Cell (SOFC) technology.
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Discussions and development of the application of 300 kW of SOFC to the 174,000 LNG carrier as a pilot project have been ongoing since mid-2022 in collaboration with MOL and SHI, which reached an agreement on a mutual application in June 2024. The system is expected to undergo joint equipment verification starting from early 2027.
The AiP certification ceremony took place on June 3, 2025, at NOVA Spektrum in Lillestrøm, Norway. The 174,000 cbm LNG carrier, which will be delivered in 2027, will feature a 300 kW SOFC, supplied by Bloom Energy, to be used as an auxiliary power generator.
MOL sees SOFC technology as a highly efficient, high-temperature process that converts fuels like natural gas, hydrogen, methanol, or ammonia directly into electricity and heat through an electrochemical process without burning them.
The Japanese player explained: “This highly efficient energy conversion reduces the amount of fuel required to generate the same amount of electricity, resulting in lower GHG emissions. In addition, since SOFC generates electricity without combustion, emissions of harmful gases such as NOx and SOx, as well as methane slip, can be significantly reduced to negligible levels.
“While the installation of SOFC on vessels is still rare, the risk assessment including Hazard Identification (HAZID) and Hazard and Operability Study (HAZOP) were conducted in collaboration with key project stakeholders, resulting in the acquisition of the AiP.”
MOL revealed last month that it was going to embark on a careful assessment of the use of Chinese and South Korean shipyards for new LNG vessels, keeping the changes in U.S. policy trends and geopolitical risks in mind.
This came shortly after the firm ordered a new LNG-fueled very large crude carrier (VLCC) from Dalian COSCO KHI Ship Engineering in China.
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Global LNG Development
Australia: Viva Energy LNG terminal cleared for construction
The Victorian Government has given the go-ahead for Viva Energy’s liquefied natural gas (LNG) terminal project in Geelong, subject to conditions. The project comprises an extension to Geelong refinery jetty, a permanently moored floating storage and regasification unit (FSRU) and a short 7km pipeline connecting it to the state’s gas main. Viva Energy’s gas terminal would have the capacity to supply in excess of 120PJ of gas per year and introduce significant new supply capacity: peak supply of up to 750TJ per day to meet the daily and seasonal gas demands of Victoria and southern Australia.
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With construction of the terminal expected to take two years, it promises a complete solution to the structural gas shortfalls forecast to impact Victoria from 2028 onwards.
The gas terminal unlocks a pathway to bring LNG from Australian gas fields or around the world, effectively acting as a virtual pipeline to deliver gas directly to where it is needed most—the major Victorian markets of Melbourne and Geelong.
Viva Energy chief strategy officer Lachlan Pfeiffer said, “Viva Energy’s gas terminal in Geelong is a transformative development for Victoria’s energy landscape, which will ensure a secure, flexible, and cost-effective gas supply, supporting renewable energy generation, and contributing to the economic well-being of Australia.
“One of the key advantages of our LNG terminal is its flexibility to scale up supply during periods of peak gas demand, ensuring that households and businesses in Victoria will have a reliable gas supply all year round. In addition, we expect the LNG terminal will be called on to supply gas for gas-powered electricity generation, providing important firming capacity to support the renewable energy sector as coal retires from the energy system.
“Timing remains a critical factor—we need to hit a range of milestones in order to get the LNG terminal constructed in time to meet the gas shortfall expected to develop from 2028 onwards,” he said.
Construction is scheduled to commence in the second half of 2026, with the majority of works in 2027.
https://esdnews.com.au/viva-energy-lng-terminal-cleared-for-construction/
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Türkiye Expands Energy Ties with Stake in Caspian Gas Field
Türkiye’s state-owned oil and gas company, TPAO, is acquiring a 30% stake in Azerbaijan’s Shafag-Asiman natural gas field, further strengthening Ankara’s energy partnership with Baku. Energy and Natural Resources Minister Alparslan Bayraktar announced the deal Monday during the Baku Energy Week conference, describing the move as a new chapter in strategic cooperation between the two countries.
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The production-sharing agreement is set to be signed Tuesday between TPAO, Azerbaijan’s state energy firm SOCAR and British energy major BP. The offshore block, located about 78 miles southeast of Baku in the Caspian Sea, sits at a depth of 650 to 800 meters. The first exploration well was drilled in 2020.
Bayraktar emphasized the historical and cultural foundations of Türkiye-Azerbaijan energy ties. “This is a strategic energy alliance based on shared values and mutual vision,” he said. “With this deal, we aim to expand joint production in Azerbaijan.”
In a message to the conference, President Recep Tayyip Erdogan reaffirmed Türkiye’s commitment to deepening energy cooperation with Azerbaijan. He praised landmark joint infrastructure such as the Baku-Tbilisi-Ceyhan and Baku-Tbilisi-Erzurum pipelines and TANAP, calling them vital to regional and European energy security.
“Our collaboration continues to make significant contributions to the energy stability of both our region and Europe,” Erdogan said. He also highlighted the recent commissioning of the Igdir-Nakhchivan pipeline as a key milestone in bilateral energy cooperation.
Bayraktar said discussions are underway to broaden collaboration in the Caspian region and beyond. “We’re evaluating additional projects, including renewable energy development in Nakhchivan and its transfer through Türkiye to Europe,” he noted.
He also referenced a recent regional pact among Türkiye, Azerbaijan, Georgia and Bulgaria for green electricity transmission, describing it as a “historic step” toward regional integration.
Erdogan pointed to Azerbaijan’s strategic role in the global energy market, especially as the region grapples with geopolitical risks and infrastructure challenges. He noted future plans to transport Turkmen gas via Azerbaijan and Türkiye to expand supply routes and boost energy diversification.
Bayraktar outlined Türkiye’s broader energy strategy focused on supply security, import reduction and affordability. He said the country now generates over 60% of its electricity from renewable sources. At COP29, Türkiye pledged to quadruple its wind and solar capacity to 120 gigawatts, beginning with 7 gigawatts added in 2024.
Additional investments include new electric transmission lines, battery storage, and the upcoming activation of the Akkuyu nuclear plant. Bayraktar also cited growing domestic gas production and increased exploration for critical minerals both at home and abroad.
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Japan: Energy Transfer Signs 20-Year Agreement to Supply LNG to Japan’s Kyushu
Energy Transfer LP subsidiary Energy Transfer LNG Export LLC entered into a 20-year liquefied natural gas (LNG) sale and purchase agreement (SPA) with Japan’s Kyushu Electric Power Company Inc. related to its Lake Charles LNG project. Under the SPA with Kyushu, Energy Transfer LNG will supply up to 1.0 million metric tons per annum (mtpa) of LNG, the company said in a news release.
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LNG will be supplied on a free-on-board basis and the purchase price will consist of a fixed liquefaction charge and a gas supply component indexed to the Henry Hub benchmark, according to the release. The agreement marks Kyushu’s first long-term LNG procurement contract from the USA and will further diversify its procurement sources and enhance the stability of its LNG supply, Energy Transfer said.
“We are proud to be selected as an LNG supplier by Kyushu, one of Japan’s leading energy companies,” Energy Transfer LNG President Tom Mason said. “Kyushu has been supportive of Lake Charles LNG for a long time and we appreciate their loyalty. We are also pleased that Lake Charles LNG continues to make strong strides toward full commercialization”.
The obligations of Energy Transfer LNG under the SPA are subject to Energy Transfer LNG taking a positive final investment decision (FID) on the Lake Charles LNG project and satisfying other conditions precedent, the company said.
If Energy Transfer LNG reaches a positive FID, the Lake Charles LNG export facility would be constructed on the existing brownfield regasification facility site and will capitalize on Energy Transfer’s four existing LNG storage tanks, two deep water berths and other LNG infrastructure, the company said.
Lake Charles LNG would also benefit from its direct connection to Energy Transfer’s existing Trunkline natural gas pipeline system. The system provides connections to multiple intrastate and interstate pipelines, which allow access to multiple natural gas producing basins, including the Haynesville, the Permian and the Marcellus Shale, Energy Transfer said.
Energy Transfer recently announced a heads of agreement (HOA) with MidOcean Energy for approximately 5.0 mtpa of LNG production from Lake Charles LNG, as well as a SPA with an international energy company for 1.0 mtpa of LNG and an HOA with a German energy company for 1.0 mtpa of LNG.
In February, Energy Transfer entered into a long-term agreement to provide natural gas to CloudBurst Data Centers, Inc.’s flagship AI-focused data center development in Central Texas.
Energy Transfer subsidiary Oasis Pipeline, LP will provide up to 450,000 million British thermal units (MMBtu) per day of firm natural gas supply to CloudBurst’s Next-Gen Data Center campus outside San Marcos, Texas, subject to CloudBurst reaching a final investment decision (FID) with its customer.
The natural gas supply would be sufficient to generate up to approximately 1.2 gigawatts of direct, or “behind-the-meter” electric power for a period of at least 10 years starting with phase 1 of the data center facilities, Energy Transfer said in an earlier statement.
The company approved the construction of an additional natural gas processing plant in the Midland Basin. The Mustang Draw plant will have a processing capacity of approximately 275 million cubic feet per day and is expected to be in service in the second quarter of 2026.
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Egypt Plans to Finalize Large LNG Purchase Deals Over Next Week
Egypt has indicated that it plans to in the coming week finalize some purchases of liquefied natural gas for delivery over the next few years, as the country deepens its dependence on imports. The government is in the final process to strike deals with as many as six companies — including Saudi Aramco, Trafigura Group and Vitol Group — to buy cargoes through June 2026, according to people with knowledge of the matter who asked not to be identified. It could buy more than 160 shipments for that period, the people said.
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There could be more deals for deliveries over the following two years, the people said. Egyptian Natural Gas Holding Co. received 14 offers for supply ranging from 18 months to three years, Bloomberg reported last month.
Egypt’s push to lock in LNG supplies is aimed at reducing its reliance on the volatile spot market and reflects a sharp reversal for a nation that was exporting gas just a year ago. Falling domestic output, rising demand from an expanding population and extreme heat have turned the nation into a major importer, tightening global supply.
Other firms Egypt is in the process of inking deals with include Hartree Partners LP and BGN, the people said. The purchases that are due to start arriving from July will come as Egypt will have three operational floating import terminals this summer, with an additional unit scheduled by the end of this year or in early 2026.
Egypt’s oil ministry officials weren’t available for comment outside business hours during Eid holidays. Vitol and Hartree declined to comment. Aramco, Trafigura and BGN didn’t immediately comment when contacted by Bloomberg.
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Trinidad and Tobago: Trinidad’s Atlantic LNG increases production in May
HOUSTON, June 2 (Reuters) – Exports of liquefied natural gas from Trinidad and Tobago’s flagship Atlantic LNG export facility increased by 43% in May compared to April, according to LSEG preliminary ship tracking data. Trinidad is Latin America’s largest LNG exporter and its flagship plant, Atlantic LNG, is jointly owned by Shell (SHEL.L), opens new tab and BP (BP.L), opens new tab with a capacity to produce 12 million metric tons per annum (mtpa) of the superchilled gas.
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In May Atlantic exported 0.83 mtpa of LNG, up from 0.58 MT in April, LSEG data showed.
Similar to the U.S., Europe bought the majority of cargoes sold by Atlantic, while the rest went to Asia and Latin America.
BP has made Trinidad and Tobago one of its focus areas for growth of its upstream production and in May announced first gas from its Mento following April’s announcement of first gas from its Cypre development, both offshore Trinidad.
https://www.reuters.com/business/energy/trinidads-atlantic-lng-increases-production-may-2025-06-02/
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LNG as a Marine Fuel/Shipping
Italian yard launches TUI Cruises’ newest LNG-fuelled ship
Italian shipbuilder Fincantieri has launched the second of two LNG-fuelled cruise ships in a series ordered from the company by German operator TUI Cruises. Like sister ship Mein Schiff Relax, which was delivered in February 2025, Mein Schiff Flow will have a gross tonnage of 160,000 and space for 3,984 guests upon completion. Onboard facilities will include 14 restaurants, 17 bars and lounges, a spa, a wellness area, and an infinity pool.
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The stateroom options will include inside and outside single cabins of 11 square metres each and suites with areas ranging from 25 to 88 square metres. Many of the outside cabins and suites will have balconies while there will be two six-person suites split between two decks and with private saunas and living rooms.
The ship will also boast emissions-reducing features such as a waste heat recovery system, a shore power charging system, and EU Stage VI-compliant catalytic converters.
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RensenDriessen makes deep-sea foray with two LNG tankers built in China
Scheduled for delivery in 2027, these dual-fuel vessels will be constructed at a Chinese shipyard. Dutch company RensenDriessen Shipbuilding & Shipbrokers has announced brokerage for two 20,000m³ LNG carriers, marking its foray into the deep-sea shipping market. Scheduled for delivery in 2027, these dual-fuel vessels will be constructed at a Chinese shipyard and are designed to comply with the International Maritime Organisation’s (IMO) Tier III standards.
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This move signifies a strategic expansion for RensenDriessen, a company that is into inland shipping.
The tankers, each spanning 160m in length and 25m in width, will be powered by WINGD LNG dual-fuel engines, have a designed service speed of 15.5 knots and incorporate iCER technology to reduce emissions.
These features are expected to enhance fuel efficiency and environmental sustainability in line with the current demands of the deep-sea LNG trade, stated the company.
RensenDriessen managing partner Wim Driessen said: “This is more than just a transaction. It’s a next step in our development as a brokerage partner with a European heart and global reach.
“We have a solid track record in building vessels in China and know how to align each project with the most suitable yard. By entering the short-sea and deep-sea markets with a proven business model, we’re opening up new opportunities for shipowners who want to combine affordability with quality and flexibility.”
The new tankers are being constructed for a Northern European owner with focus on LNG transportation and distribution.
The steel cutting for the first tanker is expected in two weeks, with its delivery anticipated in April 2027.
The second tanker’s steel cutting will follow in around four months, with delivery expected in September 2027.
Upon completion, these tankers will operate across Asian and European waters.
Concurrently, RensenDriessen has awarded an order for an LCO₂ tanker in China. This vessel will be deployed in Northwest Europe for exporting captured CO₂.
https://www.ship-technology.com/news/rensendriessen-deep-sea-foray-two-lng-tankers/
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Netherlands: Dutch firm dips its toes into deep-sea realm with LNG vessel duo
The Netherlands-headquartered RensenDriessen Shipbuilding & Shipbrokers has made its first foray into the deep-sea segment of the shipping market, thanks to two liquefied natural gas (LNG) vessels, which will be built at a selected shipyard in China. The brokerage of two 20,000-cubic-meter (cbm) sea-going dual-fuel LNG tankers enables RensenDriessen to step into the deep-sea segment, marking a new chapter for the Dutch firm, best known for its inland shipping expertise. These vessels, fully compliant with IMO Tier III standards, will be delivered from a Chinese shipyard in 2027.
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With a designed service speed of 15.5 knots, each vessel, which will measure 160 meters in length and 25 meters in width, will be equipped with WINGD LNG dual-fuel engines and iCER emissions reduction technology. Given its access to more than 50 shipyards across China, the company claims to be well-positioned to broker complex or specialized tonnage.
The LNG ships are envisioned to meet the demands of today’s deep-sea LNG trades with greater fuel flexibility and environmental performance. According to the Dutch player, the vessel duo is being built for a Northern European owner focused on LNG transport and distribution.
While the steel cutting for the first vessel is slated to take place in two weeks, with delivery expected in April 2027, the steel cutting for the second ship will follow in approximately four months, with delivery set for September 2027.
Afterward, these LNG vessels will be deployed in both Asian and European waters. RensenDriessen also has an LCO2 tanker on order in China, which will be used in Northwest Europe for the export of captured CO2.
The company is now applying its ‘Best of Both Worlds’ model by combining cost-efficient newbuilding in Asia with Dutch maritime know-how, client support, and project oversight to sea-going tonnage.
Wim Driessen, Managing Partner at RensenDriessen, commented: “This is more than just a transaction. It’s a next step in our development as a brokerage partner with a European heart and global reach. We have a solid track record in building vessels in China and know how to align each project with the most suitable yard.
“By entering the short-sea and deep-sea markets with a proven business model, we’re opening up new opportunities for shipowners who want to combine affordability with quality and flexibility.”
https://www.offshore-energy.biz/dutch-firm-dips-its-toes-into-deep-sea-realm-with-lng-vessel-duo/
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Vietnam’s Cai Mep LNG Terminal Receives First Cargo from Russia’s Sakhalin 2
Vietnam’s Cai Mep liquefied natural gas (LNG) terminal has received its commissioning cargo from Russia, and marks the Southeast Asian country’s first time receiving supply of the fuel from the LNG producer, according to an industry source and shiptracking data.
According to data from LSEG and Kpler, the cargo was loaded from Russia’s Sakhalin 2 project on April 10, onto the Blue Dragon 1 LNG tanker.
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The Blue Dragon 1 tanker arrived at the Cai Mep import terminal on May 25.
One industry source told Reuters that the terminal had received the cargo for the purpose of testing.
On track to be Vietnam’s second operational LNG terminal, Cai Mep LNG is located in the southern Ba Ria Vung Tau province, and has the capacity to import 3 million metric tons of LNG a year.
It is operated by Cai Mep LNG, a joint venture between Singapore-based Atlantic, Gulf and Pacific LNG (AG&P LNG) and Vietnamese petroleum trader Hai Linh Company.
Repeated calls to Hai Linh for a comment went unanswered. AG&P LNG did not immediately respond to a request for comment.
AG&P LNG said in August last year it was aiming to secure its commissioning cargo for the terminal to be delivered between October and November.
Vietnam’s first terminal to begin operations, Thi Vai LNG, received its commissioning cargo from Indonesia. It has since also received LNG supplies from Qatar, Malaysia and Brunei.
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Technological Development for Cleaner and Greener Environment Hydrogen & Bio-Methane
Raman Technology for Faster Methane Detection in NGL Production
According to a 2019 US Energy Information Administration (EIA) study, 510 natural gas processing plants operate in the United States. This amounts to around 80.8 billion cubic feet of processing power in the lower 48 states. A modern processing plant produces two principal commodities: natural gas liquids (Y-grade) and residual gas. Raw gas from a collection network passes through a cryogenic cooling tower, which cools it to extremely low temperatures. Most gaseous hydrocarbon components, such as C2-C6+ (ethane, propane, butane, etc.), are condensed into the liquid Y-grade product.
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Methane, the residual hydrocarbon component, boils beyond the cooling tower’s working temperature and is largely in the gas phase. This methane, known as residual gas, fuels power plants and residential and commercial structures.
A small amount of methane remains in the liquid Y-grade product. Accurately measuring and controlling that quantity has significant ramifications for the process owner.
Methane in Y-grade is a pollutant that impacts product quality and causes issues with process efficiency, custody transfer, and safety.
Some common methane criteria include concentrations of no more than 0.5% (5000 ppm) or 1.5 times the Ethane concentration (ppm).
NGL fractionators (Y-grade clients) typically do not use a methane scrubber (a demethanizer column) as their first unit operation.
As a result, exceeding the methane specification can impact the processing speed, efficiency, and quality of fractionator columns. High methane Y-grade can be accommodated through blending; however, this reduces process efficiency and profitability.
Excess methane can cause outgassing problems during the subsequent pipeline transfer of NGLs to customers. Beyond the practical issues, off-spec Y-grade can result in financial penalties and contract violations.
Monitoring the methane concentration is crucial for ensuring the Y-grade producer’s cryogenic tower is operational and on schedule.
Traditional online analysis methods, such as gas chromatography (GC), report cooling tower operational status as a C1/C2% ratio number, a popular indicator for optimizing tower performance. Individual measurement cycles for online GC equipment may take 5 to 20 minutes to report.
Raman spectroscopy has recently shown its utility and value in the online measurement of hydrocarbon products in midstream and refinery environments.
It has established itself as the leading optical method for determining composition and physical properties in NGL, natural gas, and purity products because of its selectivity, rapidity, stability, and sensitivity.
Many industrial processes, such as cryogenic cooling towers, can change faster than a conventional GC measurement cycle can complete.
While attempting to measure a rapidly changing process, a slow cycle time gives operators no relevant information during the GC cycle durations, resulting in critical events and transitions being missed or discovered late.
In comparison, a Raman measurement takes 3 to 5 seconds, which is substantially faster than a comparable GC measurement and can be utilized to enable continuous monitoring and early identification of process changes.
This speed gives operators more visibility into processes as they occur and the capacity to optimize process outcomes in relation to specifications, for example, ensuring ethane concentrations in cryogenic cooling towers are within permissible limits.
One argument against using Raman spectroscopy is its apparent limited sensitivity compared to other techniques such as gas chromatography. However, this study shows that Raman can detect low amounts of methane in NGLs (down to 130 ppm) with high precision in real time.
Experimental
The spectra were acquired using a Thermo Scientific™ MarqMetrix™ All-In-One Process Raman Analyzer. The acquisition parameters were tuned so that a new dark-subtracted spectra was acquired for each sample tested, resulting in optimal acquisition durations and averages (Figure 1).
Spectra were acquired with a Thermo Scientific™ MarqMetrix™ FlowCell Sampling Optic (Figure 2). After collection, the data was processed and modeled with Solo 9.2.1 (Eigenvector Research, Inc., Manson, WA). Minor, non-chemical fluctuations in the spectra were mitigated using extended multiplicative signal correction (EMSC).
In this investigation, liquid samples were introduced to the FlowCell in a stopped-flow manner from compressed piston cylinders with backpressure maintained at more than 1000 psi.
Back pressure was applied to the FlowCell’s exit leg to allow stop-flow manipulation and pressure measurement while keeping volatile substances in solution.
The identical samples were analyzed with GPA 2177 to provide laboratory reference values. This experiment investigated nine samples as part of the Proof-of-Concept (POC) investigation.
Results and Discussion
This study shows that it is possible to measure low-level methane in a Y-grade product at a level equivalent to standard GC measurements. Based on this POC model, which only includes nine samples, the methane model shows that an RMSEC of 100 ppm is possible (Figure 3).
The capability of a multivariate model is always determined by the quality and characteristics of its calibration dataset.
This dataset contributed to the methane response’s independence from other hydrocarbon species. A suitable calibration dataset compels modeling to rely entirely on methane Raman spectral characteristics, as shown by the Regression Vector (Figure 4).
Methane has a single strong Raman band at around 2910 cm-1, making it ideal for measuring and modeling methane at low levels. The methane model’s PLS regression vector highlights the potential for specificity in Raman spectroscopy models, using the methane band as the essential feature.
While this band almost always heavily overlaps with other hydrocarbons, a rigorous calibration set design combined with multivariate modeling enables the use of the modest but strongly overlapped methane Raman signal.
It is also worth investigating the concentrations of other hydrocarbons in Y-grade products. Raman spectroscopy can easily quantify and anticipate these additional bulk-level components.
https://www.azom.com/article.aspx?ArticleID=24498
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Australia project showcases hydrogen–helium separation tech
German firm Siqens has proved its hydrogen separation technology at CSIRO’s Hydrogen Technology Demonstration Facility (HTDF) in Victoria, Australia. The findings could support efforts to separate helium and naturally occurring hydrogen, also known as geological or white hydrogen. Both gases are often found together and need to be separated using specialist technology for hydrogen to be used as a fuel. For this project, Siqens used CSIRO’s test facility to demonstrate its electrochemical hydrogen separation rig.
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The team mimicked the separation of a naturally occurring concentration by feeding hydrogen–helium mixtures ranging from 10% to 75% into the rig.
“We showed that the rig can produce up to 4.7kg of fuel cell quality hydrogen per day, which is much higher … than had previously been demonstrated,” said Matthew Purcell, Project Manager for Siqens.
The electrochemical process works using a special membrane that allows hydrogen atoms to pass through the system. Unlike the size-based ‘sieving’ used in air separation units, the membrane is selective for protons.
To pass through the membrane, a molecule must be able to split into protons – specifically hydrogen ions – and those protons travel through the membrane and recombine into hydrogen on the other side. At the same time, helium, being inert, cannot be broken down and remains on the other side.
By the end of the separation process, the helium is left behind on one side and the recombined purified hydrogen is collected on the other.
The demo project also gave Siqens the opportunity to showcase its separation technology to potential partners. According to Purcell, 25 different organisations came to see the rig in action.
The lure of Australia
The German company chose CSIRO’s facility because of Australia’s ample reserves of naturally occurring hydrogen.
“We wanted to demonstrate our hydrogen separation technology in Australia because of the country’s natural hydrogen industry,” said Purcell.
Interest in the sector has surged, with South Australia seeing a rush of exploration activity. In a twelve-month period between 2021 and 2022, six different companies were either granted or had applied for 18 petroleum exploration licences across the state, according to Australian energy consultancy EnergyQuest.
The area under permit is equivalent to around 32% of the entire state, an approximate 570,000 square kilometres.
The naturally occurring energy source is attractive to many companies because of its potential to be three to four times cheaper than producing it via electrolysis or gas reforming with carbon capture.
Energy firm Gold Hydrogen has previously described natural hydrogen as an “inexhaustible source of green energy” and estimates natural hydrogen could be produced for less than $2.30 per kg, compared to over $6 per kg for hydrogen made via electrolysis or reforming.
However, it is not clear if these costs factor in the well drilling process that is necessary to access concentrations that remain unproven.
The strength of the sector was outlined in the Australian government’s National Hydrogen Strategy, which is supported by Geoscience Australia’s digital mapping capabilities.
Currently, South Australia is the only Australian jurisdiction with laws in place to enable hydrogen exploration. However, the 2024 strategy encourages further research and exploration, even though large-scale development strategies are not yet in place.
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