NGS’ NG/LNG SNAPSHOT May 1-15, 2024

National News Internatonal News


City Gas Distribution & Auto LPG

Adani Total ramps up CNG footprint with strong volumes; shares up over 70% in six months

Adani Total Gas has added 91 new CNG stations in the March quarter and posted strong volume growth. Shares of Adani Total Gas jumped over 3 percent in morning trade on May 2 riding on robust numbers for the quarter ended March 2024.


The net profit surged 71.6 percent on-year to Rs 168 crore and revenue rose 4.7 percent YoY to Rs 1,167 crore in the quarter under review. The Adani group firm’s EBITDA surged nearly 50 percent YoY to Rs 305 crore.

The board of Adani Total Gas also recommended a dividend of Re 0.25 per equity share of the face value of Re 1 each fully paid-up for FY24, subject to approval of shareholders. The company has fixed June 14, 2024 as the record date for the purpose of determining the entitlement of the members of the company to receive dividend.

At 9:29 am, Adani Total Gas shares were trading 2.25 percent higher on the National Stock Exchange (NSE) at Rs 950.00 per share. In the last one year, the stock has rallied 71 percent, outperforming benchmark Nifty 50 which has risen 18 percent during this period.

The company increased total CNG stations to 547, adding 91 new ones in the full year. “We are incubating new business opportunities in the areas of Compressed Biogas, EV Charging Infrastructure, and LNG for Trucking and Mining (LTM),” it said.

Adani Gas also commissioned the 1st phase of diversified feedstock-to-CBG plant at Barsana in Mathura and now has e-mobility footprint in 23 states. These, along with LTM are the next big growth drivers, said Suresh P Manglani, ED & CEO of Adani Total Gas.

Adani Total Gas’ total sales volume was 232 MMT in Q4, a 20 percent YoY increase. The CNG volume in FY24 increased by 21 percent YoY on account of network expansion across multiple geographical areas.

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Udupi CNG fuel shortage: Long queues of vehicles has become a common sight

Although the number of CNG fuel-based vehicles is increasing, the number of CNG filling stations in Udupi district has not risen. In the existing bunks, the supply is not as high as the demand.


Udupi, Karnataka: The coastal district of Udupi is going through a severe shortage of Compressed Natural Gas for Automotive applications.

Although the number of CNG fuel-based vehicles is increasing, the number of CNG filling stations in Udupi district has not risen. In the existing bunks, the supply is not as high as the demand. Due to this, motorists, especially rickshaw drivers have to wait for hours to get their fuel tanks filled.“I’ve been waiting for not less than four-five hours every day for the past one week.

 Most of the time my vehicle is idle and I am not able to take up fares, as a result of which I have lost so much of income and my bank obligations will take a beating if this continues any longer,” Sundar Shetty, a rickshaw driver in Udupi said.CNG fuel is not being supplied to existing bunks as per demand. And as the demand is high, the stock depletes quickly and sometimes the rickshaws are parked overnight in a queue for early morning refuelling, leaders of the CNG Autorickshaw Drivers Association said.In Udupi town, there is only one bunk that has CNG facility, but most of the time it is empty.

“Due to high investment on land, equipment and daily stocks, there are not many takers for this business” the bunk owners said.There is only one CNG station in Kundapura taluk out of three in Udupi district. There are more than 5,000 CNG based vehicles in the district.

The sight of hundreds of rickshaws and other vehicles waiting to fill CNG fuel at the CNG bank in Koteshwar every day from 4 am is very common.Sometimes one has to wait till 8-9 o’clock. However, there is no guarantee that everyone will get fuel.

Similar are the conditions in Karkala and Kundapur taluks of Udupi district.The rickshaw drivers and other CNG users have appealed to the Udupi district authorities and approached the Udupi Chamber of Commerce and Industry to put pressure on the government to normalise supply and to open more bunks.

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Bajaj CNG Bike Launch Confirmed on June 18; Here’s What Is Expected From World’s First CNG Motorcycle From Bajaj Auto

Rajiv Bajaj, MD of Bajaj Auto confirmed the Bajaj CNG bike launch date in India for June 2024. The CNG bike from Bajaj Auto is said to feature a bi-fuel engine. Check expected features, likely price and more details about Bajaj’s upcoming CNG bikes.


New Delhi, May 5: The world’s first CNG bike from Indian multinational automotive company Bajaj Auto is one of the highly awaited two-wheeler expected to launch in 2024. In March, many reports said that the Bajaj CNG bike would be launched in June and that the company would introduce five or six more CNG bikes in 2025. During the launch event of Bajaj NS400Z, Bajaj Auto MD Rajiv Bajaj confirmed that the Bajaj CNG bike launch will take place in June 2024. The highly anticipated Bajaj CNG motorcycle is said to feature a bi-fuel engine that will allow the riders to switch to petrol and CNG models. Due to the rising cost of fossil fuel, consumers already started switching to EVs and alternate options. Bajaj Auto had success with its three-wheeler CNG vehicles in the market, and with the entry of its first CNG bike in India, the company may disrupt the entry-level motorcycle market. Bajaj CNG bike would offer an alternate to the people who do not wish to switch to electric models or looking for alternate to petrol. Harley Davidson Lineup 2024 Unveiled in India: From Nightster to Heritage Classic and Road Glide, Here’s Name and Prices of Ten Motorcycles Announced in India.

Bajaj CNG bike launch date in India is confirmed to be June 18, 2024, according to the report by Financial Express. The report also mentioned that the specific details about the upcoming Bajaj CNG bike are yet to be revealed; however, it was witnessed by many testing in India. The report highlighted certain features from the spy images when the bike was spotted testing. It said the bike would launch with halogen lighting, a mono-shock at the rear and telescopic forks. The bike is also expected to have multi-spoke alloy wheels, disc and drum brake combination setup and a single-piece long seat. Bajaj Auto Appliance d for a trademark on January 9, 2024, revealing the new names, including Trekker, Glider, Freedom and Marathon. Bajaj Pulsar NS400 Launched in India; From Price to Specifications and Features, Know Everything About Biggest Pulsar Ever From Bajaj.

Bajaj’s CNG bike price in India is anticipated to start from Rs 80,000 or Rs 90,000 (ex-showroom); however, only the company can confirm this. According to a report by Money control, Bajaj Auto would launch its first CNG motorcycle in India, considering cost-conscious customers looking for ideal solutions amidst rising fuel costs. The report said the CNG bike from Bajaj would be launched in phases based on the CNG stations, but it said it would first be launched in Maharashtra.

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Rising heat spurs 19% surge in power sector gas consumption in 2023

Natural gas consumption by the power sector rose 19 per cent Y-o-Y to 8.8 billion cubic meters (BCM) last year, driven by the government’s mandate to meet India’s rising electricity demand, which is estimated to be growing at 6-7 per cent per annum.


Gas Exporting Countries Forum (GECF), in its annual gas market report 2024, said the world’s third largest energy guzzler’s consumption increased 15 per cent Y-o-Y to 65 BCM in 2023 amidst a shift from coal to gas in power generation. GECF expects India’s natural gas consumption to grow 6 per cent Y-o-Y to 68.9 BCM this calendar year.

“This rise in natural gas consumption reflects the country’s economic rebound and the increasing emphasis on cleaner energy sources, with the declining prices of natural gas making it more competitive,” it added.

The power sector accounted for almost 14 per cent of the total natural gas consumed by the world’s fourth largest liquefied natural gas (LNG) importer last year. At the end of December 2023, India’s LNG imports accounted for about 47 per cent of its total gas requirement.

In the power mix, coal led with a 74 per cent share, followed by renewables (13 per cent), hydro (9 per cent), nuclear (2 per cent) and gas (2 per cent) in 2023.

More gas-based power

Power sector gas consumption surged 19 per cent Y-o-Y to 8.8 BCM last year emphasising natural gas’s growing importance, the GECF report said.

The sector “mirrored” the growth in gas usage in 2023, which was led by the industrial sector, with pan-India electricity generation rising 7.5 per cent Y-o-Y to 1,702 terawatt hours (TWh) in 2023, it added. One TWh equals 1,000 gigawatt hours.

“Due to the heatwave during summer period, which boosted cooling demand, the share of gas in the electricity mix grew significantly. This was the result of the introduction of an emergency directive to address an anticipated shortfall in electricity output during peak power demand in May and June,” the report said.

The directive mandated that gas-fired power plants operate at full capacity during this period. Later, these measures were extended until November 2023, it added.

India’s peak power demand in 2023 rose to a record 240 gigawatts (GW) in September and the Power Ministry expects demand to hit 260 GW in 2024.

Gas trading on exchanges also reported a healthy growth last year. For instance, the Indian Gas Exchange (IGX) traded around 4.85 lakh million British thermal units (mBtu), or 3.3 million standard cubic meters per day (MSCMD), of gas in 2023, a 16 per cent Y-o-Y growth.

Of the total commodity traded at IGX last calendar year, 3.51 lakh mBtu was domestic ceiling price gas.

Cumulatively 1,424 trades were executed on the country’s first automated national exchange for physical delivery of natural gas with maximum number executed in daily contracts followed by monthly, weekly and fortnightly contracts.

Higher gas production

India witnessed a 12 per cent rise in its annual gas production to reach 35.1 BCM in 2023. This rise was predominantly driven by the encouraging government policies adopted to boost domestic production from existing and newly commissioned fields, GECF said.

“The majority of Indian production originated from conventional gas fields (93 per cent of the total production), with 4 per cent coming from CBM development, recording a 9 per cent y-o-Y production growth,” it added.

Directorate General of Hydrocarbons (DGH) awarded exploration and development rights for ten oil and gas blocks under the 8th round of the Open Acreage Licensing Policy (OALP) in 2023.

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India’s first Kia Seltos modified with CNG kit

Kia Motors entered the Indian market last year and took the country by storm with the worthy contender of Hyundai Venue, the Kia Seltos.  The carmaker also recently launched the anniversary edition of the Seltos. Kia also has a luxury MPV Carnival and recently launched sub-compact SUV Sonet in its lineup. The Kia Seltos has become quite a popular SUV in India and can be commonly seen on the Indian roads. Find out below India’s first Kia Seltos modified with CNG kit.


As seen from the number plate in the SUV, the Kia Seltos belongs to someone in Gujarat. Now Gujaratis are quite professional by nature and like to save money whenever possible. The Kit used in the Seltos is from Zavoli Bora, which is an Italian brand. Maruti Autogas is also the all India distributor for this brand. They have installed S32 sequential kit in this Seltos. Normally, a car with a four-cylinder engine will get four injectors but, here in this Seltos, the number of injectors placed is 8. This helps reduce the lag that is normally felt in a CNG vehicle and improve the performance. The CNG kit also leads to better price to range efficiency.

Engine and Performance of Kia Seltos

It comes with three engine options: 1.5-litre petrol, 1.4-litre turbocharged petrol, and 1.5-litre diesel. While the 1.5-litre petrol motor is good for 115PS/144Nm, the diesel engine develops 115PS/250Nm. The 1.4-litre turbocharged petrol engine, which has an output of 140PS/242Nm, is only offered with the GT Line variants. It is available with either a 6-speed manual or various automatic transmission options depending on the engine.

Cost of the Kia Seltos CNG kit

The approximate cost of installing this CNG kit on the Kia Seltos is around Rs. 50,000. The 8 injector set up can be installed on other vehicles but, the prices will be higher than the regular ones. Do note that installing an aftermarket CNG kit will void engine warranty. In case of this Seltos, Kia Motors will not honour the factory warranty.

Features and Competition

Kia Seltos’s features arsenal consists of a 10.25-inch touchscreen infotainment system with Kia’s UVO connected car technology, an air purifier, ambient lighting, and an 8-inch head-up display. It also gets ventilated front seats, a power-adjustable driver seat, a 7-inch multi-information display, an eight-speaker Bose sound system, and a sunroof. The 2020 Seltos adds smartwatch connectivity, smart-key remote engine start, and a “Hello Kia” wake up command for the voice assistant of the UVO Connect features.

It goes up against the Hyundai Creta, Renault Duster, Nissan Kicks and Maruti Suzuki S-Cross. It will also take on the upcoming Skoda VISION IN and Volkswagen Tiguan SUVs. In case you wish to buy a more rugged SUV, you can check out the Mahindra Scorpio.

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Natural Gas/ Pipelines/ Company News


Mohit Bhatia takes over as IGL director (commercial)

In a significant development, Mohit Bhatia assumed the role of Director (Commercial) at Indraprastha Gas Ltd. (IGL) today. IGL, the nation’s largest CNG distribution company, welcomed Mr. Bhatia, who brings a wealth of experience and expertise to his new position.


Mr. Bhatia holds a Bachelor’s degree in Civil Engineering from NIT, Suratkhal, Karnataka, and an MBA in Marketing from SP Jain Institute of Management & Research, Mumbai. With over 31 years of dedicated service in the oil & gas sector, he is widely recognized as a seasoned leader with a proven track record in Operations, Engineering, and Marketing.

Prior to his appointment at IGL, Mr. Bhatia served as the Chief Executive Officer of Haridwar Natural Gas, a successful joint venture of BPCL and Gail Gas. His tenure there was marked by strategic sales and marketing initiatives that significantly contributed to the company’s growth and success.Mr. Bhatia’s appointment comes following the departure of Mr. Pawan Kumar, who has transitioned back to his parent organization, BPCL. With his extensive industry knowledge and leadership acumen, Mr. Bhatia is poised to lead IGL towards continued excellence and innovation in the CNG distribution sector.,expertise%20to%20his%20new%20position.

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bp appoints Kartikeya Dube as Head of Country-India region

bp has appointed Kartikeya Dube as the Head of Country (HoC), bp India, replacing Sashi Mukundan, who has led the oil and gas major’s India operations for the last 15 years.. Dube, a chartered accountant by training, will take over as the HoC for India and Senior Vice-President, gas and low carbon for India, with effect from July 1, 2024.


Mukandan, who has been with bp for over 42 years, will retire from the top job and will ensure a seamless transition for Dube.

“Kartikeya has a track record of building diverse teams and leading collaborations across businesses and disciplines in support of bp’s growth plans. I am confident that he will lead bp India to greater heights as we demonstrate bp’s commitment to supporting India’s ambition to be energy independent while creating additional growth opportunities both for bp and India,” Mukandan said.

Dube, who started his professional career with EY before joining bp, has experience in business development, investment cases, finance, business transformation, mergers & acquisitions (M&A), risk management, debt, procurement, government affairs, and advocacy.

In the more than 20 years that he has spent with bp, Dube has held senior roles in finance, commercial and business transformation in India, Singapore and the UK.

Last year, he was named Vice-President of Group Investor Relations in bp’s head office in London. He was closely involved in setting up bp joint ventures with Reliance Industries (RIL) in India. From 2020 until 2023, he was the CFO for Jio-bp (bp’s mobility joint venture with RIL in India).

“Now, more than ever, it is a very exciting time for India. We are proud to be associated with India’s energy journey for more than a century, and to have a strong and valuable partnership with Reliance Industries that helps us deliver real value to customers. India is a crucial part of bp’s strategy as we pivot to being an integrated energy company and support the country’s aspiration for energy independence by 2047. I am excited to be taking forward our growth plans in India and build on the legacy created by Sashi Mukundan and the bp India team,” Dube said on his elevation to the top job.

Commenting on bp’s operations in India, Mukandan said “From seeing the beginnings of our gas business go to heights of excellence jointly with Reliance Industries, producing natural gas from our KG basin block, which at peak production of 30 million standard cubic meters per day (mscmd) will supply 15 per cent of India’s gas demand; to Jio-bp which is helping meet India’s fast-growing demand for transport fuels and EV charging while providing employment to thousands across India.”,bp%20for%20over%2042%20years&text=bp%20has%20appointed%20Kartikeya%20Dube,for%20the%20last%2015%20years

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Policy Matters/ Gas Pricing/ Others

India needs a long-term integrated energy policy 

How will India deal with western sanctions imposed on its oil and gas suppliers? This is an issue that crops up every now and then.. This has been a subject of discussion not only in the domestic market but also at the international space, mainly because India is among the large consumers of fossil fuel.


In fact, just a couple of days back a businessline report quoting sources had said, “With sharp escalation in tensions in the Middle East… the Indian government is in a huddle over what its strategy on oil imports should be and the alternatives it could explore in case of supply disruptions in West Asia and continued volatility in oil prices.”

It further said, “The Commerce Ministry is in close consultations with the Ministry of Petroleum and Natural Gas to weigh alternative supply options that could be explored if the situation in West Asia worsens. As over 40 per cent of India’s oil at present is sourced from the region, the task is not simple.”

“One option being considered is to increase purchase from Russia and see if it can be routed through the Chennai-Vladivostok route, which passes through the Sea of Japan, the South China Sea and Malacca Strait, in case the traditional route through the Red Sea cannot be used,” the report said.

This constant debate leads us to a question about whether India has missed the bus in handling its energy security.

Ensuring energy security is a dynamic process with new geopolitical developments and changing energy mix due to climate change pressure.

Pipeline risks

So in India’s case would a transnational pipeline network work?

India has been unsuccessful in this area, mainly due to political factors which have also put a question mark over the commercial viability of these projects.

Given the ease with which LNG can be imported now (assuming there is no volatility), geopolitically risky trans-border pipelines with large capex may not be a viable option in today’s world.

“The current contracting environment is characterized by an over-investment cycle owing to the anticipated LNG supply that will be coming onstream. By 2030, almost 200 million metric tonne (MMt) more LNG will be added from plants under construction today. This represents a growth of almost 50 per cent and it is as large as the previous over investment cycles in 2005-06 and 2013-17.

“Consequently, for long-term LNG contracts scheduled to begin beyond 2029, new contracts are likely to face downward pressure on prices. In February 2024, QatarEnergy had signed a 20-year contract extension with Petronet LNG Ltd. for 7.5 million metric tonne per annum. This was reported to be at 12 per cent Brent oil. This sets a new benchmark in the market given its size and duration for a buyer in Asia,” said, Chong Zhi Xin, Senior Director, S&P Global Commodity Insights.

For example, a Rystad Energy — a global independent research and energy intelligence company — report said, “Russian oil production has remained strong despite sanctions imposed by Western countries in the wake of Russia’s invasion of Ukraine. The country’s gas and liquefied natural gas (LNG) industries, on the other hand, have suffered due to limited pipeline infrastructure and reliance on Western companies.”

Rystad Energy expects Russian piped gas supply to China to increase due to new infrastructure, but the outlook for Russian LNG is less rosy. The Kremlin has set an ambitious plan to commission 100 million tonnes of LNG capacity by 2030 but Rystad’s forecasts show the country will miss that target by as much as 60 million tonnes.

Despite a bleak outlook, it expects Russia’s planned LNG projects to go ahead despite sanctions and challenges in securing vessels and long-term contracts, thanks to government support and incentives on financing, research and development, and tax breaks.

However, there are diverse views on whether having transnational network would have worked better for India as it would depend on nature of sanctions and their geopolitical impact and the pressure put on India to comply with western sanctions.

Supply flexibility

Further one has to consider that pipeline supplies may leave the buyer at the mercy of supplier country. Whereas in case of LNG as is the case with crude oil, the buyer has flexibility to change supply sources.

Asked whether India’s attempts to have transnational pipelines to transport gas had failed because of political reasons, Talmiz Ahmad, former Indian Ambassador to Saudi Arabia; Oman, and the UAE, confirmed that “energy security concerns had been overwhelmed by political considerations”.

Ahmad, who was Additional Secretary for International Cooperation in the Ministry of Petroleum and Natural Gas in 2004-06, said that, for instance, the Myanmar-Bangladesh-India gas pipeline did not fructify because the Bangladesh side, due to domestic political compulsions, wanted certain bilateral matters to be included in the tripartite gas agreement which were not acceptable to the Indian side.

Similarly, the Iran-Pakistan-India gas pipeline project, despite agreement on several technical and commercial issues, did not progress due to political instability in Pakistan, while the Turkmenistan-Afghanistan-Pakistan- India (TAPI) gas pipeline project had the added problem of civil conflict in Afghanistan, he said.

“Political issues do overshadow commerce,” Ahmad said. Given the political challenges that have bedevilled pipeline projects, it now made sense to obtain gas as LNG, he added.

“However, the bigger issues that India faces today are uncertainty relating to the place of gas in our energy mix. What India needs is a long-term and integrated energy policy that projects the country’s energy requirements over the next 25 years, while taking into account domestic production, import requirements of fossil fuels, and our commitments to transition towards clean energy,” he pointed out.

To sum up, there are no simple answers to whether pipelines import would have served India’s energy security better, but what is clear is that India needs an integrated energy policy.,energy%2C%E2%80%9D%20he%20pointed%20out.

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ISMA moots strategic policy interventions to meet 20% ethanol blending target by 2030

Govt’s policy support can make industry meet 60% of blending target, says association chief Prabhakar Rao. To address the challenges faced by the sugar industry and meet the 20 per cent ethanol blending target by 2030, the Indian Sugar and Bio-Energy Manufacturers Association (ISMA) has stressed the need for strategic policy interventions by the Centre. The drop in Indian sugarcane production due to the global climate phenomenon, EL Nino, has significantly impacted ethanol production, with a sudden halt in production from mid-December 2023.


Despite the drop in production, ISMA asserts that India could have produced an additional 250 crore litres of ethanol by diverting a further quantity of around 25 lakh tonnes of sugar, even after meeting the full domestic demand requirements. This surplus could have been almost adequate to meet the current ethanol year requirement from the sugar industry.

Prabhakar Rao, President of the ISMA said, “The Indian sugar industry is well-positioned to meet the government’s ambitious 20 per cent ethanol blending target till 2030. Our industry can contribute a significant 55 per cent of the ethanol requirement, and even increase that to up to 60 per cent if we can get stable policy support and investment on sugarcane production stabilisation.”

However, several challenges need to be addressed, including the availability and affordability of raw materials for ethanol production.

Benefitting all stakeholders

To enable the sugar industry to meet the Ethanol Blending Requirement, Rao suggested that the Minimum Support Price (MSP) for sugar and ethanol prices for various feedstocks be fixed harmoniously, while announcing the Fair and Remunerative Price (FRP) for sugarcane. This will ensure the financial viability of the industry and attract more investments, leading to capacity creation that can help meet domestic sugar requirements and produce ethanol as per the EBP programme, he said

ISMA emphasises the need for stakeholder collaboration, regulatory tweaks and international inspiration to transform the sugar industry. The successful implementation of these policy interventions is crucial not only for sustainable energy practices but also for the financial strength of the sector and the welfare of farmers.

As the industry navigates these challenges, Rao urged stakeholders to collaborate, innovate and take positive action to ensure a smooth transition towards a future powered by renewable resources, paving the way for a greener and more sustainable tomorrow.,policy%20interventions%20by%20the%20Centre.

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State-run energy firms line up for green IPOs

After NTPC Green’s Rs 10,000 crore initial public offer (IPO) expected around November, almost a dozen more such issues are likely to hit the market over the ensuing months, with state-run energy companies seeking to bolster the capital bases of their newly incorporated green subsidiaries.


These IPOs are part of a larger plan of these companies – Coal India, ONGC, SJVN, NHPCIndia Oil and NLC India – to create robust climate-friendly asset bases, and enjoy the tax reliefs for new greenfield ventures (see chart). While a clearer picture will emerge only later, the combined value of these IPOs could easily run to tens of thousand crores, according to official sources and market experts.

While the sequence of the IPOs will unravel over the next few months, the government, especially the Department of Investment and Public Asset Management has been encouraging the energy sector CPSEs’ plans to float subsidiaries and joint ventures to take advantage of the lower corporate tax regime of 15% for new manufacturing firms, sources said. These firms have set up new wholly owned green subsidiaries before the March 31, 2024 deadline for being eligible for the concessional corporate tax.

Besides taking advantage of low tax, another incentive to set up green JVs is that it’s easier to find equity partners for such businesses, than for the parent companies. The companies are channelling their retained earnings to fund their green forays, also because these debt-free assets are to easier be securitised, and monetisated, if need be.

In line with the government’s ambitious RE capacity addition target and the goal of net zero emission by the year 2070, energy sector CPSEs are undertaking renewable projects or pooling their existing renewable assets into their new subsidiaries, analysts said.

NTPC is on the path of building up RE capacity of 60 GW by 2032 and NTPC Green Energy is its flag bearer in renewable energy journey with an operational capacity of over 3.4 GW and 26 GW in the pipeline including 7 GW under implementation.

IPO is one of the good ways of monetisation. NTPC Green Eenrgy’s model could be emulated by the likes of NHPC, SJVN and NLC ,” a senior official said.

SJVN Green Energy Limited (SGEL) has around 3.6 GW assets currently in the pipeline which are expected to be commissioned in the next two years. SJVN is expected is expected to incur more than Rs 20,000 crore capex in FY25 out of which more than Rs 15,000 crore is expected to be incurred for renewable capacity addition entirely through SGEL.

“All the energy companies which are in brown and also those which are green already, even they are doing further green and into other green areas from wind to soar to hydrogen,” the official said.

NHPC, India’s leading hydropower company, has set up a wholly owned subsidiary NHPC Renewable Energy Ltd (NREL) which be used to house already commissioned solar capacity, and the ones in the pipeline after they are commissioned. NHPC has a total installed capacity of 7097.2 MW of renewable energy (including wind and solar) through its 25 power stations, including 1520 MW through subsidiaries.

Premier Energies files DRHP to raise Rs 1500 cr

The Centre has set an ambitious target of having an installed renewable energy capacity of 500 GW by 2030. As of May 26, 2023, coal/lignite CPSE has installed solar capacity of about 1656 MW and windmills of 51 MW. Total Renewable energy is planned to be installed at 5570 MW of renewable capacity by 2030. NLC’s wholly owned subsidiary NLC India Green Energy Limited (NIGEL) has signed the Power Purchase Agreement (PPA) with Gujarat Urja Vikas Nigam Limited (GUVNL) for the proposed 600 MW Solar Power Project at Khavda Solar Park, Gujarat.

CIL has incorporated two new subsidiaries i.e. CIL Navi Karniya Urja Limited for the development of non-conventional/clean & renewable energy and CIL Solar PV Limited for the development of the solar photovoltaic module.

India’s top oil explorer ONGC has set up a subsidiary ‘ONGC Green Limited’ recently engage in businesses related to green hydrogen, hydrogen blending, renewable energy including solar, wind and hybrid, bio-fuels and bio-gas business and liquefied natural gas.

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Global biofuel alliance sets up three-pronged work plan, says govt

While it remains without a charter, or a permanent secretariat, the Global Biofuel Alliance (GBA) has adopted a work plan focused on assessing country landscapes, drafting policy frameworks, and conducting biofuel workshops, petroleum and natural gas ministry officials said.


These were adopted as immediate goals at a key meeting of the body held on the sidelines of the G20 deliberations in Brazil last month. And, the officials added that the GBA has decided to take stock of them in July.

“India has also suggested three potential workstreams to support biofuel trade, increase awareness in biofuels, and identify support mechanisms for enhanced adoption of biofuels,” an official said.

Launched on the sidelines of the 2023 G20 summit in New Delhi, the GBA aims to reshape the global landscape and expedite uptake of biofuels worldwide. It also hopes to set standards for biofuel, expand the size of formal biofuel markets and better map demand and supply.

The India-led initiative has seen 24 countries signing up so far, with special interest generated among African nations. Apart from G20 member South Africa, non-G20 nations like Kenya and Uganda are on the list, while Tanzania is keen on joining, sources said.

However, officials could not clarify when or where a new secretariat for the GBA would be unveiled. Talks on creating a governance structure and charter would also take some time, they hinted.

India and Brazil are the main drivers at the GBA. “Beyond the initial interest evinced by all stakeholders since the GBA was formed, a major push to the initiative has been given by Brazil, as part of the current G20 chair. India’s goals with regard to biofuels align with Brazil’s in the long term,” another official said.

The primary work plan was taken up at a key meeting on the sidelines of the Energy Transitions Working Group meet in Brazil.

More global engagements

Building up the profile of the GBA, and placing its plans and objectives in front of a global audience has been prioritised, officials said.

Case in point, the GBA has engaged at the United Nations COP28 Summit in Dubai.

It was also present at the annual meeting of the World Economic Forum in Davos, and the government’s India Energy Week global summit in Goa, earlier this year.

In April, the GBA made presentations on the sidelines of the G7 energy minister’s meeting in Italy. Among the G7 nations, Italy and the United States are part of the alliance.

New Delhi also hopes the GBA will position India as a climate & sustainability champion and further bolster the country as the voice of the Global South.

Key to this is India helping lower and middle income countries also start their biofuels programme.

According to the International Energy Agency (IEA), biofuels have a potential to grow by 3.5-5-times by 2050 due to Net-Zero targets, creating a huge opportunity for India.

A record 171.2 billion litres of biofuels were procured globally in the year 2022, with India contributing just 2.7 per cent or 4.6 billion litres. Despite this, India remains the third-largest producer of ethanol, after the United States (US) and Brazil, said IEA.

By aligning itself with both these nations in the GBA, India seeks to rectify this disparity, given that it is among the largest producers of biofuel feedstock, including sugarcane, maize, and vegetable oils.

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LNG Use / LNG Development and Shipping

Gail India issues swap tender for LNG cargoes in 2025, say sources

SINGAPORE, May 3 (Reuters) -GAIL (India) Ltd GAIL.NS has issued a swap tender, offering 12 liquefied natural gas (LNG) cargoes for loading in the United States in exchange for 12 cargoes for delivery to India, two industry sources said on Friday.


India’s largest gas distributor is offering the cargoes, one per month throughout 2025, on a free-on-board (FOB) basis for loading from Sabine Pass.

In exchange, it is seeking 12 cargoes for delivery to the Dhamra terminal for the same months on a delivered ex-ship (DES) basis.

The tender closes on May 16, one of the sources added.

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India to receive first LNG cargo from Indonesia’s Tangguh LNG

SINGAPORE (Reuters) – India will receive its first cargo from Indonesia’s Tangguh liquefied natural gas (LNG) plant at the Dahej terminal on Monday, according to a Refinitiv analyst and Refinitiv ship tracking data.


The LNG cargo is being transported by the BW Helios tanker, said Olumide Ajayi, senior LNG analyst at Refinitiv.

“The vessel which had been acting as a floating storage since it lifted the cargo in mid-September is currently on a term charter to British oil major BP and is due to arrive at state-owned Petronet’s Dahej terminal on November 28,” he said.

The BW Helios picked up the cargo of 132,000 cubic metres at the Tangguh LNG loading facility on Sept. 18, according to Refinitiv data, and has a discharge date of Nov. 28.

Ajayi added that the shipment was unusual as Indonesian LNG cargoes are typically exported to north Asia, and that India receives LNG cargoes from Qatar, Oman and the UAE.

Japan, China and Korea are key LNG consumers in north Asia, but high inventories and muted spot demand in the region have weighed on Asia spot LNG prices in recent weeks.

Operated by BP, the Tangguh LNG plant is in Indonesia’s West Papua province and began production in 2009. Its output capacity is 7.6 million tonnes of LNG per annum (mtpa) from two existing trains.

BP did not immediately respond to a request for comment.

A third train is expected to come on stream in March 2023, officials at Indonesian upstream regulator SKK Migas said in July, which will bring the plant’s total production capacity to 11.4 mtpa.

Train-3 however has faced several delays from an initial planned start in the third quarter of 2020 due to natural disasters delaying shipments of required construction material and COVID-19 restrictions.

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Adani’s Dhamra LNG Seeks $600 Million Loan To Boost Gas Operations

Adani’s Dhamra LNG Terminal Pvt., a subsidiary of Adani Total Pvt., is in talks with several banks to secure an offshore loan worth approximately $600 million. The loan is intended to refinance existing debt, according to sources familiar with the matter.


The borrowing, with a tenor ranging from three to five years, is likely to be priced in connection with the Secured Overnight Financing Rate. Lenders engaged in discussions for this transaction include Credit Agricole, DBS Bank Ltd., BNP Paribas, Mitsubishi UFJ Financial Group Inc., and Mizuho Bank Ltd. The conglomerate, led by billionaire Gautam Adani, aims to finalize the loan within the next two months.

Adani Group has not responded immediately to Bloomberg’s requests for comment. However, the conglomerate has been steadily regaining investor confidence since facing scrutiny from US short seller Hindenburg Research early last year. In March, the group witnessed strong demand for its inaugural public bond sale following the short seller crisis.

Adani Total, a joint venture between Adani and TotalEnergies, is strategically positioned in the context of Prime Minister Narendra Modi’s government initiatives. The government aims to bolster India’s LNG import capacity to elevate the share of natural gas in the country’s energy mix to 15 percent by 2030, up from the current 7 percent. This move aligns with efforts to reduce reliance on more polluting fossil fuels like coal and oil.

The loan sought by Dhamra LNG underscores Adani’s commitment to expanding its presence in the natural gas sector. Adani Total’s strategic partnership with TotalEnergies, combined with India’s push for cleaner energy sources, presents significant growth opportunities for the conglomerate. By securing this loan, Adani aims to fortify its position in the LNG market while contributing to India’s energy transition objectives.

Investment in LNG infrastructure is crucial for India’s energy security and environmental sustainability. Adani’s efforts to secure financing for its gas operations demonstrate a long-term commitment to aligning with national energy goals and driving economic growth through sustainable means.

In conclusion, Adani’s pursuit of a $600 million loan for its Dhamra LNG unit reflects the conglomerate’s strategic vision to advance its gas operations and support India’s transition to cleaner energy sources. With strong government backing and investor confidence, Adani is poised to play a pivotal role in shaping India’s energy landscape for the future.

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Petrobangla nears pipeline LNG import deal with Indian H-Energy

After four years of negotiation, Petrobangla – the oil, gas and mineral corporation of Bangladesh – is close to signing agreements on import of regasified LNG from an Indian private company through a cross-border natural gas pipeline, officials at the state agency said.


As part of its bid to minimise the growing gas crisis in the country, the state-owned petroleum corporation is poised to enter a deal with Mumbai-based H-Energy Private Limited, they said.

Two agreements on pipeline installation and LNG supply are expected to be signed in the first half of the next fiscal year, the officials said.

“Discussions with H-Energy are nearing completion, with only three or four points outstanding. The Energy Division has been asked for its opinion on these unresolved issues. Once the Energy Division’s opinion is received, the agreement will be signed with the approval of the higher authorities concerned,” Petrobangla Chairman Zanendra Nath Sarker told TBS on 17 April.

The company will supply LNG within two years of signing the agreement, he said.

Petrobangla signed a memorandum of understanding (MoU) with H-Energy on 16 June 2021 for long-term import of regasified LNG.

The state agency had signed the first MoU with Indian Oil Corporation Ltd in 2017 for the same purpose.

According to officials at Petrobangla and the Energy Division, discussions are underway for importing 0.8 to 1 million tonnes per annum LNG from H-Energy.

A review of all potential aspects, including gas import through pipelines from the company, gas utilisation, economic benefits and losses, security arrangements, etc have been completed, they said.

Currently, discussions are ongoing regarding the payment method for the money given by the Indian company for pipeline installation, pipeline management, LNG price, etc, said the officials.

Once these are finalised, the matter will proceed to the agreement stage, they said.

Energy and Mineral Resources Division Secretary Md Nurul Alam told TBS on 18 April, “I came to know that progress had been made in discussions with H-Energy.”

Western region to get gas

A Petrobangla official said a 30-inch diameter 65-kilometre pipeline will be constructed from Satkhira to Khulna to transport gas from India. The plan is to bring 300 million cubic feet of LNG daily through the pipeline, he said.

The gas will be supplied to ongoing and future power plants in Khulna and thus the western region of the country will get gas for the first time, said the official.

According to a recent BBC news report, H-Energy has constructed India’s first floating storage and regasification terminal at Jaigarh Port in Maharashtra. The company has also signed an MoU with the Kolkata Port Trust to establish an LNG terminal in East Medinipur district of West Bengal. The company has informed that LNG will be sent to Bangladesh from the terminal.

Demand and supply

According to Petrobangla’s 18 April report, gas availability in the country was 2,133 million cubic feet per day (mmcfd) – 1,135mmcfd from local gas wells and 998mmcfd from import.

Against the demand for 2,317mmcfd, the power plants got 1,329.6mmcfd while fertiliser factories received 23.2mmcfd against the need for 329mmcfd on the day.

Gas import on the rise

According to Petrobangla documents, the government signed three LNG sale and purchase agreements last year. The first agreement was signed on 30 May last year with Qatar Energy Trading LLC for importing 1.5 million tonnes of LNG per annum for a period of 15 years starting in 2026.

The second agreement was signed on 19 June last year with OQ Trading Limited of Qatar to import an additional 0.25-1.5 million tonnes LNG per annum starting in 2026, in addition to the existing agreement.

The third agreement was signed on 8 November last year with the USA-based Excelerate Energy Bangladesh Limited to import 1 million tonnes LNG per annum for a period of 15 years.

Petrobangla has also signed an agreement with Summit Oil & Shipping Co Ltd, under which the company will supply LNG from 2026 for a period of 15 years.

In addition to these, a deal has been finalised to import 1 million tonnes of LNG per annum for one year from Perintis Akal Sdn Bhd, Malaysia. The Legislative and Parliamentary Affairs Division and the Cabinet Committee on Government Procurement have approved the deal. The agreement will be signed very soon.

The company will start supplying LNG this year. Discussions are also in the final stages to buy 24 LNG cargoes from Gunvor Singapore Pte Ltd over the next two years.

According to Energy Division officials, the demand for gas in the country is increasing steadily. As a result, the collection of LNG is being increased from the spot market as well as long-term contracts, they said.

Some 54 cargoes of LNG were imported from the spot market till last January starting in September 2020, the officials said. In addition, LNG is being imported from Qatar under long-term contracts, they said.

The officials said as it is currently not possible to meet the entire domestic demand for gas, the pipeline gas import move will lessen forex pressure for procuring LNG from the spot market.

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Electric Mobility/ Hydrogen/Bio-Methane

Hydrogen-enriched CNG may come to India soon

Fossil-fuel powered vehicles are seen as a major culprit for air pollution despite its small contribution. The whole world is already undergoing a complete overall due to COVID and some new changes may be seen in the transport sector in India soon. The current BS6 emission norms were tough to comply by and now the government is thinking of one step ahead. EVs are still in their budding stage in terms of charging infrastructure so they want to modify the already successful alternative, the CNG. Find everything below about Hydrogen enriched CNG India also known as HCNG.


What has the department told?

The Ministry of Road Transport and Highways of India has issued a new draft. The new draft requires suggestion on the inclusion of HCNG. HCNG is also known as hydrogen-enriched CNG. If the draft receives positive feedback it could lead to an amendment to the Central Motor Vehicle Rules 1979

HCNG is just like CNG with some minor tweaks here and there. Firstly HCNG contains hydrogen hence the name HCNG. Chemically speaking HCNG contains about 18 percent of Hydrogen for 100 percent of gas. This alternative fuel can be used in the CNG powered vehicles after slight engine optimization.

CNG is already better than any other fossil fuel-powered car.  The fuel is available cheaply as well is more environmentally friendly. Thanks to the Indian Government CNG infrastructure is quite good in the Indian market. No official price details are available for HCNG as of now.  HCNG, however, has undergone testing and initial results show lower emissions compared to CNG. Scientifically speaking HCNG produces lower CO (Carbon Monoxide), methane and THC (Total hydrocarbon emissions). The test results also showcase that HCNG is better than any other fossil fuel in terms of fuel consumption.

What will this technology cost?

Cost is a major deciding factor and reports suggest that it will be meagre. HCNG can be easily installed into CNG pipelines and bus depots.  Test phase of this new fuel may take place in Delhi due to its better CNG infrastructure. First 50 busses fitted with HCNG kit will be tested for practicality. 

Can you help for Hydrogen enriched CNG India?

The Ministry draft is open to suggestions from the common man and stake-holders. Everyone can send their comments and opinions to the Joint Secretary(MVL), Ministry of Road Transport and Highways by email or post within 30 days.

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Over 90% of fund gets used before FAME deadline; supports 1.5 mn vehicles

The Centre’s ambitious FAME-II scheme for the promotion of electric vehicles (EVs) in the country saw funds utilised touching around 90 per cent on deadline day, that is, March 31, 2024. Data from the Ministry of Heavy Industries (MHI) shows that the Centre spent Rs 10,253 crore out of the total Rs 11,500 crore allocated for the five-year scheme. These funds were used to support 1.5 million vehicles over the past five years.


Government officials said that some more funds will also be utilised for vehicles that were sold before March 31 but have not yet applied for incentives.

“Some funds will be allocated to provide incentives to manufacturers who sold their vehicles in the previous financial year but applied for incentives afterwards,” a senior official said.

The electric three-wheeler (e3W) category demonstrated the highest fund utilisation, with the allocated Rs 991 crore being fully used.

In the bus category, 94 per cent of the Rs 991-crore allocation was utilised, while in electric two-wheelers (e2Ws), 90 per cent of the Rs 4,756 crore allocation was utilised.

The lowest fund utilisation was observed in the electric four-wheeler (e4W) category, where only 64 per cent of the allocated funds were utilised.

The government has also spent Rs 633 crore out of the allocated Rs 839 crore on EV chargers.

The fund allocation was not fully achieved before the deadline.

This was due to the government’s decision in October 2023 to increase the target of the scheme from Rs 10,000 crore to Rs 11,500 crore.

This adjustment came after the MHI exhausted the funds allocated for e2Ws and e4Ws.

In the scheme’s initial phase in 2015, the government allocated approximately Rs 900 crore, and this amount surged to around Rs 10,000 crore during the second phase in 2019.

To date, the scheme has provided support to more than 1.5 million vehicles.

The government also raised the target for the number of vehicles from approximately 1.5 million to 1.7 million.

A total of 68 original equipment manufacturers (OEMs) were registered under the FAME-II scheme.

In March, the MHI announced a new scheme, the Electric Mobility Promotion Scheme (EMPS), 2024, with a budgetary allocation of Rs 500 crore, to promote the sale of e2Ws and e3Ws in the country.

A total of 11 EV manufacturers, including Ather Energy, Bajaj Auto, Hero MotoCorp, Ola Electric, and Mahindra were approved under the scheme, Business Standard had reported on April 10.

EV sales in FY24 witnessed a robust increase of over 41 per cent, notwithstanding the subsidy cuts and regulatory shifts.

Total EV registrations in FY24 surpassed 1.6 million, which is significantly higher than last year’s 1.1 million.

All this has pushed the overall EV penetration in the country during FY24 to 6.8 per cent against 5.3 per cent in FY23.

The uptick was despite the government’s decision in June to reduce subsidies under FAME to a third of the maximum Rs 66,000 subsidy it was offering on e2Ws.

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India looks to fast-track work on hydrogen trains

Indian Railways has begun work towards developing “cost-efficient” hydrogen–fuel cell trains, with indigenous technology. Initial development show the technology to be some 12 times costlier than regular diesel locomotives. However work is being carried out to develop prototypes that are “less costly” but equally efficient, officials aware told businessline.


An official said the technology development is being done in-house. Typically, a key component of the hydrogen propulsion system is the fuel cell. This device converts chemical energy into hydrogen to generate electricity, which serves as fuel to run the train.

One plan being discussed is retrofitting hydrogen fuel cells on diesel electrical multiple units (DEMUs), while another plan is to develop a new set of locomotives.

Development cost

“Initial studies show that the cost of development of one hydrogen-fuel-cell enabled locomotive could be higher by 12 times when benchmarked to a diesel or electric locomotive. So, some rework is being carried out to see that costs are brought down. Design changes are under-way too,” an official said.

“The technology and design will be completely India-made,” he added. Indian Railways is expected to complete the electrification of tracks by FY25 and a move towards hydrogen-powered trains, on select routes, is seen as the logical next step.

While the train prototypes will most likely be developed at Integral Coach Factory in Chennai, the actual manufacture could be done through domestic and international partnerships. A hydrogen-fuelled-cell train is more environment-friendly with lower footprints, practically zero emission, that traditional engines.

Global stories

Incidentally, Alstom’s Coradia iLint was amongst the first to operate hydrails, transporting passengers in North America. It carried more than 10,000 passengers in a demonstration project in Quebec from mid-June to the end-of-September 2023 on the Réseau Charlevoix rail network along the Saint-Lawrence River.

Alstom also partnered with Saudi Arabia Railways (SAR) to operate and provide demonstrations for the first passenger hydrogen-powered train in Riyadh. Germany already has retro-fitted hydrails; and China is already testing its own version of such rolling stock.

California and Italy are also working on hydrails projects including coversion of existing diesel ones to hydrogen-run locos.

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Natural Gas / Transnational Pipelines/ Others

Canada: Alberta Utility plans C$2bn pipeline enhancement

ATCO Energy Systems’ Yellowhead Mainline project would provide gas supply to Edmonton-area petrochemical and other gas demand projects, including Dow Canada’s net-zero ethylene cracker. ATCO Energy Systems, part of Canadian Utilities Limited (CUL), on May 8 launched its “largest ever” energy infrastructure project, the C$2bn Yellowhead Mainline project to deliver natural gas from Peers, west of Edmonton, to Alberta’s Industrial Heartland (AIH).


“As Alberta’s energy demand continues to grow, the Yellowhead Mainline will play a crucial role in reinforcing Alberta’s energy infrastructure and enhancing access to reliable energy from one of the cleanest sources of natural gas on the planet,” ATCO Energy Systems COO Wayne Stensby said

Yellowhead Mainline is part of CUL’s plan to invest about C$4.5bn over the next three years to expand and enhance the reliability of its natural gas and electric systems, Stensby told CUL’s annual meeting in Edmonton on May 8.

The project is expected to create 2,000 jobs during construction and provide up to 1bn ft3/day of natural gas supply to support more than C$20bn of investment by ATCO’s customers, including Dow Canada’s C$8.8bn Fort Saskatchewan Path2Zero project, the world’s first net-zero integrated ethylene cracker and derivatives facility.

“Dow appreciates the partnership with ATCO to supply Dow’s Path2Zero project,” Dow Canada president Diego Ordonez said. “Together these projects will have a profound positive impact on communities, creating jobs and economic opportunity for Alberta.”

The project consists of about 200 km of high-pressure natural gas pipeline and related control and compression facilities extending from near Peers to the AIH region, an industrial area on Edmonton’s northeastern outskirts and home to Dow Canada’s project.

Total investment is expected to exceed C$2bn, ATCO Energy Systems said, with more precise cost estimates subject to further refinement of project scope, routing and detailed engineering. Construction would begin in 2026, subject to regulatory and company approvals, and the expansion is expected to be on-stream in Q4 2027.

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Nigeria: CNG buses will cut cost of transportation by over 250%—FG

The Finance Minister and Coordinating Minister of the Economy, Wale Edun has revealed that the cost of transportation will be reduced by over 250 per cent.

Edun made this assertion when he visited the JET Motor Company Assembly Plant where Compressed Natural Gas buses (CNG) were assembled in Lagos State.


According to Edun, the development will curtail inflation rate, in a statement on Saturday by the Senior Special Assistant to the President on Media and Publicity, Temitope Ajayi.

He said,“I have come to see the CNG buses that Nigerians are asking about. I have seen them. I have tested them and driven them. I have seen them being assembled. The benefits will soon be available to Nigerians.

“Two critical aims will be achieved. Whereas it costs about N55,000 to fill a 15-20 seater bus with petrol, it will cost between N12,000 to N15,000 to fill a CNG bus of the same capacity.
This is three times if not four times less. This is a huge savings that will help reduce transport costs and at the same time, help reduce inflation.”

This shows that the cost of transportation will be reduced by 266.67 per cent.

While praising the JET’s employment of local talents in the assembly of the vehicles, Edun said the Presidentian CNG Inititative (PCNGi) was about affordable mass transit.

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Ogun: FG gives fresh condition for gas licence

The Federal Government says it will stop granting licences to gas companies with no capacity to build pipelines for gas distribution. This, the government said, became necessary to discourage the transportation of compressed natural gas through the roads. The Minister of State for Petroleum (Gas), Ekperikpe Ekpo, made this disclosure when he was in Abeokuta, the Ogun State capital on Wednesday.


Ekpo had visited Abeokuta for an on-the-spot assessment of Saturday’s CNG explosion at Ita Oshin.

A CNG gas truck owned by Gasco Marine had suffered a brake failure, rammed into the road barricade and went up in flames, killing one person and razing some vehicles.

Ekpo, who was received into the state by Governor Dapo Abiodun and his deputy, Noimot Salako-Oyedele, stated that he was sent by President Bola Tinubu to see to the root cause of the incident and sympathise with the people of Ogun State.

While saying the country must transit from fossil fuel to CNG, Ekpo revealed that he had directed the Chief Executive of the Nigerian Midstream and Downstream Regulatory Authority, Farouk Ahmed, not to issue licenses to anyone who could not pipe CNG to the end users.

The gas minister emphasised that there was the need to stop virtual gas transportation, saying the Federal Government was putting efforts in top gear to build pipelines for seamless transportation of CNG.

According to him, this would prevent explosions on the road, while saving lives and property.

“As the Federal Government, we are trying all that we can to ensure we reduce virtual transportation of gas because of the volatility of it, especially with the Ajaokuta–Kaduna–Kano pipeline.

“I have directed the authority chief executive that for any further issuance of licence, the company should be competent enough to pipe it to their end users so that we are not exposed to this kind of danger any longer.

”As a ministry, we are looking at how we can reduce a lot of virtual conveyance of gas. That is why we are putting much in developing the gas pipeline infrastructure so that the transportation would not be virtual, but rather through the pipelines. This will reduce this kind of incident and take off the pressure on our roads,” he said.

Ekpo stressed that despite the incident, CNG remains a better alternative to petrol, urging Nigerians not to be discouraged.

 “This is better than even fuel if you look at what happened in Port Harcourt where lives were lost and so many vehicles burnt. It is better we go this route,” he added.

Ekpo harped on the importance of companies using only quality cylinders for the distribution of gas to avoid incidents.

Speaking, the NMDPRA boss, Ahmed, assured Nigerians that the agency was working with the Standard Organisation of Nigeria and the Federal Road Safety Corps to forestall similar explosions on the road.

Ahmed maintained that some of the accidents occur due to the roadworthiness of the vehicle.

He added that training programmes are being organised for truck drivers to ensure safety on the road.

Responding, Abiodun appreciated the team and President Tinubu for reaching out to the state, promising to further adopt and promote the CNG initiative of the Federal Government.

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Turkey: Türkiye on road to becoming natural gas hub

Following the development, it will be possible to liquefy domestically produced natural gas and natural gas imported from different sources in the country and market it as liquefied natural gas (LNG) to world markets Türkiye will soon become a natural gas hub after the Turkish Parliament approved changes to strengthen the field of energy last week.


Following the development, it will be possible to liquefy domestically produced natural gas and natural gas imported from different sources in the country and market it as liquefied natural gas (LNG) to world markets. 

In this context, new investments will be made in natural gas liquefaction facilities in Türkiye. Natural gas will be converted into LNG, and the liquefaction center will be established in areas with natural gas lines. Natural gas will be sold to potential countries in liquid form by ships.

In this context, new investments will be made in natural gas liquefaction facilities in Türkiye. The liquefaction centers, which will be established in areas with natural gas pipelines, will convert natural gas into LNG, which will then be transported to potential countries via ships.

Sources in the Ministry of Energy and Natural Resources said that this regulation is an essential step toward the goal of becoming a natural gas hub: “We have the gas that we extract from the Black Sea. We have natural gas lines from Azerbaijan, Russia and Iran. We also purchase LNG from various countries. We store the parts of these that we need in our storage facilities. We can send some of this gas to the west via pipelines. With this legal regulation, we can liquefy some of the gas in our storage, turn it into LNG, and export it to regions where we do not have pipelines. We currently do not have a natural gas liquefaction facility. These facilities can be established with public or private sector investment in the coming period. Then we can export LNG to all parts of the world with ships.”

On the other hand, there have been reports that Türkiye also discussed purchasing $1.1 billion worth of LNG from the U.S. company Exxon Mobil.

The U.S. State Department recently discussed Türkiye’s meeting with Exxon Mobil and stated that Ankara plays an essential role in diversifying European countries’ energy sources and reducing their dependence.

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Canada: Canada’s Oil and Gas Industry Soars to New Heights

As Canada’s oil and natural gas production hit record high levels, the country is taking pains to amplify its status as a global oil and natural gas superpower. One part of this greater initiative includes an ongoing effort to transform the sector to be less reliant on U.S. markets and infrastructure through strategic expansion of its own industry at a time when the United States is taking a step back.


Canada took a major step in that direction on May first when the Trans Mountain pipeline expansion project (TMX) finally became commercially operational after 12 years and 12 years and C$34 billion (USD$25 billion). Years of insufficient pipeline infrastructure have forced Albertan oil producers to sell their oil at a discount, resulting in tens of billions of dollars of revenue loss each year. The new TMX is set to change all of that by tripling the nation’s flow of crude. 

In anticipation of a boom year for Canadian oil and gas, producers are already ramping up output, and as a result Canadian oil production is expected to break records this year, reaching a high of around 5.3 million barrels per day. Not only is this a massive boon to the Canadian economy, it’s also a huge step toward self-sufficiency for the Canadian energy industry that will enable the country to ease its reliance on U.S. markets. 

This expansion in oil production and crude transportation capacities comes at the same time that Canada is trying to ramp up its natural gas sector. The first phase of the LNG Canada liquified natural gas export facility, the largest private investment in Canadian history, is now reaching completion in Kitimat, British Columbia. The project expects to come fully online in 2025. 

While the LNG Canada facility is designed for the sole purpose of exporting natural gas to other countries, its operations will actually slash Canada’s exports to the United States, at least in the near term. Although the United States was a net natural gas exporter last year, Washington nevertheless imported 8.0 billion cubic feet per day of natural gas in 2023. And the vast majority of that was delivered via pipeline from Canada. 

As operations at the LNG Canada terminal pick up speed, those pipelines will most likely take a hit as supplies are stretched thin for the first few years. “Western Canadian producers historically have been able to raise average production by up to 0.5 [billion cubic feet per day] year-over-year, indicating a temporary supply gap for U.S. and eastern Canadian markets at the outset of LNG Canada’s full operations,” Reuters recently reported. Industry insiders anticipate that satisfying the natural gas demand of LNG Canada alone will take about four years. 

While this presents a hurdle for the United States, which doesn’t drill enough natural gas to satisfy its own demand despite being the biggest producer in the world, Canadian markets see the easing of their tight relationship with U.S. markets as an important step for their autonomy and status in the global marketplace. “The startup of LNG Canada opens new markets for Canadian gas other than the (U.S.) Lower 48 … any downturn in the amount of Canadian gas exports to the U.S. could reverberate across North America later this decade,” Eli Rubin, senior energy analyst at consultancy EBW Analytics Group, was quoted by Reuters.

To be sure, Canada is not trying to break its close trade relations with the United States. In fact, it’s continuing to lobby for greater economic cooperation between the neighborly allies going forward. However, Canada is currently in a unique position to gain strategic economic ground on a global scale as the United States continues a pause on approvals of new licenses to export LNG, and many Canadian officials feel that it would be foolish not to capitalize on that window of opportunity.

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Nigeria: SON Adopts 80 CNG-Related Standards for Operational Safety in Nigeria

The Standards Organisation of Nigeria (SON) has adopted 80 Compressed Natural Gas (CNG)-related standards to ensure safety in the fuel’s operation in the country. This was made known by the Director-General of SON, Mr Ifeanyi Okeke, during a meeting with Governor Dapo Abiodun of Ogun State, recently which came on the heels of a recent accident in Abeokuta involving a CNG truck.


The SON boss commiserated with the governor and people of the state on the unfortunate incident that recorded one fatality and many cars and properties destroyed.

The meeting, which took place at the governor’s office, was marked by discussions on aligning state-level regulations with federal standards, enhancing safety protocols, and streamlining processes for the adoption of CNG as an alternative fuel source.

Mr Okeke said the decision to elaborate and adopt 80 CNG-related standards would help ensure that operators adhere to the highest safety protocols, minimizing risks associated with handling and usage.

Highlighting the significance of the collaboration between SON and Ogun State, the Director-General reiterated SON’s commitment to upholding stringent quality standards in line with global best practices.

He emphasized the pivotal role of standardization in promoting consumer confidence, safeguarding public health, and fostering sustainable economic development.

On his part, Governor Abiodun expressed his administration’s unwavering support for initiatives aimed at diversifying the energy mix and reducing dependency on traditional fuels.

He underscored the importance of ensuring the safety and reliability of CNG infrastructure to mitigate potential risks and promote widespread adoption across the state.

The discussions also touched upon the broader national agenda, regarding President Bola Tinubu’s visionary “Renewed Hope” agenda, which prioritizes the implementation of strategic projects such as the CNG initiative.

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Canada: TC Energy hits record natural gas deliveries in Q1

TC Energy Corp., a Canadian pipeline operator, achieved record natural gas deliveries in the first quarter of 2024, driven by a surge in North American electricity demand, according to BNN Bloomberg. The Calgary-based firm reported that comparable earnings from its natural gas segments in Canada, the US, and Mexico rose to $2.37bn from $2.18bn during the same period last year.


The company noted significant activity on its NGTL system, which channels natural gas from Alberta and northeastern British Columbia to markets in both Canada and the US.

This system recorded an average daily delivery of 15.3 billion cubic feet, an increase from the previous year, and set a new single-day delivery record of 17.3 billion cubic feet.

In the US, TC Energy’s natural gas pipelines experienced a daily average flow of 30 billion cubic feet, marking a year-over-year increase of more than five percent.

Records were also set across the company’s US natural gas portfolio, including Columbia Gas, Columbia Gulf, and Great Lakes Gas Transmission.

Deliveries to US power generators climbed by 11 percent, reaching a new quarterly record.

François Poirier, CEO of TC Energy, highlighted the continuous rise in natural gas demand due to increasing electricity requirements, particularly emphasizing the record power burn in the US throughout 2023 and into the current year.

A report by McKinsey & Co. earlier this year forecasted that natural gas would remain crucial in the energy transition, with expected global demand growth of 10 to 15 percent beyond 2030 before it begins to decline.

The anticipated growth is linked to the shift from coal to cleaner-burning natural gas and increased needs from the electrification of buildings, transport, and heavy industries.

Factors such as low natural gas prices, the retirement of coal plants, and the need for reliable backup to intermittent wind and solar generation have fueled this demand.

The US saw a record consumption of 89.1 billion cubic feet per day in 2023, with an average annual increase of four percent since 2018, according to the US Energy Information Administration.

Stanley Chapman, TC Energy’s chief operating officer for natural gas pipelines, pointed to emerging data centre demand as a significant driver for future growth. McKinsey & Co. also predicts a 10 percent growth in US data centre power consumption until 2030.

TC Energy reported a first-quarter profit of $1.20bn or $1.16 per share, a decrease from $1.31bn or $1.29 per share in the prior year.

However, revenue saw an increase to $4.24bn from $3.93bn in the first quarter of 2023.

The company disclosed a recent deal to sell its Portland Natural Gas Transmission System to a fund managed by BlackRock and Morgan Stanley Infrastructure Partners, alongside an agreement to sell the Prince Rupert Gas Transmission project to the Nisga’a Nation and Western LNG.

Looking ahead, TC Energy is preparing for the spinoff of its crude oil pipeline business into a separate entity, South Bow Corp., with a shareholder vote scheduled during the annual general meeting on June 4.

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Peru: MINEM signed the contract for the natural gas massification project in the Cusco region

The Ministry of Energy and Mines (MINEM), through the General Directorate of Hydrocarbons (DGH), signed the contract for the execution of the Special Massification Project – Cusco, with the PA-FARMIN Consortium, winner of the bidding process that began on December 29, 2023.


The Vice Minister of Hydrocarbons of the MINEM, Iris Cárdenas, stated that the massification of natural gas in the regions is a Government policy, and that this process is carried out in a reliable and sustained manner because Peru has the reserves to produce and supply the demand. national.

“It is an honor to be present at this event that marks a milestone for massification in the Cusco region, contributing to sustained economic development, generating new investments and achieving greater social equity, energizing many economic activities,” he said.

During his presentation, Cárdenas presented the achievements obtained by the Energy Social Inclusion Fund (FISE), which has allowed natural gas service to be brought to more than one and a half million homes, 11,600 microenterprises and 2,500 social institutions, representing a 50 percent savings on your usual consumption.

In turn, the general director of Hydrocarbons of the MINEM, Jorge Arnao, highlighted that this portfolio will be in charge of carrying out the studies and environmental impact declaration, the certification of Non-existence of Archaeological Remains, the risk study and emergency response plan, as well as environmental monitoring.

Finally, the regional manager of Energy, Mines and Hydrocarbons of Cusco, Merciano Basilio Peláez, explained details of the project, which consists of the construction of 25.18 km of natural gas networks, including the construction of a Satellite Regasification Plant in the San Jerónimo district and connection pipes for 1,000 families.

The event was held on the land where the LNG Regasification Satellite Plant will be built, located in the Huayllapampa area, San Jerónimo district, with the participation of Mayor Máximo Rimachi and the aforementioned officials.

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Guinea:  ExxonMobil PNG’s Tera Shandro on the next decade of LNG in Papua New Guinea

A decade on from the opening of PNG LNG, Papua New Guinea’s first gas project, ExxonMobil PNG’s Chairperson and Managing Director Tera Shandro reflects on the progress so far and the potential of forthcoming projects such as the K5 billion Angore project and the Wildebeest prospect.


As the single largest business investment in the country, the ExxonMobil-operated PNG LNG project has not only helped forge a new industry that directly and indirectly employs thousands of Papua New Guineans; it has also provided valuable insights into how resource development companies can partner with the country to unlock the possibilities of tomorrow.

Since achieving first gas in 2014, the PNG LNG Project has withstood challenges surrounding market downturns, the devastating 2018 Highlands earthquake, and the global COVID-19 pandemic to build a resilient, industry-leading reputation.

“If successful, Wildebeest has the potential to expand the development window for LNG in the country to 13 years of continuous construction activity.”

PNG LNG routinely produces well above its nameplate, is among the industry’s leaders in energy emissions intensity, and has achieved over 100 million hours of work to deliver more than K24 billion back to the state and its landowners through various tax and royalty streams.

ExxonMobil’s partnership mindset has seen more than K15 billion spent with Papua New Guinean businesses, while a further K1 billion has been invested into strategic community programs that are building the capacity of individuals and community institutions.

Angore Project

Part of the original PNG LNG development plan, the Angore Project’s wells and pipeline represent K5 billion of new investment. Leveraging the existing infrastructure footprint, the Angore resource will be developed and connected to the Hides Gas Conditioning Plant in Hela Province.

As Papua New Guinea’s only significant gas development currently under construction, it is expected to bring on additional gas volumes later this year to supplement the existing PNG LNG gas production.

Using PNG LNG as the guide – combined with growing regional natural gas demand – Papua LNG is primed to build on its success to unlock more direct and indirect benefits for PNG. Currently, ExxonMobil is working alongside its project partners to ensure all key stakeholders are engaged and regulatory permitting is awarded.

Our team is progressing plans to expand infrastructure at our Caution Bay Plant to support the almost 6 million tonnes of gas to be processed per year.

Between the PNG LNG Project marking a decade of production, the start-up of the Angore Project and the Papua LNG project, 2024 is already shaping up to be another defining year. At the same time, teams continue to focus on P’nyang LNG and working with the government to advance other exciting potential developments such as the Wildebeest prospect.

If successful, Wildebeest has the potential to expand the development window for LNG in the country to 13 years of continuous construction activity.

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Natural Gas / LNG Utilization

Norway: Hybrid technology to optimise energy use and cut emissions for Matson Navigation Company’s new LNG-powered container ships

Kongsberg Maritime will supply a comprehensive range of integrated technologies to optimise energy use and reduce emissions for three new 3600 TEU LNG-powered container ships being built at Philly Shipyard for Matson Navigation Company. They are the largest Jones Act containerships ever built, at 260 metres long, and represent a new era in container shipping, according to the company’s release.


To support Matson’s drive to decarbonise its operations, Kongsberg Maritime will supply hybrid electrical systems, controlled and operated by the company’s Energy Management System.

The new ships are being built to operate Matson’s China-Long Beach Express (CLX) service. The Aloha Class vessels are the largest containerships ever built in the U.S. and are designed to operate at speeds in excess of 23 knots in support of Matson’s service hallmark – timely delivery of goods.

The Kongsberg Maritime scope of supply includes a Shaft Generator System, and a Battery Energy Saving System combined with a complete power management system. The hybrid electrical systems will provide electrical power to the vessel’s main switchboard through the Kongsberg converters.

Kongsberg Maritime will also supply rotary vane steering gear and control systems, together with a full package of monitoring, automation and control systems for the LNG fuel gas supply control and safety systems, tank gauging and instrumentation.

All systems on this extensive package, including the vessels’ propulsion control and power management, will all be linked to the K-Chief Integrated Automation System from Kongsberg.

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China: CSSC to build 18 LNG tankers for QatarEnergy

China State Shipbuilding Corp. (CSSC) has signed a contract for 18 super-heavy LNG tankers with QatarEnergy at a signing ceremony in Beijing. The 18 ultra-large LNG carriers are in the Q-Max class. They have been designed by Hudong-Zhonghua Shipbuilding, a CSSC subsidiary in Shanghai. After the signing of the contract, the Shanghai shipyard will start building those vessels.


Each of the QatarEnergy carriers will be 344 m long, 53.6 m wide and will have a draft of 12 m. It will be able to contain 271 000 m3 of LNG, about 57% more than regular LNG carriers with maximum capacity of 174 000 m3.

One of such carriers can transport 155 million m3 of natural gas at a time, which can meet the gas consumption demand of 4.7 million households in Shanghai for one month.

For more news and technical articles from the global renewable industry, read the latest issue of Energy Global magazine.

Energy Global’s Spring 2024 issue

The Spring 2024 issue of Energy Global starts with a guest comment from Field on how battery storage sites can serve as a viable solution to curtailed energy, before moving on to a regional report from Théodore Reed-Martin, Editorial Assistant, Energy Global, looking at the state of renewables in Europe. This issue also hosts an array of technical articles on electrical infrastructure, turbine and blade monitoring, battery storage technology, coatings, and more.

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Italy: HAM Italia inaugurate first LNG-CNG refuelling station in Italy

HAM Italia and the HAM Group have inaugurated the first EDUX LNG-CNG refuel-ling station in Italy, located in Via del Camposanto, in front of the ‘Stagnoni’ access to the Port of La Spezia, exit Lerici-Porto on the A12-A15 motorway.


This new HAM EDUX filling station joins the extensive network of filling stations offered by HAM Italia, which currently has more than 40 filling stations. Its customers will be able to refuel LNG (two hoses) for trucks and heavy vehicles, as well as CNG (two hoses) for cars, light vehicles, and trucks. Refuelling can be done with the HAM/Rati Carburanti/DKV/UTA/On Turtle Card for professional use or with a bank credit/debit card.

HAM Italia EDUX Porto di La Spezia is a mobile and transportable LNG and CNG refuelling station, characterised by a fast installation and start-up in less than 24 hours. The gas station is managed remotely to guarantee its correct operation, it is open 24/7 and has a year-round telephone service to resolve any incidents.

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Canada: Lower costs for natural gas, shipping and liquefaction give Canada an edge in the emerging global LNG market

Construction workers look on at the FortisBC Tilbury LNG expansion project in Delta, B.C., Monday, Nov. 16, 2015.  Worldwide concerns about energy security have put a renewed focus on the international liquefied natural gas (LNG) industry. The global demand for LNG is expected to increase over the next few decades.


Global demand growth will be driven primarily by Asian markets where the need for LNG is expected to increase from 277 million tonnes (MT) in 2025 to 509 MT by 2050 (see Figure 1). By 2050 the demand for LNG in Europe will be 83 MT and in Africa 20 MT. In South America too, demand will increase – from 13 MT in 2025 to 31 MT in 2050.

In North America (Canada, Mexico, and United States) a number of LNG projects that are either under construction or in the planning stages will benefit from the rise in global LNG demand.

North American LNG production is expected to grow from 112 MT in 2025 to over 255 MT by 2050 (see Figure 2). In Canada, the LNG projects under construction or in the planning stages include LNG Canada Phases 1 & 2, Woodfibre LNG, Cedar LNG, the Tilbury LNG expansion, and Ksi Lisims LNG. Canada’s LNG production is expected to grow from just 2 MT in 2025 to over 43 MT by 2050. In the United States production is projected to increase from 108 MT in 2025 to 210 MT in 2050.

This CEC Fact Sheet uses Rystad Energy’s Gas and LNG Markets Solution¹ to benchmark the cost competitiveness of LNG projects that are under construction and proposed in Canada compared to other LNG projects under construction and planned elsewhere in North America. (Note that the content of this report does not represent the views of Rystad Energy.)

The LNG cost competitiveness benchmarking analysis used the following performance metrics:

LNG plant free-on-board (FOB) cost break-even;

Total LNG plant cost (for delivery into Asia and Europe).

The objective of this LNG cost competitiveness benchmarking is to compare the competitiveness of Canadian LNG projects against those of major competitors in the United States and Mexico. The selection of other North American LNG facilities for the benchmark comparison with Canadian LNG projects (LNG Canada, the Tilbury LNG Expansion, Woodfibre LNG, Cedar LNG, and Ksi Lisims LNG) is based on the rationale that virtually all Canadian LNG plants are under construction or in the planning stage and that they compare well with other North American LNG plants that are also under construction or are being planned between 2023 and 2050. Further, to assess the cost competitiveness of the various LNG projects more accurately, we chose only North American LNG facilities with sufficient economic data to enable such a comparison. We compared the cost competitiveness of LNG coming from these other North American projects with LNG coming from Canada that is intended to be delivered to markets in Asia and Europe.

Comparison of LNG project FOB cost break-even (full cycle)

Figure 3 provides a comparison of the free-on-board (FOB) cost break-even for LNG facilities under construction or being planned in North America. FOB break-even costs include upstream and midstream costs for LNG excluding transportation costs (shipping) as seen from the current year. Break-even prices assume a discount rate of 10 percent and represent the point at which the net present value for an LNG project over a 20- to 30-year period becomes positive, including the payment of capital and operating costs, inclusive of taxes.

Among the selected group of North American LNG projects are Canadian LNG projects with an FOB break-even at the lower end of the range (US$7.18 per thousand cubic feet (kcf)) to those at the higher end (US$8.64 per thousand cubic feet (kcf)).

LNG projects in the United States tend to settle in the middle of the pack, with FOB break-even between US$6.44 per kcf and US$8.37 per kcf.

Mexico LNG projects have the widest variation in costs among the selected group of projects, ranging from US$6.94 per kcf to US$9.44 per kcf (see Figure 3).

Total costs by project for LNG delivery to Asia and Europe

The total cost by LNG plant includes FOB cost break-even, transportation costs, and the regasification tariff. Figure 4 compares total project costs for LNG destined for Asia from selected North American LNG facilities.

Canadian LNG projects are very cost competitive, and those with Asia as their intended market tend to cluster at the lower end of the scale. The costs vary by project, but range between US$8.10 per kcf and US$9.56 per kcf, making Canadian LNG projects among the lowest cost projects in North America.

The costs for Mexico’s LNG projects with Asia as the intended destination for their product tend to cluster in the middle of the pack. Costs among U.S. LNG facilities that plan to send their product to Asia tend to sit at the higher end of the scale, at between US$8.90 and US$10.80 per kcf.

Figure 5 compares total project costs for LNG to be delivered to Europe from select North American LNG facilities.

Costs from U.S. LNG facilities show the widest variation for this market at between US$7.48 per kcf and US$9.42 per kcf, but the majority of U.S. LNG facilities tend to cluster at the lower end of the cost scale, between US$7.48 per kcf and US$8.61 per kcf (see Figure 5).

Canadian projects that intend to deliver LNG to Europe show a variety of costs that tend to cluster at the middle to higher end of the spectrum, ranging from US$9.60 per kcf to and US$11.06 per kcf.

The costs of Mexico’s projects that are aimed at delivering LNG to Europe tend to cluster in the middle of the spectrum (US$9.11 per kcf to US$10.61 per kcf).


LNG markets are complex. Each project is unique and presents its own challenges. The future of Canadian LNG projects depends upon the overall demand and supply in the global LNG market. As the demand for LNG increases in the next decades, the world will be searching for energy security.

The lower liquefaction and shipping costs coupled with the lower cost of the natural gas itself in Western Canada translate into lower prices for Canadian LNG, particularly that destined for Asian markets. Those advantages will help make Canadian LNG very competitive and attractive to markets worldwide.

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Bulgaria: Bulgargaz launched a tender procedure for the supply of liquefied natural gas for June

Among the conditions for participation in the procedure is that the source of natural gas supply is from countries without imposed sanctions, embargoes, or any trade restrictions


“Bulgargaz“ EAD has launched a tender procedure for the supply of 1,000,000 MWh of liquefied natural gas (LNG) in June 2024, the company’s press center announced, FOCUS reported.

Among the conditions for participation in the procedure is that the source of supply of natural gas is from countries without imposed sanctions, embargoes, or any trade restrictions. The ownership of the companies must be clear and they must be of good commercial standing.

The delivery of the liquefied natural gas will be carried out at an LNG terminal in the Republic of Turkey, according to the agreement concluded with the Turkish state company BOTAS.

Companies must express an interest in participating and declare that they comply with

qualification conditions. Participants admitted to the tender procedure must submit price proposals referring to the TTF index, which will be evaluated and ranked according to the Evaluation Methodology attached to the tender documents.

The price proposals of the admitted candidates will be opened on 14.05.2024

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Japan: Japan’s Mitsui O.S.K begins operations at its Indonesian gas power plant

Japanese transport company Mitsui O.S.K Lines (MOL) has begun commercial operations at its FSRU, which will supply LNG to a power plant in West Java, Indonesia.


A FSRU is a type of shipping vessel or offshore installation used to move and transfer LNG through ocean channels. FSRUs receive and store LNG at around -160°C at sea, then heat and re-gasify it as it is required. It is delivered as high-pressure gas to an onshore pipeline and pumped into power plants. They are sometimes preferred because they can be installed at a relatively low cost and in a shorter period of time compared with an onshore LNG terminal

The project is Asia’s first ever gas-to-power project using an FSRU, the company said in a press statement on Friday. Operations officially began on 29 March, MOL added.

The unit, called Jawa Satu, will receive LNG for power generation from LNG carriers via ship-to-ship transfer, store it, re-gasify it and supply it to the 1.76GW PT Jawa Satu 1 power plant in Cilamaya, West Java, Indonesia.

Electricity generated at the power plant, which also began first operations on 29 March, will be supplied to PT Pertamina (Persero), Indonesia’s state-owned electricity company, for the next 25 years, MOL said.

MOL owns the Jawa Satu 1 power plant through a joint venture between Persero, Japanese trading house Marubeni Corporation and Japanese conglomerate Sojitz Corporation, as well as other partners. The Jawa Satu FSRU is also jointly owned by MOL, Persero, Marubeni, Sojitz and others.

The Jawa Satu project was first announced in 2018. It is co-financed by the Asia Development Bank, Crédit Agricole Corporate and Investment Bank, Japan Bank for International Cooperation, Mizuho Bank, MUFG Bank, Oversea Chinese Banking Corporation and Societe Generale Bank & Trust. Financing of private financial institutions is insured by Nippon Export and Investment Insurance.

“Japan’s Mitsui O.S.K begins operations at its Indonesian gas power plant” was originally created and published by Offshore Technology, a GlobalData owned brand.

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German: EnBW and ADNOC agreed on the supply of low-carbon LNG

Germany’s Energie Baden-Württemberg AG (EnBW) has agreed with the Abu Dhabi National Oil Company (ADNOC) to purchase low-carbon liquefied natural gas (LNG) on a long-term basis, Azernews reports.


“EnBW has signed a contract with ADNOC for the purchase of LNG for a period of 15 years. The Emirati company will annually supply 0.6 million tons of LNG to EnBW after the planned commissioning of the Ruwais LNG plant in 2028,” the statement said.

Ruwais LNG with a total capacity of 9.6 million tons per year will be the first liquefied natural gas plant in the Middle East to meet its electricity needs from low-carbon sources.

With over 28,000 employees, EnBW is one of the largest energy supply companies in Germany and Europe.

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Global LNG Development

Turkey: Turkmenistan’s natural gas exports to China outearn Russia’s supplies

Turkmen gas boss announces major new development project. Russia’s energy behemoth Gazprom announced with great fanfare in early 2024 that it had overtaken Turkmenistan as China’s largest supplier of natural gas in terms of volume. But when it comes to export earnings, Ashgabat still tops Moscow.


The Turkmen portal, Oil & Gas, reports that during the first quarter of this year, Ashgabat generated $2.4 billion in income from gas exports to China. That figure was confirmed by Daryo, Uzbekistan’s most popular news website. The Daryo report noted that Russia earned $2 billion from its gas sales to Beijing during the same period.

The reason for the volume-earnings differential is that China is hoovering up Russian gas at bargain basement prices. The Kremlin’s need for cash to keep the country afloat while maintaining its war effort in Ukraine has deprived Russia of most of its negotiating leverage in its dealings with Beijing.

Russia’s edge in export volume may last only as long as the steep pricing discounts continue. An independent outlet, The Chronicle of Turkmenistan, reported that the capacity of Russia’s Power of Siberia gas pipeline to China is projected to be 38 billion cubic meters (bcm) in 2025. Meanwhile, the collective capacity of three pipelines connecting Turkmenistan and China totals 55 bcm.

Turkmen state-affiliated media outlets have cast some shade on the Kremlin’s exports: in reports about Ashgabat’s gas earnings from China they have omitted mention of Russia. For example, in addition to Turkmenistan, a report published by Turkmenportal names only Australia ($3.6 billion), Qatar ($3.1 billion) and Malaysia ($1.15 billion) as key suppliers, mainly with liquefied natural gas. 

Meanwhile, the head of Turkmengaz, Maksat Babayev, has announced plans to develop what he described as the “world’s largest gas field” at Galkynysh. The first stage of development already “stably ensures the export of 30 bcm of gas per year to China,” the second stage will bring another 25 bcm of gas per year online. A third phase of development can supply the long-planned Turkmenistan-Afghanistan-Pakistan-India (TAPI) pipeline project with a projected capacity of capacity of 33 bcm, according to Turkmenportal.


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Canada: Canada can reduce global emissions and boost the economy by exporting LNG to Asia

Pierre Poilievre‘s Axe the (carbon) Tax campaign is a spectacular success. But the Conservative party needs its own plan to reduce fossil fuel emissions. Paradoxically, it’s a fossil fuel that provides the answer.


Canada’s rich endowment of natural gas offers us the chance to both reduce global emissions and also rescue a Canadian economy ravaged by the Trudeau government. How? By exporting liquefied natural gas (LNG) to China, Japan, South Korea and other coal-dependent Asia-Pacific countries. Switching from coal to natural gas reduces CO2 emissions by 50 percent while also eliminating the toxic compounds and lung-clogging particulates that shorten the lives of millions living in smog-stricken Asian cities.

A November 2022 study by respected consulting firm Wood Mackenzie concluded that:

Canada is well-positioned geographically: Western Canadian LNG is much closer to Asia relative to U.S. Gulf Coast LNG, which needs to be shipped to Asia through the Panama Canal to get to Asia.

LNG from Canada would be cost-competitive for northeast Asian importers … due to its relatively low shipping and liquefaction costs.

LNG from Canada has a lower intensity of emissions than LNG from many other global LNG exporters.

Asia will not be able to produce enough natural gas domestically to meet its escalating demand. With its high environmental standards and stewardship, Canada would be a great partner to fill the LNG demand gap in Asia.

If Canada aggressively ramps up its LNG exports, the emissions displaced would total 5.5 (billion tonnes of carbon dioxide) from 2022 to 2050 … the equivalent of removing all Canadian cars from the road.

In 2010, there were more than 20 LNG projects in the works in British Columbia, representing hundreds of billions in total investment. These included Exxon Mobil’s $25-billion West Coast Canada project, Chinese-owned CNOOC’s $36-billion Aurora project, Malaysian firm Petronas’s $36-billion Pacific Northwest project and the Shell-led $31-billion Kitimat LNG Canada project. After a decade of trying to navigate Canada’s byzantine regulatory process, LNG Canada is the only one left standing. And it succeeded only because South African project leader Andy Calitz refused to give up.

After five years of construction, the LNG Canada terminal is nearing completion, with the first ship scheduled to sail to China in mid-2025. The $31 billion invested in the Kitimat liquefaction plant is just one component of Canada’s first LNG export project. TC Energy Corp’s $15-billion Coastal GasLink will carry natural gas from the northeastern B.C. gas fields to the Kitimat terminal. In addition, hundreds of millions of dollars have been invested in natural gas wells and field production systems.

The economic benefits are myriad. B.C. natural gas royalties are forecast to double, from $700 million in 2024 to $1.4 billion in 2027. There are significant employment and business opportunities for First Nations, including Haisla Marine’s 50 percent interest in a $500-million contract.

That’s just LNG Canada Phase 1. Construction of another 14 million tonnes per year LNG Canada Phase 2 is scheduled to begin in 2026, with first delivery in 2032. A report from Canada Action estimates that completion of both phases of LNG Canada alone is equivalent to removing 18 million cars from Canadian roads.

A major barrier for LNG project sponsors has been the fixation of Canadian regulators on the project’s domestic emissions, which are minuscule compared to the global emissions reductions they make possible. Rather than let the project use on-site natural gas-powered electricity generation, regulators insisted that LNG Canada use zero-emissions hydropower. Having BC Hydro build a new dam and costly new transmission line delayed the project significantly.

Before COP24, the UN Climate Change Conference in Katowice, Poland, in 2018, the federal Conservatives urged the leaders of the Canadian delegation to propose that national emissions reductions include reductions from displacement of coal with exported LNG. Prime Minister Trudeau and his team of anti-fossil fuel eco-zealots declined this advice. A new government that encourages LNG projects may well see a return of the Exxon-Mobil, CNOOC and Petronas projects driven off by government intransigence.

As an alternative to the carbon tax, LNG export not only does better in emissions reduction but also creates tens of billions of dollars in economic benefits for a beleaguered Canadian private sector. Stepped-up LNG export is a vastly superior environmental alternative to the economically destructive and politically divisive carbon tax, and it would help reverse a proud, thriving nation’s decline into an indebted, unproductive, government-dominated basket case.


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Canada: Woodfibre LNG project confident it will move forward despite Pacific Northwest setback

Despite the announcement this week that Petronas’ Pacific Northwest LNG megaproject is no longer going forward, the vice president of the Woodfibre LNG project near Squamish, B.C., is confident its project will still go through.


The $1.6 billion Woodfibre LNG project — located at an old pulp mill — will process natural gas shipped by pipeline from Northern B.C. into liquified natural gas for export.

The project received federal and First Nations environmental approval last year and was awarded a 40-year natural gas export licence by the federal government last month. The project is expected to be completed by 2020.

But with the withdrawal of Petronas from B.C.’s flagship LNG megaproject in Port Edward, the future of the province’s LNG industry is uncertain.

Different challenges

Byng Giraud, the country manager and vice president of corporate affairs for Woodfibre LNG, says their Squamish project is different.

For one, he says, it’s much smaller than the Pacific Northwest project. And due to existing infrastructure — including a deep sea port — it doesn’t face the same construction challenges as the northern projects.

“We have an industrial site so we’re not creating something new. We have a pipeline that already passes right through the site. B.C. Hydro lines pass right through the site,” he said.

Furthermore, Giraud says Woodfibre has an existing export relationship with the Guangdong province of China — B.C.’s sister province — and he says there are import facilities under construction there.

“We see this project moving forward,” he said.

NDP support

As for politics, Giraud dismissed the idea the new NDP government was hostile to the LNG industry.

“I don’t see the current government as a hurdle. I see them as a different government and we’re going to have to adapt,” he said.

“And to be fair to the new premier, he actually did recognize we were meeting those conditions.”

Premier John Horgan had supported the project during the election campaign.

Woodfibre LNG is the currently the only B.C. LNG project to receive a final investment decision.

With files from The Early Edition

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US: Start-up of three LNG projects paving the way for rise in US natural gas trade

The U.S. Energy Information Administration (EIA), the statistical and analytical agency within the U.S. Department of Energy, is anticipating further growth in natural gas trade, thanks to three new liquefied natural gas (LNG) export projects, which are slated to come online by the end of next year.


Based on EIA’s Short-Term Energy Outlook (STEO), the LNG exports will continue to spearhead growth in U.S. natural gas trade as three LNG export projects currently under construction begin operations and ramp-up to full production by the end of 2025 while increased natural gas exports by pipeline, mainly to Mexico, are also expected.

The forecast indicates that net exports of U.S. natural gas – exports minus imports – will grow 6% to 13.6 billion cubic feet per day (Bcf/d) in 2024, compared with 2023, while a boost of another 20% to 16.4 Bcf/d is on the cards for 2025.

Furthermore, U.S. LNG exports are estimated to be on the rise, going up by 2% in 2024 to an average of 12.2 Bcf/d and an additional 18% in 2025, reaching 2.1 Bcf/d. In addition, U.S. natural gas exports by pipeline are set to grow by 3% or 0.3 Bcf/d in 2024 and by 4% in 2025. However, pipeline imports are expected to decline by 0.4 Bcf/d in 2024 and increase slightly by 0.1 Bcf/d in 2025.

During the 2024–25 period, EIA predicts that existing U.S. LNG export facilities will run at similar utilization rates as in 2023, since annual maintenance typically occurs in the spring and fall when global LNG demand is lower and temperatures are mild. In May 2024, LNG exports are forecasted to take a downturn while two of the three trains at the Freeport LNG export facility undergo annual maintenance.

Moreover, Plaquemines LNG Phase I and Corpus Christi Stage 3 are scheduled to kick off LNG production later in 2024 and load the first cargoes by the end of the year. The developers of Golden Pass LNG plan to place in service the first two trains of this new three-train LNG export facility next year.

The U.S. Energy Information Administration is predicting an increase in U.S. natural gas pipeline exports to Mexico as several pipelines in the country – Tula-Villa de ReyesTuxpan-Tula, and Cuxtal Phase II connecting to the Energía Mayakan pipeline on the Yucatán Peninsula – become fully operational in 2024–25.

While these pipelines started partial service in 2022–23, they have not been operating at full capacity. In addition, flows via the Sur de Texas-Tuxpan underwater pipeline are likely to increase slightly in 2024 when it begins delivering natural gas from the United States to Mexico’s first LNG export project, Fast LNG Altamira.

Even though U.S. natural gas pipeline imports from Canada remained relatively unchanged over the last two years, averaging 8.1 Bcf/d, the EIA expects pipeline imports from Canada to remain a key supply source, particularly for the U.S. Midwest region during winter months.


According to the U.S. agency, U.S. LNG imports, which primarily serve New England and generally peak in winter months, fell slightly in 2023, mainly because of record-warm winter weather. EIA predicts that LNG imports will average about 0.1 Bcf/d in 2024–25 and continue to serve as a marginal supply source during periods of high demand, particularly in the winter months.’s%20Short%2DTerm,pipeline%2C%20mainly%20to%20Mexico%2C%20are

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Japan: MOL’s LNG carrier fleet to grow to 104 vessels by March 2025

TOKYO : Japan’s shipping giant MOL expects its huge fleet of liquefied natural gas (LNG) carriers to increase to 104 vessels by March 31, 2025. MOL revealed this in its first quarter report released this week.


This includes LNG carriers owned and/or operated by joint venture companies. According to MOL, the firm had 94 LNG carriers in its fleet in the first quarter of 2023 and 97 LNG carriers in the first quarter of this year. MOL also previously said that it has more than 30 LNG carriers on order. As of March 31, 2024 MOL’s fleet also included five FSUs/FSRUs, three LNG bunkering vessels, one LNG powership, six ethane carriers, and 20 LPG/ammonia ships. MOL has also a set a target to operate 90 LNG-powered and methanol-fueled vessels by 2030

LNG earnings “stable”

MOL reported a revenue of 1,627.9 billion yen in fiscal 2023, up from the year before, while operating profit of 103.1 billion yen and net income of 261.6 billion yen dropped compared to the year before. The company’s energy business, which includes the liquefied gas segment, reported revenue of 437.8 billion yen and profit of 66.9 billion yen, both up compared to the year before. MOL said its LNG carrier business “secured stable profit, mostly unchanged year-on year, due to existing long-term charter contracts and the acquisition of new contracts.” Within the LNG infrastructure business, the FSRU business posted a year-onyear decline in profit “as a result of the redeployment of an existing vessel and preparations to commence commercial operation.” MOL said the LNG-to-powership business reported “stable” profit. During the fiscal year from April 1, 2024 to March 31, 2025, MOL expects the LNG carrier business to “maintain stable profit by fulfilling existing long-term contracts and with the profit contribution of new projects.” The LNG infrastructure business is expected to achieve profit growth, mainly due to the impact of contract renewals for existing projects, it said.

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Italy: Gunvor signs deal with LNEnergy for Italian LNG supply 

LNEnergy’s proposed plant, located at the Colle Santo onshore gas field, will supply Gunvor with approximately 44,000 tonnes (t) of liquefied natural gas (LNG) annually. 

Switzerland-based energy trader Gunvor has entered into a non-binding agreement to procure LNG from LNEnergy’s proposed facility in Italy.  


The LNG production plant, located at the Colle Santo onshore gas field, will supply Gunvor with approximately 44,000t of LNG annually for a minimum of five years. 

UK-based Reabold Resources, which holds a 26.1% stake in LNEnergy, announced the heads of agreement (HoA), outlining the terms for the LNG purchase.  

LNEnergy holds the exclusive right to acquire a 90% stake in the Colle Santo gas field. 

According to GlobalData, the Colle Santo project is expected to start production in 2025 and reach its peak in 2028.

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Abu Dhabi: ADNOC signs third long-term Heads of Agreement for Ruwais LNG project

ABU DHABI – ADNOC announced today the signing of a 15-year Heads of Agreement (LNG agreement) with EnBW Energie Baden-Württemberg AG (EnBW), one of the largest energy companies in Germany, for the delivery of 0.6 million metric tonnes per annum (mmtpa) of liquefied natural gas (LNG).


The LNG will primarily be sourced from ADNOC’s lower-carbon Ruwais LNG project, currently under development in Al Ruwais Industrial City, Abu Dhabi.

The Ruwais LNG plant is set to be the first LNG export facility in the Middle East and Africa region to run on clean power and will leverage the latest technologies and artificial intelligence (AI) tools to minimise emissions and drive efficiency.

This agreement marks the third long-term LNG supply agreement from the project. The deliveries are expected to start in 2028, upon commencement of commercial operations.

Fatema Al Nuaimi, ADNOC Executive Vice President of Downstream Business Management, said, “The Ruwais LNG project continues to gain momentum, reinforcing ADNOC’s position as a reliable global natural gas provider. This new agreement builds on the UAE-Germany Energy Security and Industry Accelerator and will support Germany as it strives to diversify its energy sources and enhance its energy security.”

The UAE-Germany Energy Security and Industry Accelerator (ESIA), signed in 2022, aims to advance cooperation in energy security, decarbonisation and lower-carbon fuels.

Peter Heydecker, EnBW’s Board Member for Sustainable Generation Infrastructure, said, “We are delighted that EnBW has signed its first LNG contract in the Middle East with our experienced partner ADNOC. In doing so, we are taking the next step in terms of diversifying our procurement portfolio and establishing our own LNG value chain. We can also use the experience gained here for our medium-term goal of establishing an import structure for green gases, since the two business fields are very similar.”

The LNG agreement is contingent upon a final investment decision (FID) on the project, including regulatory approvals and the negotiation of a definitive Sale and Purchase Agreement between the two companies.

When completed, the project, which consists of two 4.8 mmtpa LNG liquefaction trains with a total capacity of 9.6 mmtpa, will more than double ADNOC’s LNG production capacity to around 15mmtpa.

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Singapore: TotalEnergies inks 16-year LNG deal with Sembcorp Fuels

The new deal extends the existing agreement between the two companies until 2029. TotalEnergies has signed a sale and purchase agreement (SPA) with Sembcorp Fuels, a subsidiary of Sembcorp Industries, to provide up to 0.8 million tons of liquefied natural gas (LNG) annually for 16 years, starting in 2027


Under the agreement, TotalEnergies will source LNG from its global portfolio to meet Sembcorp’s demand. 

The new deal extends the existing SPA between the two companies until 2029.

The companies expect the agreement to contribute to Singapore’s energy security and decarbonization goals whilst also reflecting TotalEnergies’ commitment to sustainability.

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Egypt: Egypt’s EGAS to rent Norway’s Hoegh LNG floating unit

The floating storage and regasification unit will be leased “to secure additional needs for domestic consumption during the summer,” the ministry said CAIRO – Egypt’s Natural Gas Holding Company (EGAS) has struck an agreement with Norway’s Hoegh LNG to rent the Hoegh Galleon floating unit for liquefied natural gas, the Egyptian petroleum ministry said on Thursday.


The floating storage and regasification unit will be leased “to secure additional needs for domestic consumption during the summer,” the ministry said in a statement.

Egypt is expected to ramp up LNG imports during the summer months to meet heavy demand that had led to a wave of rolling blackouts last summer, shocking Egyptians who had grown used to a decade of reliable power supplies by the gas producer.

The government bought at least two LNG cargoes in April and is expected to purchase up to 20 over the spring and summer to prepare for increasing power demand, sources had told Reuters.

Returning to imports would reverse the most populous Arab country’s position as a natural gas exporter in recent years.

The North African country, which faces growing demand for gas from its population of 106 million, has been seeking a regional supply role but has made few large discoveries since the giant Zohr field in 2015.

In 2023, Egypt’s total natural gas production fell 11.5% year-on-year to around 59.29 billion cubic meters (bcm), the lowest production level since 2017, figures from the Joint Organisations Data Initiative (JODI) show.

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Morocco: Shell to supply Morocco with LNG in 12-year deal

RABAT (Reuters) – Shell will supply Morocco with an annual 0.5 billion cubic metres (bcm) of liquefied natural gas (LNG) under a 12-year deal, the North African country’s energy ministry said on Friday. The deal was signed by electricity and water utility ONEE and Shell, a ministry statement said without disclosing financial terms of the transaction


The gas will be transported from Spanish ports initially, using a gas pipeline that links the two countries, until Morocco builds its own LNG terminals, the ministry said.

The LNG will help ONEE operate two power stations in northern and eastern Morocco that used to operate on Algerian gas sent through the same pipeline.

Algeria unilaterally decided in 2021 to halt gas flows to Spain via Morocco through the pipeline. Rabat said it would reverse the flow in 2021 by importing LNG from Spanish terminals.

ONEE is aiming to increase the share of gas in Morocco’s electricity mix to meet low-carbon goals, the ministry said.

Renewables represented 18% of Morocco’s total electricity production last year while gas accounted for only 1.6% and coal 72%, official figures show.

By March 2023 renewable energy represented 40% of the country’s installed capacity, with Morocco planning to increase that to 52% by 2030.

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Qatar: QatarEnergy and Nakilat shake hands on deal for 9 largest LNG vessels ever built

As part of its massive shipbuilding program, Qatar’s state-owned energy giant QatarEnergy has entered into a long-term agreement with Qatar Gas Transport Company Limited (Nakilat), the country’s shipping and maritime player, for the charter and operation of nine ultra-modern QC-Max size liquefied natural gas (LNG) vessels, which are said to be the largest LNG ships ever built.


With a capacity of 271,000 cubic meters each, these nine QC-Max vessels constitute half of the 18 advanced QC-Max class LNG vessels that will be constructed at China’s Hudong-Zhonghua Shipyard, thanks to a $6 billion contract, which the Qatari heavyweight signed with China State Shipbuilding Corporation (CSSC).

These vessels, which will adopt a dual-fuel low-speed engine propulsion system and the NO96 Super+ containment system, will come with a total length of 344 meters, a beam of 53.6 meters, a depth of 27.2 meters, and a designed draft of 12 meters

The deal with Nakilat was penned on May 8 by Saad Sherida Al-Kaabi, Qatar’s Minister of State for Energy Affairs, President and CEO of QatarEnergy, and Abdullah Al-Sulaiti, CEO of Nakilat, at QatarEnergy’s headquarters in Doha. The signing ceremony was attended by senior executives from QatarEnergy, QatarEnergy LNG, and Nakilat.

Commenting on this occasion, Al-Kaabi noted: “We are very proud to have Qatar’s flagship LNG shipping and maritime champion join a list of world-class shipowners operating our state-of-the-art QC-Max LNG vessels – the largest ever built. There is no doubt that this is another testament to Nakilat’s significant capabilities.”

While the first stage of the Qatari player’s historic LNG shipbuilding program was kicked off with the order of 60 vessels at Korean and Chinese shipyards, the start of the company’s second phase of the mega shipbuilding program came in September 2023, when an order was placed for the construction of 17 LNG carriers. The firm also picked Nakilat to own and operate up to 25 conventional-size LNG carriers under the TCP agreements from March 2024.

Signing ceremony for nine LNG vessels with Nakilat; Source: QatarEnergy

QatarEnergy’s fleet expansion program has encompassed the execution of shipbuilding contracts and time charter agreements for 104 conventional LNG vessels and 18 QC-Max class LNG ships so far, amounting to a total of 122 ultra-modern vessels, with the first new ship expected to be delivered by the end of the third quarter of 2024.

“With last month’s signing of the industry’s largest single shipbuilding contract ever, QatarEnergy is pushing ahead with the implementation of its historic LNG vessel expansion program with full confidence that Nakilat and our selected international shipowners will ensure that our fleet is operated to the highest and most advanced safety, technical and environmental standards,” concluded Al-Kaabi.

The Persian Gulf state’s energy giant has put the wheels in motion to increase its gas reserves by adding another expansion project to its arsenal at the North Field, thus, the North Field East (NFE) and the North Field South (NFS) undertakings will be joined by the North Field West (NFW) project, which is anticipated to scale up the country’s LNG production capacity by almost 85% from current production levels by 2030.

The Qatari heavyweight is also determined to up its oil production ante at the country’s largest offshore oil field by about 100,000 barrels per day. To this end, the firm handed out four multibillion-dollar engineering, procurement, construction, and installation (EPCI) contract packages to multiple players, including McDermott, HD Hyundai Heavy Industries, Larsen & Toubro, and China Offshore Oil Engineering (COOEC).

QatarEnergy’s plans to step up its oil and gas production game align with Al-Kaabi’s view that employing a balancing act between energy security, affordability, and sustainability will allow countries around the globe to propel the energy transition journey forward.

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LNG as a Marine Fuel/Shipping

Bangladesh: Bangladesh to import 5 spot LNG cargoes in June

Bangladesh will import five spot liquefied natural gas (LNG) cargoes in June similar to those in May to meet the mounting natural gas demand in the current summer. State-run Rupantarita Prakritik Gas Company Ltd (RPGCL) already floated tenders last week to purchase three spot LNG cargoes for June deliveries, a senior RPGCL official told the FE on Monday.


Bid winning LNG suppliers will deliver the spot LNG cargoes during June 7-8, June 11-12 and May 18-19 delivery windows, he said.

The RPGCL will float tenders to purchase two more spot LNG cargoes in June.

Apart from five three spot LNG cargoes, Bangladesh has planned to import half a dozen LNG cargoes from two long term suppliers – QatarEnergy and OQ Trading- in June to meet the demand of natural gas.

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

All the five spot LNG cargoes will be supplied on Moheshkhali Island, with option to discharge the cargos at either of the country’s two floating storage re-gasification units (FSRUs), said the official.

The volume of LNG in each of the cargoes will be around 3.36 million British Thermal units (MMBtu).

The government has a plan to import 34 LNG cargoes from spot market during 2024 compared to the last year’s 23, said a senior Petrobangla official.

Of the total spot LNG cargoes, 23 are to be imported by June and 11 more during the July-December period.

Russia: Gazprom makes second delivery of LNG to Spain

Russia’s state-run energy company, Gazprom, has delivered its second shipment of LNG from its small-scale Portovaya LNG plant on the Baltic Sea to Spain, according to Reuters analysis of shipping data.


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LNG exports from Russia have not been under Western sanctions, unlike oil exports. According to analysis by Urgewald, a German non-profit environmental research organisation, Russian LNG is regularly transported to Belgium, France, the Netherlands and Spain. In 2023, the EU imported 31 million tonnes (mt) of Russian LNG, but in December imports reached their monthly record of 3.2mt

However, the EU has implemented measures in an attempt to stem the flow. Last week, the European Parliament passed rules that allow governments to ban Russian LNG imports by preventing Russian companies from booking gas infrastructure capacity. France, Spain and Belgium have not yet confirmed whether they will use the new law.

According to Reuters, a spokesperson for Spain’s energy ministry said the country supports the common EU position on banning Russian LNG, as Russian companies could avert a Spain-only ban by sending their fuel to other EU ports.

Nevertheless, data showed that a tanker known as the Cool Rover, which loaded LNG ship-to-ship from the floating storage and regasification unit, the Marshal Vasilkevskiy, discharged at the BBG LNG terminal in the Spanish port town of Bilbao.

Last month Gazprom made its first shipment of LNG from Portovaya to Spain.

Since the outbreak of the war in Ukraine in 2022, Gazprom’s exports of gas to Europe through pipelines has dropped significantly, draining Moscow of a key source of revenue. Last year, Russia supplied just 28.3 billion cubic metres (bcm) of gas to Europe via pipelines, down from 63.8bcm in 2022 and 148bcm in 2021.

To establish alternative customers, Russia has been developing the Arctic LNG 2 project with China.

“Gazprom makes second delivery of LNG to Spain” was originally created and published by Offshore Technology, a GlobalData owned brand.

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US: Pacific Energy in talks for LNG cargoes from US Gulf Coast projects

These discussions are focused on super-chilled gas from Tellurian’s Driftwood LNG project in Louisiana and NextDecade’s Rio Grande terminal in Texas.  

Pacific Energy is in negotiations with Tellurian and NextDecade for LNG cargoes from their proposed export terminals along the US Gulf Coast, reported Bloomberg, citing sources.   


Pacific Energy, a unit of Singapore-based Royal Golden Eagle, is developing the Woodfibre LNG project in Canada, which aims to produce around 2.1 million tonnes of LNG annually, with storage capacity of 250,000m³ and necessary export facilities.  

Additionally, it has a presence in Canada’s Montney Basin through Pacific Canbriam Energy, which specialises in liquids-rich natural gas production, and holds a 25% stake in the Jiangsu Rudong LNG terminal in China. 

A NextDecade representative said the company refrained from commenting “on rumors or speculation”, and Tellurian did not respond to requests seeking comments.  

For Pacific Energy, spokesperson John Morgan said: “We do not comment upon market speculation,” the publication said. The first phase of NextDecade’s Rio Grande LNG project is currently under construction near Brownsville, Texas. 

Conversely, Tellurian’s Driftwood LNG project has struggled to secure the necessary financial support.  

In February, reports emerged that Tellurian was considering selling its Haynesville upstream assets in east Texas and Louisiana to fund the Driftwood project, enlisting Lazard as a financial advisor for the potential sale.  

Both the Driftwood LNG and Rio Grande LNG projects have received approval from the US Energy Department.

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Technological Development for Cleaner and Greener Environment Hydrogen & Bio-Methane


EU Methane Rules: Impact for Global LNG Exporters

Last November, the European Union reached a provisional agreement on its long-developing methane legislation, which aims to reduce emissions from domestically produced and imported oil, natural gas, and coal. Gaps in the legislation represent key problems that producers and consumers are grappling with to better track and reduce emissions across natural gas value chains. The legislation should enter force in the next few months, but even afterwards there will be major uncertainties. This brief describes the methane regulation and discusses the significance for global gas suppliers, including special challenges for U.S. liquefied natural gas (LNG) exporters.



In November 2023, the European Union reached a provisional agreement on its long-developing methane legislation, which aims to reduce emissions from domestically produced and imported oil, natural gas, and coal. As Brussels takes steps to establish “methane performance profiles” of supplier countries and producers, the demand for better emissions data will ramp up quickly, including from liquefied natural gas (LNG) exporters.

The legislation should be formally adopted and enter into force within the next few months, but even afterward there will be major uncertainties. The European Commission needs to clarify how it will calculate the methane intensity of imported gas and determine “maximum methane intensity values” (i.e., an import standard). It will need to clarify how it will judge whether imported fossil fuels are produced under measurement, reporting, and verification (MRV) rules that are equivalent to EU standards, and whether there is regulatory equivalence in any other countries that could potentially allow some producers to be exempt from these requirements. Other unanswered questions concern verification of data and potential penalties for noncompliance.

EU requirements are also hard to reconcile with the way U.S. LNG volumes are produced and traded—and this is a concern since the United States is Europe’s largest LNG supplier. The methane legislation demands data “at the level of the producer” (Article 27a), but U.S. LNG sellers usually do not produce gas themselves, instead buying molecules from large producers or gas marketers. These sellers have limited information on the methane intensity of the gas they purchase, so this EU rule could be difficult to satisfy. In addition, a large share of U.S. LNG is sold on a free-on-board basis to traders or aggregators who sell from their portfolios to buyers in multiple regions, including Europe. These aggregators have no producer-level data. EU requirements will be easier to meet in countries with more concentrated production and simpler supply chains, such as Qatar.

This CSIS brief describes the European Union’s methane legislation, outlines areas of uncertainty, and discusses the significance for the global LNG industry.

Near the Finish Line but More Distance to Cover

In November 2023, the European Union’s major legislative bodies reached a provisional agreement on new methane rules. The European Commission, the Council of the European Union, and European Parliament had all introduced separate versions of the legislation, and “trilogue” negotiations resolved key differences. Two parliamentary committees have endorsed the agreement, and after a recent plenary vote in the parliament and pending approval from the council, the methane legislation will be published in the Official Journal of the European Union and enter into force, barring any surprises, in the summer.

It has taken years for the legislation to reach this point. The European Union first introduced a methane strategy in 2020. The commission’s legislative proposal followed in late 2021, the council approved its “general approach” in December 2022, and the parliament adopted its position in May 2023. There were persistent disagreements, including rules related to leak detection and repair as well as MRV. A significant area of dispute—and the critical issue for global LNG suppliers—concerned gas import rules. Key parliamentary committees and many environmental organizations advocated stringent requirements for imported gas. Rather than adopting a firm import standard, the European Union has imposed a series of information requirements that will ratchet up between now and 2030.

The legislation is nearing the finish line, but unfinished details will be significant for domestic oil and gas producers and suppliers to the European Union. These issues include MRV equivalence; verification of data; the methodology to calculate methane intensity and “maximum methane intensity values”; and potential penalties for operators and importers who fail to meet the new obligations. While key elements of the legislation could evolve before and after it enters into force, each of these issues is examined below.

MRV Equivalence

The methane legislation imposes new MRV rules on all domestic operators, aiming to increase the accuracy and reliability of reported emissions. As of January 2027, these standards will then be applied to imports, so the European Union will have to assess whether other countries’ MRV regulations are equivalent to or stronger than their own. This is a critical issue that could influence market competitiveness—or eventually even market access for gas suppliers. Crafting the rules for determining MRV equivalence will be challenging given the variation in regulatory regimes and governing bodies across countries. For example, how can countries demonstrate to Brussels that their rules—such as U.S. Environmental Protection Agency (EPA) requirements or upstream regulations in Nigeria or Colombia—are as strong as those in the European Union? Article 29a does outline important clauses related to measurement and quantification of methane emissions and notes that the commission may request standardization organizations to develop harmonized standards. But for now, there is considerable uncertainty over the information suppliers must provide.

Article 27a of the agreed text states that EU importers must demonstrate by January 2027 that supply contracts concluded after the entry into force of the legislation are produced in countries with MRV measures equivalent to or stronger than EU rules. Importers must undertake “all reasonable efforts” to bring previously concluded supply contracts into compliance and report annually on progress. The commission must recommend optional model clauses to provide this information, and member states and the commission “shall protect the commercial secrecy of data obtained.”

Crucially, the methane legislation allows for international producers or other countries to be exempted from requirements, but under conditions that may prove difficult or time consuming. Article 27a(4) specifies that MRV measures can be determined to be equivalent to EU rules if producers meet EU methane quantification standards or the Oil and Gas Methane Partnership (OGMP 2.0) Level 5 standards and are also subject to independent third-party verification (see discussion below). Article 27a(5) notes that Brussels can also determine country-level equivalency to its rules, but only if producing countries initiate a request and provide all necessary data to prove their MRV requirements are equivalent to or stronger than EU rules. Again, independent third-party verification of data is required. U.S. methane regulations might meet such a standard, but it remains uncertain how this process will work and how long it will take.

Verification of Data

The provisional legislation notes the importance of independent, accredited verification of data to satisfy monitoring and reporting requirements. But it is unclear which entities will emerge as accreditation bodies, aside from references to Regulation (EC) No 765/2008, which provides a broad framework on how accreditation systems should operate. Article 9 specifies that verifiers must be separate from operators, “undertakings,” and importers subject to the regulation. Article 8(2b) of the legislation states that verification activities “shall be aligned with European or international standards and methodologies,” but the commission will still have to adopt a delegated act specifying a methodology for calculating methane intensity.

The technical sophistication required to analyze and interpret methane emissions data suggests a limited pool of potential verifiers. Commercial entities in the certified gas space offer independent third-party verification of emissions data, but it is unclear which of their varying methodologies may be deemed acceptable.

Methane Intensity

An essential goal of the legislation is to measure the methane intensity of the European Union’s imported fossil fuels, but the methodology for calculating such values has yet to be determined. Article 27b states that a delegated act will be adopted within three years of enactment, which will set the rules and “consider the different production processes and site conditions for the production of crude oil, natural gas, and coal, and shall take into account existing international methodologies and best practice.” There are several questions about how this standard will be calculated. For example, in areas with significant associated gas production (gas produced along with oil), how will emissions be allocated across products: based on mass, energy content, or economic value?

Importers with supply contracts concluded or renewed after the enactment date are required to begin annually reporting their products’ methane intensity by 2028. Until then, importers should “undertake all reasonable efforts” to report methane intensities for existing contracts. The timeline for the commission to develop and publish a methodology is a concern, given the complexity of methane emissions monitoring, quantification, reporting, and verification.

Maximum Methane Intensity Values

The European Union will set a maximum methane intensity value to cap allowable emissions for crude oil, natural gas, and coal imports beginning in 2030. The consequences for failing to meet this standard are not yet clear. There have been proposals to impose a fee on noncompliant suppliers, and there is an implicit threat that the European Union could eventually close market access to emissions-intensive gas suppliers. In May 2023, the parliament proposed that the commission “study the possibility of introducing an ambitious upstream methane emission intensity performance standard at below or equal to 0.2 percent.” This 0.2 percent target would align with an earlier goal set by the Oil and Gas Climate Initiative, as well as the agreed 2030 target for signatories to the Oil and Gas Decarbonization Charter and the upstream methane intensity target in the waste emissions charge under the U.S. Inflation Reduction Act of 2022 (IRA). Although the 0.2 percent methane-intensity target was dropped in the November 2023 provisional EU agreement, it may resurface if Brussels determines there is value in global alignment—but the commission may also want to set its own target.

How quickly the European Union will set its methane performance standard matters greatly. If it takes several years to create a methodology and set a target, “third countries” and companies will have limited time to adjust their processes and equipment. Accelerated action would help gas suppliers prepare to meet or exceed the standard.

Potential Penalties

Like other extraterritorial rules, such as the European Union’s Carbon Border Adjustment Mechanism, an explicit goal of the methane legislation is to push global actors to align with EU standards. Not all gas-producing countries share the same ambitions. Gas suppliers may simply refuse to provide the requested data or provide incomplete data, perhaps arguing that they lack the technical systems or financial resources necessary to meet the European Union’s MRV requirements. Gas producers could argue that domestic laws on national security or corporate data secrecy prevent them from sharing sensitive information. They may also provide incomplete or poor-quality data that fails to meet the standard set by Brussels.

What happens if suppliers refuse to provide the data? Article 30 explicitly states that a failure to meet the requirements of Articles 27(1), 27a(1) and 27a(2), 27b(2) and 27b(2a), and Annex VIII will be subject to penalties. Penalties are capped at “20% of the annual turnover of the legal person concerned in the preceding business year” or “20% of the yearly income in the preceding calendar year” for natural persons. Article 30 also includes a list of factors to be considered when imposing penalties. But the European Union delegates enforcement to its 27 member states. This raises the possibility of a variable regulatory landscape—especially among member states with deeper concerns over energy security or natural gas prices—that would undercut the legislation’s effectiveness.

Why This Matters for Global Gas Producers

It is easy to get lost in the minutiae, but these rules are important for global gas producers. Gaps and uncertainties in the legislation represent key problems with which both producers and consumers are grappling regarding how to better track and reduce methane emissions across natural gas value chains.

The European Union is well ahead of other gas-importing regions in demanding and publicly sharing more granular data on the emissions intensity of purchased gas. But as Brussels clarifies these rules, Japan, South Korea, and other gas importers are in the early stages of gathering information on emissions intensity from their gas suppliers. It is possible—although far from certain—that they could eventually adopt similar requirements. Supply-side regulations—such as the U.S. EPA’s final rule on greenhouse gas emissions from the oil and gas sector and the IRA’s methane fee and associated reporting requirements—have the greatest potential to drive methane reductions from the oil and gas industry. But a stronger demand pull for gas with demonstrably lower emissions intensity could also create a powerful signal.

There is an essential, unresolved question about how these regulatory requirements will shape commercial terms and the day-to-day business of the global gas trade. The European Union’s methane legislation seems it will be most effective in developing national- or operator-level methane intensity profiles. Developing this data would be an important achievement, creating incentives for emissions reductions. But the EU requirements do not map neatly onto commercial transactions. Will emerging data on emissions intensity become available at the level of LNG cargoes or discrete pipeline volumes? If so, will the market begin to assign a premium to gas with lower emissions intensity? Emerging rules in the European Union might push the oil and gas industry in this direction, but regulatory and market momentum elsewhere will probably be necessary.

While these rules will apply to all imported gas, they will be especially challenging for U.S. LNG exporters because of the complicated nature of U.S. gas supply chains. The United States is unique in this regard, but since it has become such a large LNG exporter to Europe, Washington and Brussels will have to reach some accommodation. Time is of the essence—because within a few months LNG suppliers to Europe will be playing by a new set of rules.


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Feasibility Studies Demonstrate Progress in Methane Abatement Technologies

Researchers are continuing to report strong progress in the efforts to reduce and eliminate methane slip (emissions of unburnt methane). The Methane Abatement in Maritime Innovation Initiative (MAMII), part of the Safetytech Accelerator established by Lloyd’s Register announced the results of four recently completed technology feasibility studies, reporting the outcomes showed strong potential to cut methane emissions in the maritime industry. 


MAMI reports the technologies of four companies, Daphne Technology, CDTi Advanced Materials, Rotoboost, and Plenesys, were selected from among 20 proposals in the call for technologies to mitigate methane emissions from the exhaust stacks of LNG-fueled ships. Scientists and environmentalists are focused on methane emissions reporting that they are more harmful to the environment than other forms of the so-called greenhouse gases. 

Three shipping companies, Capital Gas Ship Management, MSC Mediterranean Shipping Company, and Seapeak, joined from within the 20 companies that are members of MAMII. The shipping companies collaborated in the study helping with the development of commercially viable applications of the technologies.

“The feasibility studies for CH4 technologies represent a critical step towards reducing our environmental footprint and underscore our resolve to contribute positively to the maritime industry’s sustainability goals,” said Alexandra Xystra, Technical Manager, Capital Gas Ship Management.

The four companies presented different approaches to the challenges of methane abatement but all reported strong results. According to MAMII, the studies assumed efficiencies reaching 78 to 85 percent and also presented new ways of dealing with methane converting it to alternatives that could be redeployed to enhance economic efficiency for the operators.

“Information about how methane combustion performs under different conditions will be critical to solving the challenge of methane slip,” explained Bud Darr, MSC Group, Executive Vice President, Maritime Policy & Government Affairs. “Research insights from studies such as this one get the industry a step closer to understanding not only combustion performance but also what combination of onboard technologies can deliver significant methane emissions reduction.”

Daphne Technology focused on its implementation in the auxiliary engines of a dual-fuel 14,000 TEU containership. MAMII reports it showed that a two-unit installation, can cover four auxiliary engines, ensuring operational flexibility and providing an assumed removal efficiency of 85 percent. This study outlined a potential reduction of up to 440 metric tons of methane annually.

CDTI investigated its catalyst’s performance to demonstrate that it could offer increased methane conversion at lower temperatures and across various engine loads. The catalyst achieved 80 percent methane conversion.

The feasibility study conducted by Plenesys examined process compatibility and mechanical and electrical adaptations. It also included a techno-economic and environmental assessment of the technology deployment. The study demonstrated that the solution can effectively reduce methane slip by 78 percent, converting it to hydrogen for engine reinjection. 

Rotoboost explored the implementation of its Thermo-Catalytic Decomposition system on LNG-fueled vessels. TCD system not only reduces methane slip by improving combustion efficiency but also lowers CO2 emissions due to the higher calorific value of the hydrogen-enhanced fuel mix. The study concluded that the hydrogen drop-in fuel generated by the onboard system presents several benefits such as significant emission reductions and additional revenue from carbon by-products.

“These technologies represent a significant stride towards mitigating methane emissions in the maritime industry, contributing to a sustainable and cleaner future for our oceans and the planet,” commented Nadia Echchihab, Head of Innovation Programmes for Safetytech Accelerator.

MAMII hopes to progress these research projects to on-ship trials as soon as possible. MAMII was launched in September 2022 by Safetytech Accelerator to bring together industry leaders, technology innovators, and maritime stakeholders to advance technologies for measuring and mitigating methane emissions in the maritime sector. The goal is to promote the adoption of validated solutions.

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BYD Shark, a plug-in Hybrid Ford Ranger Rival, launches in Mexico

BYD doesn’t sell passenger vehicles here in the U.S., and the latest round of American tariffs on Chinese-made EVs all but ensures it won’t for a while. But the automaking giant is going all guns blazing in Mexico. The world’s second-largest EV maker after Tesla already sells several all-electric models in the country, including the Tang SUV, Yuan crossover, and Seal sedan among others.


Now it has added another brand-new model to its portfolio in Mexico: the Shark plug-in hybrid. It’s BYD’s first-ever pickup truck. The Shark marks BYD’s entry into a segment traditionally dominated by American and Japanese carmakers. And for its first attempt, it appears impressive, at least on paper.

Most specifications have now been announced on the BYD Mexico website. Apart from Mexico, BYD plans to sell the Shark in Brazil, Europe and Australia as well. Its only direct competitor is the Ford Ranger PHEV, but it will also lock horns with the likes of the Toyota Hilux and Chevrolet S10 among others, as our pals at Motor1 Brazil have pointed out. (While it has garnered headlines for its electric vehicles, BYD also sells a significant amount of hybrids as well.)

In terms of dimensions, the Shark is slightly longer and taller than the Ford Ranger, measuring 214 inches long, 77.5 inches wide and 75.5 inches tall. Its wheelbase spans 128.3 inches. The Shark’s maximum towing and payload capacities are 5,511 pounds and 1,840 pounds, respectively.

Like its rivals, it rides on a body-on-frame platform, using an architecture similar to that of the BYD Seal U SUV in China and the Fangchengbao range of off-road SUVs. BYD calls this the DMO platform, where DM stands for Dual Mode (hybrid) and O stands for off-road.

The plug-in hybrid system combines the 1.5-liter turbo engine with two electric motors, one on each axle, to deliver 430 horsepower. BYD says that’s enough to propel the truck from 0-62 miles per hour in 5.7 seconds.

Its electric-only range is about 62 miles on the outdated New European Driving Cycle (NEDC), so expect the real-world range to be much lower. It also uses BYD’s cutting-edge Blade battery, whose cells are part of the chassis structure.


In terms of design, the fascia has cues from the latest-generation Hyundai Santa Fe and the Ford F-150 Lightning. There’s a full-width LED light bar up front with a rather large floating BYD logo mounted on the radiator grille. Black cladding all around gives it the rugged off-roader look.

Inside, a 12.8-inch rotating infotainment screen dominates the dashboard, similar to the Seal. It is complemented by a 10.25-inch digital gauge cluster. Other notable features include a 12-inch heads-up display, wireless Apple CarPlay and Android Auto connectivity and bidirectional charging among others.


BYD will offer the Shark in two variants in Mexico, GL and GS. The GL starts at 899,980 Mexican pesos (about $53,432) whereas the GS costs about 969,800 pesos ($57,577), according to the exchange rates at the time of publication.

By comparison, the Ford Ranger starts at around 818,000 pesos, while a mild-hybrid diesel Hilux costs about 851,400 pesos. In other words, the Shark is in good company. 

The Biden Administration reportedly plans to slap a 100% tariff on Chinese EVs, up from 25% previously. It’s unclear if that includes PHEVs, but launching a pickup truck in North America could be BYD’s message to the U.S. that it plans to expand its presence on the continent, regardless of what America thinks.

The question of whether Chinese EVs will enter the U.S. through the U.S.-Mexico-Canada (USMCA) free trade agreement remains debatable. Recent developments, including Mexico’s refusal to engage in further discussions with Chinese automakers and the withdrawal of incentives, suggest that this prospect is improbable, at least for now.

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