Tag: tank terminals

China nurtures pilot projects to build up domestic hydrogen supply chains

China’s National Energy Administration recently called for building up various demonstration hydrogen projects across the country, but local industry participants said it would still take years to transform China’s insular hydrogen ecosystem into an international manufacturing hub.

China is the world’s largest hydrogen supplier. In 2024, the country produced 36.50 million mt of hydrogen, accounting for 35% of the global total supplies, NEA data showed. However, over 98% of the supplies were produced from coal, natural gas or as industrial byproducts, instead of renewable-based water electrolysis.

Furthermore, most hydrogen supplies have been consumed domestically due to challenges in long-distance hydrogen transmission and the lack of international off-takers.

Given the current challenges and market conditions, NEA’s newly launched policy provided a list of projects that are considered qualified as “pilot demonstration projects”. In China’s context, the shortlisted demonstration projects are expected to receive financial support from national and provincial governments, enjoy better interest rates for loans, set standards and templates for future projects, and get on the fast track for commercialization.

“The shortlisted projects focus on three perspectives: decarbonizing China’s hydrogen production, tackling the logistic bottlenecks, and scaling up demand, which are also the key challenges in China’s hydrogen industry,” a Beijing-based hydrogen analyst told Platts, part of S&P Global Commodity Insights.

Boosting renewable hydrogen supplies

In the list of eligible project types, published on June 10, NEA prioritized large-scale renewable and nuclear hydrogen production projects, which means projects that have no less than 100 MW or 20,000 cu m/hour of capacity. Eligible projects are also required to integrate supply and demand, utilizing the clean hydrogen in industrial processes like ammonia and methanol synthesis, refining and producing sustainable aviation fuel.

Smaller renewable hydrogen projects are considered eligible if they are in China’s rural coastal and desert areas and can operate independently, without electricity supplies from the public power grids, NEA said, adding that such projects have a lower capacity threshold of 10 MW.

Meanwhile, NEA called for projects that leverage carbon capture and storage technologies to decarbonize hydrogen produced from fossil fuels, as well as projects that can boost the consumption of hydrogen byproducts in nearby industrial plants. The policy called for selecting pilot regions to build up industry clusters that connect suppliers and buyers for such low-carbon hydrogen.

Local analysts pointed out that large-scale renewable hydrogen production remained challenging in China and globally because the intermittency of renewable electricity could significantly impact hydrogen outputs and trigger safety hazards.

Transportation, storage and utilization

NEA also called for projects that can enable large-scale, long-distance hydrogen transportation. The eligible projects should be able to carry no less than 600 kg of hydrogen in a single vehicle or build pipelines that can transport hydrogen over no less than 100 km.

NEA said projects with a hydrogen storage capacity above 20,000 cu m would be considered eligible, without showing preferences towards any existing technologies.

From the demand side, NEA supported projects that can adopt at least 1,000 mt/year of renewable hydrogen to substitute emission-intensive fuels and raw materials in heavy industries, such as refining and coal chemical industries.

Meanwhile, NEA supported co-firing coal and gas with hydrogen and ammonia for power generation. Eligible gas-fired projects should have generation capacities above 10 MW, and the hydrogen/ammonia content should be no less than 15%. Eligible coal-fired projects should have generation capacities above 300 MW, and the hydrogen/ammonia content should be no less than 10%.

NEA also called for exploring ways to use carbon markets to finance these pilot projects.

“Different from countries like Japan and Singapore that focus more on developing international hydrogen supply chains, the latest NEA policy still focuses more on building up the domestic ecosystem first. Notably, NEA did not give any specific signals regarding maritime transportation or unlocking demand from international buyers,” the Beijing-based analyst said.

“Given the technical hurdles and market reality, China’s strategies for engagement with international customers are still exporting hydrogen electrolyzers to their markets or helping them build up renewable hydrogen projects locally, instead of exporting hydrogen or ammonia produced within China,” the analyst said.

“Looking ahead, over 245 GW of renewable hydrogen capacity has been announced in Asia Pacific. Of that, 43 GW of projects are in the advanced planning stage, and 37 GW are planned to start by the end of 2030. China has 8.5 GW of capacity under construction and 16.3 GW in the advanced planning stage, mostly eyeing to serve the domestic market,” Commodity Insights analysts said in a report titled Clean Hydrogen Production in Asia-Pacific, published on June 9.

NEA’s latest hydrogen industry report showed that, as of December 2024, China’s production cost of hydrogen fell to Yuan 28/kg ($3.85/kg), decreased by 15.6% year over year. In comparison, the NEA report showed the US PEM electrolytic hydrogen price was at $5.2/kg and the EU PEM electrolytic hydrogen price was at Eur 6.1/kg ($6.94/kg) on an annual average basis in their respective key markets, citing Platts data.

By Ivy Yin – Energy Transition Market Specialist / June 13, 2025.

PBF Energy (PBF) Gained Over 15% This Week. Here is Why.

The share price of PBF Energy Inc. (NYSE:PBF) surged by 15.02% between June 5 and June 12, 2025, putting it among the Energy Stocks that Gained the Most This Week. Let’s shed some light on the development.

Aerial view of an oil refinery, with smoke billowing from its chimneys.

PBF Energy Inc. (NYSE:PBF) is one of the largest independent petroleum refiners and suppliers of unbranded transportation fuels, heating oil, petrochemical feedstocks, lubricants, and other petroleum products in the United States.

PBF Energy Inc. (NYSE:PBF) shot up this week after analysts at Wells Fargo raised the firm’s price target from $18 to $21, while maintaining an ‘Equal Weight’ rating. Given seasonality and persistently narrow crude differentials, Wells Fargo continues to favor the large refiners over the smaller ones.

Moreover, it was reported last week that UBS analysts have maintained their ‘Buy’ rating on PBF Energy Inc. (NYSE:PBF), while reiterating a price target of $26.

While we acknowledge the potential of PBF as an investment, we believe certain AI stocks offer greater upside potential and carry less downside risk. If you’re looking for an extremely undervalued AI stock that also stands to benefit significantly from Trump-era tariffs and the onshoring trend, see our free report on the best short-term AI stock.

By: Sultan Khalid / 13.06.2025

Shell to boost LNG capacity to 12mt by 2030

The projects contributing to this capacity boost include those in Canada, Qatar, Nigeria and the UAE.

il and gas company Shell has announced plans to expand its capacity by up to 12 million tonnes (mt) by the end of the decade, reported Reuters, citing Shell’s Integrated Gas president Cederic Cremers.

This increase is attributed to several projects currently under construction, as confirmed by Cremers.

Cremers stated: “That is not an ambition. Those are all projects that are currently in construction.”

The projects contributing to this capacity boost include those in Canada, Qatar, Nigeria and the United Arab Emirates (UAE).

Shell’s current buying capacity stands at approximately 70 million tonnes per annum (mtpa) of contractual liquefied natural gas (LNG).

Shell LNG Marketing and Trading delivered nearly 65mtpa of LNG to more than 30 countries last year.

In addition to construction projects, Shell is also enhancing its supply capabilities through strategic acquisitions and partnerships.

Cremers highlighted the recent acquisition of Pavilion Energy in Singapore, which was completed by the end of the first quarter, and contracts with third-party suppliers as key to its strategy.

Looking to the future, Cremers noted that by 2030, a significant portion of new supply, around 60%, is expected to come from the US and Qatar, with demand primarily driven by Asia and sectors that are challenging to electrify.

Shell earlier this year projected that global LNG demand could surge by around 60% by 2040, spurred by economic growth in Asia, the impact of AI, and initiatives to reduce emissions in heavy industries and transportation sectors.

Earlier this month, Shell announced the final investment decision to initiate production at the Aphrodite gas field in the East Coast Marine Area in Trinidad and Tobago.

By: Offshore-technology / June 12, 2025

California fuel imports hit 4-year high amid refinery outages

NEW YORK, June 9 (Reuters) – California’s fuel imports rose to the highest in four years in May as refiners turned to historical trading partners in Asia and tapped some unusual routes to make up for shortages in the No.2 U.S. oil consumer state, according to shipping data and traders.

The rise in shipments to California offers an early look at the future of the biggest gasoline and jet fuel markets in the U.S., which are expected to become more reliant on imports after Phillips 66(PSX.N), opens new tab and Valero(VLO.N), opens new tab close two major refineries in the state by next year, amid growing regulatory and cost pressures, and declining demand for gasoline.

“California’s refining capacity is shrinking faster than its fuel demand is declining, forcing the state into a long-term import-dependent position,” Kpler analyst Sumit Ritolia said.

California’s total petroleum product imports rose to 279,000 barrels per day (bpd) in May, the highest since June 2021, when a similar volume was imported, according to data from vessel tracker Kpler.

About 187,000 bpd, or nearly 70% of the imports came from South Korea and other Asian exporters, who have historically been the top trading partners for California and other West Coast states, which are geographically isolated from major U.S. refining centers along the Gulf Coast.

Recent outages in California at refineries owned by Chevron (CVX.N), opens new tab, PBF Energy (PBF.N), opens new tab and Valero(VLO.N), opens new tab caused a supply crunch in markets along the U.S. West Coast that necessitated more imports, traders and analysts said.

“We have seen tighter supplies due to several refinery outages,” StoneX oil analyst Alex Hodes said. That boosted prices in the U.S. Pacific Northwest substantially and led to increased imports, he said.

There were several days where San Francisco gasoline was more than $40 a barrel above Gulf Coast pricing, nearly double the year-to-date average of $21, WoodMac analyst Austin Lin said.

Flows on the route from the Caribbean were sporadic before this year’s refining outages, averaging just 6,000 bpd throughout last year, the data showed.

The Bahamas does not refine oil but exports fuel and blending components shipped there from the U.S. Gulf Coast refining hub as part of a workaround to a century-old U.S. shipping law to supply fuel to the East Coast when pipeline shipments are insufficient.

The Jones Act bars movement of goods between U.S. ports unless carried by ships built domestically and staffed by local crew. However, there were only 55 such petroleum tankers as of the start of 2024, according to a government report, making them expensive and hard to procure.

Sailing a tanker from Texas to California via the Bahamas is typically too expensive, but the recent refinery outages opened up the arbitrage to the West Coast from everywhere, a second U.S. gasoline trading source said.

By: Shariq Khan and Nicole Jao / June 9, 2025

Could MARA be readying to team with Exxon or Aramco on flare gas Bitcoin mining?

Bitcoin meets Big Oil in what could be the industry’s most ambitious flare-gas mining play yet.

Could MARA (formerly Marathon Digital) be in exploratory talks with Exxon Mobil and Saudi Aramco to colocate Bitcoin mining units at oilfields, directly tapping flare-gas for power?

Crypto Twitter thinks it’s possible, and if confirmed, the partnership could turbocharge the scale and legitimacy of gas-to-Bitcoin operations, turning waste methane into a monetized digital asset while addressing ESG concerns.

MARA stock pumper Cryptoklepto thinks, “It is more likely than not that at least one of these scenarios plays out in the next 6 to 12 months for $MARA.”

While none of the companies have formally announced a deal, MARA CEO Fred Thiel hinted at “discussions with some of the largest energy companies in the world” on May’s earnings call, adding that “chunks of flare-gas generation” will soon come online where we’re able to deploy our Bitcoin mining operations.

The timing aligns with Aramco’s May 2025 announcement of 34 new MoUs with U.S. firms and follows Exxon’s earlier pilot with Crusoe Energy in North Dakota.

Pilot-Proven, Ready to Scale

MARA isn’t starting from scratch. In late 2024, it launched a 25-megawatt pilot in Texas using stranded shale gas, avoiding grid competition while qualifying for methane abatement credits. “The AI guys are prepared to pay almost any price for energy,” Thiel told Reuters. “Bringing crypto-mining to the raw power supply lets us avoid that fight.”

The company’s mobile, plug-and-play infrastructure is tailor-made for oilfields. These portable modules convert otherwise flared methane into electricity, which is then used to mine Bitcoin, a process that Exxon and Crusoe demonstrated at scale by diverting 18 million cubic feet of gas per month and cutting CO₂-equivalent emissions by up to 63%.

Saudi Aramco has previously denied any intention to mine Bitcoin. In 2021, the company labeled such reports “false and inaccurate.”

However, MARA’s Thiel recently claimed the firm has 4–5 gigawatts of excess capacity, a scale that could power tens of thousands of mining rigs. If even a small portion were redirected, it would surpass the total output of many standalone crypto facilities.

Exxon, meanwhile, has the institutional memory and data from its two-year Crusoe pilot, which could make fast-tracking a new venture with MARA less speculative than it seems.

Why Now? A Confluence of Pressure and Opportunity

Behind the scenes, regulatory momentum is building. A U.S. methane emissions fee under the Inflation Reduction Act kicks in this year, pushing oil producers to find ways to reduce or monetize their emissions. Flare-gas mining offers a low-capex, high-upside path to compliance, particularly when paired with carbon offset markets.

Further, bills have been approved in Texas specifically to encourage Bitcoin mining using flare gas.

At the same time, Bitcoin miners are grappling with compressed margins following the April 2025 halving. MARA, one of the industry’s largest listed players, produced 950 BTC in May but must now aggressively pursue sub-$0.03/kWh energy sources to remain competitive. Flare-gas, once a fringe energy input, could become a post-halving lifeline.

Skepticism remains warranted. No SEC filings, public agreements, or official comments confirm the Exxon or Aramco partnerships. Given Aramco’s past denial, any shift in stance would likely involve months of permitting, infrastructure build-out, and reputational calculus.

If oil majors greenlight Bitcoin mining at the wellhead, the flare-gas conversation will shift from “can it work?” to “how fast can it scale?” MARA, with its turnkey modules and Wall Street footprint, may be first in line.

What to Watch

Public filings or MoUs from Exxon, Aramco, or MARA confirming pilot collaborations.

Energy regulator responses to flare-gas mining amid the methane fee rollout.

Q3 production updates: MARA’s energy costs and BTC yield per site.

Community pushback around noise and emissions from MARA’s Texas flare site.

“You’re going to find is a mix of thermal, a mix of wind, solar and some flare gas. It really depends on the market and the partner.

We’re in discussions with some of the largest energy companies in the world that have a mix of all those energy sources and nuclear.

In regards to flare gas, there are a lot of gas assets around the world that are very applicable to this method…

And what I think you’ll see us doing more and more in the future is as we continue to work with especially oil and gas producers, you’ll see chunks of this flare gas type generation come online in different parts of the world where we’re able to deploy our Bitcoin mining operations, as a way to monetize that stranded gas. And we are super excited about those opportunities.”

By: Liam ‘Akiba’ Wright / Jun. 9, 2025

Dialog seen ripe for re-rating on potential tank terminal contracts

KUALA LUMPUR: Dialog Group Bhd’s stock could see an upward re-rating once long-term tank terminal contracts for its Pengerang Deepwater Terminal (PDT) Phase 3 are secured.

Hong Leong Investment Bank Bhd (HLIB Research) said near term potentials include storage leases for ChemOne’s aromatics plant and Petronas’ joint venture biorefinery.

The firm maintained its forecasts and reiterated a ‘Buy’ call on Dialog, keeping the target price unchanged at RM2.59.

“We believe the eventual award of long-term tank terminal contracts for PDT Phase 3 will help re-rate the stock, which is currently trading at a reasonable valuation of 16 times forecast earnings for financial year 2026, compared to its five-year mean of 23 times.

“We like Dialog for its recurring income business model and its unique position in riding the future expansion of Pengerang via development of tank terminals,” it said in a research note.

HLIB Research also highlighted that Dialog’s downstream engineering, procurement, construction and commissioning business has swung back to minor profitability in the third quarter of financial year 2025 (3Q25).

It said the group had assured that there would be no further cost provisions in anticipation of the official handover of Melamine plant in Kedah and gas compressor plant in Kluang to Petronas by the second half of 2025.

On the midstream front, HLIB Research said storage rates edged up slightly to S$6.4 (RM20.98) to S$6.6 (RM21.63) per cubic metre in 4Q25, compared to S$6 (RM19.67) to S$6.5 (RM21.31) over the past year.

It noted that this uptick was driven by stronger storage demand from oil traders, spurred by increased crude supply from OPEC+ and softening oil prices amid escalating trade tensions and heightened demand uncertainty.

“The temporary shortfall from upstream in 4Q25 should be mitigated by better midstream contribution,” it said.

By S. Birruntha – June 8, 2025

Evonik completes pipeline to supply hydrogen to chemicals site, refinery

German speciality chemicals company Evonik Industries AG (ETR:EVK) has made a pipeline of more than 50 kilometres (31.07 miles) ready to transport hydrogen to the Marl Chemical Park and the Gelsenkirchen refinery in North Rhine-Westphalia.

The connection, starting in Legden in northern North Rhine-Westphalia, consists of a 41-kilometre former natural gas pipeline repurposed for hydrogen transport, a newly built three-kilometre section crossing the Marl Chemical Park, and a roughly ten-kilometre hydrogen pipeline leading to the refinery in Gelsenkirchen-Scholven. The pipeline system enables the transport of hydrogen to be produced using several hundred megawatts of electrolysis capacity in northern Germany.

The pipeline is part of the GET H2 Nukleus project, which aims to connect the green hydrogen production in northern Germany with industrial customers in North Rhine-Westphalia and Lower Saxony.

“In almost two years of intensive project work, we and our partners have successfully converted a natural gas pipeline for hydrogen operation and built new sections,” said Andreas Cieslik, Head of Evonik’s Pipeline Business.

The Marl chemicals site is gaining importance as a hydrogen hub as Evonik recently launched a start-up to produce green methanol by combining captured carbon dioxide with 200 tonnes of green hydrogen annually. The site also hosts the Rheticus research project, which uses hydrogen and bacteria in artificial photosynthesis to convert carbon dioxide into speciality chemicals. In addition, Evonik is investing a low double-digit million-euro sum in a pilot plant to produce its proprietary anion exchange membrane, a key component for green hydrogen production via AEM electrolysis.

By: Anna Vassileva / Jun 4, 2025.

PetroChina to Shut Its Largest Northern Refinery Within Weeks

State-run oil giant PetroChina will shut the last remaining crude processing unit at its biggest refinery in northern China within weeks, industry sources told Reuters on Wednesday.

Dalian Petrochemical, PetroChina’s 410,000-barrels-per-day refinery in downtown Dalian, north China, has been shutting processing units since the end of 2023.

Now the last remaining crude unit, with a capacity of 200,000 bpd, will be switched off on June 30, according to Reuters’s sources.

Dalian Petrochemical accounts for almost 3% of the total Chinese refining capacity. The facility processes predominantly Russia’s Far Eastern ESPO crude grade.

The municipal authorities of Dalian have been pushing for years for the relocation of the refinery away from Dalian city.

The relocation and the closure of the Dalian Petrochemical facility are part of that plan after several deadly incidents over the past decade at the refinery, which is located in a densely populated area in Dalian city.

PetroChina’s parent company, CNPC, reached an agreement with the Dalian authorities two years ago to build a smaller, 200,000-bpd crude oil refinery at a new refining and petrochemicals site on Changxing island.

Yet, PetroChina has yet to take a final investment decision for the new refinery, Reuters’s sources said.

Stronger economic growth than previously expected and booming demand for petrochemicals will lift China’s oil demand by 1.1% this year, according to state giant China National Petroleum Corporation (CNPC).

However, China’s consumption of transportation fuels has peaked, Wu Mouyuan, vice president of CNPC’s think tank, said earlier this year.

Like CNPC, the International Energy Agency (IEA) also believes that oil demand for fuels in China has reached a plateau.

“With the overall Chinese economy pivoting from manufacturing to services-based growth and as the adoption of electric vehicles expands in the transport sector, the data strongly suggest that the combustion uses of petroleum fuel in China have already reached a plateau and that the potential for future growth may be very limited,” IEA market analysts said in March.

By Tsvetana Paraskova for Oilprice.com – Jun 04, 2025

Crude Processing At One of Europe’s Top Refineries Goes Offline

BP’s refinery in Rotterdam had both its crude units offline on Tuesday morning, Reuters reports, citing energy consultancy Wood Mackenzie.

A crude unit with a capacity of 200,000 barrels per day (bpd) went offline early on Tuesday. This follows the shutdown of the other 200,000 bpd crude unit in early May for planned maintenance.

As a result of the shutdowns, the 400,000-bpd oil refinery in Rotterdam now has both crude units offline.

The Rotterdam refinery is one of Europe’s largest and has the capacity to process 400,000 bpd of crude, or 19 million tons per year.

At the facility, BP produces gasoline, diesel, jet fuel, LPG, fuel oil, and raw materials for the petrochemicals industry. The refinery supplies all BP gas stations in the Netherlands and exports fuels to the U.S., Germany, Belgium, Luxembourg, Switzerland, and the UK.

The reduced refining capacity in Europe could boost refining margins for the other refineries at a time when the driving season and peak demand period for the year start.

Refining capacity closures and resilient fuel demand have tightened global fuel markets in recent weeks, benefiting refiners globally.

Refining margins have been rising this year and hit in May the highest global composite margin in more than a year. As the driving season begins and summer approaches, peak demand in the northern hemisphere is here.

Refiners, including U.S. refining giants, are benefiting from the higher margins, although these margins are far below the record highs seen in 2022 amid the oil market turmoil.

Still, global composite refining margins hit $8.37 per barrel in May—the highest level since March 2024, according to data from Wood Mackenzie cited by Reuters.

During the second quarter, the higher margins and demand are a boon to refiners, which saw increased turnaround activity and weak refining margins in the first quarter of the year.

By Tsvetana Paraskova for Oilprice.com / Jun 03, 2025

Norway’s Oil and Gas Investment Set for Record High in 2025

Investments in Norway’s oil and gas sector are set to hit a record high this year, led by increased investments in operating fields, Statistics Norway said on Tuesday in its latest survey of companies’ investment plans.

The quarterly survey of investment plans showed that total investments in oil and gas activity in Norway in 2025, including pipeline transportation, are estimated at $26.6 billion (269 billion Norwegian crowns), up by 6% compared to the estimates in the previous quarter.

“The upward adjustment for 2025 is to a large extent driven by higher estimates within the category fields on stream,” the statistics office said.

However, investments are expected to peak this year and begin to decline moderately from 2026 onwards. The estimate for 2026 is now at $20.5 billion (207 billion crowns), down by 4.3% from the expected 2025 investment level, according to the statistics office.

Investments in 2023 and 2024 jumped, due to Norway’s oil tax package from 2020 incentivizing operators to submit a plan for development and operation (PDO) for several new fields, Statistics Norway noted.

Inflation and rising supply chain costs have also boosted the value of the investments in the past two years.

Considering that “very few new developments have occurred since 2022”, it is not surprising that a moderate decline in investments in field development is indicated this year. But this decline in investment in field development is being offset by expectations of a very high planned investment activity in fields on stream, the statistics office said.

Further exploration efforts and new discoveries would be crucial to slowing the expected decline in Norway’s oil and gas production in the 2030s, the authorities of Western Europe’s largest oil and gas producer have said in recent years.

Production from the Norwegian Continental Shelf is expected to decline gradually in the coming years, the Norwegian Offshore Directorate said in April in its annual report.

“However, the level of this decline will depend on the volume of new resources discovered and how much of the discovered resources are developed and actually come on stream,” the regulator said.

By: Oil Price / May 28, 2025