BP signs MOU on large-scale green hydrogen production in Egypt


To evaluate technical, commercial feasibility

Builds on Egypt’s renewables, hydrogen plans

Follows string of other hydrogen deals at COP27

BP has signed a memorandum of understanding with the Egyptian government with the aim of establishing a large-scale renewable hydrogen production facility in the North African country, it said in a statement Dec. 8.

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BP is to evaluate the technical and commercial feasibility of developing an export hub in Egypt, exploring high-potential locations across the country for renewables.

“Egypt has world-class renewable energy resources, and we look forward to working with the government to explore how we can support its ambitious low-carbon strategy,” BP executive vice president of gas and low carbon energy Anja-Isabel Dotzenrath said in the statement.

The MOU was signed by BP, Egypt’s New and Renewable Energy Authority, the Egyptian Electricity Transmission Company, the General Authority for Suez Canal Economic Zone and the Sovereign Fund of Egypt for Investment and Development (TSFE).

TSFE CEO Ayman Soliman said the MOU builds on the fund’s green hydrogen portfolio and its “mandate to transform Egypt into a regional hub for green energy.”

Hydrogen was a prominent theme at the UN Climate Change Conference hosted by Egypt in Sharm el-Sheikh in November, with several deals and projects launched on the sidelines.

BP CEO Bernard Looney attended COP27 as a delegate of Mauritania, with which the company signed a separate MOU on green hydrogen production at the conference.

The EU signed strategic hydrogen partnerships with Kazakhstan, Namibia and Egypt, seeking a diverse range of suppliers to meet its planned 10 million mt/year of imports by 2030.

And Fertiglobe led a consortium commissioning a first phase of the 100-MW Egypt Green hydrogen plant for ammonia production, also supported by Egypt’s Sovereign Fund.

BP is developing a portfolio of renewable and low-carbon hydrogen projects globally, including in the UK, Netherlands, Germany, Spain, the Middle East, the US and Australia, it said.

Europe and Asia-Pacific are seen as becoming major importers of hydrogen and its derivatives, drawing supplies from potential producing regions such as the Middle East, Australia and Latin America.

Platts, part of S&P Global Commodity Insights, assessed the cost of producing renewable hydrogen via alkaline electrolysis in Europe at Eur23.70/kg ($24.93/kg) Dec. 7 (Netherlands, including capex), based on month-ahead power prices. Production costs in the Middle East, by contrast, were assessed at $3.55/kg (Oman).

In Asia-Pacific, costs were assessed at $3.39/kg in Western Australia, well below the $9.41/kg cost in demand center Japan.

US Midcontinent ISO coal supplies ahead of winter are better than last year: grid officials


Railroads had more capacity on routes serving MISO

But power prices are still expected to rise this winter

Coal supplies for power plants heading into winter are looking better this year than last year in the Midcontinent Independent System Operator, which is good news because coal conservation measures can put added upward pressure on power prices, MISO officials said Dec. 6.

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“As of right now, we are not seeing a risk around fuel supply from a coal perspective,” said J.T. Smith, executive director of market operations at MISO. “I am not as concerned as I was at this time last year,” he told the Markets Committee of the MISO Board of Directors.

Despite better coal supplies, MISO Illinois Hub average on-peak wholesale power prices are still expected to be 48% higher from December to February compared to the same period last year, the US Energy Information Administration said in its December Short-Term Energy Outlook.

Natural gas prices are expected to push up power prices across the US this winter. While natural gas prices are projected to be lower this winter than they were last summer, they are still expected to be higher than they were last winter, according to EIA.

Coal conservation

MISO started out the summer with about 20 GW of coal-fired generators using conservation measures, and by Nov. 15, that number was down to about 8 GW, said David Patton, the president of Potomac Economics, the independent market monitor for MISO.

What tends to happen is when natural gas prices are high, coal-fired plants are more economic and run more often, Patton said. If coal supplies are running low, coal-fired plants can increase their prices to conserve coal, which can change the supply stack and meaningfully increase power prices, he said.

But recent developments, including falling natural gas prices and improvements to the coal supply chain, are leading to less coal conservation, Patton said. “Certainly, the fact that we are apparently going to avoid a rail strike is really good news from the perspective of coal supply,” he said.

Nationwide, US power sector coal inventories are projected to be 95 million st in December, up from 92 million st in December 2021, EIA said.

Easing constraints

Coal supply constraints eased this fall, as railroads were able to provide more capacity on routes that serve multiple units in MISO, the IMM said in a presentation. “Several resources eliminated coal conservation measures entirely,” the presentation said.

The fact that coal-fired generators are conserving less coal this fall going into winter is an indicator that they are comfortable with their supplies, Smith said.

But while a strike was averted and deliveries have improved, there are still issues in the coal supply chain, Smith said.

“There is still tightness at the mines, there is still tightness along the rails,” he said. Chemicals for pollution controls are also a limiting factor because generators only keep several days of chemical supplies on hand, he said.

MISO’s reliance on coal-fired power has gone down in recent years. In the winter of 2018-2019, coal accounted for 47% of the fuel mix, and in the winter of 2021-22, coal dropped to 35% of the fuel mix. Over the same period, gas-fired power grew from 25% to 29% and wind grew from 9% to 18%, the presentation said.

The change in the winter resource mix is largely due to retirements of coal-fired plants and the growth of wind power on the system, Smith said.

EU set to consider lower TTF gas price cap ahead of Dec. 13 energy council


Initial proposal was for TTF month-ahead cap of Eur275/MWh

TTF month-ahead cap could be lowered to Eur220/MWh: draft

Cap would be triggered after only five trading days

A proposed price cap on the Dutch TTF month-ahead gas price could be lowered to Eur220/MWh ($230/MWh) from an initial European Commission proposal of Eur275/MWh, according to a leaked draft of an amended market correction mechanism regulation.

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The EU’s energy commissioner Kadri Simson said Nov. 28 that member states remained “polarized” over the EC’s proposal for a TTF gas price ceiling, with discussions set to continue ahead of the next ministerial meeting Dec. 13.

The EC first proposed a new market correction mechanism that would trigger a cap on the TTF month-ahead price of Eur275/MWh if a number of conditions were met.

These were that the front-month TTF settlement price exceeded Eur275/MWh for two weeks and that the TTF price was Eur58/MWh higher than an LNG reference price for 10 consecutive trading days.

However, EU energy ministers failed to agree Nov. 24 on the proposals during an emergency council in Brussels, with a number of member states rejecting the Eur275/MWh cap as too high and ineffective.

Proposals for a number of changes have since been circulated among member states, including reducing the cap to Eur220/MWh and cutting the duration that the price would have to exceed that level to five trading days.

In addition, the spread between the TTF month-ahead price and the LNG reference price would be only Eur35/MWh, down from Eur58/MWh, according to the draft.

The EC could not be reached Dec. 7 for immediate comment on the amended proposal.

TTF reality

EU officials have said in recent months the TTF was no longer fit for purpose and did not reflect the new reality in Europe where LNG is a more dominant supply source.

Platts, part of S&P Global Commodity Insights, assessed the Dutch TTF month-ahead price at an all-time high Eur319.98/MWh late August.

Prices have weakened since on the back of healthy storage and demand curtailments, though prices remain historically high with Platts assessing the TTF month-ahead price Dec. 6 at Eur138.90/MWh.

Simson said a majority of member states supported the logic of the market correction mechanism, but they had questions regarding the level of the cap and the duration of the instrument.

Simson said the two-week period for prices to exceed Eur275/MWh had been considered long.

She also said some member states had “strong outstanding concerns” regarding potential risks to financial stability and security of supply.

Greece, with the backing of 14 member states, argued that the proposed price level would be ineffective in practice.

“The ceiling of Eur275/MWh is not really a cap. We need a realistic mechanism that can be put into practice,” Greek energy minister Kostas Skrekas said following the last council meeting Nov. 24.

“With a cap of between Eur150/MWh and Eur200/MWh, Europe can secure the gas it needs and cause significant demand reductions,” Skrekas said.

Policy safeguards

In her comments Nov. 29, Simson said the EC had introduced safeguards in its price cap proposal to protect against any threat to gas supply security.

She said that if triggering the market correction mechanism created any issues with security of supply, there was the option to suspend the cap immediately.

Simson also stressed the market correction mechanism was designed to be temporary. “It is not meant to be an instrument to structurally reduce gas prices to prewar levels.”

That, Simson said, could only be achieved through lowering gas demand and replacing gas with renewable energy sources.

Oil demand from petchems to stay robust in any energy-transition scenario: Aramco


‘The more intense the transition, the more important petrochemicals’: CEO

Growth in material use largely missing from net-zero debate: Amin

Oil demand from the petrochemicals sector is likely to remain robust “no matter which energy transition scenario plays out,” said Amin Nasser, Saudi Aramco president and CEO, on Dec. 6, the opening day of the 16th Gulf Petrochemicals and Chemicals Association (GPCA) Annual Forum, being held for the first time in Riyadh, Saudi Arabia.

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Under a net-zero scenario, petrochemicals could still account for more than half of total global oil demand by 2050, said Nasser in a keynote speech. “The more intense the transition, the more important petrochemicals will be to the oil and gas industry, and other industries,” he said.

The ongoing downstream push by state-owned Aramco to convert more of its crude oil to chemicals was highlighted by Saudi Arabia’s energy minister, Prince Abdulaziz bin Salman, as he inaugurated the forum. Flagging the previously stated Saudi Arabian goal to expand Aramco’s liquids-to-chemicals capacity to 4 million barrels per day by the end of the decade, the minister said, “We shall deliver it.” Aramco will be able to “work for the full chain of chemicals, including specialty products. And every molecule we produce, we will ensure that we use it, consume it, produce it, and send it as a finished product,” he said.

Aramco recently announced plans for the first large-scale deployment of its crude-to-chemicals cracking technology at the company’s S-Oil affiliate in South Korea, and a joint project between Aramco and Sabic to develop a crude-to-chemicals complex at Ras al-Khair, Saudi Arabia. Aramco is the parent of Sabic.

“These are major steps forward in our downstream business, and show the power of technical innovations to meet our ambitions. More advanced, more sustainable materials would undeniably strengthen the power of our net-zero ambition and our chemicals strategies,” said Nasser. “Our strategy to convert up to 4 million barrels per day of liquids into chemicals by 2030 is beginning to take shape.”

Nasser went on to highlight to a packed audience what he describes as a crucial component “largely missing from the net-zero debate—the enormous impact that growth in material use will have on reducing global greenhouse gas emissions.” Labeling it the materials transition, Nasser said it is “just as important as the energy transition to climate protection … and especially relevant to the chemical industry and its future strategies. Global net-zero emissions goals will not be met without a successful materials transition.”

Demand for materials including concrete, iron, and steel is projected to more than double from 79 gigatons in 2011 to 167 gigatons in 2060, Nasser said. But materials production, use, and eventual disposal already account for almost a quarter of all global CO2 emissions, he said. “So the increase in materials use, even if somewhat decoupled from economic growth, will be shadowed by a further rise in CO2 emissions, particularly in hard-to-abate-industries,” Nasser said.

To help reduce emissions in this growth environment, more durable and more sustainable advanced materials “must be the building blocks of 21st century life,” he said. This is where chemistry in action could shape a lower-emission, more sustainable future through a circular carbon economy and better materials efficiency, he said. However, the cost of advanced composite materials is much higher than that of steel, aluminum alloys, and concrete, and Nasser called on the chemical industry to reduce its costs through further innovation.

The “big opportunity” for the chemical industry is steadily to supplement existing materials with more durable, sustainable, and lower-carbon alternatives including polymer- and carbon-based materials, he said. “Already, every 1 megawatt of installed renewable energy capacity utilizes 8 to 11 tons of petrochemicals-based materials. This will bring a viable path to a truly sustainable materials future within reach and is exactly why we are strengthening our focus on materials transition at Aramco, making it a central part of achieving our 2050 net-zero ambition.”

Lower-carbon hydrogen will also play a major role in a variety of applications in the chemical industry, according to Nasser. “It can produce ammonia and methanol, or be used as a clean energy source in steam crackers, and in turn can produce more sustainable fertilizers, plastics, and other industrial products,” he said. Aramco and Sabic recently obtained the world’s first independent certification for the production of blue hydrogen and blue ammonia.

Abdulrahman al-Fageeh, GPCA chairman and CEO of Sabic, said in an opening speech that with global economic growth predicted recently by the International Monetary Fund to fall to 2.7% in 2023 from 3.2% in 2022, concerns about a global recession are already impacting demand for chemicals. The chemical sector usually feels the effects of a recession “two to three quarters before the global economy,” he said. “I can tell you … it has already begun for chemicals.”

However, the chemical industry “has always managed to overcome the challenges that it is facing. The key to our success is by seizing every opportunity that challenges bring. Through such action, the GCC can shape a sustainable future.”

This year’s annual forum is being held under the overall theme Chemistry in Action: Shaping a Sustainable Future.

UK government set to ease planning restrictions on onshore wind


Consultation on removing rigid site rule

Supportive communities freed up to act

Over 20 GW stuck in planning bottleneck

The UK’s Conservative government has yielded to pressure from a powerful group of its own MPs to consult on onshore wind planning policy, potentially lifting the current de facto ban on the technology.

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The UK has 14.24 GW of operational onshore wind capacity. The influential Climate Change Committee recommends the UK doubles this to 29 GW by the end of the decade. Over 20 GW of onshore wind projects are in development.

“Under the proposals, planning permission would be dependent on a project being able to demonstrate local support and satisfactorily address any impacts identified by the local community,” the government’s Department for Levelling Up, Housing and Communities said late Dec. 6.

Local authorities would have to demonstrate their support for certain areas as being suitable for onshore wind, moving away from rigid requirements for sites to be designated in local plans, it said.

The consultation, to be launched by Christmas and concluded by the end of April, would also look at how local partnerships could ensure communities benefit from hosting wind farms via lower energy bills.

The Conservative Environment Network, including former prime ministers Boris Johnson and Liz Truss, has been lobbying aggressively for a lifting of the ban after new Prime Minister Rishi Sunak said he would not abandon the Conservative Party’s manifesto pledge to block the technology.

“I’m delighted the government will end the de facto block on new onshore wind in England, unlocking this cheap, clean power source where communities agree. This is an important step to strengthen our energy security and cut people’s bills,” CEN director Sam Hall said.

“It is vital that the plans, when finalized, ensure communities get a genuine say without making it impossible for new projects to be approved,” he said.





Total pipeline (operational or at any stage of development)








Under construction








In the planning system




At an early stage of development




Source: RenewableUK

Labour skepticism

Industry welcomed the move but the opposition Labour Party was less impressed.

“Rishi Sunak has been pushed into a partial change of heart but it is not nearly enough,” said Labour’s shadow business secretary Ed Miliband.

Developers’ may still be denied the right of appeal, Miliband said, allowing councils to sit on applications even if communities were in favor.

“This will still leave onshore wind in a unique position in relation to planning, making it harder to build than incinerators or landfill sites,” he told BBC Radio.

Polls consistently showed onshore wind is “hugely popular with local communities,” industry group EnergyUK said.

“We urge the government to build on that support, and put in place a regulatory framework that ensures onshore wind projects vital to our energy security are not held back by regressive and outdated prohibitions,” it said.

Vattenfall’s Head of UK Onshore Development, Frank Elsworth, said communities had responded positively when they saw the investment, jobs and support for local businesses that projects brought.

“There does not need to be a one-size-fits-all approach to community engagement — the most successful projects are those that enable communities to help shape the way the wind farm will benefit the surrounding area,” Elsworth said.

Platts assessed the UK onshore wind renewable capture price at GBP295.88/MWh ($359/MWh) on Dec. 5. The assessment has been extremely volatile all year and is currently on an upswing, having fallen below GBP100/MWh during a mild, windy October, S&P Global Commodity Insights data showed.

NZ carbon auction clearing price falls for first time; market awaits rules for 2023


Clearing price slips to NZ$79/mtCO2e from NZ$85.40/mtCO2e

NZU prices in spot market up nearly 21% this year

Govt likely to accept CCC recommendations: sources

New Zealand concluded its last carbon allowance auction of the year on Dec. 7, with the auction clearing price falling for the first time ever as the market awaits the government’s decision on price setting for 2023.

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The auction clearing price for the allowances called New Zealand Units, or NZUs, fell to NZ$79/mtCo2e ($50/mtCo2e) from NZ$85.40/mtCo2e in the September auction, with the revenue generated falling 7.5% to NZ$381 million from a sale of 4.8 million units.

The clearing price has risen consistently since the first auction held in March 2021 and this was the first time it fell.

“There was kind of a debate in the market where it will clear. Many people felt it will clear lower than NZ$79/mtCo2e, so to clear at 79 is a good result,” Nigel Brunel, head of commodities and carbon trading at Jarden, said.

Expectations were for lower prices than in the September auction as the spot market price closed at NZ$82/mtCO2e on Dec. 6 and the auction clearing price is usually lower than the previous day’s spot price. While the spot price for NZU rose to a record high of NZ$88.50/mtCO2e in November, it has since fallen and has been trading lower for the last few weeks.

“Trading is fairly muted post the auction and was last at NZ$82/mtCO2e. This is almost the worst of all cases in that it gives no real direction,” Paul Burgin, trader at Carbon HQ, said.

Another trader said the spot market price was at $82/mtCO2e, but they did not do any deal at that price.

Despite the fall from its peak, the NZU has risen over 20% this year, outpacing allowance prices in Asia with Australia and South Korea down over 35% and 50%, respectively, while the relatively new China ETS price was up nearly 7%.

NZUs are distributed by the government through a mix of free allocations and four auctions in a year. The auction clearing price is the lowest successful bid at which NZUs are sold to all successful bidders.

Each NZU represents one metric ton of carbon dioxide equivalent emissions and can be traded by participants in the secondary market.

2023 reforms, prices

Market participants said the lower price was also the result of the government holding off on its decision to accept recommendations of Climate Change Commission (CCC) regarding ETS price settings for 2023.

CCC, an independent body tasked with advising the government on climate policy, earlier in 2022 recommended steep increases in the ETS price settings, which are expected to push the price of NZUs higher.

It recommended raising the auction reserve price to NZ$60/mtCO2e from NZ$30/mtCO2e currently, and the cost containment reserve trigger price to at least NZ$171/mtCO2e from NZ$70/mtCO2e currently.

The auction reserve price is the minimum price at which the NZUs can be sold to participants. The cost containment reserve trigger price leads to additional units released for sale to balance prices but the reserve has already been exhausted for 2022.

“The government hasn’t made its decision about the Climate Change Commission’s recommendations and the market got a bit tired waiting, so there was a bit of profit-taking,” Brunel said.

The government’s decision, due by the end of December, is expected to give a definitive direction to the market for the next year.

“If they don’t accept the recommendation, the price will possibly plateau, which will be terrible for the government. If they go with the extreme recommendations, there could be a spike,” Harrison Bissell, carbon broker with Carbon Market Solutions, said.

The price of NZUs is already one the highest in the world and the government’s decision could have a significant impact on the price trajectory for 2023. The government had last year accepted the CCC’s recommendations on price settings for 2022.

Unless there is some signal otherwise, the government is most likely to accept the CCC recommendations for next year, Bissell added. “I suggest the long-term players will be watching like hawks,” Burgin said regarding the government’s decision.

US pledges to export 9-10 Bcm of LNG to UK over next year under energy pact


US LNG important for storage filling in 2023: UK government

US supplied 9.1 Bcm of LNG to UK in Jan-Oct 2022

UK sees potential 8% gas demand reduction this winter

The US has pledged to export 9-10 Bcm of LNG to the UK over the next year as part of a broad energy security pact announced Dec. 7.

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Under the new UK-US Energy Security and Affordability Partnership, the two countries will “drive work to reduce global dependence on Russian energy exports, stabilize energy markets and step up collaboration on energy efficiency,” the UK government said.

The announcement comes after UK Prime Minister Rishi Sunak and US President Joe Biden met at the G20 Summit in Bali last month where they agreed to take forward work to address the UK’s short-term energy needs.

A potential commitment to 10 Bcm of US LNG deliveries to the UK in 2023 was widely reported ahead of the meeting.

The UK is far less reliant on Moscow for its gas than other countries in Europe, with Russian gas and LNG supplies making up less than 4% of UK supply in 2021.

In April, the UK announced its intention to impose a ban on Russian LNG imports.

Sunak said Dec. 7 the UK and US would “ensure the global price of energy and the security of our national supply can never again be manipulated by the whims of a failing regime.”

The initiative will be steered by a new UK-US Joint Action Group, led by senior officials from the UK government and the White House.

“The group will work to ensure the market delivers sustained increases in the supply of LNG to UK terminals from the US,” it said.

As part of this effort, the UK government said the US would strive to export at least 9-10 Bcm of LNG over the next year via UK terminals, more than doubling the level exported in 2021.

“This will be good for both UK and European partners as we look to replenish gas storage next year,” the UK government said.

Any US-UK commercial term or spot deal would have to be agreed by US LNG producers or offtakers and UK buyers, but the two governments plan to work to facilitate the supply arrangement.

“Both governments will work to proactively identify and resolve any issues faced by exporters and importers,” the UK government said.

In tandem with shoring up security of energy supply, the group will also work on measures to increase energy efficiency and reduce demand for gas.

“It is already estimated that there could be an 8% reduction in demand for gas in the UK this winter,” the UK government said.

US LNG imports

US LNG supplies to the UK have already risen strongly so far in 2022, with volumes totaling 9.1 Bcm of gas equivalent in the first 10 months, according to data from S&P Global Commodity Insights.

That compares with a total export volume of 4 Bcm from the US to the UK in the whole of 2021, the data showed.

The UK has large LNG import capacity at its three operational terminals — two at Milford Haven in Wales (Dragon and South Hook) and the Isle of Grain facility in southeast England — totaling more than 35 million mt/year (48 Bcm/year).

The US already pledged earlier this year to increase LNG supplies to the EU in 2022 by 15 Bcm and to deliver an additional 50 Bcm/year in subsequent years compared with 2021 levels.

The UK relies on imported gas to meet around half of its demand, with Norway the top supplier, accounting for some two-thirds of the UK ‘s imports last year, according to government data. LNG makes up the bulk of the remainder, but the UK is relatively exposed to the spot market for additional LNG purchases.

Spot gas prices across Europe hit record highs in late summer, while spot LNG prices also remain at sustained highs. Platts, part of S&P Global Commodity Insights, assessed the DES Northwest Europe marker for LNG delivery in January at $33.22/MMBtu on Dec. 6.

The US has been the main supplier of LNG to the UK in 2022 with its supply of 9.1 Bcm in the first 10 months, followed by Qatar (7.2 Bcm), according to data from S&P Global.

UK utility Centrica already has a long-term LNG purchase deal with US LNG producer Cheniere Energy signed in 2013. It loaded its first cargo from Cheniere’s export facility at Sabine Pass in Louisiana in 2019.

Under the terms of the agreement, Centrica purchases some 1.75 million mt/year of US LNG for an initial 20-year period, with the option for a 10-year extension. The agreement is on a FOB basis, giving it destination rights for the cargoes.

As well as the US, Qatar has also been front and center of UK efforts to lock in new long-term LNG supply deals and Qatari energy minister Saad al-Kaabi met in October with the UK’s Business Secretary at the time, Jacob Rees-Mogg.

Other energies

The UK government said Dec. 7 the new UK-US action group would also work to reduce global reliance on Russian energy by driving efforts to increase energy efficiency and supporting the transition to clean energy.

The group also plans to look to accelerate the development of clean hydrogen globally and promote nuclear as a secure source of energy. On nuclear, the UK and US will promote nuclear energy as a “safe and reliable” part of the clean energy transition, the UK government said.

“The partnership will also drive international investment in clean energy technologies, from offshore wind to carbon capture,” it said.

“This will complement the work the UK and US are doing together with G7 partners to support the use of clean and sustainable energy in developing countries.”

China slowdown sounds alarm bells for dry bulk market


Emission rules to spawn multi-tier freight market

Earnings may stay at par among various ship sizes

Grim economic outlook may weaken freight levels

This is the final story in a two-part series based on a survey by S&P Global Commodity Insights. You can read the first story here.

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Stormy seas lie ahead for the dry bulk market as the shipping industry comes to terms with the new environmental regulations being introduced by the International Maritime Organization in 2023, a survey by S&P Global Commodity Insights has found.

The new regulatory requirements such as the Energy Efficiency Existing Ship Index, or EEXI, and Carbon Intensity Indicator, or CII, are expected to create a multi-tier market based on ships’ ratings, fuel choices and performance.

The economic slowdown being faced by the world’s largest commodity consumer China is also weighing on the dry bulk freight market, along with the demand squeeze being seen in key dry bulk commodities that is impacting the earnings of bulkers across all sizes.

The survey has shown that the earnings in bulker sectors across Capesize, Kamsarmax/Panamax and Ultramax/Supramax may average around the same levels next year as in 2022 due to the subdued economic climate on the back of high interest rates and slow growth.

New regulation may forge multi-tiered market

The upcoming emission-related regulations are expected to create a multi-tier spot market for Supramax class bulkers, according to 56% of survey respondents.

It will be slightly different situation for the Capesize and Panamax ships, which tend to have longer ballast leg sailings than Supramaxess, which help them draw better environmental ratings based on the CII parameters.

“There has already been a two-tier market in the dry bulk segment for some time,” said maritime research consultancy Drewry’s Director-Deputy Head Maritime Advisors Jayendu Krishna.

“First, it was for eco- and non-eco vessels. That was followed by scrubber and non-scrubber vessels under high bunker price environment. Going forward, it will be for fuel oil-propelled single-fuel vessels versus dual-fuel vessels,” he added.

It could also result in a category of ships that could trade anywhere in the world, while others would be restricted to certain regions.

“However, the number of ships in those two categories will likely fluctuate and ships could jump between these groups,” said a shipbroker source, adding that the market has become convoluted in recent years.

According to a shipping executive with a mining major, charterers may not pay different voyage freight rates depending on the fuel used or the efficiency of the ship unless they have to. “I don’t think this could change at least until 2025,” the executive added.

A multi-tier market could pose many challenges for freight traders and market analysts as it would blur the ability to gauge market trends in the event of less liquidity within a specific tier, said Marc Pauchet, Director, Dry Bulk Research, at Maersk Broker.

Grim outlook may keep bulker earnings at parity

A volatile spot dry bulk market can be expected next year, with 40.54% of survey respondents saying they expect the earnings of all dry bulk segments to stay at levels close to each other in 2023.

Less than a quarter (22.52%) of participants expected vessel sizes and earnings would correlate, while 36.94% said the Supramax sector could continue to earn more than gearless vessels next year.

“If the overall dry bulk market is poor and stays close to operating expenses, which is what I expect for next year, then the contrast in time charter earnings won’t be much different across various segments of bulkers,” said the shipping executive with a mining major.

“But Supramax rates could increase if there is a ceasefire in Ukraine and there is reconstruction work,” the source added.

Some shipping industry watchers say commodities’ “love story with China” has come to an end, which has visibly impacted larger Capesize segment and to an extent the Panamax sector.

“Commodities like iron ore, aluminum and copper that have a large exposure to China have underperformed and impacted the Capesize freight rates,” said Rishi Nyati, Managing Director at Emarat Maritime.

“In the long-term, there is little doubt that China has peaked. Not too different from Japan in the late 1980s. Therefore, I feel commodities that are highly exposed to China will suffer in the long term,” Nyati added.

Over 2021-2022, high container rates have benefited the Supramax sector due to the de-containerization of cargoes. “But I believe the support Supramaxes saw from containerized cargoes is finished for the foreseeable future,” a shipping executive said.

There were also expectations among survey participants that the Ultramax and Supramax segments would continue to outperform the larger Panamax segment due to a drop in the movement of coal on the latter.

“China is importing less coal, while the surge in Europe has already taken place this year, and India’s [coal] demand will not be enough to compensate,” Pauchet said.

“I think the earnings of Handysizes, Supramaxes and Panamaxes will most likely be quite tight indeed, but I can’t see Capesizes re-correlating with the other three segments; they will carry on having a life of their own,” he added.

Some other market participants disagree, saying there will be times when the Capesizes may earn less than Supramaxes and Ultramaxes.

“But overall, I don’t think Supramaxes can average higher than Capesizes over the next year,” the shipbroker said.

Argentina’s YPF, Malaysia’s Petronas eye partners for $10 billion LNG terminal


Target is to build the terminal in five years

Floating liquefaction vessels could be used in near term

Project hinges on approval of a law to set stable conditions

Argentina’s state-backed energy company YPF and Malaysia’s Petronas plan to look for partners to help build a $10 billion liquefaction terminal and related infrastructure, a key for boosting output from the Vaca Muerta shale play, a company source said Dec. 6.

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The companies signed a memorandum of understanding for the project in September, saying that the target is to reach 25 million mt/year of LNG exports in 10 years.

The five-train liquefaction terminal will be built in Bahía Blanca, a port in southern Buenos Aires province, and will be supplied by a dedicated pipeline from Vaca Muerta in northern Patagonia, the source said.

YPF, the biggest gas producer in Argentina, and Petronas plan to look for partners for building and financing the plant in modules, helping to stretch out the capital requirements, the source said.

As a first step, the source said they will build the pipeline to deliver gas to two floating liquefaction terminals supplied by Petronas. The exports from these vessels will help bring in the revenue for paying for the construction of the onshore terminal, the source added.

A pivotal law

A key for moving forward with the project is the approval of a bill designed to promote investment in LNG export infrastructure.

“The bill is a priority,” the source said.

Without the legal, regulatory and tax stability that the law would provide, it will be hard to attract investors for the project and buyers for the LNG, the source warned. Argentina has a reputation for sudden changes in regulations and taxes that have made it difficult to fulfill export contracts or curbed profits, exposing sellers to legal challenges.

The source said the bill is expected to go to Congress during the extraordinary sessions that run from December to the end of February.

If the bill is approved, YPF and Petronas will sign a contract for the project and begin to arrange partners, including for supplying gas for export.

The possibility of exporting gas stems from the vast resources in Vaca Muerta, estimated at 300 Tcf. That is way more than the country can consume and will build on its current production of nearly 140 million cu m/d, which is in line with average annual demand.

More production growth is expected in Vaca Muerta as companies like Chevron, ExxonMobil and Shell develop new projects.

The Argentinian government has set a target of boosting gas production to 163 million cu m/d by 2026, and grow from there to supply an expected rise in demand for gas as a transition fuel for achieving net-zero carbon emissions by 2050. Most of the production growth is expected to come from Vaca Muerta.

India’s draft renewable hydrogen policy accentuates export opportunity


1.72 million/mt 2030 green H2 export

Roadmaps with France, Singapore

5 million mt/yr 2030 green H2 output goal

India’s upcoming renewable hydrogen policy is poised to encourage exports in anticipation of strong demand from countries with 2050 net zero targets, 20 years ahead of India’s own net zero commitment.

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A 2021 draft green hydrogen/ammonia policy seen by S&P Global Commodity Insights earmarks a figure of 1.72 million metric tonnes of renewable hydrogen for exports by 2029-2030.

“Earlier it was supposed to be about 50:50 [split between national use and exports], but now I think the major emphasis is on exports,” said Vivek Singla, President, Green Hydrogen at ReNew Power, a renewable firm planning hydrogen/ammonia/methanol projects in coastal locations in India.

An interim policy was released in February projecting a 5 million mt production target by 2030 for renewable hydrogen with incentives for producers including accelerated project approvals, cheaper power and access to land at ports.

Singla said it was expected the channel for conventional ammonia imports would be used to export renewable ammonia.

“Exports are likely to be a priority for earning foreign exchange, especially as India has a huge oil import bill and here is an opportunity to reverse it,” said Ankit Sachan, Hydrogen Analyst at S&P Global Commodity Insights.

Domestic deployment of hydrogen could also be delayed due to higher production costs and a 2070 net zero target, would give India additional time to transition, he said.

While India will target southeast Asian markets and Europe it is up against stiff competition from Australia and the Middle East, the latter already selling pilot cargoes of clean ammonia to Europe and Japan.

S&P Global Commodity Insights’ Hydrogen Production Assets database shows India has 54 renewable or low carbon projects with a combined projected capacity of 1.99 million mt, versus 137 Australian projects with a projected capacity of 9.84 million mt.

Platts, a part of S&P Global Commodity Insights, assessed Queensland hydrogen produced via PEM Electrolysis (including capex) at $5.75/kg Dec. 2, down 2% month on month.

It assessed Japan hydrogen produced via alkaline electrolysis (including capex) at $8.86/kg Dec. 2, down 1.56% month on month.

Early moves

India’s early export moves include Indian renewable firm Greenko and Singapore’s Keppel Infrastructure Holdings’ memorandum of understanding Oct. 25 to explore production and export opportunities, targeting a 250,000 mt/yr of renewable ammonia.

“The collaboration between Keppel Infrastructure and Greenko is set to support India’s goal to manufacture 5 million tonnes of green hydrogen per annum by 2030 and become a production and export hub,” the companies said.

Meanwhile on Oct. 18, an Indo-French Roadmap on the Development of Green Hydrogen was announced, aimed at establishing a “reliable and sustainable value chain for decarbonised hydrogen.”

“There are talks going on everywhere,” Prabhat Kumar, Additional Secretary in India’s Ministry of External Affairs said on Nov. 10 at the Energy Security Conference organized by Confederation of Indian Industries in New Delhi.

The draft policy is focused on setting up two green hydrogen production, use and export hubs, with refineries and fertilizer production units in close vicinity.

Green refueling hubs meanwhile are planned at all major ports, according to the draft.

The government’s proposed outlay in the Green Hydrogen Mission draft is Indian Rupees 301.55 billion ($3.69 billion) for 2022-23 to 2029-30.

A full-chain policy would also see India support domestic manufacturing of electrolyzers and other enabling technologies.

It seeks 24-GW/yr of electrolyzer manufacturing capacity and a 100 GW-130 GW installed electrolyzer capacity, both by 2030.

For feedstock, it seeks a 160 GW-200 GW installed renewable energy capacity for renewable hydrogen by 2030.

The draft says the government would offer Rupees 140.05 billion under Production-Linked Incentive Scheme to support indigenous electrolyzer manufacturing.

The base case scenario assumes an electrolyzer cost of $600/kW and a renewable energy price of Rupees 2.3/kWh.

The resultant renewable hydrogen cost would be Rupees 195/kg ($2.29/kg) in 2022-23, falling to Rupees 125/kg ($1.53/kg) by 2029/30.

TotalEnergies signs 10-year SAF deal with Air France-KLM


MOU involves access to more than 800,000 mt of SAF for 8 years

Air France-KLM also signed long-term agreement with Neste recently

Flurry of SAF deals have been seen so far in 2022

TotalEnergies has agreed to supply airline group Air France-KLM with more than 800,000 mt of sustainable aviation fuel, or SAF, over a 10-year period starting from 2023.

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The companies signed a memorandum of understanding Dec. 5 for it is one of the larger long term SAF supply deals seen in this nascent market.

SAF is a renewable alternative to traditional jet fuel, made by converting sustainable feedstocks into fuel. It is mostly manufactured from bio-waste, namely agricultural waste fats and/or oils, or residue raw materials.

More and more airlines are chalking up an increasing number of long-term SAF supply deals as part of their efforts to reduce carbon footprints.

The SAF will be produced at TotalEnergies’ biorefineries, and will be used by Air France-KLM Group’s airlines, mainly for flights departing from France and the Netherlands.

TotalEnergies aims to produce 1.5 million mt of SAF by 2030. TotalEnergies claims that the SAF it produces reduces “CO2 emissions by at least 80% on average over the entire lifecycle, compared with their fossil equivalent.”

“Air France-KLM is fully committed to advancing SAF production in Europe and around the world. This MoU… is another building block in the development of French production that can meet the airlines’ needs, marking a milestone in the successful decarbonization of our business,” said Air France-KLM CEO Benjamin Smith.

In late-October, Air France-KLM also signed a deal with Finnish refiner and clean fuels producer Neste for the delivery of more than 1 million mt of SAF, over a period of eight years starting in 2023.

The French energy major has already been supplying some SAF for a number of Air France-KLM Group commercial flights for the past two years.

SAF infrastructure

France is building more infrastructure to boost imports of sustainable aviation fuel, with notably the construction by Compagnie Industrielle Maritime of four dedicated tanks to blend SAF with jet fuel at the Le Havre terminal.

Only three countries in the world are currently applying a mandate for a minimum amount of SAF to be blended with fossil jet fuel: Sweden, Norway and France, with a minimum 1% of SAF in aviation fuel since Jan. 1, 2022.

The EU’s blending mandate will kick in in 2025, with a minimum 2% SAF, to be increased to 5% in 2030 and 63% in 2050. In the summer of 2021, SAF accounted for only 0.01% of total aviation fuel demand in Europe.

Air France-KLM hopes to reduce its CO2 emissions per passenger/km by 30% by 2030 compared to 2019, by using 10% SAF in its fuel needs by 2030.

Aircraft can currently only operate using a maximum 50% blend of SAF and conventional jet fuel known as Jet A1. But the amount of SAF that can be blended into Jet A1 depends on the purity of the initial petroleum-based product.

The SAF market remains tiny in comparison with the amount of jet fuel traded globally, and accounts for only 0.02% of global jet fuel use, according to estimates by S&P Global Commodity Insights.

But the SAF market is poised to grow steadily in the coming decades as the aviation and energy sectors collaborate more to reduce greenhouse gas and carbon emissions.

SAF prices are currently around two times higher than fossil fuel-derived jet fuel compared to two years ago when they were four times the price.

Platts assessed Northwest Europe SAF price at $2,166.819/mt on Dec. 2, S&P Global data showed. Platts assessed a conventional jet fuel cargo at $983/mt on Dec. 2, on an FOB Amsterdam-Rotterdam-Antwerp basis.

FEATURE: One year later, Australia’s international carbon scheme still a work in progress


Focus on capacity building, domestic market review behind delays

Indonesia, Vietnam under consideration as members: source

Finalization of scheme guidelines expected in 2023: experts

It has been more than a year since Australia launched the A$104 million ($70.9 million) Indo-Pacific Carbon Offsets Scheme to help neighboring countries generate credits for a fast-growing Australian carbon market, but ongoing domestic policy reforms and a shift in focus to capacity building have slowed the momentum.

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The Indo-Pacific Carbon Offsets Scheme (IPCOS) was launched by Australia in November 2021 during the COP26 UN Climate Change Conference to help enhance the capacity of partner countries in the Indo-Pacific region to participate under Article 6 of the Paris Agreement, and for the generation and trade of high-integrity carbon credits.

As part of the scheme, Australia signed agreements with pacific island countries Fiji and Papua New Guinea in November 2021 to help Australia’s private sector meet its emissions reduction targets by enabling investment in carbon projects in these countries.

The price of Australian Carbon Credit Units (ACCUs) has trended higher than the global voluntary market carbon credits, raising the possibility of higher returns for member countries. The price of a generic ACCU was at around A$32/mtCO2e, according to market sources. Platts, part of S&P Global Commodity Insights, assessed the price of nature-based avoidance carbon credits at $12.35/mtCO2e on Dec. 1.

Slow momentum

However, with another climate conference wrapping up in Egypt, the momentum has slowed following the initial agreements. Papua New Guinea’s decision to place an interim ban on exports of carbon credits has created further uncertainty.

“The IPCOS program direction has shifted from the previous government’s focus on credit generation for a voluntary market in addition to supporting partner countries in building capacity for international cooperation, to one primarily focused on capacity building at this stage,” said Mei Zi Tan, manager, international research and projects at Carbon Market Institute, an Australian carbon industry association.

This change in direction has delayed the progress on draft guidelines for use of such credits, Tan told S&P Global, adding that ongoing reforms to the country’s compliance emissions trading scheme, Safeguard Mechanism, as well as a review of Australian Carbon Credit Units (ACCUs) has also slowed action on the scheme.

“How carbon offsets generated under IPCOS are used in Australia in the future may be subject to government consideration following the finalization of policy reviews and reforms, including the Climate Change Authority’s Review of International Offsets, ACCU review and the Safeguard Mechanism reforms,” a spokesperson from Australia’s Department of Climate Change, Energy, the Environment and Water (DCCEEW) told S&P Global.

Australia’s Climate Change Authority, an independent body tasked with advising the government on climate change policy, published a report in August on the criteria for acceptance of international carbon credits under IPCOS within Australia.

The report recommended that the IPCOS design should align with Article 6 of the Paris Agreement by applying robust accounting to ensure the avoidance of double counting.

It also recommended that the projects should endeavor to deliver non-carbon co-benefits to partner countries, thus contributing to sustainable development goals alongside emissions reductions.

The government is due to respond to the CCA’s report by February 2023 and has recognized the importance of high integrity of carbon credits.

“IPCOS is not participating in a race to purchase cheap abatement. It is a 10-year, demand-driven program to build the region’s capacity to participate in high-integrity international markets and help partners meet their Nationally Determined Contributions,” DCCEEW spokesperson said in a statement.

IPCOS is currently more pitched at general capacity building around markets for Small Island Developing States, Daniel Lund, special adviser on climate action to the Fijian government, said.

The slow progress comes amid heightened bilateral activity between other Asia-Pacific countries such as South Korea, Japan and Singapore. Papua New Guinea in November became the 25th country to participate in Japan’s cross-border carbon trading scheme, Joint Crediting Mechanism.

2023 outlook

While the scheme did not add any new members during 2022, market experts and the government have said that negotiations were ongoing, with the entry of more partners and progress in the framing of guidelines expected during 2023.

“Vietnam has been added to the IPCOS list, aside from Indonesia,” a market source told S&P Global based on interaction with government officials.

“To our understanding, several countries have expressed interest in partnering with Australia and the negotiations are ongoing. Work is continuing with announced partners in PNG and Fiji where separately CMI is, with DFAT support, assisting Fiji with the preparation of a Carbon Market Roadmap,” Tan said.

While there has been no progress on IPCOS for some time, activity is expected in the next six months, said Anil Bhatta, managing director at Carbon & Clean Energy Solutions, an environmental consultancy.

He expected to see IPCOS projects on the ground in PNG and Fiji before any other country.

“In the coming months, there will be more capacity-building work, and the IPCOS design should be finalized,” Bhatta added.

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