Energy Transition Archives

US Interior boosts investment in plugging orphaned oil, gas wells on public lands

Philippines’ First Gen Corp aims to start commercial operations at its inaugural offshore LNG receiving terminal in Batangas in early October and is currently negotiating to finalize medium-term LNG supplies until 2027, company Chief Commercial Officer Jon Russell told S&P Global Commodity Insights in an interview.

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The company is also attracting a “high level of interest” for the invitation bid launched June 1 for its initial commissioning cargo, Russell said.

“The Philippines is a relatively new entrant in the LNG market. I think there has been a lot of interest from potential sellers in finding an opportunity to play a role in this new market,” Russell said. “We are all trying to find our feet.”

The First Gen terminal, the second LNG terminal in the Philippines, is starting operations at a time when production at the country’s indigenous Malampaya gas field is declining rapidly, making the development of LNG infrastructure imperative.

First Gen, the largest user of natural gas in the Philippines, has a contractual obligation to draw gas from Malampaya until early 2024. However, First Gen has indicated that it is open to extending those contracts, Russell said.

“It’s been a difficult period for buyers, and we are pleased to see on behalf of the Philippines that LNG prices have become a little bit more realistic of late… We are also hopeful that from 2026 onwards, prices would be more reasonable and supply more plentiful for buyers like us,” Russell said.

Asian LNG spot prices hit a record-high of $84.762/MMBtu on March 7, 2022, reflecting the impact of the Russia-Ukraine war, but have weakened now. Platts assessed the July JKM at $9.001/MMBtu and August JKM derivatives at $9.46/MMBtu June 8, according to S&P Global data.

When it comes to pricing the company’s medium-term contracts, it has not ruled out traditional oil-linked contracts, Henry Hub or novel featuresif those are on the table, Russell said.

The company’s subsidiary FGEN LNG Corp has already executed a five-year time charter for the FSRU BW Batangas that will be deployed at the First Gen Clean Energy Complex in Batangas City for LNG storage and regasification.

First Gen’s existing liquid fuel jetty, used to bring in condensates to stem any potential outages of Malampaya gas, has now been converted into a multi-purpose jetty, Russell said.

“After the upgrade, the jetty is much bigger and can handle FSRUs and LNG carriers to take regasified LNG onshore to be used directly by our power plants,” Russell said, adding that the jetty is also connected to an existing gas grid, allowing LNG and Malampaya gas to be co-mingled.

BW Batangas, formerly BW Paris, is due to arrive at the complex around June 14, Russell said, adding that the FSRU will be taken to Subic to carry out a ship-to-ship transfer with a single cargo before it returns for commissioning.

First Gen has already invited bids for an LNG cargo of around 154,500 cu m, subject to an operational tolerance of plus/minus 3%, for August-September delivery.

“We want to use the cargo to show that the terminal works and to demonstrate that the gas plants work on a range of fuels because there is a big difference in the calorific value between the fuels,” Russell said.

“First Gen decided to proceed with this development before the normal contracts were in place because we had existing capacity,” he said.

By 2030, the company aims to increase its installed power capacity to 13 GW through gas, hydro, geothermal, wind and solar, Russell said.

“We have big plans to add additional gas plants. 1.2 GW can be realized quickly,” Russell said, adding that “we are also looking to subsequently add another 3-4 GW at additional sites in various parts of the Philippines including Luzon.”

Small-scale LNG

Malampaya was developed with the idea that it would be a growing market for gas. However, historically the use of Malampaya gas has been limited to a few power plants because as a pipeline gas it was relatively expensive, and it was not that easy to develop a gas grid, making it challenging to capture non-power customers, Russell said. Still, power generated using Malampaya gas has always been competitive, he said.

“Except for the recent period following the invasion of Ukraine, the price of LNG has been broadly comparable with the price of Malampaya gas over the long term,” Russell said.

According to Russell, LNG “opens new possibilities and can displace the liquid fuels market throughout the Philippines quite easily.”

In addition to ensuring energy security, LNG will also help Philippines decarbonize by providing an alternative to coal and enable the ramp up of more intermittent renewables such as solar and wind, Russell said. Opportunities to develop small-scale LNG also exist.

“We certainly are looking to develop the small-scale LNG market by making a provision for LNG trucking for supplying onshore,” Russell said, adding that it was drawing interest from potential customers.

“We are also looking at small scale LNG supplied on the vessel side, using special vessels to be able to take LNG in smaller parcels to other parts of the Philippines. So, I think that market will develop too,” he added.

Onshore LNG terminal

The company could also revisit its plans for constructing an onshore terminal, a plan that was envisaged in 2012, with an initial targeted capacity to handle 3.5 -4 GW, or about 3 million-5 million mt/year of LNG, Russell said.

“We went quite a long way down the track in developing that,” with several rounds of FEED and an EPC process but “paused” and pivoted towards a floating solution as it could be realized more quickly and with lower capital expenditures, Russell said.

However, the company’s current site is expandable and can add two 200,000 cu m storage tanks if required, he added.

Whether First Gen would build the full initially contemplated terminal or a variation of that would be reevaluated in the future, depending on signs of emerging gas demand and after more clarity emerges in regulatory policies and in the refinement of offtake contracts, he said.

Port Arthur asks US FERC to act on Phase II LNG expansion, after second review

Highlights

Nonprofit groups, EPA, push FERC on air impacts

Debate over environmental justice impacts

Sempra Energy is asking the US Federal Energy Regulatory Commission to act promptly on its application to double the capacity at its Port Arthur LNG facility, pushing back on environmental advocates faulting the regulator’s second environmental analysis released in May.

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The developer argued that additional concerns raised by the groups are misplaced — regarding air quality, water quality, erosion, vessel traffic and fisheries impacts in FERC’s assessment. The expansion project has already been “inexplicably delayed” since its application was filed in February 2020, Sempra told the regulator.

Launched in February 2023, FERC’s supplemental environmental assessment for the approximately 13.5 million mt/year Phase II expansion delved into environmental justice, air quality and climate change impacts — two years after FERC released the first environmental assessment.

The added review arose as the commission has come under increasing pressure to take into account impacts of concentrating multiple major LNG facilities along the US Gulf Coast, particularly if sited near communities already facing pollution from numerous industrial sources. FERC Chairman Willie Phillips, like his predecessor Richard Glick, has promised to elevate attention to environmental justice matters in FERC’s deliberations.

Countering requests for another public hearing, Sempra is arguing the review has already stretched too long.

“Review and public scoping for the proposed Expansion Project have been underway for approximately four years,” Port Arthur said in June 7 comments, noting pre-filing review started in June 2019.

“Each of the environmental assessments has concluded that approval of the Expansion Project, with the recommended mitigation measures, would not constitute a major federal action significantly affecting the quality of the human environment,” the developer said. It also pointed to recent comments in the record from residents and community leaders supporting the project.

Environmental advocacy

The US Environmental Protection Agency’s Region 6 office was among commenters in late May pressing FERC to look further into impacts on communities facing cumulative health hazards from prior pollution.

While FERC’s supplemental assessment found the increased cancer risk from the expansion project is 0.009% to 0.09%, and therefore not significant, EPA’s Region 6 said such an evaluation does not fully account for cumulative impacts and the “atypically over-burdened conditions” that the existing population faces.

Because of the high number of industrial sources in the area, the Region 6 office said more emphasis should be placed on analyzing existing pollutant concentrations and health risks. It said it believed that is needed even though the expansion project’s contributions to exceedances of National Ambient Air Quality Standards are below the so-called significant impact level, or SIL.

Environmental justice advocacy group Port Arthur Community Action Network also urged FERC to further evaluate air quality in the context of health challenges faced by Port Arthur residents, in May 30 comments. It noted that the EPA is in the process of re-evaluating and proposing lower NAAQS limits.

In PACAN’s view, the project’s nitrogen oxide emissions should be considered significant, and it called into question FERC’s reliance on a Texas air permit, contending the Texas Commission on Environmental Quality overrode an administrative law judge’s recommendations in favor of lower emissions limits for the project. PACAN has appealed the Texas air permit in the US Court of Appeals for the 5th Circuit.

Further, Environmental Integrity Project, on behalf of a handful of groups, objected FERC’s acceptance of the lack of a Section 401 water quality certification for the expansion.

Port Arthur response

Port Arthur countered many of those views in its comments June 7.

FERC should give deference to the determination from Texas regulators that no further water quality review for the expansion project was needed, after it already reviewed the base project, Port Arthur said.

And it asserted that PACAN’s assertions on air quality “ring especially hollow” after its “unsuccessful” litigation of the same issues in a state evidentiary hearing.

“PACAN’s full and fair opportunity to litigate its concerns before an impartial, state decision maker bears on the commission’s review of PACAN’s comments here,” Sempra argued. The group’s appeal of the Texas finding focused narrowly on emissions limits for refrigeration compression turbines, it said.

As for EPA, it said “Region 6’s generalized comments do not acknowledge the Expansion Project’s contribution to any NAAQS exceedances were shown to be trivial.”

And it pointed to existing EPA and state rules that rely on the SILs as benchmarks.

“[A] modeling analysis that demonstrates the source under review does not result in modeled concentrations greater than SILs, by extension demonstrates that the source will not cause or contribute to a violation of the NAAQS and will therefore not be adverse to public health, including the health of even the most sensitive individuals with an adequate margin of safety, including children, the elderly, and people with pre-existing medical conditions,” it said.

Corresponding adjustments should not be enforced in voluntary market: Verra, ICVCM

Highlights

Article 6, VCM fundamentally different systems

Freeing obligations key to reducing risk

Corresponding adjustment should be optional

Corresponding adjustment, a fundamental requirement for carbon trading between countries under Article 6 of the Paris Agreement, should not be obligatory in the voluntary carbon market, executives from Verra and the Integrity Council for the Voluntary Carbon Market said June 8 at the GenZero Climate Summit in Singapore.

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Article 6 requires corresponding adjustments to be made when a country buys carbon credits from another country to fulfill its climate targets, known as Nationally Determined Contributions. Trades in the voluntary carbon market, however, usually take place between non-governmental entities, namely corporates with voluntary commitments.

There has been a heated debate in the carbon industry as to whether the VCM should be Article 6-compliant, especially when it comes to multinational companies buying voluntary credits to offset their operational emissions across national boundaries.

David Antonioli, CEO of the world’s largest VCM carbon credit issuer, Verra, and Pedro Barata, Co-Chair of Expert Panel with ICVCM, which sets the code of conduct for VCM suppliers, both highlighted fundamental differences between the VCM and Article 6, and called for the freeing of the VCM from corresponding adjustment obligations.

Overcoming uncertainties

The debate has triggered regulators in project host countries to re-evaluate the workings of the voluntary market after being told to make corresponding adjustments on VCM credits generated in their territories, and consequently giving up the right to claim the credit for the host country’s NDC.

This has led to disruptive policies and even direct bans on VCM carbon credit exports, with the resulting regulatory uncertainties putting VCM project investment at significant risk.

“Some people argue that, given that they have not managed to win the argument in the Global North, the governments of the Global South should be enforcing corresponding adjustments for any international transaction. I find that very disturbing,” ICVCM’s Barata said.

“I won’t talk about carbon colonialism or nationalism, but I think it is a bit cheeky to ask the Global South governments to enforce something that the Global North is not doing,” he said.

“When Amazon invests in electrifying its vehicle fleet in the United States, which reduces emissions in the United States, nobody says the US need to make a corresponding adjustment,” Nathaniel Keohane, President of the Center for Climate and Energy Solutions (C2ES), said at the conference.

“That’s a precisely analogous case. I think this gets to the point about where the double standard starts,” he said.

There was considerable interest in many countries to leverage the VCM to help drive economic activity, Verra’s Antonioli said.

“If we required a corresponding adjustment, that would up-end that whole opportunity that we have in helping to drive finance to help countries get on a sustainable path,” he said.

An option, not a must

Antonioli said buying correspondingly adjusted carbon credits should be an option instead of an obligation for companies.

“A company that’s buying and retiring carbon credits isn’t necessarily reporting to the country where it operates. It’s a very different accounting system [compared with country-level emission accounting under Article 6],” he said.

The Verra official advocated VCM participants adjusting their claims. “If you have a corresponding adjustment, you can make a certain claim. And [if] you don’t have a corresponding adjustment, you make a slightly different claim. I think we just need to be transparent about that,” he said.

Some argued that, without mandatory corresponding adjustment of VCM credits, the private sectors’ carbon finance may benefit host countries with less ambitious NDCs, ICVCM’s Barata said.

“They’re putting up this scary story that somehow countries will be freezing their ambition because of the potential for massive floods of finance coming from the voluntary carbon market. I don’t think that’s how government entities act in any part of the world,” he said.

Alternative Marine Fuels: Monthly Market Indicators

Highlights

IMO to hold 80th session of Marine Environment Protection Committee July 3-7

Allegations of fraudulently-certified European biodiesel imports from Asia puts downward pressure on May/June prices

Global alternative marine fuel markets have been a hot topic at Oslo’s Nor Shipping Trade Fair, with Greek shipowner Angelicoussis Group teaming up with Chevron to explore ammonia as marine fuel, and Fortescue Metals Group planning to promote a worldwide carbon tax on shipping.

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SHIPPING

Member states of the International Maritime Organization are aiming to finalize new greenhouse gas emissions targets and regulations in early July, which are meant to provide market signals to industry stakeholders to invest in sustainable fuels, Secretary-General Kitack Lim said June 5 at the Nor Shipping event in Oslo. The UN’s shipping agency will hold the 80th session of Marine Environment Protection Committee July 3-7, where some 170 countries are expected to conclude a Revised Greenhouse Gas Strategy for the coming decades. The IMO has set targets to reduce the carbon intensity of international shipping by 40% by 2030 and to halve emissions by 2050 from 2008 levels, but environmentalists and shipping industry participants said those do not align with the Paris Agreement’s climate goal to avoid climate disaster.

METHANOL

Methanol’s application as a marine fuel continued to grow. Stena Line ordered two hybrid propulsion ships capable of running on methanol as part of its efforts in shifting to renewable fuels to meet future decarbonization targets. Trafigura suggested hydrogen has a low volumetric energy density and needs to be processed into e-methanol to be feasible for the shipping industry. Platts, part of S&P Global Commodity Insights, will launch daily production cost-based renewable methanol prices for North America, Europe and Asia, in response to market feedback and maritime industry’s need for price valuations for sustainable methanol, effective June 19, Platts announced on May 31.

LNG

LNG bunker prices in Europe fell in line with European LNG values. The Rotterdam LNG bunker fuel price was assessed at $11.805/MMBtu June 6, down $2.405/MMBtu compared to May 5. It also hit a two-year low since June 4, 2021, when it was assessed at $11.707/MMBtu. Looking ahead, 19 vessels with alternative fuel propulsion were ordered in May, according to data from DNV’s Alternative Fuels Insight (AFI). Seven LNG-fueled vessels and 12 methanol vessels were ordered in May. Platts launched one assessment for LNG bunker fuel at Port Sines on May 1, to complement its price assessments at Rotterdam, Singapore, and Jacksonville.

AMMONIA

Low-carbon ammonia market activity continued to be heard in May and early June, with producers bidding $400/mt for Northwest Europe renewable-power derived ammonia (green ammonia), but offering at $700/mt. This was lower than April’s offers heard at around $800-1200/mt while April’s bid was almost unchanged at $400-500/mt, reflecting an ongoing weaker ammonia market. Conventional ammonia for Northwest Europe spot deliveries averaged $368.60/mt in May down from April’s average of $407.50/mt. Prices continue to weaken with S&P Commodity Insights assessing CFR spot for Northwest Europe at $360/mt June 7. Fortescue Metals Group plans to promote “green ammonia” as marine fuel globally and wants a worldwide carbon tax on shipping to make the zero-emission fuel commercially competitive, Executive Chairman Andrew Forrest said June 6. Many shipping professionals said ammonia generated from renewable hydrogen is a strong candidate for a future fuel, but ammonia-fueled marine engines are not expected to be technically ready until 2024-2025. “We are developing ammonia fuel, and ammonia bunkering around the world,” Forrest said at the Ocean Leadership Conference in Lillestrom, part of the Nor-Shipping event.

BIOFUELS

In European biodiesel, the market continues to respond to allegations of fraudulently-certified imports from Asia that have put downward pressure on prices in recent months. Prices have seen some recent recovery, but buyers report lower confidence in advanced biodiesel and feedstocks. There have been reports of slowing production amid low prices and high supply, but crop-based production margins have seen some support from lower rapeseed prices.

In its Transport in Transition report published last month, DNV expects the shipping energy mix to compromise 50% low- and zero-carbon fuels mainly based on renewable hydrogen. Based on DNV’s study, global production capacity of sustainable biofuels could grow from 11 million mt of oil equivalent currently to 23 million mtoe by 2026 before a further increase to somewhere between 500 million mtoe and 1.3 billion mtoe by 2050. However, the shipping industry would need to consume 250 million mtoe/year by 2050 if it was to fully decarbonize primarily using biofuels, according to DNV.

Platts, part of S&P Global Commodity Insights, launched a new blended bio-bunkers assessment in Singapore called Platts Bio-Bunkers B24 Singapore (ABUNA00), effective May 8, 2023. The new Singapore delivered B24 bio-bunkers calculated assessment reflects a ratio of 76% fuel oil based on Platts benchmark Marine Fuel 0.5% Bunker Dlvd Spore $/mt assesses. Platts also launched four assessments for biofuel B35 in Indonesia.

INTERVIEW: Tokyo Gas mulls new LNG supplies, long-term contract renewals as net-zero looms: CEO

Tokyo Gas will seriously weigh up whether to renew long-term LNG supply contracts over the coming years and consider new supply options even as 2050 net-zero targets come more into focus, the new head of the Japanese utility said.

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“We will be entering a phase to give serious consideration for [expiring contracts] with various projects,” Tokyo Gas President and CEO Shinichi Sasayama said in an interview with S&P Global Commodity Insights.

“Our procurement department should be initiating talks with several [suppliers] and listing up [contracts for talks] but we are not in a situation to decide immediately because we still have time by 2030,” said Sasayama, who took the helm of the largest Japanese city gas utility April 1.

Speaking at the company’s head office in Tokyo, Sasayama highlighted the quandary the company faces in seeking a balance between limiting its exposure to LNG supply risk and price volatility while moving towards decarbonization under Japan’s national target of reaching net zero by mid-century.

“What agonizes us is because traditional long-term contracts span over 20 years, if we sign 20-year contracts [for LNG supply] from 2030, we will be in 2050 when we need to be net-zero by then,” Sasayama said.

Most recently, Tokyo Gas let a 10-year contract to import 1 million mt/year of Brunei LNG expire at the end of March.

Enhancing trading

Looking ahead, Tokyo Gas will explore new LNG supply sources in “North America, Asia, Australia, the Middle East and Africa” in addition to its new supply commitments with LNG Canada and Mozambique LNG projects, Sasayama said. “We are in the midst of considering a wide range [of supply options],” he added.

During three years to fiscal year 2025-26 (April-March), Tokyo Gas aims to boost its LNG trading capability, particularly in the European and Atlantic markets.

“We are working to strengthen our [LNG] trading in the form of asset optimization and trading,” Sasayama said. “For instance, we bring our North American LNG to Europe instead of bringing it to Japan, and bring [cargoes] held by European [companies] in Asia to Japan for locational swaps to cut freight costs.”

“Such locational swaps do not only cut freight costs but also shorten ship delivery periods that would eventually improve our ship operations and stabilize our supply and demand balance,” Sasayama said.

Tokyo Gas operates a fleet of 10 owned-and-controlled LNG carriers and holds a combined LNG storage capacity of 3.45 million kl (3.45 million cubic meters) over four import terminals in eastern Japan.

The company also intends to further utilize its LNG storage capacity to be able to stock up on LNG when the market is cheap and cut back its purchasing when the market is expensive, using steps including time-swaps, Sasayama said.

Australian policy concerns

Tokyo Gas, which sources over half of its annual imports of more than 12 million mt from Australia, is cautiously monitoring a series of policy changes in the country, Sasayama said.

While the Australian Domestic Gas Security Mechanism reform, which came into force April 1, is not expected to impact LNG liftings under long-term contracts, Sasayama said the company “would be extremely concerned” if it caused disruptions to the company’s stable supply because of the nature of “various contractual forms for short-term contracts.”

The ADGSM reform allows the government to prioritize supply to the domestic market should it perceive any gas shortages in the country.

On reforms to Australia’s Safeguard Mechanism for reducing emissions at large industrial facilities coming into force July 1, Sasayama said that the possible impact on new LNG projects coming online in the country was a potential concern.

The Safeguard Mechanism applies to industrial facilities emitting more than 100,000 mt/year of CO2 equivalent, including in oil, gas production and mining and is expected to require offsetting of CO2 emissions through steps such as purchasing carbon credits and carbon capture and storage.

“With various long-term [LNG] contracts up for renewal talks before and after 2030, I believe starting up new projects in Australia would contribute to easing the supply and demand balance,” he said. “So if [the mechanism] hinders starting up new projects in Australia, it would raise concerns on the supply and demand sides in the long run because I believe those new projects would contribute to easing the supply and demand balance,” he said.

E-methane in the US

Tokyo Gas, meanwhile, is embarking on developing its supply chains of e-methane produced from using CO2-free hydrogen and CO2 as part of its decarbonization efforts, with the company having already established its production and scale-up technologies, Sasayama said.

Securing competitive hydrogen remains a key hurdle to overcome through securing sites accessed with cheap renewable energy sources and CO2 emissions, he said.

Together with other Japanese city gas utilities, Tokyo Gas sees a proposed project using the existing Cameron LNG facility in Louisiana as competitive, given its abundant access to renewables and relevant facilities, Sasayama said.

“For this one, we are considering making an FID [final investment decision] in the end by around 2025,” he said, adding that the decision would be taken together with Osaka Gas, Toho Gas and Mitsubishi.

The project envisages production of 130,000 mt/year of e-methane in the US by 2030, which would be liquefied at the Cameron LNG facility then exported to Japan.

The 130,000 mt/year of e-methane production is equivalent to 1% of the total combined annual city gas demand of Tokyo Gas, Osaka Gas and Toho Gas, which aim to introduce 1% e-methane into city gas sales in 2030.

Mitsubishi participates in the Cameron LNG project via Japan LNG Investment, a 70:30 joint venture between Mitsubishi and NYK Line, which holds a 16.6% stake in the project. Tokyo Gas also lifts around 720,000 mt/year of Cameron LNG under a long-term contract.

Sasayama also said that Tokyo Gas is looking at the possibility of bringing e-methane to Japan by blending it into LNG cargoes from the Cameron project.

Norway gives Aker BP go-ahead for Alvheim oil tie-in Tyrving

Highlights

Latest tie-in project estimated at 25 million boe

Alvheim area to produce over 1 billion boe to 2040

Low-sulfur medium grade boosted by Urals curbs

Norway’s authorities have given the go-ahead for the latest in a series of oil tie-in projects by Aker BP aimed at boosting production from the Alvheim hub, which the company has plans to keep in operation until 2040, it said June 8.

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In a statement, Aker BP estimated reserves from the Tyrving tie-in project, previously known as Trell & Trine, at 25 million barrels of oil equivalent, and the cost of the three-well project at $700 million, saying the field would come on stream in the first quarter 2025.

Alvheim, with various existing tie-ins, loads from a floating production, storage and offloading vessel in the North Sea, with recent loadings in the region of 50,000 b/d. Gas is sent to the UK via the Scottish Area Gas Evacuation pipeline.

The crude is medium in gravity, unlike typical North Sea grades, with an API metric of 32.5, and is also low in sulfur.

Aker BP — which has engineering company Aker and BP as its largest shareholders — has cited refiners buying Alvheim as an alternative to Russia’s Urals; in the aftermath of the invasion of Ukraine, CEO Karl Johnny Hersvik cited premiums to Dated Brent in a range of $4.50-$9.50/b for the grade.

The company estimated the new crude stream would come with a low CO2 footprint of 0.3 kg per barrel of oil equivalent produced.

The company launched production from another Alvheim tie-in, Frosk, in March, estimating resources there at 10 million boe. Another Alvheim tie-in, Kobra East & Gekko (KEG), is under development and due on stream in the first quarter of 2024.

Alvheim expectations

Originally developed by US company Marathon Oil, the Alvheim area has produced triple the original projection of 171 million boe, and the goal is for volumes from the production vessel to eventually exceed 1 billion boe, Aker BP said.

Marking the 15th anniversary of production at Alvheim, Aker BP described it as one of Norway’s most successful oil and gas developments.

“I am very pleased to see utilization of existing infrastructure to increase production of oil and gas,” Petroleum and Energy Minister Terje Aasland was quoted by the company as saying. “This extends the lifespan of important fields… at a time when Europe needs all the energy we can supply.”

Aker BP’s senior vice president responsible for Alvheim, Ine Dolve, said: “New discoveries and fields linked to the Alvheim FPSO contribute to the fact that we are now planning operations until 2040 and have an ambition for the vessel to process a billion barrels before we shut down.”

“It is people and technology, not luck, that has made Alvheim the success story it is today,” she said. “The subsurface is challenging with many thin oil zones. The high recovery rate we have achieved is to a large extent attributed to a world-class subsurface team, drilling engineers and operations personnel.”

Platts, part of S&P Global Commodity Insights, assessed North Sea benchmark Dated Brent at $76.71/b on June 7, up 42 cents on the day.

Dubai’s Kent awarded large UK electrolytic hydrogen FEED contract

Highlights

Six Grenian Hydrogen projects linked to HyNet

Studies prepare sites for final investment decisions

30-MW Protos electrolyzer shortlisted for LCHA

Dubai-headquartered engineering firm Kent has been appointed as front-end engineering and design (FEED) contractor for Grenian Hydrogen’s six electrolytic hydrogen projects in northwest England and north Wales, Kent said June 7.

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The projects, ranging from 10 MW to 30 MW, are located at the Protos Energy Park in Cheshire and large manufacturing plants in St Helens (Liverpool), Stretford (Manchester), Middlewich and Winnington (Cheshire). Grenian is also developing projects in Wrexham, north Wales, and in Speke, Liverpool.

FEED studies will develop sites “such that related final investment decisions can be made to progress each of the projects to execution,” Kent said.

Grenian Hydrogen, a joint venture between Progressive Energy, Statkraft and Foresight, has been awarded funding under the government’s Net Zero Hydrogen Fund and Hydrogen Business model to develop six green hydrogen projects within the HyNet cluster in northwest England and north Wales.

“The Department of Energy Security and Net Zero’s funding requirements impose a strict budget and tight timescale,” said Matt Wills, Market Director Low Carbon at Kent. The contractor’s prior work with HyNet and its hydrogen technology expertise would help it meet FEED project goals, he said.

“This cluster of projects is a huge step forward for the future viability of green hydrogen,” he added.

HyNet comprises full value chain infrastructure to produce, transport and store low carbon hydrogen across the northwest of England.

Partners to the project include Eni, Essar and Cadent, while 40 organizations have signed up to decarbonize via HyNet projects.

These include Grenian’s flagship 30 MWe Cheshire Green Hydrogen at Peel’s Protos site near Ince, which has been short-listed by the government for a 15-year Low Carbon Hydrogen Agreement (LCHA).

The agreements are to support selected producers via a premium payment, calculated as the difference between a strike price (reflecting a unit cost of production negotiated on a project-by-project basis) and a reference price (based on the price of hydrogen sold, with a floor at the natural gas price).

Platts, part of S&P Global Commodity Insights, assessed the price of hydrogen (UK PEM electrolysis, including capex) at GBP5.54/kg June 6.

FEATURE: China sets sights on overseas alumina projects to unlock bauxite deposits

Highlights

Six Grenian Hydrogen projects linked to HyNet

Studies prepare sites for final investment decisions

30-MW Protos electrolyzer shortlisted for LCHA

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FEED studies will develop sites “such that related final investment decisions can be made to progress each of the projects to execution,” Kent said.

“This cluster of projects is a huge step forward for the future viability of green hydrogen,” he added.

HyNet comprises full value chain infrastructure to produce, transport and store low carbon hydrogen across the northwest of England.

Partners to the project include Eni, Essar and Cadent, while 40 organizations have signed up to decarbonize via HyNet projects.

These include Grenian’s flagship 30 MWe Cheshire Green Hydrogen at Peel’s Protos site near Ince, which has been short-listed by the government for a 15-year Low Carbon Hydrogen Agreement (LCHA).

Platts, part of S&P Global Commodity Insights, assessed the price of hydrogen (UK PEM electrolysis, including capex) at GBP5.54/kg June 6.

EU carbon tax, SAF mandates may divert airline traffic to Switzerland, UK: IATA

Highlights

Airlines need to only pay global, not regional taxes

SAF mandates create cartels, prohibit competition

Required SAF investments a third of fossil fuel investments

The Europe Union’s carbon taxes and mandates for using sustainable aviation fuel are likely to hike operational costs for airlines that may choose to fly instead to nearby countries such as Switzerland, the UK and Turkey, an official from the International Air Transport Association told S&P Global Commodity Insights.

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From 2026, the EU will apply its Emissions Trading Scheme, or EU ETS, not just to flights within the bloc, but also to flights entering or leaving it, according to a decision taken earlier in 2023, unless the Carbon Offsetting and Reductions Scheme for International Aviation, or CORSIA, becomes stricter.

In April, the EU also passed the ReFuelEU aviation initiative that requires fuel suppliers to blend SAF in increasing amounts, from 2% of overall fuel supplied by 2025 to 70% by 2050.

EU ETS and the SAF mandates will amount to higher costs for flying into Europe and airlines will try to avoid paying these taxes, Marie Thomsen, IATA’s senior vice president of sustainability and chief economist said in an interview on the sidelines of the organization’s general assembly in Istanbul on June 5.

“I think it will displace traffic from the EU to countries close to the EU but outside it, for instance the UK, Switzerland and Turkey,” said Thomsen. “I think we can totally foresee that happening if local taxes are applied. Ideally this cost should be one cost for the whole world and any different costs in different areas is going to be problematic for a global industry such as ours.”

SAF cartels

The 1944 Chicago Convention for international air transport recognized the need to exempt jet fuel from taxation and emphasized the importance to have “a common price,” she said.

Platts, part of S&P Global, assessed SAF in Northwest Europe at $1758.263/mt on June 6, compared with $724.75/mt for FOB NWE jet cargoes.

SAF purchase mandates could lead to the formation of cartels and oligopolies that will control the price of SAF, inhibit competition and dissuade producers from looking into production pathways other than the current commercially viable HEFA (hydroprocessed esters and fatty acids), Thomsen said.

“As soon as you have a mandate, you are favoring the existing incumbents, so that means you are favoring the very few people that know how to produce HEFA and only HEFA,” said Thomsen.

“Now you will have created a little cartel in effect, so mandates tend to de-incentivize other research and development and it tends to make it harder for new entrants to enter the market. It also gives outsize pricing power to the people who are part of this little cartel.”

In 2022, SAF production tripled to some 300 million liters (240,000 mt), but was still less than 1% of total jet fuel production, according to IATA.

SAF will account for most of the renewable fuel production, which is expected to reach an estimated capacity of at least 69 billion liters (55 million mt) by 2028, according to IATA. Over 130 relevant renewable fuel projects have been announced by more than 85 producers across 30 countries.

Favoring fossil fuels

SAF is expected to provide about 62% of the carbon mitigation needed to achieve net-zero emissions by 2050, according to IATA.

If renewable energy production reaches 69 billion liters by 2028, the trajectory to 100 billion liters (80 million mt) by 2030 would be on track and if just 30% of that amount produced is SAF, the industry could achieve 30 billion liters (24 million mt) of SAF production by 2030.

However, the development of SAF and other technologies to achieve net-zero emissions will require at least $180 billion in annual investments between now and 2050.

The $180 billion figure is just a third of the $570 billion in annual planned investments in new oil and gas developments by the end of the decade, based on figures in a 2022 report from the International Institute for Sustainable Development, Thomsen said.

The $180 billion figure also pales in comparison with the amount spent globally on fuel subsidies, she said.

In 2022, global subsidies worldwide for fossil fuel consumption soared to more than $1 trillion, by far the largest annual value ever seen, according to estimates by the International Energy Agency.

The investments are “an indication of the money that is out there that today favors fossil fuels energy when we are struggling to get markets going for sustainable fuels: that is a staggering incoherence,” said Thomsen.

Australia faces tight nature-based carbon credit supply as key removal method expires

Australia is expected to face a shortfall in nature-based carbon credits supply over the next two-three years as a key method for carbon removal expires in 2023 with no replacement expected this year, industry sources told S&P Global Commodity Insights.

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The Human-Induced Generation method made up 32% of Australian Carbon Credit Units in fiscal year 2022-23, Clean Energy Regulator, or CER, data showed. HIRs are the most prominent nature-based carbon credits in Australia, with others nature-based credits making up about 8% of the total ACCU generation in 2022-23, excluding avoided deforestation.

HIR projects involve storing carbon by regenerating permanent native forests on a property where vegetation has been suppressed by activities such as unmanaged livestock grazing, feral animal activity and chemical destruction of regrowth.

The HIR method will expire Sept. 30, after which no new projects will be registered, the CER said June 2.

Existing generation

HIR projects generated nearly 4 million ACCUs in fiscal 2022-23 (July-June), slightly behind the 4.4 million ACCUs generated by landfill gas-based projects and followed by avoided deforestation ACCUs of around 2 million, according to CER data.

Overall, HIR projects have generated nearly 36% of total ACCUs issued over the last three fiscal years.

While avoided deforestation is a nature-based method, it was officially discontinued earlier in 2023 and is generally not favored by buyers looking for high-integrity ACCUs.

Platts, part of S&P Global, assessed the price of Generic ACCUs at A$35/mtCO2e ($23.17/mtCO2e) on June 5 and HIR ACCUs at A$36.25/mtCO2e. Generic ACCUs mostly represent credits from landfill gas and avoided deforestation methods and usually trade at a discount to HIR ACCUs.

The only other nature-based methods that are generating credits of notable volume are Savanna Fire Management, or SFM, and Environmental Planting, or EP.

EP accounted for just 1% of total ACCU issuance in FY 2022-23, and SFM represented a 2.4% share, thus leaving a large supply gap.

There has been a significant number of project registrations for the soil carbon sequestration method, but only one of the projects has been issued ACCUs by the CER until now.

“There has always been talk about soil carbon but I just haven’t seen anybody get something off the ground or execute some of the issuance or seeing signs that it can be scaled up as much,” a carbon broker said.

New method

The CER is consulting on a method, called Integrated Farm Management, or IFM, which is seen as a potential replacement for the HIR method.

The IFM method aims to allow separate land-based activities to be combined on the same property or aggregated properties, according to the CER.

The method was supposed to get the government’s approval by February 2023, according to CER website.

However, there was no sign of the method being approved in the near term with most industry participants suggesting a timeline as wide as six to 18 months.

A draft for the IFM method was nearly 60%-70% complete and on track for parliamentary approval by the first half of 2023 but it got stalled due to a government-backed panel, called Chubb review, a major project developer said.

The Labor government set up an independent panel in 2022 to review the integrity of several carbon methods and overall market governance.

The panel, headed by Australia’s former Chief Scientist Ian Chubb, published its report in January and recommended setting up a new committee to monitor method development and improve market governance.

The new independent panel, called Carbon Abatement Integrity Committee, or CAIC, will replace the existing panel.

However, the recruitment process for CAIC members is in early stages, according to an update from a government official May 22.

“I think there is a capacity issue in Canberra. When you consider what the government in lockstep with the CER needs to prosecute over the next three years, it’s quite a material roadmap,” said Guy Dickinson, CEO of BetaCarbon, a blockchain-based carbon startup.

Supply gap

“There is going to be a hole in supply and in two to three years when the demand is going to be ramping up particularly through compliance, with hopefully voluntary demand increasing as well,” the carbon broker said.

The potential supply gap in nature-based credits is expected to appear as the demand for ACCUs starts increasing from big emitters under the country’s strengthened emissions compliance scheme, Safeguard Mechanism, as well as from the voluntary market.

Even if IFM gets approved in the near term, market participants do not expect the method to start generating ACCUs before 2026 as developers establish new land management practices, assess their commercial viability and work with landowners on implementation.

“We have a shortfall around quality credits, and that shortfall will lead to a shortfall in the medium term in that 24-month period because you will get a lot of people clamoring for the same credits before they ever get to the market,” Dickinson said.

The market was still uncertain on the impact of HIR method’s expiry on the spot ACCU price.

“HIR sunsetting shouldn’t have a direct impact on spot ACCU prices but may play into anxiety around a supply shortfall,” said Kyle Hamilton, associate director, markets, RepuTex, a carbon market research firm.

The impact on the price will not be visible in the first year but two or three years down the line, it is expected to have a positive impact on price, the carbon broker said.

Black Sea Ukraine sunflower oil market enters third quarter at multi-year lows

Highlights

Sunflower oil pricing hits 3-year lows in the week ended June 2

Obstruction of the port of Pivdennyi impacts prices

The beginning of the summer months has been marked by a steep decline in the value of sunflower oil for FOB Black Sea Ukraine delivery, with the price falling $236/mt from March 1.

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Platts assessed sunflower oil FOB Black Sea Ukraine at $689/mt as of June 2, with value reaching the lowest level since early May 2020, amid problematic shipping conditions and a slump in global demand.

Black Sea grain corridor operations remain hindered

The 60-day extension of the Black Sea Grain Initiative confirmed on May 18 did little to relieve downwards pressure on sunflower oil prices, as the European market remained heavy on stocks purchased on a prompt basis prior to the deal’s renewal.

Difficulties for exporters continued in the immediate aftermath, with the port of Pivdennyi — one of the three ports covered by the agreement — remaining inactive, in the absence of approvals for incoming ships.

The ongoing blockage of Pivdennyi is a suspected retaliation by Russia over the obstruction of its nearby ammonia pipeline, with continued impediment since April 29 reducing market optimism regarding grain corridor operations.

Market demand for Ukrainian shipments weakened in response, with trades for Russian origin product on a CIF Turkey basis reflecting a shift towards more secure transportation routes for some consumers.

“The question for buyers is how will the corridor work, the same as last month or better” a trader said. “With Pivdennyi blocked, its uncertain how many purchases we’ll see.”

Producers remained restricted as slower Odessa port operations and shifts towards the Danube ports limited their reach towards destinations such as India and China, while buy options remained wide amid low rapeseed oil prices and Russian availability.

“Danube ports are more efficient for freight and insurance, but still very limited,” a market participant said.

Foreign policy limits sunflower product exports

External policies also weighed on Ukrainian sunflower oil prices, as key destinations for both oil and oilseeds attempted to limit cheap inflows to protect domestic industry.

On April 28, the European Commission imposed a ban until June 5 on the export of Ukrainian sunflower seed, rapeseed, wheat and corn to Poland, Hungary, Bulgaria, Romania and Slovakia after a series of complaints and unilateral restrictions from them. The neighboring countries have historically been major consumers of Ukrainian sunflower seeds exports.

Domestic prices for sunflower seeds saw a slow decline during May, according to market sources, with pessimism fueled further by the EC’s potential decision to extend the ban beyond its expiry date.

The price of Ukrainian sunflower seeds decreased on the week on May 30, according to a producer, with values seen at Hryvnia 12,500-13,200, including VAT, on a CPT plant basis.

The decision of the Turkish government to impose a 36% duty on sunflower oil imports from June 1, from no duty, further accelerated the slide in Black Sea prices.

A sudden rise in bidding seen around mid-May quickly subsided, as consumer stocks filled and spot delivery windows moved into the higher duty period.

“There aren’t many terminals in Turkey can take the oil and tranship it for re-export and may people just don’t want to pay the duty,” a trader said.

Buyer interest remained scarce at the beginning of June on high destination market supplies and the prospect of further price reductions, with buyers withdrawn from the market as sellers sought tradeable values.

Australia’s biggest carbon credit generating method to expire in September

Highlights

HIR method generated highest volume over last 3 years

Regulator advises new application submission by July 2

No method approved yet to replace HIR after September

The Human-Induced Regeneration method, the biggest generator of carbon credits in Australia, will expire in September 2023, the Clean Energy Regulator said June 2.

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There will be no new project registration under the HIR method after Sept. 30, with project developers advised to submit new applications by July 2, the regulator said.

The method is the only nature-based method that generates a significant volume of Australian carbon credit units, or ACCUs.

The method generated nearly 4 million ACCUs in fiscal 2022-23 (July-June), just a step behind 4.4 million ACCUs generated by landfill gas-based projects.

However, HIR projects have generated the highest volume of ACCUs since at least FY 2019-20, with nearly 6.4 million HIR ACCUs issued in FY 2021-22.

The fall in FY 2022-23 was mainly due to new measures being implemented by CER to better uphold the integrity of the HIR projects.

As a result, the issuance of HIR ACCUs flatlined since early January.

Platts, part of S&P Global Commodity Insights, assessed the price of Generic ACCUs at A$34.50/mtCO2e ($22.49/mtCO2e) June 1 and HIR ACCUs at A$35/mtCO2e. Generic ACCUs are generated from avoidance-based methods, such as landfill gas, and are usually sold at a discount to HIR ACCUs.

Road ahead

“While all best endeavors will be taken by the Clean Energy Regulator to assess applications and register projects prior to the expiry date, participants should be aware that submitting applications fewer than 90 days before the expiry increases the risk that the project may not be able to be registered prior to the expiry date,” the regulator said in a statement.

The HIR projects already registered will continue to be issued ACCUs till their crediting period ends. The usual crediting period for HIR projects is 25 years.

However, projects whose crediting period starts after Sept. 30 will not be able to continue their projects when the method expires, the regulator added.

The new projects or those yet to be accepted have the option of registering under a new method that will replace the HIR method.

However, the integrated farm management, or IFM, method that was expected to replace HIR is yet to be approved by the CER.

“The concern is that once HIR lapses, there is going to be a lag from that closure and the development and finalization of a new method to replace it,” a project developer told S&P Global.

There will be further delay as developers work out measures to implement any new land management practices, assess the commercial viability of method activities, and explain the approach to landholders, the developer added.

“We see a material lag in credit issuance of up to two years from projects registered under new IFM once it is released,” the developer said.