Category: Nieuws

Port of Gothenburg and Inter Terminals Sweden (ITS) will develop a methanol storage facility for bunkering by the end of 2023.

ITS will rebuild tanks and other related infrastructure in Gothenburg. The management of the gases from methanol when loading into ships is a challenge that will be handled through a Vapor Recovery Unit (VRU), ITS said.

In January, ship owner Stena Line bunkered its ferry Stena Germanica with methanol in Gothenburg via ship-to-ship transfer. Previously, Stena Germanica received methanol from trucks when berthed at the port. The methanol was supplied from methanol producer Methanex.

Northwest Europe grey methanol was pegged at $775/t average in March, or 42pc premium to very low-sulphur fuel oil (VLSFO), Argus data showed. Northwest Europe bio-methanol was assessed at $2,680/t or 4.9 times higher than VLSFO.

Grey and bio-methanol do not contain sulphur, which makes them compliant with the 0.5pc sulphur cap on marine fuels imposed by the International Maritime’s Organisation (IMO) starting in January 2020.

IMO requires that vessels reduce their CO2 emissions 40pc by 2030 and 70pc by 2050 from 2008 base levels. Grey methanol combustion lowers CO2 emissions by only 7pc compared to VLSFO. By comparison, bio-methanol could be carbon natural, if produced from sustainable biomass.

Argus by Deyzhah Knox and Stefka Wechsler, April 24, 2023

Abu Dhabi-owned Cepsa said it plans to build a 500,000 t/yr second-generation hydrotreated vegetable oil (HVO) plant in southern Spain in partnership with Bio Oils, the Spanish subsidiary of Singapore-based palm oil producer Apical.

The plant will be located near the city of Huelva, where Cepsa operates a 220,000 b/d refinery and Bio Oils runs a 500,000 t/yr fatty acid methyl ester (Fame) biodiesel facility. Cepsa is Bio Oils’ main customer and the pair share port installations and vessels in Huelva. Cepsa announced plans for an HVO facility at Huelva last month, putting the cost of the project at €1bn ($1.05bn). That investment will now be shared with Bio Oils.

Feedstock supply for the new plant has been secured through a long-term contract with Apical, which operates eight palm oil refineries, four biodiesel facilities and two palm kernel crushing facilities worldwide. Apical sold over 11mn t of palm oil products in 2021. Cepsa said it will source “organic waste such as agricultural residue” and used cooking oil (UCO) from Apical and this will make up most of the plant’s feedstock.

Cepsa expects the HVO plant to come on stream in the first half of 2026, taking the firm towards its target to produce 2.5mn t/yr of biofuels by 2030, including 800,000 t/yr of sustainable aviation fuel (SAF). Cepsa’s existing biofuels production capacity at Huelva and its other Spanish refinery — the 244,000 b/d Algeciras complex — had increased to 705,000 t/yr by the end of 2022 from 578,000 t/yr a year earlier.

Cepsa is focusing on biofuels and renewable hydrogen to achieve a target to reduce its scope 1 and 2 CO2 emissions by 55pc in 2030 and to become carbon neutral by 2050. The firm recently announced an acceleration of its renewable hydrogen capacity rollout in Huelva, where it now expects to have 400MW of electrolyser capacity on line in 2026, up from 200MW previously. This will be in time to supply the new HVO plant with renewable hydrogen for the hydrotreatment process.

Cepsa, which is controlled by Abu Dhabi sovereign wealth investor Mubadala, has said that the 1GW of hydrogen electrolysis capacity it expects to have on line at Huelva in 2030 should be enough to decarbonise its own fuels and petrochemicals business as well as the fertilizer business of Fertiberia, one of its partners in Huelva.

Argus by Jonathan Gleave, April 24, 2023

If you think, as we do, that U.S. crude oil production is likely to increase by 1.5 to 2 MMb/d over the next five years, almost all those barrels will be light-sweet crude that needs to be exported, and exporters will overwhelmingly favor the marine terminals that can accommodate Very Large Crude Carriers (VLCCs), it would be hard to ignore the game-changing impacts that Enterprise Products Partners’ planned Sea Port Oil Terminal could have.

SPOT, which could be completed as soon as 2026, will have robust pipeline connections from the Permian and other shale plays and be capable of fully loading a 2-MMbbl VLCC in one day, enough to handle virtually all the incremental exports we’re likely to see over the next five years. In today’s RBN blog, we discuss the fast-increasing role of VLCCs in U.S. crude oil exports and the potentially seismic impacts of the SPOT project.

RBN’s middle-of-the-road “Mid” forecast sees U.S. crude oil production increasing to 14 MMb/d by 2028, about 2 MMb/d higher than the 2022 average, with three-quarters of that incremental output coming from the Permian and most of the rest from other shale plays that also produce high-API-gravity, low-sulfur oil — see The Price You Pay for more (and a downloadable MS Excel version of that forecast).

Given that U.S. refineries’ ability to economically process light-sweet crude is essentially maxed out, it’s a good bet that almost all those incremental barrels will be bound for export terminals along the Gulf Coast.

And, as we said in Calling the Shots, it’s just as likely that, on their way to overseas refineries, as many of those barrels as physically possible will be headed through terminals like the Enbridge Ingleside Energy Center (EIEC) and South Texas Gateway (STG) — both in the Corpus Christi area — whose docks can receive and load VLCCs with minimal reverse lightering, the most cost-effective way to move massive volumes of oil to Europe and Asia.

But crude oil pipelines from the Permian to Corpus are nearing capacity, more oil is being diverted toward Houston-area export terminals across Magellan’s pipelines, the Midland-to-ECHO pipeline system and other pipes — see Sooner or Later and Houston Bound for more on that — and Enterprise continues to advance its plan to build SPOT in 115-feet-deep waters about 30 nautical miles off the coast of Freeport.

Enterprise has estimated that it will have a full license for the project in hand by September 2023, and that it will take about 30 months to build the facility. In What It Takes, we explained that SPOT will have two single-point mooring buoys (purple-and-white-striped diamonds in Figure 1) and the ability to simultaneously moor two VLCCs and load one per day — providing an extraordinary level of cost- and time-efficiency.

Crude will flow to SPOT on a pair of 36-inch-diameter pipelines from two Enterprise storage-and-distribution terminals: the existing ECHO Terminal (orange tank icon southeast of Houston; 8.4 MMbbl of tank storage) and the proposed Oyster Creek Terminal (orange-and-white-striped tank icon north of Freeport; 4.8 MMbbl of planned capacity) in south-central Brazoria County.

RBN Energy by Housley Carr, April 19, 2023

This week, OPEC+’s surprise output cuts made it even stronger.

Key markers in the Dubai crude market — the benchmark for Middle Eastern grades — leapt higher after the Saudi-led decision. The most active timespread for Dubai swaps jumped to above $1 a barrel in backwardation, according to data from PVM Oil Associates Ltd, outperforming the Brent curve.

While OPEC+’s production cuts will take effect only next month, Dubai’s strength reflects expectations that the reductions will strengthen an already-robust market for Middle Eastern supplies.

Saudi Arabia, Iraq, the UAE and Kuwait pledged to cut a combined 980,000 barrels a day of output, with generally heavier and more sulfurous crude as the bulk of their production.

That’s likely to lift the relative value of Dubai crude — which is both a proxy for Middle Eastern oil markets as well as medium-sour oil varieties — against global benchmarks such as Brent even further, a shot in arm for long-haul cargo flows from the Atlantic Basin and Americas into Asia.

Even prior to the OPEC+ cuts, traders were already bullish on Dubai versus other crudes, as red-hot Chinese demand hoovers up the region’s supplies and lackluster European consumption weighs on Brent.

“Given the bulk of the cuts stem from medium and heavy Middle Eastern producers, we would not be surprised to see Dubai trade at a premium to Brent in the coming months, particularly as China looks to ramp imports,” RBC analysts including Mike Tran and Helima Croft wrote in a report.

For months, the Middle Eastern oil market has been among the tightest in the world as regional exporters support Asia’s recovering demand. This week, OPEC+’s surprise output cuts made it even stronger.

Key markers in the Dubai crude market — the benchmark for Middle Eastern grades — leapt higher after the Saudi-led decision. The most active timespread for Dubai swaps jumped to above $1 a barrel in backwardation, according to data from PVM Oil Associates Ltd, outperforming the Brent curve.

Bloomberg by  

Many private Chinese refiners in the Shandong province are buying increasing volumes of Iranian crude as competition for Russian oil from China’s major state-held refiners and from Indian buyers has made Moscow’s barrels relatively more expensive.

China’s private refiners, the so-called teapots, are estimated to have imported 800,000 barrels per day (bpd) of Iranian crude oil and condensate in March, up by 20% compared to February, Emma Li, an analyst with Vortexa, told Bloomberg.

Imports from Iran into the Shandong province—home to most of the private refiners in China—could continue to be robust in the coming months, according to the analyst.

There isn’t official data on Iranian imports into China, so the market relies on tanker-tracking companies that aim to capture the true picture of how much of Iran’s oil, sanctioned by the U.S. and going to very few destinations these days, is being shipped to China.

The private refiners in the world’s top oil importer are now betting more on cheap Iranian crude, as Russian supply is going to the state-owned Chinese majors and to India’s refiners. Russia’s crude is also cheaper compared to international benchmarks, but heightened competition has driven up prices in recent weeks.

Russia was the single largest crude oil supplier to China in January and February, overtaking Saudi Arabia, which was the number-one supplier of oil to China last year, according to Chinese customs data from last month.

As China accelerated the buying of cheap Russian crude oil at discounts to international benchmarks, Chinese imports of crude from Russia jumped by 23.8% year over year to 1.94 million barrels per day (bpd) in January and February 2023.

India, for its part, is also boosting imports of Russian oil to record levels. In February, Russia remained India’s top oil supplier for a fifth consecutive month.

Both India and China are not abiding by the G7 price cap as they seek opportunistic purchases of cheap crude.

OilPrice.com by Tsvetana Paraskova, April 11, 2023

Saudi Aramco’s joint venture Huajin Aramco Petrochemical Co (HAPCO) earlier this week broke ground on a $10 billion integrated refinery and petrochemical complex in Panjin city in China’s Liaoning Province.

HAPCO is a joint venture between Aramco (30%), NORINCO Group (51%) and Panjin Xincheng Industrial Group (19%).

Aramco announced earlier that the complex was expected to be fully operational by 2026. The Saudi firm will likely supply up to 210,000 barrels per day (bpd) of crude oil feedstock to the facility.

The complex will combine a 300,000 barrels per day refinery and a petrochemical plant with annual production capacity of 1.65 million metric tons of ethylene and 2 million metric tons of paraxylene.

In another major announcement, Saudi Aramco signed agreements to acquire a 10% stake in Shenzhen-listed Rongsheng Petrochemical Co. for $3.6 billion, fortifying its presence in China’s downstream sector.

NORINCO Group’s general manager said that the project will play an important role in “deepening economic and trade cooperation between China and Saudi Arabia, and achieving common development and prosperity.”

By Oil&Gas, April 11, 2023

European producers and traders of biodiesel say Chinese product entering the EU is being wrongly labelled as an ‘advanced’ biofuel, and sold into Germany where it is counted twice towards emissions savings targets in transport. This, they say, is having multiple effects on supply-demand balances and prices.

Advanced liquid or gaseous biofuels — those produced from feedstock listed in Annex IX Part A of the EU Renewable Energy Directive (RED II) — are mandated in Germany and are permitted to count twice towards the country’s greenhouse gas (GHG) reduction target for transport fuels, once a baseline target of 0.3pc by energy content has been met. The domestic advanced biofuels target will rise to 2.6pc by 2030.

Suppliers of biodiesel to Germany told Argus they are seeing offers for advanced biodiesel made from feedstocks such as sludge from food production waste, acid oils from soap stocks and palm oil mill effluent (Pome). They say the amount being shipped in bulk from China is far in excess of what can reasonably be available for export.

A European producer said that between 130,000-150,000t of such product is being sent to Europe each month.

“This has a brutal effect on the whole market,” the producer said. “Advanced product counted against the [German] quota allows blenders to use smaller amounts of biodiesel to reach their targets. This destroys our market here and makes it impossible to produce and trade.”

Chinese customs data, which groups all fatty acid methyl ester (Fame) biodiesels together, show a significant rise in exports destined for Europe.

Biodiesel exports more than doubled on the year to 455,000t in January-February and the vast majority this made its way to the Netherlands from where it will be redistributed within Europe.

The European producer said that with most product recently offered out of China having a cold filter plugging point (CFPP) of +10°C — the sort of warmer weather grade now in favour ahead of the summer months — “there is little choice but to participate in the flow if [companies] want to stay afloat.”

The European Waste-based & Advanced Biofuels Association (Ewaba) said it is treating reports relating to these concerns “as a matter of high priority” given they are “creating worrying conditions for our members.”

“We are taking different steps involving certification schemes and customs authorities and if any dubious practice is identified we are confident it will stop shortly,” it told Argus.

Germany’s federal office for agriculture and food (BLE) told Argus that while it is responsible in Germany for the implementation of the sustainability criteria of RED II in sustainability regulations, the responsibility for monitoring and controlling cultivation, supply and production chain rested with independent certification systems and bodies, which are previously recognised and then monitored.

Knock-on price shocks hit EU producers

This influx of advanced biofuels has weighed on German greenhouse gas (GHG) emission reduction certificate prices.

These are used by companies that bring liquid or gaseous fossil fuels into general circulation and are obligated to pay excise duty or energy tax on those fuels. Also known as tickets, the tradeable certificates are primarily generated by blending renewable fuels into fossil fuels.

The Argus price for advanced double-counting GHG certificates, which are generated by blending advanced biofuels excluding Pome, fell by 51pc from the end of 2022 to €430/t CO2e on 24 March.

Tickets generated by blending biofuels made from Pome declined in that time by the same value share, to €218/t CO2e.

In physical terms, losses to spot prices for biodiesel produced from used cooking oil (Ucome) since the start of the year have led to reduced runs in Europe, as producers contend with negative margins given higher supply of competitively priced advanced grades from outside the EU.

The Argus Ucome fob ARA range spot price declined by close to 30pc from the last trading day of 2022 to a near 29-month low of $1,176/t on 22 March, before rebounding slightly. Suppliers to Germany have sold Ucome stocks into other European markets given the lack of domestic demand.

Rising targets rely on feedstock availability

There no confirmed release date for 2022 data for German biofuels consumption, BLE told Argus. In 2021, the most common source of advanced biofuels was the biomass fraction of industrial waste typically used to produce biomethane, followed by Pome used to produce biodiesel or hydrotreated vegetable oil (HVO).

Pome is excluded from the double-counting incentive but its use is not capped. Argus estimates global availability of Pome at just over 760,000t in 2023, with more than 680,000t of this from Asia-Pacific.

Argus estimates availability of acid oils from soap stock at a little more than 2mn t in 2023, with just over 900,000t in Asia-Pacific.

These are based on assumptions about vegetable oil production, chemical refining shares and free fatty acid (FFA) content.

Estimated global used cooking oil (UCO) availability is 9.4.mn t, of which Asia-Pacific represents close to 5.7mn t. UCO falls under Annex IX Part B of RED II, as do waste animal fats (Tallow categories 1 and 2), for which estimated availability is just under 700,000t in Europe this year.

Germany caps the energetic share of biodiesel from Part B feedstocks at 1.9pc to 2030 and there is no double counting.

Germany recently revisited a potential ban on crop-biofuels. The environment ministry plans to submit a draft law to ban the use of biofuels from crop and feed “as soon as possible”, minister Steffi Lemke said in January. The cap on crop-based biofuels used to fulfil Germany’s GHG quota is 4.4pc in energy terms.

German biofuels association VDB has said ethanol producers mostly use grain that is unsuitable for the food sector, and biodiesel producers have already cut back output in favour of food production.

Germany’s greenhouse gas (GHG) reduction target for 2023 is 8pc.

Argus by John Houghton-Brown, April 11, 2023

Following my recent article detailing Average Gasoline Prices Under The Past Four Presidents, I received a flurry of feedback. Some commentors were angry about a comment I made in that article that Russia’s invasion of Ukraine helped boost gasoline prices last year to record levels.

If I can summarize the gist of the comments, it would be: “You don’t know what you are talking about. This is all Biden’s policies. It had nothing to do with Russia or Ukraine.” One person insisted that I don’t understand the oil industry or oil refining, despite having spent years actually working in a refinery.

As I pointed out to some in response, I didn’t delve deeply into causation of high gas prices in that article. But let’s do that here. First, let’s look at the average weekly retail gasoline price in 2022, with several significant events highlighted on the graphic.

We can see that gasoline prices began a steep climb within a week of Russia’s invasion. In the midst of that initial climb, President Biden signed an Executive Order (E.O.) to ban the import of Russian oil, liquefied natural gas, and coal to the United States.

One can certainly debate whether this ban was the right move (and I warned about the implications beforehand in Russia Is A Major Supplier Of Oil To The U.S.), but there is no question that this decision had an impact on oil and gas prices.

Of course, correlation does not imply causation, so let’s talk about what actually happened to impact gasoline prices.

The Russian oil we imported was largely finished products and partially finished products that were largely used to produce diesel in U.S. refineries. There are two high-demand seasons for diesel each year — spring planting season for farmers and fall harvesting season.

So, we had a refinery disruption that impacted diesel production just before a high demand period. In addition, this came at a period of extremely high jet fuel (like diesel, jet fuel is a “distillate”) demand, as people started to travel in large numbers after being pent up for some long as a result of the pandemic.

That caused an even greater spike last year in distillate prices, and it forced refiners to respond. However, when refiners shift production toward distillates, it comes at the expense of some gasoline production. This negatively impacted gasoline production just as refiners start building up stocks heading into high-demand gasoline season (summer).

Note that this isn’t just idle speculation. I had several discussions about these events with one of my former refinery managers, who explained exactly what the refiners were facing.

The other major event on the graphic is President Biden’s decision to release an unprecedented amount of oil from the U.S. Strategic Petroleum Reserve (SPR) as a tool to combat rising prices. This was a move I opposed, because I don’t view high prices as the kind of emergency the SPR is supposed to protect against. That would be more of a significant loss of oil imports that threatens to cause shortages. This wasn’t the situation last year, so I thought the SPR release was unwarranted.

But, as one of my critics argued “The only reason prices went down last year was that President Biden used the SPR politically in an election year.” Indeed, that probably helped reverse the price rise last year. At the same time, the withdrawals put the U.S. in a more vulnerable position with respect to our emergency oil reserves. Further, it’s easy to be cynical about this move, because politicians — of both parties — have often treated the SPR as the “Strategic Political Reserve”, to be used to placate voters upset with rising prices.

All of this led to the historic price increases in 2022. There isn’t one single cause, which is why some will say “It was Biden’s policies” and some will say “It was Russia’s invasion of Ukraine.” Both are true, but neither is the exclusive cause. Russia invaded Ukraine, and in response President Biden made an executive order that caused disruptions in the refining sector — even if many agree it was the right thing to do.

Forbes by Robert Rapier, April 4, 2023