Category: Nieuws

Canada’s Trans Mountain pipeline expansion (TMX) is set to enter partial operation on May 1, years behind schedule and at more than four times the original cost – but with the potential to affect oil flows even outside North America.

Canada, the world’s fourth-largest oil producer with nearly 5 million barrels per day (bpd) of output, will have more than enough export pipeline capacity once the C$34 billion ($24.9 billion) TMX becomes fully operational.

The expanded pipeline will ship an extra 590,000 bpd from Alberta to Canada’s Pacific Coast, giving Canada’s heavy crude producers access to U.S. West Coast and Asian markets, and boosting prices for their grades.

Here are some key issues facing the project.

WHEN WILL TMX BE FULLY OPERATIONAL?

Crude will flow through both TMX and the existing 300,000 bpd Trans Mountain line from May 1. The Westridge Marine Terminal in the Port of Vancouver will be able to load cargoes from all three berths, a spokesperson said.

However, Trans Mountain does not expect the first ship to load until the second half of May, and is still awaiting permission to open six more sections of the project, the Canada Energy Regulator (CER) said on Friday.

WHERE WILL THE CRUDE GO?

TMX cargoes are expected to sell to both Chinese and Californian refiners, traders and analysts say.

Many Chinese refineries are set up to process heavy sour crudes, but shipping brokers have warned the cost of hauling crude to Asia on Aframax vessels, a roughly 18-day trip one way, may limit demand.

California has complex refineries that can process both light and heavy crude and is 2-4 days’ voyage away from Vancouver.

WHO ARE THE SHIPPERS?

There 11 committed shippers on TMX, accounting for 80% of volumes. The remaining 20% of capacity will be available for spot shipments.

Committed shippers include Canadian Natural Resources (CNQ.TO), opens new tab, MEG Energy (MEG.TO), opens new tab, Cenovus Energy (CVE.TO), opens new tab, Suncor Energy (SU.TO), opens new tab, BP (BP.L), opens new tab, Chinese state energy major PetroChina and Marathon Petroleum (MPC.N), opens new tab.

WHAT CRUDE WILL IT TRANSPORT?

The new pipeline is expected to ship primarily heavy crude, while the existing line moves mainly light barrels. Multiple grades are being offered for sale from TMX but traders expect this to stabilize to a few grades once trade matures, one source said.

Commodities pricing agency Platts has launched two new daily assessments for crude loaded at Westridge. Pacific Dilbit is similar in quality to Access Western Blend, and Low TAN Dilbit aligns with Cold Lake crude, the agency said last week.

WHY IS THERE A TOLLING DISPUTE?

The budget blowout means TMX has had to raise tolls to recoup some costs. The shippers are disputing the rate increase, and the CER, which approved higher interim tolls last year, will hold a hearing this year to decide the final tolls.

ast week the CER approved a request from shippers to disclose additional detailed cost and expense information.

The dispute is significant because the final tolls will determine the value of the pipeline when Ottawa puts it up for sale.

WHAT IS TMX WORTH TO CANADA?

Some analysts predict the discount on benchmark Canadian heavy crude Western Canada Select will narrow to less than $10 a barrel versus U.S. crude, from a $14 a barrel discount currently, resulting in millions of extra dollars in revenue for Canadian producers.

TMX operations will contribute C$9.2 billion to Canadian GDP and C$2.8 billion in taxes over 20 years from 2024 to 2043, according to Ernst & Young.

The Bank of Canada said the start of commercial operations on TMX will add roughly a quarter of a percentage point to second-quarter GDP growth.

($1 = 1.3669 Canadian dollars)

By: Reuters / Nia Williams, April 29, 2024

Much lower natural gas prices this year compared to 2023 dragged down profits at some of the largest oil and gas companies, which have so far reported a mixed bag of earnings for the first quarter of 2024.

U.S. supermajors ExxonMobil and Chevron, as well as France’s TotalEnergies, all cited lower natural gas prices as a key downward pressure on earnings that couldn’t be fully offset by stable crude oil and liquids realizations and refining margins.

Exxon reported on Friday underwhelming earnings for the first quarter that were lower than consensus estimates due to declining natural gas prices and non-cash adjustments.

The U.S. supermajor booked first-quarter earnings of $8.2 billion, down from $11.4 billion for the first quarter of 2023. Earnings per share were $2.06 for the first quarter of 2024, down from $2.79 for the same period last year.

Exxon’s Q1 2024 earnings per share were below the analyst consensus forecast of $2.19 compiled by The Wall Street Journal.

“Natural gas prices moved back inside the 10-year range, reflecting continued high inventory levels and lower demand,” Exxon’s executives said on the conference call.

Related: Growing Shadow Fleet Makes Oil Price Cap Impossible to Police

On the other hand, refining margins rose to the top of the 10-year range, driven by strong demand, industry downtime, and supply disruptions, while average crude prices were flat in the quarter as the market remained relatively balanced, the company said. But these and a stellar performance in Guyana could not fully offset the weak natural gas prices.      

During the first quarter, the benchmark U.S. natural gas prices at the Henry Hub mostly traded below $2 per million British thermal units (MMBtu) amid a market glut in a warmer winter and lower demand. The low prices even prompted major gas-focused producers to curtail some output in March and April.

The lower natural gas prices hit Chevron’s earnings, too. But unlike Exxon, Chevron slightly beat the analyst earnings estimates, thanks to higher oil and gas production that offset part of the weaker refined product margins and low natural gas prices.

The annual drop in Chevron’s Q1 earnings was primarily due to lower margins on refined product sales and lower natural gas realizations, partly offset by higher upstream sales volumes in the U.S. The supermajor reported a 406,000-barrels-per-day rise in net oil-equivalent production in the United States due to the acquisition of PDC and higher production in the Permian and DJ Basins.

Chevron’s worldwide production was up 12% from a year ago, primarily due to the acquisition of PDC, strong operational performance in the Permian and DJ Basins in the U.S., and the Tengizchevroil affiliate in Kazakhstan.

“Adjusted first quarter earnings were down $1.3 billion versus last year. Adjusted upstream earnings were down modestly. Higher liftings were more than offset by lower natural gas realizations,” Chevron’s CFO Eimear Bonner said on the earnings call with analysts.

Similarly to Chevron, European major TotalEnergies also beat first-quarter estimates even as its net income dropped by 22% from a year ago. Stable oil prices and healthy refining margins failed to fully offset a decline in natural gas prices, but helped TotalEnergies beat analyst forecasts as it reported Q1 earnings on Friday. The company announced additional share buybacks and an increase in the first interim dividend for 2024.

“In a context of sustained oil prices and refining margins but softening gas prices, the Company announced first quarter 2024 adjusted net income of $5.1 billion and cash flow of $8.2 billion, in line with its ambitious 2024 objectives,” TotalEnergies’ chief executive officer Patrick Pouyanné said.

UK-based Shell, the world’s top LNG trader ahead of TotalEnergies, said earlier this month that it expects the trading results in its Integrated Gas division to be lower in the first quarter of 2024 compared to an exceptionally strong fourth quarter of 2023.

The trading and optimization results in Integrated Gas “are expected to be strong, but significantly lower than an exceptional Q4’23,” the company said ahead of the results release on May 2.

By Oilprice / Tsvetana Paraskova – Apr 29, 2024

Saudi oil giant Aramco is exploring the formation of a joint venture in the Saudi Aramco Jubail Refinery Company (SASREF) with Chinese partner Rongsheng Petrochemicals, Aramco said in a statement on Saturday.

Aramco recently signed a cooperation framework agreement that envisions Rongsheng’s potential acquisition of a 50% stake in SASREF, it added.

“The agreement also lays the groundwork for the development of a liquids-to-chemicals expansion project at SASREF, in addition to Aramco’s potential acquisition of a 50% stake in Rongsheng affiliate Ningbo Zhongjin (ZJPC),” Aramco said.

Aramco acquired a 10% interest in Rongsheng in July 2023 through its subsidiary Aramco Overseas Company BV, based in the Netherlands.

Rongsheng in turn owns a 100% equity interest in ZJPC, which operates an aromatics production complex and has an interest in a joint venture that produces purified terephthalic acid.

By: Reuters / Adam Makary,   27 Abr, 2024.

The IEA has released its first forecast for 2025 which shows global oil demand growth slowing to 1.15mn b/d next year — some 700,000 b/d lower than Opec’s latest projection.

In its latest Oil Market Report (OMR), the Paris-based agency also lowered its oil demand growth forecast for this year by 130,000 b/d to 1.2mn b/d, citing lower heating fuel use and a protracted factory slump in advanced economies.

The 2024-25 figures contrast sharply with 2022 when the global economy’s emergence from the Covid-19 pandemic led to a demand increase of 2.25mn b/d — something the IEA said had now largely run its course.

“Despite the deceleration that is forecast, this level of oil demand growth remains largely in line with the pre-Covid trend,” it said. The IEA also reiterated its view that a peak in oil consumption is in sight this decade, although it notes that without an increased investment push into clean energy technologies, “the decline in global oil demand following the peak will not be a steep one”.

The IEA said its 2025 forecast reflects a “somewhat sub-par economic outlook” and included vehicle efficiencies and an expanding electric vehicle (EV) fleet acting as “further drags on oil consumption.”

China, which has led much of the world’s oil demand growth over the past few decades, is slowing down, according to the IEA. The agency lowered its 2024 forecast for Chinese oil demand growth by 80,000 b/d to 540,000 b/d, falling to 330,000 b/d in 2025, although China still remains the single largest contributor to global growth next year.

The IEA’s latest forecasts continue to reflect stark differences with Opec in the way they see oil demand unfolding over the years and decades ahead. Opec sees oil demand growth substantially higher at 2.25mn b/d in 2024 and 1.85mn b/d in 2025.

On global oil supply, the IEA nudged down its 2024 growth estimate by 30,000 b/d to 770,000 b/d. While non-Opec+ production is projected to expand by 1.6mn b/d, this is partially offset by an 820,000 b/d forecast fall from Opec+ — assuming the group’s latest voluntary cuts remain in place until the end of the year.

Relentless oil supply growth from outside Opec+ is set to continue putting pressure on the alliance to keep production lower for longer. The IEA said that additional production from the US, Brazil, Guyana and Canada “alone could come close to meeting world oil demand growth for this year and next.”

The IEA’s latest supply forecast assumes Opec+ voluntary cuts remain in place until the end of 2024, which would keep the market in a deficit of 270,000 b/d, it estimates. Opec+ has yet to decide on its output policy for the second half of the year and may do so at a ministerial meeting scheduled for 1 June in Vienna.

Global observed oil stocks increased by 43.3mn bl to a seven-month high in February, despite a further 24.6mn bl decline in on land stocks, the IEA said. Oil on water rose to a “sizeable” 67.8mn bl in February, driven by shipping disruptions in the Red Sea that have forced vessels to take the longer alternate route around the southern tip of Africa.

By: Argus, Aydin Calik / April 16, 2024

In recent years, the production of renewable diesel and sustainable aviation fuels from biological sources, particularly natural oils, has experienced remarkable growth. This surge is largely driven by global climate change initiatives mandated by governments worldwide, coupled with the increasing emphasis on carbon capture and sequestration. As a result, substantial investments have been made in retrofitting and adapting existing refinery hydroprocessing infrastructure to accommodate natural oils or blends of natural oils with crude oil, facilitating the production of RD and SAF.

The rationale behind these investments lies in the molecular compatibility of natural oils with mid-distillate fuel products like diesel and aviation fuel, as well as the optimization of hydroprocessing units for the removal of unwanted sulfur and oxygen compounds. In modified hydroprocessing applications, the high-temperature decomposition of triglycerides leads to the production of RD and SAF through the hydroprocessing of esters and free fatty acids. The resulting oxygen-free RD and SAF products are fully interchangeable with petroleum hydrocarbons.

However, hydroprocessing of refined natural oils presents its own set of challenges, particularly in terms of corrosion. To address this issue, the authors have developed a molecular mechanistic model to quantify simultaneous high-temperature corrosion caused by naphthenic acids and sulfidation in refinery operations. This model, known as CorrExpert®-Crude, has been adapted to address high-temperature FFA corrosion, given the similarities between FFA and naphthenic acids.

A crucial aspect of modelling corrosion for FFA is understanding the inhibitive role of hydrogen in the presence of iron sulphide species. Although natural oils do not contain sulphur compounds, reactive sulphur species present in coprocessing applications facilitate the formation of a potentially protective nano barrier layer of iron sulphide. Additionally, FeS acts as a catalyst for the reduction of FFA through atomic hydrogen, generated from the dissociation of molecular hydrogen.

The prediction model incorporates factors such as hydrogen partial pressure, residence time, and reactive sulfur concentration to assess FFA corrosion risk for various commonly used natural oils in renewable applications. By considering these parameters, the model provides a comprehensive framework for evaluating corrosion risk and metallurgical performance in RD/SAF units. This pioneering solution offers an easy-to-use tool to enhance the reliability of unit piping and equipment in renewable fuel production facilities.

By: Storage Terminals Magazine, April 15, 2024 

 OPEC+ once again extended its oil production cuts this month. The decision was anything but unexpected and, unlike previous production policy announcements, it had the desired effect on prices. However, it could only work for so long. Soon, OPEC will need to make a decision.

Last year, oil traders were almost exclusively focused on demand and threats thereof, especially in China. This year, they are beginning to understand that withholding 2.2 million barrels of oil daily while global demand actually rises will, at some point, start eating into supply. Oil prices are on the rise.

True, some OPEC+ members have been producing more than their assigned quota, and they have been asked to take steps to compensate, which normally means temporary deeper cuts. But it seems that overproduction—and the rising output of quota-exempt Iran, Venezuela, and Libya—has not interfered with the purpose of the cuts. Only they cannot continue forever.

Some analysts have noted in the past few months that OPEC+ will have to start unwinding the cuts at some point, especially if Brent crude tops $100 per barrel. The argument made by these analysts is that at that point, prices will start destroying demand as they usually do.

Yet OPEC+ may decide to stick with the cuts until oil is well above $100, according to the CEO of Dubai-based consultancy Qamar Energy, Robin Mills. In a recent opinion piece for The National, Mills suggested sticking with the cuts is one of the two roads ahead of OPEC, with all foreseeable consequences, such as higher inflation and higher U.S. production. The other road Mills describes as OPEC believing its own strong demand forecasts and unwinding the cuts. This is definitely one way of framing the road ahead. In the same vein, however, one could argue that sticking to the cuts is also a sign of belief in OPEC’s strong demand expectations: if demand is so resilient and prone to expand, it will expand even in a higher-price environment.

This is precisely what happened in 2022 when the start of the Russia/Ukraine conflict pushed oil above $100 per barrel and held it there long enough for the annual average to come in at close to $95 per barrel. Demand during that year of high oil prices rose by over 2.5 million barrels daily. And that was before China came roaring back from the pandemic lockdowns, which only ended in late 2022.

So, while it would make sense to expect OPEC+ to start thinking about putting an end to its production cuts, it might make more sense to keep them in place—not least because an unwinding of the cuts would have about the same effect on prices as the news that U.S. shale output grew by over 1 million bpd last year.

OPEC expects oil demand this year to grow by 2.2 million bpd. With the cuts in place, this rate of demand growth is certain to push the global market into a deficit. Estimates of the size of this deficit vary, with the IEA seeing a “slight” deficit as a result of the OPEC+ cuts and stronger demand prompted by the Red Sea situation. Qamar Energy’s Mills, however, sees a deficit of as much as 4 million barrels daily developing later in the year.

Should this happen, there would be nothing easier for OPEC than announcing an end to the cuts, or at least a tweak, to avoid a price slump. And a deficit environment would be the best time to make these tweaks—with prices high and demand resilient, the effect of such an announcement on prices would be mitigated by the fundamentals. Because the cuts can’t go on forever, not when some OPEC members are already grumbling against the quotas.

By: Oil Price, By Irina Slav / April 11, 2024

ACME Group and Hydrogenious LOHC Technologies have signed a memorandum of understanding (MoU) to collaborate on a feasibility study to explore the joint development of large-scale hydrogen supply chains from ACME’s projects in Oman to supply hubs in Europe using the innovative LOHC technology. Both parties intend to extend the partnership to evaluate the hydrogen value chain from USA to Europe.

Oman benefits from abundant renewable energy resources such as solar and onshore wind while US Inflation Reduction Act offers production incentives leading to competitive hydrogen production cost. The green hydrogen produced by ACME in these projects can be stored in LOHC and transported by tanker to Europe to supply and decarbonise industrial offtakers, energy and mobility.

‘Green hydrogen is emerging as a real opportunity that can transform the global energy systems and meet the decarbonisation goals of industry and governments. While some will continue to challenge the economic and technical feasibility, we have taken conclusive decisions on our Oman project and partnering with Hydrogenious to develop efficient logistics using LOHC is the next step in delivering cost effective value proposition for our customers,’ says Ashwani Dudeja, group president and director for ACME Group.

Hydrogenious’ LOHC technology is perfectly suited for large-scale hydrogen imports via maritime supply chains, enabling viable and cost-effective import vectors to Europe. By safely binding hydrogen to the thermal oil benzyltoluene (LOHC-BT) in a chemical process, the volatile green molecules can be efficiently stored and transported at ambient pressure and temperature using the existing liquid fuel infrastructure.

‘As companies, ACME and Hydrogenious are at the forefront of the energy transition and share the common goal of driving global decarbonization. Our collaboration will contribute to making clean hydrogen from the MENA region and the US available to European off-takers in the mid to long term,’ explains Toralf Pohl, Chief Commercial Officer at Hydrogenious LOHC Technologies and continues: ‘Due to its inherent safety, LOHC-BT is particularly suited for handling hydrogen in ports and urban environments, as it is hardly flammable, very stable and has a competitive volumetric storage density, enabling large-scale, long-distance hydrogen value chains without hydrogen losses.

By: Tankstorage / Anamika Talwaria, April 10, 2024