Category: Nieuws

In recent weeks, Rhine freight rates for transporting liquid bulk products up the Rhine rose significantly to the various destinations as market players cope with the retreating water levels, lack of available barges and a necessary re-supply of product into tanks.

The hefty backwardation in the gasoil markets, seen since the start of the Russian invasion of Ukraine, has prompted traders to cut back on stocks in hinterland depots and only move the bare minimum of product into tanks.

The current rise in demand from end consumers, along with a expected cutback in natural gas usage in favor of diesel and heating oil, adds up to the problems the market currently faces. Next, barges are in most cases secured for medium and long-term on a Time Charter basis or face long waiting times before loading at various terminals in ARA, thus limiting the spot barge supply even further.

Traders are not able to cover their positions and there are therefore concerns over local product availability, as alternatives like rail deliveries are coping with staff shortages and not all barges will be able to travel past bottlenecks like Kaub (draughts expected to drop below 150cm) and Maxau (expected to drop below 140cm) in the coming days. Freight rates were stable and low during the spring, although the warmer and dry weather has caused an early snowmelt season in the Alps. Since May, water levels have been retreating which started limiting the supply of product.

The situation deteriorated in July, with water flows currently reaching thresholds normally seen during autumn and even hitting the bottom of the five-year range, firmly below the levels seen during the drought period starting August 2018. This has all led to the freight rate levels we currently see in the market, with no idea when this situation will stabilize.

Insights Global keeps track of the spot market up the Rhine and in ARA and publishes daily benchmark rates that reflect the current market conditions. If you are interested in more information, please feel free to contact me or the office via info@insights-global.com!

Petrobras has restarted the sale processes of the Abreu e Lima Refinery (RNEST), in Pernambuco; Presidente Getúlio Refinery Vargas (REPAR), in Paraná; and Alberto Pasqualini Refinery (REFAP), in Rio Grande do Sul, Brazil, as well as the logistics assets integrated into these refineries.

The main subsequent stages of the sale processes of these three refineries will be informed to the market in a timely manner.

Petrobras’ refining divestment plan represents approximately 50% of the national refining capacity, totaling 1.1 million bpd of processed oil, and considers the full sale of the following assets: Abreu e Lima Refinery (RNEST), Shale Industrialization Unit (SIX), Landulpho Alves Refinery (RLAM), Gabriel Passos Refinery (REGAP), Presidente Getúlio Vargas Refinery (REPAR), Alberto Pasqualini Refinery (REFAP), Isaac Sabbá Refinery (REMAN) and Lubricants and Petroleum Derivatives do Nordeste (LUBNOR), as well as the logistics assets integrated to these refineries.

The sale of these eight refineries is being conducted in accordance with Decree 9188/2017 and the Petrobras Divestment System, through independent competitive processes, which are in different stages, as widely disclosed by the company. The operations are in line with Resolution No. 9/2019 of the National Energy Policy Council, which established guidelines for the promotion of free competition in the refining activity in the country, and are part of the commitment signed by Petrobras with CADE in June 2019 to the opening of the refining sector in Brazil.

Petrobras concluded the sale of RLAM, on 30 November 2021, and the REMAN, LUBNOR and SIX refineries have already had their purchase and sale agreements signed and are awaiting the fulfillment of the conditions precedent, among them, the obtaining of regulatory approvals, to be completed. REGAP is in the binding phase.

The divestments in refining are in line with the portfolio management strategy and the improvement of the company’s capital allocation, aiming at maximising value and greater return to society.

Hydrocarbon Engineering by Bella Weetch, July 28, 2022

Sasol Ltd., South Africa’s largest fuel producer, declared force majeure on the supply of petroleum products due to delays in deliveries of crude to the Natref refinery it owns with TotalEnergies SE, leaving just a fraction of the country’s fuel-production capacity still operational.

Natref, a 108,000 barrel-a-day plant, was forced to shut after the late oil shipments, the company said in a statement. “Sasol Oil will not be in a position to fully meet its commitments on the supply of all petroleum products from July 2022,” the firm said.

The shutdown means the whole of South Africa’s oil-refinery fleet is out of action after a string of other facilities suspended production over the past two years. As a result, the country’s monthly petroleum product imports are set to as much as triple by next year from pre-pandemic levels, energy consultant Citac said in a May report.

Only Sasol’s synthetic fuel operations, which use coal as a feedstock, remain fully operational, making up about a fifth of nationwide capacity.

A fire at the Engen oil refinery, which will be converted into a terminal, and an explosion at Glencore Plc’s Cape Town refinery, have rapidly curbed capacity.

Sapref, the country’s biggest plant, which is owned by Shell Plc and BP Plc, stopped operations ahead of a sale and was subsequently damaged by floods. State-owned PetroSA’s gas-to-liquids plant, another synthetic operation, has run out of feedstock.

Meanwhile, a clean-fuels policy that’s set to take effect next year raises the likelihood that refineries unable to meet the new standards will have to shut permanently.

For now, the outage at Natref is temporary. Crude oil shipments are expected to start arriving shortly, with the plant expected to ramp up to maximum production by the end of July, Sasol said.

The partners have yet to conclude options on the future of the plant, Sasol Chief Executive Officer Fleetwood Grobler said earlier this year.

The Cape Town refinery is also expected to restart in the second half of 2022.

Bloomberg by Paul Burkhardt, July 28, 2022

The International Energy Agency (IEA) estimates that global refining capacity decreased by 730,000 barrels per day (b/d) in 2021—the first decline in global refining capacity in 30 years.

In the United States, refining capacity has decreased by about 1.1 million b/d since the start of 2020, contributing 184,000 b/d to the global decline in 2021. Global demand for refined products dropped substantially in 2020 as a result of the COVID-19 pandemic.

Less petroleum demand and the associated lower petroleum product prices encouraged refinery closures, reducing global refining capacity, particularly in the United States, Europe, and Japan. However, the US Energy Information Administration (EIA) notes that a number of new refinery projects are set to come online during 2022 and 2023, increasing capacity.

As global demand for petroleum products returned closer to pre-pandemic levels through 2021 and early 2022, the loss of refinery capacity contributed to higher crack spreads—the difference between the price of a barrel of crude oil and the wholesale price of petroleum products—which serve as one indicator of the profitability of refining.

After Russia began its full-scale invasion of Ukraine in late February 2022, the impacts of reduced global refining capacity were exacerbated.

Associated sanctions on Russia—with more than 5 million b/d in crude oil processing capacity—disrupted exports of Russia’s refined products into the global market, and will likely continue to do so as import bans in the European Union and United Kingdom come into full force.

Constraints on global refinery capacity have been contributing to higher crack spreads in the first half of 2022, and they are likely to continue contributing to high crack spreads through at least the end of this year.

In its June 2022 Oil Market Report, the IEA expects net global refining capacity to expand by 1.0 million b/d in 2022 and by an additional 1.6 million b/d in 2023. New refining capacity growth includes several high-profile, high-capacity refinery projects underway, particularly in China and the Middle East, which could add more than 4.0 million b/d of new capacity over the next two years.

High-capacity refineries require access to reliable sources of crude oil inputs to maintain higher utilization and to a sufficiently large pool of potential customers to supply. Many of these new refineries are located in coastal areas and have easy access to export refined products that are not consumed domestically.

The most global refining capacity under development is in China. Chinese capacity is scheduled to increase significantly this year because of the start of at least two new refinery projects and a major refinery expansion.

The first new refinery is the private Shenghong Petrochemical facility in Lianyungang, which has an estimated capacity of 320,000 b/d and reported trial crude oil-processing operations beginning in May 2022.

The second new refinery is PetroChina’s 400,000 b/d Jieyang refinery, in the southern Guangdong province, which is expected to come online in the third quarter of 2022 (3Q22). A planned 400,000 b/d Phase II capacity expansion also began operations earlier in 2022 at Zhejiang Petrochemical Corporation’s (ZPC) Rongsheng facility.

Although these projects are the most imminent new capacity expansions in China, the country is expected to continue increasing its refining and petrochemical processing capacity through a number of additional projects expected to come online by 2030.

Most noteworthy among these additional expansions are the 300,000 b/d Huajin and the 400,000 b/d Yulong refinery projects, which both have target start dates in 2024.

Outside of China, the 300,000 b/d Malaysian Pengerang refinery restarted in May 2022 after a fire forced the refinery to shut down in March 2020. The refinery’s return is likely to decrease petroleum product prices and increase supply, particularly in south and southeast Asian markets.

Substantial refinery capacity was also added in the Middle East during the past year. The 400,000 b/d Jizan refinery in Saudi Arabia reportedly came online in late 2021 and began exporting petroleum products earlier this year.

More recently, the 615,000 b/d Al Zour refinery in Kuwait—the largest in the country when it becomes fully operational—began initial operations earlier this year and the facility’s operators expect to increase production through the end of 2022.

A new 140,000 b/d refinery is scheduled to come online in Karbala, Iraq, this September, targeting to be fully operational by 2023. A new 230,000 b/d refinery operated by a joint venture between state-owned-firms OQ (of Oman) and Kuwait Petroleum International is set to come online in Duqm, Oman, likely in early 2023.

More than 2 million b/d of new refining capacity construction is expected to come online to support markets in the Indian Ocean basin in 2022. At the same time, a handful of major projects are also planned in the Atlantic basin.

The 650,000 b/d Dangote Industries refinery in Lagos, Nigeria, set to be the largest in the country when completed, may come online in late 2022 or 2023. The refinery would most likely meet Nigeria’s domestic petroleum product demand as well as demand in nearby African countries, and it would also reduce demand for gasoline and diesel imports into the region from Europe or the United States.

In Mexico, state-owned refiner Pemex has been building a 340,000 b/d refinery in Dos Bocas, which hosted an inauguration ceremony on 1 July, even though the refinery is still under construction and is unlikely to begin producing fuels until at least 2023.

TotalEnergies is planning to restart its 222,000 b/d Donges refinery along the Atlantic Coast of France in May 2022, after closing the facility in late 2020, and some reports indicate the facility has begun importing crude oil for processing.

In addition to major new refinery projects, other facilities are also moving forward with capacity expansions at existing refineries—particularly in India. HPCL’s Visakha Refinery is undergoing a major expansion, estimated at 135,000 b/d, which is scheduled to come online by 2023. A number of other similar expansions are underway in India that may come into effect in 2024 or later.

Although no projects to build new refineries in the United States are currently planned, major refinery expansions are underway at a handful of Gulf Coast refineries, most notably ExxonMobil’s Beaumont, Texas refinery, which plans to increase its capacity by 250,000 b/d by 2023.

Facilities along the Gulf Coast currently account for 54% of all US domestic refining capacity. They supply fuels for US domestic petroleum consumption, but they are also substantial exporters into the Atlantic basin market, particularly into Central and South America and also into Europe.

If the projects mentioned above were to come online according to their present timelines, global refinery capacity would increase by 2.3 million b/d in 2022 and by 2.1 million b/d in 2023.

EIA cautions that the estimate is not necessarily a complete list of ongoing refinery capacity expansions. Moreover, many of these projects have also already been subject to major delays, and the possibility of partial starts or continued delays related to logistics, construction, labor, finances, political complications, or other factors may cause these projects to come online later than currently estimated.

By Green Car Congress, July 28, 2022

Shell, French utility Engie, gas shipping company Anthony Veder and tank storage firm Vopak have agreed to study the feasibility of shipping hydrogen from Portugal to the Netherlands, signalling progress for a project that was hit by the exit of Portugal’s two largest energy companies last year.

The companies plan to produce 100 t/d of hydrogen via electrolysis using renewable power at the Portuguese port of Sines from 2027, with the potential to scale this up over time. The hydrogen would be liquefied and shipped to the port of Rotterdam for distribution and sale.

The companies’ agreement to progress towards a feasibility study will help move forward plans outlined by the Netherlands and Portugal to develop a strategic export-import value chain for renewable hydrogen.

The countries in 2020 signed an agreement to combine their respective 2030 national hydrogen strategies. But Portugal’s Galp and EDP quit the H2Sines project for exports to the Netherlands last year. Galp said at the time it would instead focus on “supplying hydrogen for our Sines [oil] refinery”, and EDP said “its future green hydrogen investments should be directed at other projects”.

Shell could draw on the experience in shipping liquid hydrogen it gained as a member of the HESC project, which earlier this year undertook the first seaborne movement of liquid hydrogen on a 75t vessel to Japan from Australia.

Rotterdam-based Vopak operates a storage terminal at the port for a wide variety of oil products, chemicals, and gases, and Anthony Veder owns a fleet of 33 gas carriers for LNG, ethylene, and LPG.

The firms have applied for funding for the project through the EU-managed Important Projects of Common European Interest (IPCEI) framework.

Argus by Sheel Bhattacharjee, July 28, 2022

Oil prices rose about 1%, with global benchmark Brent settling at a two-week high in volatile trade on Tuesday as traders worried about tight supplies and a weaker dollar.

Brent futures rose $1.08, or 1.0%, to settle at $107.35 a barrel. U.S. West Texas Intermediate (WTI) crude rose $1.62, or 1.6%, to settle at $104.22.

Brent posted its highest close since July 4 and WTI its highest since July 8. At one point during the volatile session, both benchmarks were down around $2 a barrel.

“Crude oil has staged an incredible turnaround today,” said Robert Yawger, executive director of energy futures at Mizuho.

“There was no big red bullish headline to greenlight the rally, but the combination of beaten down open interest and low trade volume will often encourage wild price swings,” Yawger said.

The U.S. dollar

Oil prices have whipsawed, supported by supply fears due to Western sanctions on Russia, but pressured by global central bank efforts to tame inflation which stoked fears that a potential recession could cut energy demand.

On Friday, open interest in New York Mercantile Exchange futures fell to the lowest since September 2015 as investors cut risky assets like commodities, worried that the Federal Reserve will keep raising U.S. interest rates.

The U.S.-Canada Keystone pipeline was operating at reduced capacity on Monday after a pump station was shut.

Libya’s new National Oil Corp (NOC) chief Farhat Bengdara rejected challenges to his appointment and work resumed at some shuttered fields and ports.

The U.S. 3:2:1 and gasoline crack spreads – measures of refining profit margins – both fell to their lowest since April.

“Crack spreads continuing plunge of past four weeks to narrowest level since late April … suggesting weakening product demand,” said analysts at Ritterbusch and Associates, a consultancy.

Last week, U.S. President Joe Biden visited top oil exporter Saudi Arabia, de facto leader of the Organization of the Petroleum Exporting Countries (OPEC), whose crude exports slipped in May to a four-month low.

Biden hoped to strike a deal on an oil production boost to tame fuel prices, but the kingdom’s foreign minister said the market’s problem was not a crude shortage but a lack of refining capacity.

In the United States, expectations for an increase in crude inventories weighed on prices. Analysts polled by Reuters forecast crude inventories rose by 1.4 million barrels last week.

The American Petroleum Institute (API), an industry group, will issue its inventory report at 4:30 p.m. EDT (2030 GMT) on Tuesday. The U.S. Energy Information Administration (EIA) reports at 10:30 a.m. EDT (1430 GMT) on Wednesday.

On Tuesday, people familiar with Biden’s plans told Reuters that the president plans to announce new federal measures aimed at the climate crisis on Wednesday.

Early in the session, oil prices fell on weak economic data from around the world.

Reuters by Scott Disavino, July 26, 2022

Here’s a thought: fuel shortages wouldn’t be as severe as they are today had bureaucrats not thrown a spanner in the works of two long-delayed LNG terminals.

One may be tempted to cite the recent defaults by LNG suppliers under long-term contracts alongside record-high prices on the spot market to declare that the need for more LNG terminals has become moot.

But before leaping to conclusions, consider the following: it’s not sovereign-backed Qatar Energy that’s been defaulting on long-term contracts; rather the international trading houses — Eni and Gunvor — that have defaulted on promised cargoes and messed up the country’s power sector.

One of the two planned terminals is backed mainly by Qatar and has three local industrial groups as minority shareholders. After six years of navigating the regulatory rigmarole, the terminal is still a distant dream.

Had the terminal received the promised pipeline capacity from Sui companies in time, it would’ve been importing Qatari gas under long-term contracts already, for onwards sale to the local industry, without the need for any sovereign guarantees.

The other planned terminal is wholly owned by Mitsubishi Corporation, one of the most influential players in the global energy market. No LNG trader in the world would’ve defaulted on its cargoes because the Japanese player is responsible for more than half the LNG imported every year by Japan, one of the biggest gas importers worldwide.

Impact of Ukraine war

Pakistan began importing LNG in 2015 as domestic gas reserves started depleting at a faster pace. The country has already installed two terminals on Port Qasim. Pakistan State Oil Company Ltd uses the Engro Elengy Terminal to import gas under long-term contracts, while Pakistan LNG Ltd brings spot purchases through the GasPort LNG Terminal.

Less than 50 per cent of annual LNG imports are through the spot market, where prices skyrocketed after the Russian invasion of Ukraine on Feb 24. Little wonder that no bidder responded to the latest tenders by Pakistan LNG Ltd for 10 cargoes. Before that, the state-owned company made three unsuccessful attempts to buy LNG in July.

As for the four long-term contracts meant to bring more than half of the country’s total LNG imports at substantially lower than spot rates, there have been constant defaults by global suppliers.

Since the beginning of 2021, Eni has defaulted on at least four cargoes while Gunvor has defaulted on at least seven, according to data compiled by the Institute of Energy Economics and Financial Analysis.

Force majeure or not?

Pakistan reserves the right to impose a penalty on defaulting suppliers equalling 30pc of the cargo cost. Suppliers invoke force majeure — unforeseeable circumstances preventing them from fulfilling the contract — to avoid paying the penalty.

“Long-term contracts must always require the supplier to disclose the fuel source and the vessel’s name. Otherwise, what’s stopping it from selling the cargo on the spot market whenever the rate is high enough to justify a default on long-term deliveries?” said an energy expert with many years of LNG procurement experience for European employers.

It’s difficult to invoke force majeure on a false pretext if the long-term buyer knows the source of LNG and the vessel that’s supposed to deliver it.

The developers of both upcoming terminals have repeatedly asked the government to allocate at least 300 million cubic feet per day (mmcfd) of pipeline capacity each before they take the final investment decision (FID), however, there has been little tangible progress from the state-owned gas utility companies on the allocation of pipeline during the past few years.

Qatar-backed Energas LNG and Mitsubishi-backed Tabeer LNG have capacities of 750-1,000mmcfd each. Given the capacities of the already-operational Engro Elengy (690mmcfd) and GasPort LNG (750mmcfd), the addition of the two “merchant” terminals can more than double the country’s re-gasification capacity.

They will also increase the country’s LNG storage capacity, which currently stands at 320,000 cubic metres.

Pakistan is one of the top seven LNG importers globally, yet it ranks as low as 18th in terms of storage capacity.

As a matter of fact, the country uses the existing Floating Storage and Re-gasification Units (FSRUs) of the existing two terminals merely as re-gasification units. This means the system relies heavily on the gas line-pack, which is the volume that can be stored in a pipeline for scheduling purposes.

According to a July 4 report by Reuters, Germany has leased as many as four FSRUs in a bid to quickly diversify away from Russian energy. “But here, foreign investors have been running from pillar to post for years just to get the promised pipeline capacity,” said the energy expert.

DAWN by Kazim Alam, July 27, 2022

The United States is shipping record volumes of liquefied natural gas (LNG) to Europe to help EU allies in their efforts to fill gas storage ahead of the winter amid growing uncertainty about Russian gas supply. 

For the first time ever, the European Union imported in June more LNG from the United States than gas via pipeline from Russia, as Moscow slashed supply to Europe in the middle of last month.

Going forward, demand for U.S. LNG is set to remain robust as Europe races to reduce its dependence on Russian pipeline gas.  

In the U.S., LNG export capacity is growing as new trains at Sabine Pass and Calcasieu Pass came online this year. But in order to continue growing, the LNG industry will need more domestic midstream infrastructure – pipelines – to carry natural gas from production centers to LNG export terminals on the U.S. Gulf Coast and demand centers on the Eastern Seaboard. 

The Marcellus-Utica basin, the largest U.S. gas-producing region, and the second biggest gas-producing shale region, the Permian, could soon run into pipeline constraints that could undermine America’s ability to raise its LNG exports, energy analyst David Blackmon writes in Forbes.

The Federal Regulatory Energy Commission (FERC) hasn’t raced to approve pipeline projects, while the mixed messages from the Biden Administration continue to add uncertainties for upstream and midstream operators. 

There’s also opposition from communities to pipelines crossing their land or passing close to their homes. 

Such is the case with the Matterhorn Express Pipeline, designed to transport up to 2.5 billion cubic feet per day (Bcf/d) of natural gas through approximately 490 miles from Waha, Texas, to the Katy area near Houston, Texas.

The pipeline developers WhiteWater, EnLink Midstream, Devon Energy, and MPLX LP reached a final investment decision in May to move forward with the construction of the pipeline, expected to be in service in the third quarter of 2024, pending the receipt of customary regulatory and other approvals. 

But landowners in Williamson County, where the pipeline is planned to cross, are worried about the impact of the pipeline on their properties, although the county hosts at least a dozen pipelines already. Some Williamson County residents have asked the pipeline developers to reroute some parts of the project. 

“Williamson County lies in the most direct path from Midland to Freeport,” County Commissioner Russ Boles told Austin American-Statesman. 

The industry, for its part, calls for streamlined approval of pipeline projects that would help bring more gas to U.S. demand centers and LNG export facilities.

There are currently 11 major natural gas projects pending approval before the FERC, more than half of which have their final environmental documents, the Interstate Natural Gas Association of America (INGAA) said at the end of March 2022, days after the U.S. and the EU announced a deal for more U.S. LNG exports to the EU as the latter seeks to replace Russian supplies. 

“FERC’s approval is the imperative next step for these important projects. Without the additional capacity, which totals more than 12,141 MMcf/day pending currently, some of the added gas supply policymakers are calling on developers to produce will not reach American consumers or LNG terminals along U.S. coasts for export,” INGAA said. 

The American Petroleum Institute (API) has a ten-point plan to restore U.S. energy leadership. This plan includes a recommendation that the FERC “should cease efforts to overstep its permitting authority under the Natural Gas Act and should adhere to traditional considerations of public needs as well as focus on direct impacts arising from the construction and operation of natural gas projects.” 

U.S. LNG exports are set to decline in the second half of 2022 because of the outage at Freeport LNG, the EIA said in its latest Short-Term Energy Outlook (STEO) on Tuesday. U.S. LNG exports are forecast to average 10.5 Bcf/d in the second half of 2022, which is 14% less than the forecast in the June 2022 STEO. 

The EIA expects LNG exports will grow in 2023, averaging 12.7 Bcf/d on an annual basis, or 17% higher than in 2022.

The U.S. will need pipelines and a federal policy supporting such projects in order to continue growing LNG exports and delivering gas to the domestic demand centers.  

Oilprice.com by Tsvetana Paraskova, July 27, 2022