Category: Nieuws

In such uncertain times, there are few economic sectors that are a 100% sure bet for investors – but energy storage certainly seems to be one of them. As the world leans more earnestly toward decarbonization and the United Nations and the Intergovernmental Panel on Climate Change sound a “code red for humanity” as the window of opportunity to avoid the worst impacts of global warming rapidly closes, energy storage has become one of the fastest-growing industries as demand for clean energy heats up. 

The global energy storage market is on track to hit one terawatt hour by 2030, a quantity that would mark a more-than 20-fold increase over the already groundbreaking 17 gigawatts/34 gigawatt-hours that were online at the end of 2020. “Overall investment in battery storage increased by almost 40% in 2020, to USD 5.5 billion,” the International Energy Agency (IEA) reported at the end of last year.

“The global storage market is growing at an unprecedented pace. Falling battery costs and surging renewables penetration make energy storage a compelling flexible resource in many power systems,” says Yiyi Zhou, a clean power specialist at Bloomberg BNEF. “Energy storage projects are growing in scale, increasing in dispatch duration, and are increasingly paired with renewables.”

The breakneck increase in storage capacity is largely being driven by China and the United States, which are currently embroiled in a quietly simmering energy storage war. Each of these countries added gigawatt-scale additions of energy storage capacity in 2020. Together, China and the U.S. represent more than half of the global energy storage market projections for 2030.

China is currently winning the race, having more than doubled its energy storage capacity additions in 2020. What’s more, in July of last year, Beijing announced that it is planning to install 10 times more capacity than its 2020 levels by just 2025.

Oilprice by Haley Zaremba, April 4, 2022

Vladimir Putin’s fateful decision to invade Ukraine and the ongoing brutality have made Russia a pariah state to many leading hydrocarbon-consuming nations, which in turn has caused cuts in Russian crude oil production and exports.

That raises a few important questions, chief among them the degree to which other producers — including the U.S. and the non-Russian members of OPEC+ –– can ramp up their production and displace Russian oil. U.S. output has been increasing recently, albeit only gradually, and production could rise much more quickly under the right circumstances.

But if it does, would there be enough crude export capacity available along the Gulf Coast to handle, say, another 500 Mb/d or 1 MMb/d? In today’s RBN blog, we examine the ability of key U.S. export facilities to stage, load and ship out increasing volumes of oil.

Last week, the International Energy Agency (IEA) forecast that, on average, 1.5 MMb/d of Russian oil production will be shut in during April and double that amount — a staggering 3 MMb/d — may be offline in May.

There are three primary drivers behind the decline, according to IEA: (1) more run cuts by Russian refiners as the economy there slows, (2) Russian storage capacity filling up and (3) more foreign buyers shunning Russian barrels. To many — including the U.S., Canada, the UK and Australia — the stuff is tainted, not in a physical sense but because Russian oil sales help to finance a disgusting, immoral war.

The 27 member nations of the European Union (EU) feel the same way, and it was reported Thursday by The New York Times that EU officials are drafting an embargo under which they would quickly wean themselves off Russian oil too –– a challenging task, given what has become continental Europe’s heavy dependence on crude from the east.

It is too soon to know how this will all play out, but it would seem logical to expect that, for the global crude oil market to be restored to balance, the declines in Russian production and exports will need to be offset to a considerable degree by rising production in — and exports from — the handful of oil-producing countries able to ramp up their output and sales to foreign buyers. In recent weeks we have blogged extensively about related aspects of this same Russia-centric story.

For example, in Help Is on Its Way and Baby, I Got It, we discussed the U.S.’s ability to help Europe replace piped-in Russian natural gas with U.S.-sourced LNG. In We’re Not Gonna Take It, we wrote about how U.S. refiners could replace Russian imports in their slates.

Also, in I Can’t Go for That (No Can Do) we looked at why many U.S. producers have been slow to increase their crude oil output, and in I Want to Break Free we examined how the Biden administration’s planned release of up to 180 MMbbl from the Strategic Petroleum Reserve (SPR) may serve as (in President Biden’s words) “a wartime bridge to increase oil supply until production ramps up later this year,” a topic we also discussed in Road to Nowhere.

RBN Energy, by Housley Carr, April 20, 2022

Europe’s plan to reduce dependence on Russian gas and strengthen the continent’s energy security depends on its ability to secure specialized ships that provide the fastest way to import alternative supplies and quickly build the associated infrastructure.

Since Russia invaded Ukraine last month, Germany, Italy and the Netherlands have announced plans to secure floating storage and regasification units (FSRUs) – liquefied natural gas tankers with heat exchangers that use seawater to convert the supercooled fuel back to gas.

These docked ships offer Europe the fastest way to end its dependence on pipelines carrying large amounts of fuel from Russia. “Europe is crying out for FSRUs to get energy in whatever it takes,” said Yngvil Asheim, director of Oslo-based BW LNG, one of the world’s handful of FSRU owners.

The EU plans to cut its dependency on Russian natural gas by two-thirds by the end of this year and aims to import 50 billion cubic meters of LNG annually. While there are doubts about whether there is enough LNG supply worldwide to meet European needs, analysts say infrastructure could be a critical bottleneck.

Europe has the infrastructure to regasify 170 bcm of LNG, but most of the spare capacity is in the Iberian Peninsula, which lacks sufficient pipelines to move supplies further north.

The construction of LNG import terminals on land takes at least five years and is expensive. FSRUs, which can each import about 5 bcm per year, are cheaper and faster to install. But despite being faster to install, FSRUs can still take several years to install. Global supply chain tightness threatens further delays, industry figures say.

Germany, which has no LNG import terminals, is exploring possible locations in the North and Baltic Seas for three FSRUs with an estimated capacity of 27 bcm, and estimates the first could come into operation this year. Jason Feer, head of business intelligence at energy and shipping brokerage Poten & Partners, predicts that Germany’s first FSRU will not be operational before 2024.

The Dutch gas transport group Gasunie has said it may be able to import LNG in the third quarter of this year. Robert Songer, an analyst at ICIS, a commodity data company, said this project was first planned a decade ago. “Anything bigger and not yet on the drawing board will definitely take longer,” he said.

Reserve ships are also scarce. Of a global fleet of about 50 FSRUs, Karl Fredrik Staubo, chief executive of Golar LNG, a Bermuda-based FSRU owner, estimates that only five vessels are available and three of contracts could be released this year. Not all of these are suitable for Northern Europe as water below 10C is too cold for the heat exchange system used on some ships.

Europe could accelerate the green shift, but what will happen in the rest of the world and Asia. At these prices they will burn coal.

According to industry sources, charter rates for FSRUs have risen by at least 50 percent since the outbreak of war in Ukraine to between $150,000 and $180,000 per day. Rystad Energy estimates it costs $40mn to $60mn per year to charter an FSRU. “Companies are in a bidding war” [for FRSUs]”, says Gordon Milne, director of FSRU Solutions, a consultancy.

Until the sudden surge in demand, the FRSU market suffered from overcapacity. “It no longer makes sense to build a new FSRU,” says Oystein Kalleklev, Flex LNG, an LNG shipping company. Due to construction backlogs, it may take until 2027 before a new unit is delivered.

The increased competition for LNG and the FSRUs needed for its imports is likely to deter poorer future LNG importers, such as Sri Lanka, Brazil and Panama, who would instead turn to dirtier fuels. “Europe could accelerate the green shift, but what will happen in the rest of the world and Asia,” Asheim said. “At these prices they will burn coal.”

WHATSNEWS2DAY, by Jacky, April 14, 2022

Major global trading houses plan to cut crude and fuel purchases from state-controlled Russian oil companies as early as May 15.

Major global trading houses plan to cut crude and fuel purchases from state-controlled Russian oil companies as early as May 15, sources said, to avoid falling foul of European Union sanctions against Russia.

The EU did not impose a ban on Russian oil imports in response to Russia’s invasion of Ukraine, as some countries like Germany are highly dependent on Russian oil and do not have the infrastructure in place to switch to alternatives. [nL5N2VO3PE]

The trading companies are, however, ending their purchases from Russian energy group Rosneft as they seek to comply with the wording of existing EU sanctions that aimed to limit Russia’s access to the international financial system, the authorities said. sources.

The wording of the EU sanctions exempts oil purchases from Rosneft or Gazpromneft, which are listed in the legislation as “strictly necessary” to ensure Europe’s energy security.

Traders are wrestling with what “strictly necessary” means, the sources said. It may cover an oil refinery receiving Russian oil via a captive pipeline, but it may not cover the buying and selling of Russian oil by intermediaries. They are reducing their purchases to ensure they comply by May 15, when EU restrictions come into force.

The inclusion of Russian state infrastructure company Transneft, which owns major ports and pipelines, will add an extra layer of complexity to any future sale.

Trafigura, a major buyer of Russian oil, told Reuters it “will fully comply with all applicable sanctions. We expect our trading volumes to be further reduced from May 15.”

Vitol, another big buyer, declined to comment on the May 15 TSTIME. Vitol has previously said traded volumes of Russian oil will “decline significantly in the second quarter as current contractual obligations diminish”, and that it will cease trading Russian oil by the end of 2022.

The war and sanctions against Russia have already led many Western buyers of Russian crude like Shell to stop further spot purchases.

European refiners are increasingly reluctant to process Russian crude. This has already disrupted Russian exports, although purchases from India and Turkey have made up some of the delay. Sales to China also continue unabated.

Rosneft and Gazpromneft volumes were 29 million barrels, or nearly 1 million barrels per day (bpd) in April, or more than 40% of overall Urals crude oil exports from western Russian ports in April, according to the loading plan.

The International Energy Agency said Wednesday that Russian oil supply could be down 3 million bpd from May.

Rosneft declined to comment. Gazpromneft did not immediately respond to Reuters requests for comment. Other Russian oil buyers, Gunvor and Glencore, declined to comment on the impact of the TSTIME.

Energy trading companies face compliance and reputational risks due to the current round of Western sanctions. They need to look closely at the entities they can remunerate as well as the nationality of their employees. In addition, the absence of an outright prohibition complicates the termination of existing contracts.

“All companies sit down with their lawyers to figure out what they can and can’t do,” a senior trade source said. “It’s unclear what this means for the whole supply chain, for shippers, insurers,” adding that his company was looking at the implications for non-state-owned oil sales.

“Lawyers feast on this. Where there is uncertainty, companies will back down. Russian oil flows will be significantly reduced in the future.”

Reuters by Julia Payne, April 19, 2022

The deeply impoverished South American microstate of Guyana, which was rocked by the COVID-19 pandemic, finds itself at the epicenter of the continent’s latest mega-oil boom. Since 2015, ExxonMobil, which has a 45% stake and is the operator, along with its partners Hess and CNOOC which own 30% and 25% respectively, has made a swathe of high-quality oil discoveries in Guyana’s offshore 6.6-million-acre Stabroek Block.

Exxon, which is the operator of the Stabroek Block, has made over 20 discoveries, 6 of those in 2021 alone, which the global energy supermajor estimates to hold at least 10 billion barrels of recoverable oil resources. The most recent crude oil discoveries, announced in January 2022, were at the Fangtooth-1 and Lau Lau-1 exploration wells. Those finds will boost the Stabroek Block’s oil potential adding to the 10 billion barrels of recoverable oil resources already estimated by Exxon.

The integrated energy supermajor is investing heavily in the Stabroek Block, which will be a game-changer for the company. Exxon’s first operational field in the Stabroek Block Liza Phase-1 achieved a nameplate capacity of 120,000 barrels per day during December 2020.

The next notable development for the Exxon-led consortium and a deeply impoverished Guyana is that the Liza Phase-2 development pumped first oil in February 2022. That operation is expected to reach a nameplate capacity of 220,000 barrels daily before the end of 20220, lifting the Stabroek Block’s output to around 340,000 barrels per day. In September 2020 Exxon gave the green light for the Payara oilfield project.

This $9 billion development is the supermajor’s third project in the Stabroek Block, and it is anticipated that Payara will start production during 2024, with the asset expected to reach a capacity of 220,000 barrels per day before the end of that year.

Earlier this month, Exxon made the final investment decision on the Yellow Tail offshore development choosing to proceed and invest $10 billion in the project. This was announced on the back of Guyana’s national government, in Georgetown, approving the project and signing a petroleum production license for Yellow Tail with the Exxon-led consortium.

This will be the integrated energy supermajor’s largest project to be developed to date in offshore Guyana. It is anticipated that Yellow Tail will commence production in 2025 reaching a nameplate production capacity of 250,000 barrels per day before the end of that year. That will lift overall petroleum output from the Stabroek Block to at least 810,000 barrels per day.

Exxon envisages that the Stabroek Block will be pumping over 1 million barrels per day by 2026 when the Uaru project, which has yet to be approved, comes online.

As a result of Exxon’s investment, Guyana will become a major player in global energy markets and a top 20 producer with the former British colony pumping an estimated 1.2 million barrels daily by 2026, two years earlier than originally predicted.

It isn’t only the Exxon-led consortium in the Stabroek Block which is enjoying drilling success in offshore Guyana. In late-January 2022 Canadian driller CGX Energy and its partner, the company’s majority shareholder, Frontera Energy discovered oil with the Kawa-1 exploration well in the 3-million-acre Corentyne Block in offshore Guyana.

The block, where CGX is the operator and its parent company Frontera owns a 33.33% working interest, is contiguous to the prolific Stabroek Block lying to its south-southwest. The Kawa-1 well is in the northern tip of the Corentyne Block, close to the discoveries made by Exxon in the Stabroek Block.

CGX and Frontera intend to invest $130 million in exploring the Corentyne Block. That includes spudding the Wei-1 exploration well in the northwestern part of Corentyne during the second half of 2022. According to CGX, the geology of the Kawa-1 well is similar to discoveries made in the Stabroek Block as well as the 5 significant finds made by TotalEnergies and Apache in neighboring Block 58 offshore Suriname.

It is believed that the northern segment of the Corentyne Block lies on the same petroleum fairway that runs through the Stabroek Block into Suriname’s Block 58.

These events point to offshore Guyana’s considerable hydrocarbon potential, supporting industry claims that the United States Geological Survey grossly miscalculated the undiscovered oil potential of the Guyana Suriname Basin. The USGS, which committed to revisiting its two-decade-old appraisal during 2020, only for that to be prevented by the COVID-19 pandemic, estimated 2 decades ago that the Guyana Suriname basin had to mean undiscovered oil resources of 15 billion barrels.

To date, Exxon has disclosed that it estimates to have found at least 10 billion barrels of crude oil in the Stabroek Block. This number can increase because of the latest discoveries in the block and ongoing development activities. Then there are TotalEnergies and Apache’s crude oil discoveries in Block 58 offshore Suriname where the flow-tested Sapakara South appraisal well has tapped a reservoir estimated to hold oil resources of over 400 million barrels.

In 2020 U.S. investment bank Morgan Stanley estimated that Block 58 could possess oil resources of up to 6.5 billion barrels.

The low costs associated with operating in Guyana, reflected by projected industry-low breakeven prices of $25 to $35 per barrel, and a favorable regulatory environment make it an extremely attractive jurisdiction for foreign energy companies. That appeal is enhanced by the crude oil discovered being relatively light and low in sulfur, making it particularly attractive in a global energy market where demand for low-carbon intensity and reduced emission fuels is rapidly growing. For those reasons investment from foreign energy companies and hence exploration as well as development activities in offshore Guyana are accelerating.

Aside from Frontera allocating up to $130 million to be invested in exploration activity in the Corentyne Block, Spanish energy major, Repsol, plans to ramp up activity in the nearby Kanuku Block in offshore Guyana. The company has contracted Noble to spud the Beebei-Potaro well in the block during May 2022. The Kanuku Block, where Repsol is the operator and holds a 37.5% interest with partners Tullow and TotalEnergies owning 37.5% and 25% respectively, is located south of, and contiguous to, the prolific Stabroek Block.

That places it close to Exxon’s Stabroek discoveries, notably the Hammerhead, Pluma, Turbot, and Longtail wells, indicating that the northern part of the Kanuku Block potentially contains the petroleum fairway that runs through the Stabroek and northern part of the Corentyne Block into offshore Suriname Block 58.

Recent oil discoveries combined with rising interest as well as investment from foreign energy investment coupled with the speed with which Exxon is developing the Stabroek Block could see Guyana pumping well over 1 million barrels per day earlier than expected. Some industry analysts speculate that volume could be reached by 2025 which is supported by statements from the CEO of Hess, Exxon’s 30% partner in the Stabroek Block, John Hess. These latest developments in offshore Guyana couldn’t come at a more crucial time with the U.S. looking to bolster crude oil supplies in the wake of Washington banning Russian energy imports.

If Guyana can rapidly grow low-carbon intensity offshore oil production as predicted, the deeply impoverished South American microstate will become an important supplier of crude oil, especially for the U.S. This will also deliver a significant economic windfall for Guyana, which has already seen its gross domestic product expanded by a stunning 20.4% during 2021 when crude oil production was only averaging 120,000 to 130,000 barrels per day.

OILPRICE by Matthew Smith, April 12, 2022

President Joe Biden’s decision to ban Russian energy imports to the U.S. is boosting the outlook for South America’s newest oil-producing nation Guyana as well as neighboring Suriname.

The deeply impoverished microstates share the offshore Guyana-Suriname Basin where global energy supermajor ExxonMobil with its partners has made a slew of quality petroleum discoveries in offshore Guyana’s Stabroek Block. In 2000 the U.S. Geological Survey estimated that the offshore basin, which is one of South America’s largest, holds mean undiscovered crude oil resources totaling 15 billion barrels.

There is growing evidence that the USGS may have grossly underestimated the basin’s hydrocarbon potential. This resulted in the U.S. government agency announcing it was planning to reassess the petroleum resources of the Guyana Suriname Basin in 2020, although that was put on hold because of the COVID-19 pandemic.

The mounting evidence that the Guyana Suriname Basin possesses far greater potential than originally believed indicates that the geological resource will be a game-changer for two of South America’s poorest countries.

Exxon estimates its discoveries in the Stabroek Block alone hold 10 billion barrels of recoverable oil resources, which have the potential for at least 10 development projects. As a result, analysts believe Guyana will be pumping over one million barrels of crude oil daily by 2027, which will deliver a tremendous economic windfall for one of South America’s most impoverished nations. Neighboring Suriname, which shares the Guyana Suriname Basin, is also poised to benefit from an oil boom of its own.

French oil supermajor TotalEnergies, which is the operator, and partner Apache both have a 50% stake in offshore Suriname Block 58 which is 1.8 million acres in size and contiguous to Exxon’s prolific Stabroek Block. The partners have reported a slew of oil discoveries since January 2020 with the latest being the February 2022 discovery at the Krabdagu-1 exploration well.

This is the fifth significant oil discovery in the block and the sixth if the non-commercial November 2021 discovery at the Bonboni-1 exploration well is included. The oil found in Block 58 is characterized as medium to light crude oil with an API gravity of 25 to 43 degrees.

Those discoveries demonstrate that Block 58 possesses considerable petroleum potential with some analysts estimating that it could hold up to six billion barrels of recoverable oil resources. TotalEnergies announced that by the end of 2022 it intends to identify sufficient oil resources, through drilling three exploration and appraisal wells in Block 58, to progress investment in operations for first oil development.

In a November 2021 media release, Apache announced the successful flow testing of the Sapakara South-1 appraisal well, which the driller estimated had tapped a reservoir containing 325 million to 375 million barrels of oil resources. By February 2022, Apache had revised that estimate upward to over 400 million barrels.

The U.S.-based driller has allocated $200 million to conduct further exploration and appraisal activities during 2022 most of which will be directed to offshore Suriname. The planned undertakings include spudding an exploration well in Block 53, located to the immediate east of Block 58, where the Apache has a 45% interest.

The raft of discoveries in Block 58 along with Malaysian national oil company Petronas and partner Exxon discovering oil in Block 52 points to Surname’s considerable petroleum potential. There is considerable speculation among industry participants and energy analysts that the petroleum fairway which lies underneath the Stabroek Block continues into Suriname’s part of the Guyana Suriname Basin.

It isn’t only deep-water blocks in offshore Suriname which possess considerable potential. The shallow waters immediately off the former Dutch colony’s coast are also thought to possess considerable hydrocarbon potential. By mid-2021, Staatsolie, Suriname’s national oil company and industry regulator, had completed a shallow water bid round.

Block 5 was awarded to Chevron while Blocks 6 and 8 went to a consortium composed of TotalEnergies (40%), Qatar Petroleum (20%), and Staatsolie (40%).

In December 2021 Chevron sold a 20% stake in Block 5 to energy supermajor Shell while retaining a 40% interest with the remaining 40% held by a subsidiary of Staatsolie. CGX Resources, along with partner Frontera, January 2022 oil discovery in the shallow water Corentyne Block in offshore Guyana bodes well for the success of Suriname’s shallow-water blocks. The Corentyne Block is contiguous to Block 58 offshore Suriname as well as the shallow water blocks 5 and 6.

Analysts believe that the petroleum fairway running through the Stabroek Block extends into the northern tip of the Corentyne Block, where CGX made the Kawa-1 discovery, and into Suriname’s shallow-water blocks 6 and 8.

In a June 2021 speech, Suriname’s President Chandrikapersad Santokhi stated that his administration expected Apache and TotalEnergies to make a final investment decision regarding developing Block 48 by the end of 2022. Paramaribo anticipates that first oil from Block 58 will be produced by early as 2025 or 2026 at the latest.

According to industry consultancy Rystad Energy, Suriname’s oil production will reach 650,000 barrels per day by the end of this decade. That will deliver a tremendous financial windfall for a country ranked as the fourth poorest, by per capita gross domestic product, in South America.

It will also provide Paramaribo with the opportunity to not only resuscitate an economy caught in a deep crisis that was sharply exacerbated by the COVID-19 pandemic but to restructure Suriname’s onerous sovereign debt.

OILPRICE by Matthew Smith, April 8, 2022

Despite Exxon’s recent exploration hurdle, Brazil has big plans for its oil industry as it hopes to increase its production levels significantly throughout 2022. With uncertainty around what the Russian invasion of Ukraine will mean for the energy industry over the coming months, Brazil is hoping to fill a supply gap as countries around the world look for alternative oil and gas sources. In addition, the replacement of state-run Petrobras’s CEO could shake up Brazil’s oil and gas industry.

Exxon Mobil Corp is currently exploring a new area off the northeast coast of Brazil, but its first well came up dry this week. This is Exxon’s first drilling development in Brazil in a decade, a region that it hopes will help boost its long-term production potential.

The energy major has invested heavily in the Brazil and Guyana oil markets in recent years, in the hope of discovering new low-cost oil regions that will help sustain its output and where it can implement low-carbon technologies as it strives to eventually achieve net-zero.

With a stake in 28 offshore blocks, Exxon hopes this stumble will not hinder its production potential in the region. Exxon’s spokesperson, Meghan Macdonald, stated “While we didn’t encounter hydrocarbons at this particular exploration well (Cutthroat-1), ExxonMobil will continue to integrate the data from our findings into regional subsurface interpretation efforts in order to better understand the block’s exploration potential.”

And some of Exxon’s other projects have been more fruitful. Its operations with Norway’s Equinor in the Bacalhau offshore field are expected to produce 200,000 bpd of oil and gas by 2024. In 2021, Exxon announced it would be investing 40 percent of an $8 billion total in the field.

This month, Brazil’s Minister of Mines and Energy, Bento Albuquerque, announced plans to boost the country’s oil production by 300,000 bpd, around a 10 percent increase in 2021. Brazil’s output already stands at around 3 million bpd of crude putting it at around ninth place in the world for production. 

Albuquerque told the Valor Econômico newspaper, “Countries that have stock, like the US, Japan, India, and others, are releasing. But there also has to be an effort to increase production.

She [Jennifer Granholm] asked me if Brazil could be part of this effort and I said ‘of course it can’. We are already increasing production, while most OECD countries have reduced. We have increased our production in the last 3 years.” 

The statement came in response to international pressure for oil-producing states to ramp up their oil and gas production as shortages are leading to energy insecurity and rising prices worldwide.

Following the Russian invasion of Ukraine, oil prices soared. In addition, as several countries introduce sanctions on Russian energy products, many governments are looking for alternative sources of oil and gas to ensure their energy security over the coming months. 

But some are not so confident about Albuquerque’s aim to increase production. There are plans for three offshore projects to come online in 2022 – the Petrobras Mero 1, with the Guanabara FPSO, producing approximately 150,000 bpd of oil, and Equinor’s Peregrino phase 2 and Peregrino 1 producing around 110,000 bpd. However, the reduced output in Brazil’s other maturing oil fields will likely reduce this output increase. 

A local consultant told Bnamericas, “In reality, the increase would have to be over 15%, with 5% to 8% to compensate for the natural decline and another 10% to actually increase production.

That would be 500,000b/d of new capacity, which is very unlikely.” This view has been echoed by several experts in the field, suggesting Albuquerque may not be able to deliver on his promise. 

While this rapid production increase may not be possible, big changes to the country’s state-owned company could mean a change to the national oil industry is just around the corner.

This week, President Bolsonaro moved to replace Petrobras CEO Joaquim Silva e Luna with a new head. The appointment of economist Adriano Pires as CEO of Petrobras and sports giant Rodolfo Landim as chairman is expected to take place in April.

Pires has been adamant in his stance on market pricing policies, pushing for the privatization of the state-run energy firm. Silva e Luna was appointed as CEO only last year after his predecessor was pushed out, suggesting somewhat of a trend. At present, Petrobras shields consumers from the global volatility of energy prices.

But many have suggested that the oil prices should reflect the Brent Benchmark, adjusting fuel prices accordingly. However, with the next election taking place in October, Bolsonaro could lose voters if diesel and gasoline prices continue to rise. 

Recent stumbling blocks in the search for new oil finds have not dampened Brazil’s optimism for developing its oil industry further over the coming years.

As new operations come online, Minister of Mines and Energy, Bento Albuquerque, has announced production increases in response to international shortages. In addition, there is the potential for change in state-owned energy company Petrobras as a market-oriented CEO takes over.  

OILPRICE by Felicity Bradstock, April

U.S. refineries are reaching their capacity for the first time since the pandemic started, pushing up fuel costs already at record highs after Russia invaded Ukraine and roiled global oil markets.

Refineries in the United States are operating at 92 percent of capacity, according to data from the Energy Information Administration, meaning most of their refining units are full.

“(Refiners) are looking at ways to put more barrels through,” said John Auers, executive vice president of refining at energy consultancy Turner, Mason & Co. “And they’re going to do that. But right now they’re full.”

The industry lost significant capacity during the pandemic as refineries closed permanently — a reckoning forced by mounting costs and declining future prospects for gasoline as the energy transition accelerated. 

Now they’re having to do more with less as the global market loses gasoline and diesel from Russia, which had been a major exporter of refined products to Europe.

With refineries nearing capacity, it’s more difficult for the U.S. to fill the gap left by the loss of Russian products, which comes as demand for fuel recovers from the pandemic, analysts said.

Refinery closings have stripped 3 million barrels per day from the global market since January 2020, including 1 million barrels a day in the U.S, according to the industry trade group American Fuel & Petrochemical Manufacturers.

“Even if refineries hadn’t closed and even if stocks were at more normal levels, there’d have been a price spike just because of how much supply — Russian export — is being removed from the market,” said Rob Smith, director of global fuel retail at S&P Global.

“But it likely wouldn’t have been as severe or as long lasting as the one we will deal with now.”

The diminished refining capacity is more palpable for diesel and jet fuel, of which Russia was a major supplier, Smith said. “Not coincidentally, that’s the product family that’s really skyrocketed,” he said, referring to the rise in demand for those products.

The tight refining market is a far cry from the early days of the pandemic, when the first stay-at-home orders hit and the rate of refinery utilization plunged to its lowest level since at least the early 1980s. Utilization rates fell to 70 percent in April 2020 from 93 percent in December 2019, according to the EIA.

As the pandemic kept people home and off freeways, it accelerated the energy transition and hastened the closures of some refineries. 

Shell closed its Convent refinery in Louisiana last year, taking 240,000 barrels per day of capacity from the market as part of a company effort to reduce carbon emissions. Also last year: multiple years of hurricane damage cemented Phillips 66’s decision to close its Alliance refinery in Lousiana, which processed 255,000 barrels of crude per day.

HOUSTON CHRONICLE by Amanda Drane, April 5, 2022

The recent slump in oil prices does not reflect the actual risk of Russian supply disruption, a senior executive of Vitol has warned.

Brent crude dropped from close to $140 per barrel right after the start of the war in Ukraine to $104 per barrel last week as the United States and the International Energy Agency announced massive reserve releases.

However, this would not be able to offset lost Russian barrels over the next few months, Bloomberg quoted Mike Muller, head of Vitol’s Asian operations, as saying.

“Oil feels cheaper than most would’ve predicted,” Muller said on a podcast produced by Gulf Intelligence. “Oil prices could be higher given the risk of disruption of supplies from Russia. But people are still lost figuring out those numbers.”

In the third quarter, Muller said, Russian oil and oil product exports could be down by between 1 and 3 million barrels daily, from 7.5 million barrels daily under normal circumstances.

Muller also noted that demand was going to continue to strengthen despite China’s recent dip because of the resurgence of the coronavirus.

“China will throw the kitchen sink at making sure the economy delivers,” Muller said. “We are going to see China put a massive effort into infrastructure spending and propping up the economy. You’re going to see a big outlay.”

At the same time, any additional supply from Iran will be slow in coming. This weekend, Iran’s foreign minister Hossein Amir-Abdollahian said the parties at the nuclear deal negotiating table were close to an agreement, adding, “We have passed on our proposals on the remaining issues to the American side through the EU senior negotiator, and now the ball is in US court.”

Oil started the week with a decline after the Houthi rebel group in Yemen and the Saudi-led coalition agreed to a truce that alleviated some Saudi oil supply concerns sparked last month by a string of Houthi attacks on Saudi oil targets.

OILPRICE by Irina Slav, April 5, 2022