Wednesday, May 27, 2020

Oil on Floating Storage Soars to Record Highs, But Peak Still Some Way Off

Floating storage already in excess of 180 mil barrels. Freight rates stay elevated as storage tightens spot tonnage. Inland storage crisis may have been averted but demand still in doldrums.

Oil on floating storage is now at its highest level in the history of the oil market and despite modest signs of a demand recovery, industry sources and analysts say the peak for these volumes is still some way off.

There are some signs that oil is starting to improve based on global road traffic and congestion data as travel restrictions start to ease. But looking at the amount of oil on water on a real time ship tracking platform, there are many signs that the imbalance of supply and demand remains very skewed.

There are currently more than 200 million barrels of oil and products on floating storage, representing around 5% of global carrying capacity, according to data from S&P Global Platts trade flow software cFlow.

Around 10-20% of the global tanker fleet represents a reasonable ceiling for floating storage, which would allow the storage of around 400 million-800 million barrels of crude and products, according to Platts Analytics.

Energy research firm Kpler estimates that floating storage volumes were as high at 180 million barrels for the week beginning May 11, making it the largest ever volumes for oil on floating storage.
This is a rise of almost 95% in the past two months, as data showed that floating volumes of crude and oil products were as high as 92.09 mill barrels for the week beginning March 9. The data includes volume of commodities on tankers that are idled offshore for seven days or more.

“Floating volumes are likely to keep going up in the next few months as many vessels that were recently fixed on floating storage are still sailing to their destinations or in some cases have not been loaded,” Erik Broekhuizen, head of Tanker Research & Consulting at Poten & Partners, said recently during a webinar.

But there are some signs that oil on water is beginning to decline as production cuts from OPEC+ along with involuntary production cuts from the US, Canada, Brazil and Norway start to come into play.

Oil on water, which includes the total volume of crude and products on tankers, was estimated to be around 1.25 billion barrels for the week beginning May 11, from 1.30 billion barrels the previous week.

Freight Impact

Shipping sources remain skeptical about whether oil on water will start to fall unless demand does start to rise steadily and more production cuts are enacted. And, looking at the tanker market, sources say it could be a long time before any balance is close to being found.

Oil going on water is still set to increase given the overproduction compared to current demand,” said Paul Marsh, research director at Navig8 said during a webinar.

How long it will take to unwind oil from ships is a million dollar-question,” he said. “There are widely diverging views about when this is set to happen, but it will surely take more time to offload storage than it took to build it. This could be anywhere between one and two years, maybe more.

Shipping sources noted that despite a slight fall in crude cargo inquiries, freight rates for VLCC and Suezmax tankers had found some support from time charter bookings

With so many tankers booked on time charter, the tonnage list on the spot market has tightening considerably, pushing up freight. “New ships are being booked on time charter given the overproduction, although the rate has slowed“, a shipbroker said.

He said demand for West African crude still remained particularly lackluster. “The spot market is looking bleak in the long term given the low demand,” he said. “We are seeing a number of cargoes unsold in June, which would mean more vessels would go on storage.

During the floating storage rush at the end of March, time charter bookings for short periods of around six months were estimated at around $120,000/day for VLCCs, and periods up to one year at around $85,000/day.

Ship owners are continuing to ask for expensive rates despite weaker spot market. This week, VLCC daily earnings for spot fixtures were estimated at around $55,000/day, according to Marsh.

Pace of Recovery

Production cuts from OPEC and its allies came into place this month and with hefty involuntary shut-ins from producers in the US, Canada, Brazil and Norway, supply is beginning to fall.

But demand remains in the doldrums and despite slight improvements, the fundamentals remain far from ideal. The International Energy Agency continued to call on oil producers to do more to contain the impact of the coronavirus on the oil markets.

Demand will not jump from one day back to levels we had before the crisis and we still have a huge amount of surplus and plus a lot of floating oil around the world, so therefore one needs to be very careful if one doesn’t want to change,” the IEA’s executive director Fatih Birol said during a webinar.  

Platts Analytics said the fall in production so far this month had helped to avert an inland storage crisis and that $25-30/b was a fair value for Dated Brent for the coming months.

The current supply losses, OPEC’s determination, and trend towards opening up point to stronger oil prices than we believed earlier,” it said in a note. “[But] we are not overly bullish as much anxiety persists, particularly around demand and the impact of opening up from lockdowns on the infection rate.

Amount of Stored Oil Expected to Peak in 2nd Quarter, EIA Says

The amount of crude oil in storage tanks is expected to peak in the second quarter, before demand significantly increases around the world.

Storage tanks around the world added 6.6 million barrels of oil per day during the first quarter, but that accelerated to 11.5 million barrels per day in the second quarter as shutdown orders related to the coronavirus pandemic stunted travel and economic activity, the U.S. Energy Information Administration said Tuesday.

Those shutdown orders are expected to ease around the world during summer, boosting demand and oil prices, the EIA said.

Starting in the third quarter, the EIA said, global consumption of crude oil, gasoline, diesel, jet fuel and other products will increase for at least six consecutive quarters — reducing inventories and raising prices. The price of U.S. oil was just above $30 on Tuesday.

Global consumption of oil, gasoline and other related products is expected to average 92.6 million barrels per day in May, an 8 percent decrease from 100.7 barrels per day during the same time period last year, the EIA reported.

Economic growth and global consumption of crude oil and other fuels is expected to increase in 2021 but remain lower than 2019 levels, the agency said.

Tuesday, May 26, 2020

A new oil price war is just a few dollars per barrel away

The oil market has had a month of significant recovery. Since the historic cuts by Saudi Arabia and Russia took hold, and the US shale industry began to contract, crude prices have jumped around 70 percent and seem to have established a “floor” at $30 a barrel and a trading range of around $35.

That is nowhere near enough for oil-producing states that count on energy revenue to fund their budgets, but it is a move in the right direction after the carnage of “Black Monday.” It shows that the oil market can be at least partly regulated by supply actors, even in the midst of the most savage demand destruction in history because of global economic lockdowns.

The recovery was mainly due to signs that the energy-guzzling economies of East Asia — principally China, Japan and South Korea — were resuming economic activity at a faster-than-anticipated rate, and also the realization that “tank top” — exhaustion of the world’s storage capacity — was not going to happen.

The big storage facility at Cushing, Oklahoma, was never at serious risk of breaching capacity, and demand for expensive floating storage is declining.

There is still a lot that could go wrong like a serious second wave of coronavirus or a complete rupture in trade relations between the US and China but, barring these, the outlook for oil is better than you might have reasonably expected a month ago. Analysts are looking at an average of around $35 this year and perhaps more than $50 in 2021.

A lot is riding on the OPEC+ deal led by Saudi Arabia and Russia. This will be the subject of talks at the OPEC meeting next month, when participants will have to decide whether to reduce the level of cuts from 23 percent to 18 percent of output. There is a considerable body of opinion within the organization that the 23 percent level should be adhered to for an extended period. Saudi Arabia has already gone even further than that, with an extra one million barrels per day reduction, backed by other Gulf producers.The other significant variable in the OPEC equation is the level of compliance with the cuts. Russia, which has long argued that big cuts were impossible for its oil business because of geological and climatic reasons, appears to have found a way around those challenges.

For Iraq, Nigeria and Libya, the financial situation is dire enough to distract them from the precise terms of the OPEC+ deal and maybe tempt them to sell as much as possible while prices hold.

But the big imponderable is in US shale. On all the indicators — well shut-ins, fall in rig count, job losses and bankruptcies — the past month has been savage, especially in the Texas heartland of the industry, as the price of West Texas Intermediate fell through the floor.

Rising prices change the economics again. Not many shale operators are viable at $30, but as the price creeps upward it makes sense for them to start thinking of pumping again. Upward of $40, there could be a renewed surge in shale production.

This would drop a spanner in the works of the global industry. It would make no sense at all for Saudi Arabia to continue with its market-changing cuts, which are exacting a big price in terms of lost revenue, if the US was swamping the world with oil again. The battle for market share — with the Kingdom turning the pumps full throttle again — would be back on.

We’re not there yet by any means. Much depends on whether President Donald Trump’s administration adds the oil industry to its list of sectors needing support in the big pandemic support package struggling through Congress. The Democrats don’t like that idea but, in an election year and with promises of environmental concessions by Big Oil, they might be persuaded.

Even as the oil industry congratulates itself on its policy response to the pandemic, it has to be aware that a new oil price war is just a few dollars per barrel away.

• Frank Kane is an award-winning business journalist based in Dubai. Twitter: @frankkanedubai

Disclaimer: Views expressed by writers in this section are their own and do not necessarily reflect Arab News' point-of-view

Friday, May 22, 2020

Majority of marine fuel buyers anticipate price rises, but limited risk management in place


Despite recent low bunker prices a significant proportion of marine fuel buyers still do not have any risk management strategies in place to mitigate anticipated price rises. 
Two thirds of LQM Petroleum Services clients polled in a webinar last week (12 May) thought that marine fuel prices would rise in the next 12 months. But at the same time, only half the participants said that they currently use risk management strategies to mitigate this risk.
“This trend reflects the wider industry’s understanding of the tools available to manage bunker price volatility,” said LQM Chief Executive Daniel Rose. “But we were encouraged by the fact that three quarters of participants on our call stated that they would be interested in locking in today’s low prices.” 
LQM Petroleum Services is a hybrid bunker broker and trader which protects itself from energy price changes by entering into fuel oil swap agreements. 
“We fully understand the reluctance by some owners and charterers to enter into the fuel oil futures market: it’s an area which leaves some overwhelmed and those with relatively small clip sizes feeling overlooked,” said Daniel Rose. “But we’re in the unique position of being both a broker and experienced trader. We can guide potential participants through the entire process and help clients manage their specific hedging needs.” 
He noted that the fuel swaps market has independent credible benchmark pricing, robust clearing solutions and good liquidity. These are the fundamentals for a successful futures market,” he said.
Opinions as to the duration of the current market volatility were less clear-cut. 21% of the webinar participants thought that current conditions would continue only for the next three months; 32% thought between three and six months whilst 36% felt that six to 12 months a more likely scenario.
Several shipowners, charterers and traders attended the webinar and responded to the poll.

Thursday, May 21, 2020

Crisis Talk — with Christophe Salmon, CFO of Trafigura, on hedging oil’s biggest crash

Trafigura Christophe Salmon 

Christophe Salmon
Group Chief Financial Officer

As a crucial middleman in the oil business, Trafigura has had to cope with concerns about the creditworthiness of some of its counterparts, and unprecedented volatility in the oil price that saw the West Texas Intermediate (WTI) contract turn negative at the end of April. Christophe Salmon, the company’s chief financial officer, explained how the company has coped with the crisis, and how its funding approach, based on deep banking relationships and a secured financing structure, proved resilient to the chaos around it.

When did you realise how serious the crisis would be?

Let’s not forget that the virus crisis started in China much earlier than March 2020, when it reached Europe.

We have a strong presence all around the globe, and we could already see in January the impact of the virus. Our directly employed staff in China went off for Chinese New Year and did not come back to the office for more than a month.

With our team of analysts we saw, probably a bit earlier than others, that the virus issue in China was having a huge impact on the economy and was more serious than was realised in Europe. This gave us more time to think and to assess the consequences of the virus for the types of commodities we trade.

What were the main challenges for Trafigura?

The first challenge was, at a basic level, to make sure the company continued to run as a business. We are not an investment firm, we are trading physical commodities, moving goods from point A to point B, and that requires a lot of manpower in chartering ships, managing the finance, contracts and so on.

We needed to continue to run our business without impairing our risk management framework, and we can say now, two months into the lockdowns in India and Europe, that it is mission accomplished in that respect. It was a big effort from our business continuity teams — in our back office in India, for example, we had to make sure everyone had sufficient bandwidth to be able to connect directly into our systems and to maintain the integrity of our information technology.

The second challenge, though, was responding to the rapidly changing market conditions.

The commodity that has seen an extraordinary level of volatility has been oil. We have seen the oil price crashing with this combination of a shock in demand and a shock in supply. Opec+ turning on the taps to the market at the same time as global demand was crashing drove the price down very significantly. We have since seen a big effort from Opec+ to reduce supply, but then prices began to collapse again because everyone could see that the effort to contain supply was not at the level of the demand destruction.

All these changes in the space of perhaps eight weeks amounted to something that had never been seen before, and we reached the extreme point of the April maturity of the Nymex WTI contract turning negative one day before the maturity date.

Our job as a commodities trader is to balance physical supply and demand. This shock in demand has triggered a huge need for the market to absorb excess supply and to place this excess supply into storage. Companies like Trafigura and a few of our competitors have stored very significant volumes of crude oil all around the globe to respond to this shock.

The market has gone deeply into contango, and is incentivising physical players to store and sell oil on a forward basis, with the price difference covering the storage costs, and allowing companies engaged in this “cash and carry” strategy to profit.

Companies like Trafigura and a few other peers have done very well in this period by being able to absorb the shock.

How does that storage trade and the volatility in oil affect your funding?

Trafigura does not take any speculative position on outright commodity price. We are never long or short on the commodity we trade, we always hedge our market risk position on the flat price.

Practically speaking, if you have a quantity of crude oil which isn’t sold, we have a reverse derivative position on Nymex or ICE, which fully mitigates and balances any drop in the cash price of the physical leg.

A commodity trading firm is naturally long physical and short derivatives — when the oil price collapses, the derivatives market will transfer to you a lot of margin. So when the oil price collapsed, we received a lot of money back from the exchange. With this cash, we adjusted the loan-to-value of the inventories with our banks.

We have structured our financing so that banks finance the mark-to-market value of the inventory, with the mark performed typically every week.

So when the price goes down, we receive our margin first and we pay that to the banks over the week. It’s always easier when you receive the cash first, and you use the cash to amortise or adjust the value of your financing against the physical inventory.

When the market goes up, the process goes in reverse — we have to pay up front to meet a margin call on the derivatives, and get the money back from the banks the following week when the banks adjust their funding to the increased value of the inventory.

A physical commodity that’s properly hedged, properly insured and managed from an operational perspective can be seen as quasi-cash — that’s why the banks are comfortable financing 100% of it.

A second point, and probably a reason we had an easier life than others in the recent volatility, is that we need to deploy less working capital to finance the same volume of oil. A cargo of oil that was worth $70m in January, is now worth $30m — the same molecules, same crude oil but the value has more than halved.

The main pillar of Trafigura’s funding is to grant security to its banks over the inventories that the banks are financing — and that is the most robust type of funding you can have in place, because banks adjust their funding volumes based on the same value that drives your funding needs.

During these crises, a company like Trafigura always has a low level of utilisation of its credit lines — during the whole of the crisis in March and April we were able to maintain a significant liquidity position and low utilisation, because of the drop in commodities prices.

They say there’s no such thing as a perfect hedge — did that matter for you?

What we have left in our business is basis risk, due to the difference in correlation between the derivative contracts and the physical commodities we trade.

Sometimes the correlation between the hedging instrument and the commodity is not perfect. In the context of the Covid-19 crisis and the high level of volatility, we have seen an increase in our value-at-risk, but our VaR was kept at below 1% of our group equity.

Value-at-risk is there, but it’s an amount that’s small in the grand scheme of things.

How about counterparty risk?

We were doing well in this period, but some of our business counterparties were not — the airline companies, for instance, and some other big energy users.

So we have worked very carefully through our credit department and commercial division to make sure counterparty or performance risk was properly understood and properly measured and mitigated.
Two or three months after the beginning of the crisis, we have not had material issues in this period with counterparty risk. One can say that it is a matter of time. The conditions of our counterparties really depend on how long the virus crisis lasts — are we out for another one month, three months or six months? There is only so much pain that certain industries can sustain. We are, however, confident that the end of the lockdown, combined with significant stimulus from public policies, are limiting the downside for the global economy.

In the normal course of business, we try to mitigate risks as much as we can — we are very significant users of all the credit risk mitigants, you can imagine. CDS not so much, though, because the companies where the CDS market is available are only a tiny portion of the client base.

But we are very significant users of bank letters of credit, or silent payment guarantees from banks, and of insurance. Trafigura is a significant buyer of credit insurance in the Lloyds market in London.

In this crisis, we have tried to be proactive, and to mitigate the credit risk we have to take, and to decrease it. We have put more emphasis on getting down-payments from our clients, or having a letter of credit covering our next shipment.

How about your long-term funding approach?

Today, most of our funding comes from banks. Capital markets funding represents under 10% of our funding needs.

The benefit of this funding mix is that you can put a face to a name. For me, it is not “Bank XYZ”, it’s “Mr ABC”, where we have had a relationship lasting for years.

Especially during crisis times, the debt capital markets can be very volatile and very sentiment-driven. With banks, you have a person or a group of expert people to talk to, which in a stressful environment can be a much more reliable partner.

So we have no intention of changing this funding approach.

We have around 135 banks in our group, as one of our core principles in funding has been diversification. Each of these banks has their competitive edge — some banks are funding transactions in South America that others cannot because they don’t have any regional expertise. Some banks have expertise in the financing of metals in sub-Saharan Africa, and the others have not.
We try to find the right match between our needs and the bank’s expertise — that’s why we have so many banks around the world.

But we do have a core group of around 20 banks, which have a billion dollars or more of mainly secured self-liquidating facilities out to Trafigura, with whom we have an even more privileged relationship, even more of a partnership approach.

How did your banking group respond to the crisis?

Especially since the end of March, we have seen the cost of funds increase for some of these banks. The banks have seen huge drawdowns on corporate revolvers, mainly in dollars, and the non-US banks have seen an increase in their cost of funds to access dollars from their original currency through the cross-currency markets.

For a short period of time, perhaps two to three weeks, we saw a significant increase in cost of funds, which basically offset the drop in the Libor rate. The net effect for us was almost a flat price.

But the increased cost of funds for the banks was temporary — the mechanisms of the central banks to inject liquidity to banks and to the debt capital markets meant the funding pressure subsided. But there was a lag between the announcements and the execution.

Since the second half of April and [in the first half of] May, things have more or less come back to normal.

What about the issues we have seen with bankruptcies in commodity trading?

When these price movements occur, that is when you see a number of badly managed companies going under in our sector.

So companies that are either speculating, or lack the proper risk management frameworks, get into trouble. We have seen a number of bankruptcies of smaller regional players, especially in southeast Asia, and this has put a lot of strain on the banks, who will have to provide for these losses.

But they are looking to the large players like Trafigura as a kind of flight to quality. We have seen a stress on the bank side, not targeted at the leaders of the sector, but at the medium-sized regional players, who may have more difficulty accessing funding.

We expect an acceleration of the consolidation of the sector around the big players, but also an acceleration of the development of solutions such as blockchain in trade finance — we are working with the government of Singapore, the International Chamber of Commerce and a few banking partners on a blockchain solution to secure transaction and save cost.

Have your securitization programmes been affected?

We have a significant trade receivables securitization programme, which has been going for 16 years, and so it has been through a number of different economic cycles. To date there have been no defaults under these programmes — the fact that we deal with a commodity which is essential to our counterparts has been a good mitigant.

During the course of March and April, we have put in place additional credit monitoring for some of these obligors in the programme.

But we are a long-term player in our sectors, so our business counterparts which are here today will be there tomorrow — sometimes with a different shape, but they will be there.

So we wanted to make sure that we act in partnership with our end buyers. In a number of cases, that meant we had requests from some clients for deferred payment. In each case, we have had a very bespoke approach, depending on our analysis of the credit situation of the client, and the quality of the long-term relationship.

This was going on through March and April, but since the end of April we have not seen any new requests for payment deferrals — an acknowledgement that our clients have absorbed the shock, or found ways to monitor and manage their liquidity in an appropriate fashion.

What do you expect for the future of the oil industry, given recent market conditions?

What is likely to happen is a combination of bankruptcies in the exploration and production sector, and, as a consequence, mergers and acquisitions.

The last time when prices really went to the rock bottom — when Brent was at $12 and WTI at $11 — was in the late 1990s. During these years you had major consolidation. Total bought Elf and Fina, Chevron bought Texaco, same thing with Exxon Mobil.

Any period where there is a significant decrease in oil prices, you have M&A.

The big event of the past few years is the very rapid development of the US shale oil and gas production. Now, the production of US, Saudi Arabia and Russia are almost at the same level.

In the US, this is not one single company, it is multiple companies, and especially in the shale industry, you have multiple very small companies.

Some are going to go bankrupt and will be merged into bigger companies — probably some of the US oil majors will take the opportunity to consolidate the E&P sector.

How has Trafigura’s status as an unrated, private company changed how the crisis has affected you?

More than just being private, we are a partnership. Trafigura is an association of key partners — 700 people out of the 8,000 members of staff at Trafigura are shareholders in the business, and, when you think about it, this is the best system for alignment between management and shareholders. We think this is a key recipe of success.

Having said that, being private doesn’t mean opaque — we publicly release our financials twice a year, and the quality of our financials is the same as for listed companies.

The second point — we do not have a public rating, and we like to keep it that way. We have an implicit low investment grade rating, and that is what our core banks see in their internal models. We like to keep it that way because, at the end of the day, we are extracting most of our funding from banks which understand our business model rather than making credit decisions on the basis of a third party rating.

In addition, holding a rating could cause Trafigura to take more short-term-focused decisions in order to maintain a particular rating level, which would conflict with the group focus on long-term value creation.
By Owen Sanderson / 13 May 2020

Wednesday, May 20, 2020

OPEC+ Deal Could Collapse As Oil Prices Shoot Up

The OPEC+ coalition appears determined to ease the global oil glut and lift the oil prices that had cratered in April because of OPEC+ wrangling and crashing global demand in the pandemic.

Oil prices have rallied since the start of the new OPEC+ cuts. These cuts, along with curtailments in North America, have combined with improved global oil demand and the new notion that the worst of the demand collapse is likely behind us, to instill confidence in the market that it is now heading for a deficit.

The more bullish sentiment, however, raises another question—will producers be tempted by rising crude oil prices to disregard quotas within OPEC+? Will U.S. shale resume drilling activity sooner than the market needs it?

OPEC and its partners in the pact realized early last month that they had underestimated what turned out to be a devastating impact of COVID-19 on global demand. With oil revenues for petro states crashing as oil demand and oil prices collapsed, OPEC’s leader Saudi Arabia and all other producers in the OPEC+ group soon realized that they need to quickly force the market into balance to save their oil-dependent economies from taking an additional hit on top of the pandemic-related slowdown.

Three weeks into the new OPEC+ deal to cut production, the market sentiment has markedly shifted.

When the pact announced the deal on April 12, analysts were saying that these cuts—albeit 10 percent of typical global demand—would be ‘too little too late’ to save the oil market from the abyss.

Now the mood has improved, and so have oil prices. The price of oil is now 80 percent higher than it was in mid-April, and analysts are pointing out that the cuts from OPEC+, combined with economics-driven curtailments in North America to the tune of 4 million bpd, is bringing the oil market closer to deficit in the coming months.  

Improving global oil demand and faster-than-expected production curtailments from outside the OPEC+ pact are set to push the oil market into deficit in June, Goldman Sachs said last week.

OPEC+--with huge help from North America’s cuts because of unsustainably low oil prices for its producers--managed to swing the market mood to expectations of a deficit as soon as next month. OPEC and its de facto leader and largest producer, Saudi Arabia, have a track record for purposefully tightening the oil market whenever Saudi Arabia and perhaps a few other major oil producers in the cartel have a strong incentive to see higher oil prices, Reuters analyst John Kemp wrote this week.

This spring, the Saudis had the biggest incentive to reverse the flood-them-all-with-oil policy from March and April—money. With oil prices at $20 or below and demand crashing in the pandemic, the world’s top oil exporter had to save face and its economy.

So far, Saudi Arabia, OPEC, and Russia are declaring unwavering support to market stabilization, promising to go the extra mile to rebalance the market—and to see higher oil prices.  

OPEC members and their ten non-OPEC partners have slashed oil exports by a massive 5.96 million bpd for the first 13 days of May compared to April averages, oil-flow tracking company Petro-Logistics said at the end of last week.    
Saudi Arabia has pledged an additional 1 million bpd of cuts on top of its promised cuts as part of the OPEC+ deal. Even Iraq, the biggest cheater in all the previous pacts, said that it is committed to the production cuts.  

Saudi Arabia and the leader of the non-OPEC countries, Russia, put out a statement last week, saying that they “remain firmly committed to achieving the goal of market stability and expediting the rebalancing of the oil market.”

“We would like to especially commend the efforts of responsible producers around the world who have willingly adjusted their production out of a sense of shared responsibility,” Saudi Energy Minister Prince Abdulaziz bin Salman and Russia’s Energy Minister Alexander Novak said.

For U.S. producers, curtailments have nothing to do with “shared responsibility”—the economics are unfavorable, storage availability is still scarce, and demand is still low. The U.S. shale patch has announced more than 1.5 million bpd in cuts for Q2, lifting the oil prices and market sentiment over the past two weeks. But with prices rising, some producers could be tempted to resume activity, nipping a sustained market recovery in the bud.

“Further strength in the oil market would send the wrong signal to producers, with them likely more reluctant to cut output in a rallying market,” ING strategists Warren Patterson and Wenyu Yao said on Wednesday.  

By Tsvetana Paraskova for

Tuesday, May 19, 2020

Belying Oil’s Price Volatility, Cushing Has Always Had Ample Storage Space For U.S. Producers’ Crude

US-ECONOMY-ENERGY-MARKET-OIL AFP via Getty ImagesAn aerial view of a crude oil storage facility is seen on May 5, 2020 in Cushing, Oklahoma. - Using his fleet of drones, Dale Parrish tracks one of the most sensitive data points in the oil world: the amount of crude stored in giant steel tanks in Cushing, Oklahoma. The West Texas Intermediate oil stored in the small town in the midwestern United States is used as a reference price for crude bought and sold by refiners in Asia, hedge funds in London and traders in New York. (Photo by Johannes EISELE / AFP) (Photo by JOHANNES EISELE/AFP via Getty Images)

Cushing is going to fill up!  Cushing is filling up!!!  Of all the hyperbolic, buffoonish comments uttered by talking heads on CNBC and in the financial media, this is the worst.  According to the most recent data provided by the EIA, Cushing has 93.346 million barrels of storage capacity, of which 76.093 million barrels’ worth is classified as working storage.  The EIA’s weekly data showed 65.446 million barrels in storage at Cushing as of May 8th, a figure that declined by 3 million barrels in last week’s data.  So, even at its peak, Cushing was 86.0% full.  Then how could Cushing storage possibly be “running out” with 14% of existing capacity available and more implicitly in reserve?
Cushing has never run out of storage. Cushing never will run out of storage. 

In the past eight years, Cushing’s working storage capacity, as measured by the EIA, has increased 58.5%.  The amount of oil stored at Cushing is more than three times the amount stored there 15 years ago.  America is producing more oil.  America’s midstream companies somehow noticed this trend and have produced more storage tanks in which to store that oil.

But as the contract for West Texas Intermediate crude for June delivery finished its trading life Monday at 2:30 ET quoted at $32.13 per barrel, that does not explain what happened the last time.  Last month’s contract (for May delivery) finished trading on April 21st at $11.57 per barrel, after famously closing at (-$37.63) per barrel on the day prior to expiration. 

It’s all part of a trade.  Last month that trade was “short oil.”  This month the trade became “long oil.”  It’s that simple.  The commodities markets are characterized by wild swings in sentiment and just as wild swings in price.  This is why producers and consumers hedge, and use oil contracts to balance out their natural biases (producers are naturally short and consumers are naturally long.) 

But the headlines in April screamed “oil prices turned negative because there was no place to put it,” when the government’s own figures show there was, in fact, ample space to store oil.  Why?  Well, renting Cushing storage—controlled by big midstream players—is not as easy as renting a U-Haul or as scalable as leasing server space from Amazon AMZN .  As the EIA stated in its April 27th, 2020 Today in Energy publication:

Although EIA data indicate that some storage remains available at Cushing, some of this physically unfilled storage may have already been leased or otherwise committed, limiting the uncommitted storage available for financial contract holders without pre-existing arrangements. In this case, these contract holders would likely have to pay much higher rates to storage operators for any uncommitted space available.  Taken together, these factors suggest that the phenomenon of negative WTI prices is mainly confined to the financial markets.

As with any financial product, when amateurs get caught short market inefficiencies occur.  

The existence of the USO oil ETF, a frequent target of my criticism in my Forbes columns, only exacerbates this situation.  Because USO’s sponsor, USCF, states quite clearly in its many SEC filings that it has no means to take delivery of physical oil and no desire to do so, USO serves to create more paper contracts and offset the natural balance of hedging.  As those contracts are rolled—though USO has changed its contract purchasing/selling process several times in the past month—that creates a net shortage of the paper, and the markets can get wacky.  

So, for those who like to proclaim European superiority over American methods, the Euros have us beat when it comes to oil pricing.  Brent oil trades only in paper form, and unlike Cushing, Brent is not a physical town, but a location of offshore platforms (three of four of which have been shut down as the field matures) in the North Sea.  No one can deliver oil to Brent because there is no such place, although the contract price is composed of a mix of three other locations that are actually physically sited.

This is not meant as any disrespect to the good folks of Payne County, Oklahoma.  Cushing is important, and a quick check of any pipeline map would show that most of the U.S.’ massive hydrocarbon superhighways have been built to stop by Cushing to “count” in oil delivery figures before heading elsewhere to be refined.  The nearest refinery to Cushing is a one-hour drive north up OK-18 in Ponca City at Phillips 66 PSX ’s facility, and the salt caves that hold the U.S.’ strategic petroleum reserve sit in four sites along the Gulf Coast, the closest one to Cushing located in Bryan Mound, TX, about 550 miles away.  

So, contrary to the takeaway from articles like this credulous Bloomberg piece, Cushing has plenty of space. Those who hold short positions in oil may not want you to believe that, but it's the truth.  Remember always that those same folks are just as likely to be the ones telling you—via compliant reporters in the mainstream financial media—that all is fine and dandy in the energy markets when they happen to be long those very same contracts.  
It’s probably best not to listen to them at all.

Monday, May 18, 2020

Oil Price Continues to Rally as Economies Reopen

Crude oil prices increase

Oil prices closed on a third straight weekly high on Friday as prices continued to rally on economies reopening from their COVID-19 lockdowns.

Brent was up at $32.50 on Friday’s trading, with West Texas Intermediate (WTI) on $29.43, as both benchmarks kept up their sustained rallies on positive market sentiment and hopes of oil prices having bottomed out during the end of April, which saw WTI going negative.

“Oil prices extended their recovery for a third week running as sentiment toward demand improves as more countries ease their lockdown conditions and allow for economic life to return to something approximating pre-coronavirus conditions,” said Edward Bell, commodity analyst at Emirates NBD.

“For the month of May alone the improvement in oil futures has been dramatic: Brent has gained nearly 30% while WTI is up by around 56%. June WTI futures expire this week but the relative improvement in sentiment toward crude and easing concerns over whether storage was reaching tank tops should prevent a repeat of last month’s hysteria when expiring futures moved into negative prices for the first time ever,” he added.

Production Cuts Play Their Part

Also assisting with the continued price recovery have been the production cuts that came into affect from the start of this month according to Ole Hansen, head of commodity strategy at Saxo Bank, as the worst case scenario of storage facilities reaching full oil capacity having been averted for now.

“Crude oil continues to push higher and in hindsight the short-lived collapse to a negative WTI price last month probably saved the market and set in motion the recovery currently seen.

“Major producers around the world, potentially faced with heightened risk of tank tops and the price collapse spreading, stepped up their efforts to cut production. A development which together with a pick-up in demand was highlighted by the International Energy Agency in their latest oil market report as key reasons for the recovery seen during the past month,” he added.

The IEA in their May outlook report revised their global demand numbers, with demand set to go down by 8.6 million barrels per day (bpd) this year, from an earlier estimate of 9.3 million bpd. “With estimates that demand may not fully recover for at least another year, we suspect that the current recovery may eventually run out of steam.

“Also considering the risk that U.S. shale oil producers, some desperate to survive, will be able to restart shut-in production as the price reaches economically viable levels above $30/b,” he added.

Markets Are Rebalancing

Speaking at Adnoc’s virtual majlis last week, Dr Sultan Ahmad Al Jaber, UAE Minister of State and Group CEO of Adnoc, said signs were pointing to an oil market that was rebalancing itself. “When it comes to oil, there are signs that the market has tightened in recent weeks. The Opec+ agreement, voluntary cuts outside Opec-plus plus, and production shut-ins are working together to start to rebalance the market.

“This will take time. As economies begin to open up, demand will follow, but the path to the next normal is not a straight line,” he added. Al Jaber also highlighted how Adnoc was well positioned to handle the current downward in prices thanks to its low cost production.

“Through our transformation, we have focused on what we can control and that is our costs. We’ve been laser-focused on being one of the lowest-cost producers in the world,” he said.

“This has given us the flexibility and the resilience that we need at times like these. In this environment, we are continuing to work even harder to preserve our resources, and maximise our profitability,” Al Jaber added.

Gulf’s Oil Producers Well Placed for Oil’s Eventual Upturn

Oil rigs are being frequently targeted by pirates.

As demand for oil crashed amid the coronavirus outbreak, many traders seized the opportunity to store cheap oil stock to resell at a higher price. However, this scenario wasn’t an easy task for everyone.

The shipping costs increased sharply and storage facilities surpassed the 90 per cent occupancy mark for the first time in five years. This caused the West Texas Intermediate (WTI) delivery prices for May to reach a historic negative value for the first time ever.

In other words, the delivery contract owner had to pay the receiver of the oil shipment, as there was no storage facility available to accommodate the incoming oil shipments.

The current outlook for the oil market nevertheless is gaining positive momentum as global lockdowns are starting to ease up in the EU, China and southeast Asia. These indicators should quickly reflect in a negative manner on existing oil stockpiles, which will then increase overall demand and driving prices upwards by July and August as stockpiles head towards a 60-65 per cent occupancy.

Meanwhile, the implementation of the OPEC+ agreement of reducing 9.7 million barrels per day has served as a moderate market sedative. It has managed to demonstrate the commitment of OPEC’s major producers – Saudi Arabia, the UAE and Kuwait – towards a more balanced market. Their adoption of a responsible approach is in the best interest of the oil industry, their fellow OPEC members and allies.

Two weeks after the production agreement came into effect, the three states pledged an additional combined cut of 1.18 million barrels per day and raising the total amount contributed by OPEC+ to 10.88 mbd. This drove Brent crude past the $30 mark for June shipment deliveries.
Sidelining shale

The production cut was not the only factor. The oversupply of crude due to the shutdown of airports and the global scale of lockdowns severely reduced demand for fuel, halted major industries which account for most of the refined products’ consumption, and that in turn reflected primarily on high-cost unconventional hydrocarbon producers.

The effect of oversupply has driven shale oil producers in the US, Canada and other parts of the world to shut down their producing wells. The smaller oil producers with a higher breakeven averages were also forced to sell their assets at big discounts to larger corporations, while others filed for bankruptcy, which resulted in a forced production reduction unlike the voluntary approach by the OPEC majors.

By April, more than 41 smaller producers in the US filed for bankruptcy as they could not sustain their output with the current market situation and as debtors and shareholders lost faith in their feasibility and competitiveness.

Meanwhile, the three largest oil producers in the GCC had announced before the coronavirus outbreak, plans for more exploration and production enhancement projects.

They have not been reducing their capital spending plans, even with market conditions turning extremely fragile unlike international oil companies (IOCs), which have been suffering much in the current crisis.

The cost of oil extraction is relatively less for the UAE, Saudi Arabia and Kuwait, where it is below the $16 per barrel mark.

Together, they account for a staggering 17.5 mbd of crude oil production capacity that is unrivaled by any producer in the world. The 18 per cent of global market production capacity at the hands of the three states have provided a strong negotiating advantage within OPEC.

Their level of coordination has proved to be very resilient through decades of constructive cooperation for the best interests of OPEC as an organization and the wider industry. Smaller producers do not enjoy these competitive advantages.

The government support to national oil companies (NOCs) has earned the three countries greater leverage and confidence in the global markets, while other big players such as Occidental Petroleum struggle with their $40 billion loan.

The NOCs in the Gulf enjoy a much stable cashflow position and have secured ample reserves during times of higher oil trading prices. This has encouraged larger consumers such as China and India to further turn to GCC crude imports.

Given these conditions, the Gulf NOCs are anticipated to be the biggest beneficiaries in regards to global marketshare as COVID-19 lockdowns ease.

Thursday, May 14, 2020

A London-based trading house bought 250,000 barrels of oil during the historic plunge below $0, and likely made a fortune
  • London-based oil trading house BB Energy bought 250,0000 barrels of oil when US prices turned negative on April 20, raking in a huge profit in the process, Bloomberg reported Wednesday. 
  • BB Energy was one of the few trading houses that had storage capacity at a time when other traders were scrambling for options, allowing it to buy up the historically cheap oil, an unnamed source told Bloomberg.
  • The Commodity Futures Trading Commission warned on Wednesday that the West Texas Intermediate for delivery in June could also turn negative upon expiry.
One trader bought 250,000 barrels of oil and secured a rare payout at a time when oil prices turned negative, causing jitters in markets and leaving most other traders scrambling to find storage options across both sides of the Atlantic, Bloomberg reported on Wednesday.

But for BB Energy, a London-based trading house,the historic oil market crash was golden opportunity owed to its competitive advantage of having storage capacity over other firms, a source who was not authorized to speak on the topic, told Bloomberg. 

BB Energy bought around 10% of all barrels of WTI crude futures for delivery in May.

US oil prices hit an all-time low of -$37.63 on April 20 due to an extreme shortage in storage options for oil, meaning most traders apart from BB Energy had to effectively pay traders to take the oil off their hands. 

It remains unknown whether BB Energy is still holding on to the barrels it bought and how much the trading-house paid (or indeed was paid) for them as well as how much it made.

BB Energy trades 20 million metric tonnes of crude and petroleum products annually. 

Lack of storage options, particularly at a key storage facility in Cushing, Oklahoma, and the reduction in demand for the commodity during the ongoing coronavirus pandemic, have both contributed to WTI 's historic price crash.

Oil has been ravaged by the coronavirus pandemic which has all but shut down international travel, and greatly reduced manufacturing output, in turn torpedoing demand for oil.

Concerns are mounting that the June contract for oil could follow the same pattern as May, with demand for storage outweighing supply at the expiry of the contract, pushing oil below zero again.

The US Commodities regulator issued a rare warning on Wednesday urging market participants to prepare for a repeat-case scenario of negative prices for the June WTI contract.

"We note that we are issuing this advisory in the wake of unusually high volatility and negative pricing experienced in the May 2020 West Texas Intermediate (WTI), Light Sweet Crude Oil Futures contract on April 20 (the penultimate day of trading and expiration of the contract," the Commodity Futures Trading Commission said in a notice.

On Wednesday, OPEC has downgraded its demand forecast by a third, saying it expects demand to fall by just over 9 million barrels per day in 2020. OPEC had previously forecast a slump of of 6.84 million barrels per day. 

The price of US oil is currently trading around $26.62, up 4.3%. Brent, the international benchmark is at $30.36 a barrel, up 2.9%, as of 6:20 a.m. ET, according to Markets Insider data.

Wednesday, May 13, 2020

Occidental offering voluntary job buyouts, citing need for spending cuts: document

Occidental Petroleum

(Reuters) - Occidental Petroleum Corp (OXY.N) is offering its employees voluntary buyouts over the next two weeks, according to a document seen by Reuters on Tuesday, citing the sharp decline in oil prices and the coronavirus pandemic for “severe dislocations” in its business.

Occidental bet heavily on the continued growth in U.S. shale oil, taking on heavy debts for its controversial purchase of Anadarko Petroleum last year for $38 billion. That bet has proved ill-timed following the coronavirus outbreak, which has cut fuel demand worldwide by about 30% and is responsible for the worst oil-and-gas-industry downturn in 40 years. 

Energy companies worldwide, including Exxon Mobil Corp (XOM.N) and Royal Dutch Shell PLC (RDSa.L), have slashed capital expenditures and oil output to reckon with the pandemic. 

Houston-based Occidental last week posted a $2 billion quarterly loss and has slashed capital spending drastically to shore up its balance sheet. The company said that if spending cuts are not met, it will have “serious potential consequences” to the company, the document said. 

Interested employees can submit a resignation offer to Occidental through May 26, specifying the number of months of base salary that they will accept for voluntary separation, according to the document. Employees can amend or withdraw offers unless the company has already accepted them by then, the document said. Offers not accepted will expire automatically on June 12.
Occidental declined to comment. 

The company's shares are down 64% on the year, making it one of the worst-performing stocks in the Standard & Poor's 500 stock index .SPX

Occidental has been cutting expenses to deal with its debt-laden balance sheet and had been laying off workers and selling assets to pare down debt even before the fall in oil prices.

The company said last week it is considering raising new cash, swapping debt for stock or refinancing existing debt due to shrinking oil demand. It withdrew its outlook for 2020. 

It cut its 2020 capex budget on three separate occasions this year, most recently to $2.5 billion from an original plan of $5.3 billion. 

Reporting by Devika Krishna Kumar in New York and additional reporting by Shariq Khan in Bangalore; Writing by David Gaffen; Editing by Sandra Maler and Leslie Adler

Tuesday, May 12, 2020

A day trader who bought hundreds of oil contracts was told he owed $9 million after a trading-platform issue meant it failed to show oil's historic plunge below $0

Mario Tama/Getty Images

  • A day trader who bought hundreds of oil futures contracts during its historic price crash last month was told he owed $9 million after a technology issue prevented his trading platform from displaying negative oil prices, Bloomberg reported on Friday.
  • On April 20, Syed Shah, a day trader in Canada, bought 212 futures contracts for what he thought was $0.01 each, not knowing that oil was actually trading at -$3.70 per barrel at the time, according to Bloomberg.
  • The platform he used, Interactive Brokers, could not display negative prices, so Shah and other traders were oblivious to the huge drop.
  • "It's a $113 million mistake on our part," Thomas Peterffy, the founder and chairman of Interactive Brokers, told Bloomberg, adding that customers who suffered losses as a result of the issue would get their money back.

As oil crashed, Shah bought 212 futures contracts for what he thought was $0.01 per barrel, not realizing that oil was actually trading at negative $3.70 per barrel, Bloomberg said.

Shah couldn't see the price in real time, as Interactive Brokers' system was unable to display a price below zero.

"I was in shock," Shah told Bloomberg. "I felt like everything was going to be taken from me, all my assets." Shah added that he didn't sleep for three days after the incident.

As oil crashed, Shah bought 212 futures contracts for what he thought was $0.01 per barrel, not realizing that oil was actually trading at negative $3.70 per barrel, Bloomberg said.

Shah couldn't see the price in real time, as Interactive Brokers' system was unable to display a price below zero.

"I was in shock," Shah told Bloomberg. "I felt like everything was going to be taken from me, all my assets." Shah added that he didn't sleep for three days after the incident.

Thomas Peterffy, the founder and chairman of Interactive Brokers, told Bloomberg that oil turning negative revealed bugs in the company's software.

"It's a $113 million mistake on our part," Peterffy told Bloomberg. (That estimate was later revised down to $109 million, Bloomberg said.)

"We will rebate from our own funds to our customers who were locked in with a long position during the time the price was negative any losses they suffered below zero."

Meanwhile, in Europe, another Interactive Brokers customer, Manfred Koller, faced a similar situation as Shah on April 20, according to the report.

Koller, who lives near Frankfurt, Germany, purchased oil contracts for his friends at $11 and between $4 and $5 on the platform. His trading screen froze just after 2 p.m. ET.

"The price feed went black, there were no bids or offers anymore," Koller told Bloomberg, adding that his trading account didn't indicate any problems.

Later, Koller received a notification from the brokerage that he owed $110,000.

It was widely known that the derivatives exchange CME Group's benchmark oil contracts could go negative, and it had alerted its clearing-member firms that they should test negative prices on their systems, Bloomberg said.

An alert sent on April 8 said: "If major energy prices continue to fall towards zero in the coming months, CME Clearing has a tested plan to support the possibility of a negative options underlying and enable markets to continue to function normally." There was another alert on April 15.

While Peterffy acknowledged that Interactive Brokers received this notification, he told Bloomberg it needed more time to upgrade its software.

"Five days, including the weekend, with the coronavirus going on and a complex system where we have to make many changes, was not a sufficient amount of time," he said.

Monday, May 11, 2020

Aruba Offering Oil Storage After PDVH Exit

a picture that shows where is Aruba located

The Dutch Caribbean island of Aruba is offering to lease oil storage after terminating an ill-fated refining project with PdV Holding (PDVH), the opposition-controlled US subsidiary of Venezuela’s national oil company PdV.

The lease offer comes at a time of severe tightness in onshore and floating oil storage owing to a historic supply glut and a collapse in demand caused by the Covid-19 pandemic.

Aruba has 10 available storage tanks with capacity for 665,000 bl of clean products, 5.224mn bl of crude and 518,000 bl of naphtha, according to promotional material obtained by Argus. Another seven tanks currently awaiting repairs have capacity for 4.224mn bl of crude.

Aruba’s prime minister Evelyn Wever-Croes noted strong interest in the storage lease. “It will take us at least a month to get the best offer for Aruba, do the inspections of the tanks and start sending crude so we can receive the lease payment, which is being estimated to net at least 5mn florins ($2.8mn per month).”

The storage became available after Delaware-based PDVH signed an agreement with the government of Aruba and Refineria di Aruba (RdA) that puts a definitive end to a $1.1bn refinery project spearheaded by PdV in Caracas in 2016 and inherited by Venezuela’s political opposition last year when it took over PdV’s US assets.

After the long-term lease was signed in 2016, the project manager, Houston-based Citgo Petroleum, conducted preliminary work to refurbish Valero’s former 235,000 b/d San Nicolas refinery into a heavy crude upgrader. In addition to logistical advantages for PdV, the Aruba project would have helped to absorb Venezuelan crude production that could no longer be processed at mostly inoperable upgraders at PdV’s Jose complex in Venezuela.

PDVH and the government of Aruba and RdA started negotiations in April 2019 to end the project. A memorandum of understanding that suspended the project and laid the groundwork for an operational transition was signed in October 2019. On 28 February 2020, PDVH through its subsidiary Citgo Aruba Holding (CAH) signed a transfer of operatorship agreement with RdA. The withdrawal included labor severance packages.

Tax Obligation

Under the new agreement that received final signatures on 1 May, PDVH agreed to pay $17mn in back taxes to Aruba. The funds already earmarked to comply with the tax obligation will come from PDVH, the holding company told Argus.

The “amicable” agreement “will potentially save PDV Holding’s shareholder up to US$150 million” and does not impact Citgo Petroleum’s fuel supply contracts with Fuels Marketing and Supply Aruba, and with Queen Beatrix International Airport for jet fuel, PDVH said. The firm added it will continue to cooperate “with investigations into irregularities in the Aruba Project under the prior management’s control.”

For Aruba, the termination agreement marks the end of “long and intense” negotiations. “There were times that we thought that we would not be able to finalize this because of the unstable situation in Venezuela,” Wever-Croes said after the signing last week.

Sunday, May 10, 2020

Oxy gets the OK to Maintain Anadarko contract in Algeria

Algerian authorities have given Occidental Petroleum Corp. (OXY) the go-ahead to maintain Anadarko’s contract in the North African country, according to a release on state firm Sonatrach’s website.

Algeria had previously blocked Occidental Petroleum’s deal to sell Anadarko assets in the country to France’s Total following Occidental’s acquisition of the US-independent.

“The energy ministry agreed for the maintenance of Anadarko Algeria Corporation in the association contract with Sonatrach and other companies,” the Ministry said in a statement.

Occidental Petroleum has informed the Ministry of its new strategic approach and its “commitment to continuing Anadarko Algeria Corporation activities in Algeria,” and it will seek new partnership opportunities, the statement said.

Friday, May 8, 2020

North American oil producers slash output faster than OPEC skeptics expected

NEW YORK (Reuters) - North American oil companies have slashed production faster than skeptical OPEC officials and industry analysts expected, on course to cut roughly 1.7 million barrels per day by the end of June, according to a Reuters analysis of U.S. state and company data. 

The Organization of the Petroleum Exporting Countries and allies led by Russia struck a deal last month to contain a worsening supply glut as the coronavirus pandemic cratered global fuel demand by about 30%, sending prices plunging. 

The group, known as OPEC+, agreed to cut output by 9.7 million barrels per day (bpd) for May and June. They also pushed for non-OPEC+ members, including North American countries, to contribute another 10 million in output cuts, for total cuts of about 20% of world supply. 

During talks last month, some OPEC members raised concerns that nations like the United States and Canada couldn’t muster that magnitude of cuts from private companies without state mandates. 

That hasn’t turned out to be the case. Numerous producers in North America announced sizeable cuts, including ConocoPhillips, Exxon Mobil, Chevron Corp and Canada’s Cenovus Energy. The United States and Canada, which produce more than 17 million barrels per day, have already cut output by about 10%, according to Reuters estimates. 

U.S. Energy Secretary Dan Brouillette said in April that the department expected U.S. production to drop by 2 to 3 million bpd by year-end. He and other U.S. officials said there was no need to mandate cuts because low prices would cause companies to shut production. Regulators in top oil states, including Texas and North Dakota, considered forced cuts, but none have limited production. 

“The power of the market can be ferocious sometimes,” said a senior OPEC source, adding he was surprised at the speed of U.S. and Canadian supply reductions. 

Some energy ministers wanted formal commitments for cuts from non-OPEC nations prior to holding a meeting, emphasizing their countries have ceded market share for years. 

Iran’s oil minister, Bijan Zanganeh, said in early April that cuts from countries such as the United States and Canada should be resolved before OPEC even held a meeting. Russian government spokesman Dmitry Peskov said economically-induced cuts were not equal to more drastic, forced cuts from state oil producers designed to stabilize markets. 

They were concerned because U.S. producers have benefited from previous cuts by OPEC and Russia. While OPEC+ producers have been cutting production to raise prices since 2016, shale producers took advantage of those higher prices to pump more - effectively stealing market share. The United States has become the world’s largest crude producer while OPEC and Russia kept output constrained. 

As of February, the latest month for which data is available, the Energy Information Administration said U.S. crude output was 12.8 million bpd. Weekly figures show output has dropped to 11.9 million bpd, but that data is considered less reliable than monthly figures.

In recent days, prices in physical markets have rebounded. Analysts revised their outlook for production shut-ins due to the swift response from operators. 

“When prices went negative it really accelerated some of the cuts,” said Allyson Cutright, director at Rapidan Energy Group in Bethesda, Maryland. The consultancy recently increased its forecast for U.S. and Canada cuts to 2.3 million bpd in June. 

The heaviest reductions are coming from Texas, the largest U.S. producing-state, with 5 million bpd of output. Texas output is likely to drop by 20%, or 1 million barrels, by the end of May, said Karr Ingham, executive vice president of the Texas Alliance of Energy Producers. 

“Operators are shutting in anywhere from 20% to 50%, and some more than that, based on what they think they can get to market,” Ingham said.
In North Dakota, output has dropped by at least 400,000 bpd since March 1, nearly a third of the state’s around 1.4 million bpd output before the crisis. State officials expect the volume shut to rise further.[L1N2CM16O] 

“This is worse than anything that any of us have ever seen,” said Pete Miller, former CEO of Houston-based National Oilwell Varco, speaking on a call with investors Monday. 

ConocoPhillips has cut the most, saying it will reduce 460,000 bpd across the United States and Canada. Exxon Mobil announced worldwide cuts of roughly 400,000 bpd, with two-thirds of that from the two countries.

Trump, on Tuesday, tweeted that the rise in oil prices was due to increased demand, but the rebound in consumption has so far been tepid. “The fierce response from the U.S. producers is what has turned the market around,” said John Kilduff, a partner at Again Capital in New York. On Tuesday, Brent crude futures closed at nearly $31 a barrel, the highest in three weeks. 

Billions of barrels have gushed into storage during the glut. The oversupply will weigh on the market for years if demand does not pick up. 

“There’s just so much crude oil,” said Bob Yawger, director of energy futures at Mizuho in New York. 

Reporting by Jessica Resnick-Ault, additional reporting by Jennifer Hiller in Houston and Dmitry Zhdannikov in London; Editing by David Gaffen, Simon Webb and Aurora Ellis