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Crude oil and natural gas have both been lagging some of the blistering pace of other commodities this past week.

Oil continues to be torn between the uneven recovery in global fuel demand, especially due to continued virus flareups across Asia, writes Ole Hansen, Head of Commodity Strategy, Saxo Bank.

Adding to this has been the disastrous hacking attack on the Colonial Pipeline which supplies 2.5 million barrels/day of fuel products from refineries in Texas to consumers along the US East coast.

As a result the US national average retail gasoline prices have risen above $3 a gallon for the first time since 2014, but while fuel stations across the East and South have started to run out, some refineries have been forced to cut runs leading to lower demand for crude oil.

A bigger-than-expected cut in crude stocks, reported by the American Petroleum Institute last night, was offset by a big increase in gasoline stocks.

All this happens as the commodity sector remains on a tear with several key raw materials from copper and iron ore to corn and palm oil trading at or near multi-year highs.

Inadvertently thereby adding to the debate over whether commodity-driven inflation pressures will be persistent enough to force the Federal Reserve to tighten policy sooner than currently expected.

Hence the focus on today’s US CPI data which is expected to show a year-on-year jump of 3.6%. With most of the change being down to seasonality, the focus may for once be centered on the monthly increased, expected at just 0.2% compared with 0.6% in March.

The rally this past week has been led by industrial metals and grains while crude oil and natural gas for various reasons have struggled to keep up. Overall, however, the Bloomberg Commodity Spot index is trading at a fresh ten-year high, and now up by one-third since early November when vaccine news accelerated growth and demand expectations.

Meanwhile, during the week, Opec, the IEA and the EIA have all published their monthly oil market reports. Overall no major changes were made with world oil demand seeing a small downgrade due to virus breakouts in Asia while non-Opec supply was lowered due to slower US shale growth.

Since late March Brent crude oil has traded in a rising but narrowing channel, currently between $70.80 and $67.25, the latter also being the 21-day moving average, a technical indicator which gives a good idea about short term momentum. We struggle to see Brent make much short-term headway above the triple top at $71.3, so while urging short-term caution we maintain a bullish outlook for the second half of 2021, primarily due to the prospect for a rapid growth in global fuel demand as vaccine rollouts reduce the impact of local virus flareups.

Natural Gas has spent the past couple of weeks trading sideways within a relative tight range between the $2.86 and $2.98, levels that represents the 50% and 68.2% Fibonacci corrections of the February to March sell-off. The close proximity to the rising trend line from the April low points to a market that is getting ready for break, either towards $2.80 or higher towards the February high around $3.31.

TradeArabia, by Ole Hansen, May 18, 2021

What do businesses need to operate? Electricity, water and gasoline are near the top of the list, and recent infrastructure failings suggest the foundations of the US economy may be on shakier ground than thought.

In February, extreme weather overwhelmed the electric grid in Texas, causing days of power and water outages in a state where many people depend on electric heat. Oil production plummeted and refineries were forced to close.

Three months later, a criminal gang believed to be operating in Eastern Europe launched a cyberattack on the Colonial Pipeline, which stretches from Texas to New Jersey and transports half the fuel consumed on the East Coast. Panic buying and gas shortages followed.

Both snafus caused real trouble for consumers and businesses, but they are far from isolated events. The US Department of Homeland Security warned in February 2020 that a cyberattack had forced a natural gas compression facility to close for two days. In 2018, multiple US natural gas pipeline operators were hit by an attack on their communication systems.

The threats from cyberattacks and extreme weather have been well known for years, but experts say wide swaths of the United States’ critical infrastructure remain vulnerable. The private sector and government both have roles to play in hardening defenses and preventing future damage.

“The ransomware attack on the Colonial Pipeline in the US shows the critical importance of cyber resilience in efforts to ensure secure energy supplies,” Fatih Birol, the head of the International Energy Agency, said on Twitter. “This is becoming ever more urgent as the role of digital technologies in our energy systems increases.”

The private sector owns roughly 85% of US critical infrastructure and key resources, according to the Department of Homeland Security. Much of that needs an urgent upgrade. The American Society of Civil Engineers estimates there will be a $2.6 trillion shortfall in infrastructure investment this decade.

“When we fail to invest in our infrastructure, we pay the price. Poor roads and airports mean travel times increase. An aging electric grid and inadequate water distribution make utilities unreliable. Problems like these translate into higher costs for businesses to manufacture and distribute goods and provide services,” the group warned.

As the Colonial Pipeline crisis unfolded, President Joe Biden signed an executive order that is designed to help the government deter and respond to cyber threats. The order will establish standards for software purchased by federal agencies, but it also calls on the private sector to do more.

“The private sector must adapt to the continuously changing threat environment, ensure its products are built and operate securely, and partner with the federal government to foster a more secure cyberspace,” the order states.

The private sector can work more closely with the government, analysts say, including improved information sharing with law enforcement agencies. Corporate boards need to be fully engaged on cyber issues, and management should relentlessly enforce basic digital hygiene measures including the use of strong passwords. If hackers demand a ransom, it’s best to not pay.

Experts say that regulators need to increase oversight of critical infrastructure. The Transportation Security Administration, for example, is charged with regulating pipeline cybersecurity.

But the agency issues guidelines not rules, and a 2019 watchdog report found it lacked cyber expertise and had only one employee assigned to its Pipeline Security Branch in 2014.

“For twenty years the agency has chosen to take a voluntary approach despite ample evidence that market forces alone are insufficient,” Robert Knake of the Council on Foreign Relations said in a blog post.

“It may take years to get the pipeline industry to a point where we can have confidence that companies are appropriately managing risks and have constructed systems that are resilient,” he added. “But if it is going to take years to secure the nation, it is well past the time to get started.”

Biden, meanwhile, is pushing his roughly $2 trillion plan for improving the nation’s infrastructure and shifting to greener energy as part of the solution.”In America, we’ve seen critical infrastructure taken offline by floods, fires, storms and criminal hackers,” he told reporters last week. “My American Jobs Plan includes transformative investments in modernizing and in securing our critical infrastructure.

But critics say the infrastructure proposal doesn’t do enough to address malicious cyber security, especially in light of the Colonial Pipeline attack.

“This is a play that will be run again, and we’re not adequately prepared. If Congress is serious about an infrastructure package, at front and center should be the hardening of these critical sectors — rather than progressive wishlists masquerading as infrastructure,” Ben Sasse, a Republican senator from Nebraska, said in a statement.

Are prices going up? That can be hard to measure

Just about everything is getting more expensive as the US economy rebounds and Americans spend more on shopping, traveling and eating out.
US consumer prices in April shot up 4.2% from a year earlier, the Bureau of Labor Statistics reported last week. It was the biggest increase since 2008.

Big moves: The biggest driver of inflation was a steep 10% increase in used cars and truck prices. Prices for shelter and lodging, airline tickets, recreational activities, car insurance and furniture also contributed.

Rising prices unnerve investors because they could force central banks to pull back on stimulus and raise interest rates sooner than expected. This week, investors will be watching to see if the inflationary trend is taking hold in Europe, with price data due Wednesday.
But spare a thought for the bean counters tasked with calculating inflation during a pandemic, when buying patterns have changed dramatically because of lockdowns and the big shift to online shopping.

“On a practical level, statistics offices have faced the problem of having to measure prices when many items are simply not available for purchase due to lockdowns. They also need to account for shifts in the timing of seasonal sales caused by the pandemic,” said Neil Shearing, group chief economist at Capital Economics.

“All of this means that ‘measured’ inflation, which is to say the monthly figure reported by statistics offices, may differ from the true rate of inflation on the ground,” he added.

CNN Business, by Charles Riley, May 18, 2021

May 14, 2021 A new company has been launched with $250m of backing from private equity firm Bluewater.

Global Energy Storage (GES) has been set up by the management team of hydrocarbon storage and logistics firm Global Petro Storage (GPS) and is focused on developing storage and logistics projects for LNG, LPG, hydrogen, ammonia and renewable fuels.

The team is based in Singapore, the Netherlands, UAE and London is led by chief executive Peter Vucins and executive chairman Eric Arnold. CIO Alan Hyslop, CFO Sim Seow Wah, and CTO Mark Synnott also join from GPS.

Mr Vucins said the team would initially work across both GES and GPS, which Bluewater first invested in five years ago. He said the management team would stay with GES in the event of a Bluewater exit from GPS.

The CEO said GES was developing an “exciting pipeline of projects” in Southeast Asia and Latin America and expected to announce its first deal “very soon”.

GES is also interested in contributing to decarbonisation in the UK, which has ambitions for growing hydrogen production, particularly in places like Humberside.

In addition, GES has signed up to the Transhydrogen Alliance, alongside Dutch engineering firm Proton Ventures, Dubai-based Trammo, and VARO, an European mid- and downstream energy company. The consortium was set up to work together on the production and import of green hydrogen and green ammonia into Europe via Rotterdam.

Mr Vucins said: “There is an urgent need for storage assets for the next generation of low carbon fuels.

“GES has the expertise and financial backing to develop this crucial infrastructure at key locations around the world.

“I am delighted that GES will be playing its part as we all work together to meet the ambitious, and essential, Paris carbon reduction targets.”

Mr Arnold said: “GES has a unique proposition. Our team has proven experience that is second-to-none. We have PE backing, so we can make swift decisions and take a longer view, rather than focusing on just the next quarter. And we have a strong focus on energy transition fuels. You put these together, and I believe Global Energy Storage is extremely well-placed to make a significant contribution to the Energy Transition.”

Bluewater managing director Martin Somerville added: “Peter and Eric are genuine leaders in the sector, and that’s why we’re supporting this new vehicle to build on the continuing success of GPS. GES will allow them to target new markets and opportunities that help deliver new storage solutions for the energy transition.”

By Private Equity Insights, May 14, 2021

India, the world’s third-largest oil importer, is the latest coronavirus hotspot. It has recently hit a record-breaking number of new daily coronavirus cases—a statistic that dented oil demand and pressured oil prices.

OPEC+, out of its own necessity, has intervened in the oil market on the supply side of the equation to offset the pandemic-depressed oil demand. And despite the group’s relative success at curbing oil production to prevent excess oil inventories from ballooning before the market fully recovers, India’s booming case counts have prevented oil prices from a quicker recovery.

This has put even more pressure on OPEC+ to perform to meet market expectations. But there is no doubt a shift in the momentum of the oil markets. Indeed, oil prices have recovered somewhat in recent months, and the overwhelming majority of oil experts and analysts think this trend will continue.

The question isn’t whether the market will improve. The question is how quickly will it improve, and where will that recovery peak.

Lockdowns in Europe add another unknown element into the oil price mix. A month ago, Europe renewed many of its lockdown restrictions, delaying the oil price recovery. But now, as India is in the midst of its worst COVID-19 surge since the pandemic began, Europe is getting ready to lift those lockdowns. EU officials have submitted this week a proposal to ease summer travel restrictions to its 27 nations. This will increase the demand for jet fuel—a critical component of crude demand.

In the United States, Covid-19 cases are also shrinking while the number of vaccinated grows. As a result, several U.S. states, including New York, are relaxing restrictions. All of this will have a profound effect on the price of crude oil.

But that’s not to say that all analysts agree on what this will do to oil demand, let alone what effect it will have on oil prices.

The IEA, for starters, revised up its oil demand outlook for this year on April 14. By its estimates, oil demand will now increase by 5.7 million bpd this year, reaching 96.7 million bpd. The reason for this upward revision was due to increases in the IEA’s oil demand forecast for the United States and China—the two largest oil importers in the world.

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As of April 6, the EIA saw global oil demand at 97.7 million bpd this year. Compared to Brent prices that were near $65 per barrel in March, the EIA sees not much movement in the price of Brent, estimating $65/barrel in Q2 2021, $61 per barrel in H2 2021, and even worse–$60 per barrel in 2022.

Not even a week ago, Rystad Energy adjusted its oil demand for April down by almost 600,000 bpd. For the month of May, it revised it down by 914,000 bpd, citing India’s demand problems as a result of the pandemic—a situation that would no doubt result in a new inventory glut.

But not everyone is so pessimistic. Goldman Sachs sees things as much rosier, with oil reaching as much as $80 this summer. Its rationale for this positive outlook on oil prices is simple. “The magnitude of the coming change in the volume of demand—a change which supply cannot match—must not be understated.”

Rystad analyst Louise Dickson said that oil demand should still increase by 3 million bpd between now and the end of June, India troubles or no. According to her, oil prices should make their way back to $70 per barrel in the coming months.

UBS sees vaccine rollouts as a major positive for the oil industry. As people return to normal activities and businesses fully reopen, oil demand will cause Brent to increase to $75 per barrel in H2, according to analyst Giovanni Staunovo.

Moody’s has a rather positive view of the timing of an oil price rebound as well, citing pent-up consumer demand that will propel forward a global economic recovery. But their medium-term price range is still capped at $65 per barrel. Moody’s sees this economic recovery as hastening a rebound in oil demand through the end of this year and the beginning of next year.

The outlook may be uncertain, but the current trend is definitely one of drawing down oil stocks—a sign of increased oil demand while OPEC+ continues to restrict output. In the highly visible U.S. oil market, for example, commercial crude inventories have finally retreated back to the five-year average for this time of year at 493 million barrels.

India’s virus explosion will not prevent an oil price recovery. But it very likely that it will slow the recovery well into the second half of this year or even the beginning to middle of next year.

If that turns out to be the case, that’s a long time for OPEC+ members to continue their output restrictions while demand takes its sweet time recovering.

Oil price, by Julianne Geiger, May 13, 2021

Exxon Mobil’s effort to build an energy trading business to compete with those of European oil majors unravelled quickly last year as the firm slashed the unit’s funding amid broader spending cuts, 10 people familiar with the matter told Reuters.

Exxon Mobil’s effort to build an energy trading business to compete with those of European oil majors unravelled quickly last year as the firm slashed the unit’s funding amid broader spending cuts, 10 people familiar with the matter told Reuters.

The cuts left Exxon traders without the capital they needed to take full advantage of the volatile oil market, these people said.
The coronavirus pandemic sent prices to historic lows — with US oil trading below zero at one point — before a strong rebound.

That created an immense profit opportunity for trading operations willing to take on the risk.

Exxon instead systematically avoided risk by pulling most of the capital needed for speculative trades, subjecting most trades to high-level management review, and limiting some traders to working only with longtime Exxon customers, according to interviews with 10 former employees and people familiar with Exxon’s trading operation.

Traders were restricted to mostly routine deals intended as a hedge for Exxon’s more traditional crude and fuel sales rather than gambles seeking to maximise profit, four of the people said.

The trading retreat came after Exxon had worked in the previous three years to bolster its trading unit with revamped facilities, high-level hires and new tools to help traders take on more risk.

The company’s cautious strategy in the pandemic sparked the exodus of some of those senior-level new recruits, along with Exxon veterans, as the company downsized the department amid broader spending cuts, according to the people familiar with its trading operation.

“They were careful with capital during a period of time when they maybe shouldn’t have,” one trader who left Exxon in the last year said of its management.

Exxon’s trading retreat came as the company overall posted a historic $22.4bn net loss in 2020.

Exxon does not separately report the performance of its trading unit, Reuters was not able to determine the trading department’s overall profit or loss, or the specific reduction it made in capital available for speculative trading.

Some of Exxon’s biggest rivals made enormous trading profits last year as their traders bought oil and stored it when prices plunged, then sold it at higher prices for future delivery.

Rival Royal Dutch Shell said in March that it doubled its 2020 trading profits to $2.6bn over the previous year, BP Plc’s trading arm earned about $4bn, a near record, Reuters reported previously, based on an internal BP presentation. Such profits helped both companies offset massive losses from a collapse in fuel demand and prices as the pandemic curtailed travel worldwide.

Exxon declined to comment on whether it scaled back speculative trading or reduced the department’s capital and staffing.
An Exxon spokesman said its trading team continues to have a “broad footprint.”

“We’re pleased with our progress over the past couple of years,” said spokesman Jeremy Eikenberry.

The cutback in Exxon’s trading operation comes amid broader setbacks. The firm’s stock, after hitting its lowest level in nearly two decades last year, was removed from the Dow Jones Industrial Average, an index of the top 30 US companies.

The firm’s cash flow declined sharply, and its debt rating was cut two notches in 12 months.

Exxon said in October that the firm would eliminate 14,000 jobs, about 15% of its global workforce, by the end of 2021.
Among the belt-tightening measures: asking US office workers to empty their own trash bins, two sources said.

Top oil trading firms make money by buying and selling oil to take advantage of price differences in different markets, a strategy known as arbitrage.

They also speculate on futures contracts, betting on whether the oil price will rise or fall by specific dates, the big players include trading units at major oil producers such as BP, as well as specialized merchants such as Trafigura AG.

The risks are high, but successful trading desks can deliver returns of 20% to 25%, much higher than other parts of the oil-and-gas business, estimated Andy Brogan, a partner at advisory firm EY and leader of its oil-and-gas practice, in an October EY publication.

Exxon, the largest US oil producer, has historically viewed trading skeptically and limited its activity.

After Darren Woods became CEO in 2017, however, he broke with tradition and sought to build up the company’s small trading unit.

The company began hiring consultants, recruiting veteran traders and revamping its trading floors in Spring, Texas, and Leatherhead, England

Among the hires were well-regarded traders and marketers from firms including commodity trader Glencore Plc and US refiners Andeavor and Phillips 66.

Exxon equipped the expanded staff with risk management tools to help trading executives assess potential losses, laying the foundation for a bolder strategy, two people familiar with the operation said.

CEO Woods initially pledged last March that the firm would “lean into” the oil-market decline by continuing major investments across the company.
He reversed course a month later, ordering broad spending cuts as oil fell below $30 a barrel.

Woods vowed to protect a $15bn-a-year shareholder dividend as Exxon’s stock price tumbled.
By contrast, Shell and BP reduced their dividends.

Exxon’s decision contributed to deep spending cuts and heavy borrowing across the US oil giant, which took on about $21bn in debt last year

The quick retreat of Exxon’s revamped trading desk underscores the firm’s longstanding aversion to risk, said Anish Kapadia, director of energy at Palissy Advisors.

“The trading business is a risk business,” he said. “That has never been one of Exxon’s fortes.”

Exxon cancelled an early 2020 trading strategy meeting at Exxon’s Irving, Texas, headquarters.
After that, “everything went on hold,” said one person close to the company.

The oil-market collapse in April triggered a working capital freeze in the trading group, a former Exxon trader told Reuters.

As cost-cutting continued throughout 2020, the trading operations in Texas and England began sending expatriate workers back to their home countries to save on allowances for housing, cars and tuition benefits, said two people familiar with the moves.

Exxon’s financial woes and restrictions on trading led to the exodus of many department staffers, including senior traders and managers, according to three former trading employees and others familiar with the operation

Exxon laid off some trading employees and offered others early retirements or severance packages, the people said, while more staffers left through attrition.

Reuters could not determine the total number of departures.

Among the prominent departures were Exxon veteran Steve Scott, who led Exxon’s British crude oil trading operation in Leatherhead, people familiar with the matter said.

They also included Ben Knowles, who was behind Exxon’s exports to Europe and Asia; and Nelson Lee, who while at oil producer BHP Billiton orchestrated some of the first exports of US crude in decades before joining Exxon in June 2018

Scott and Knowles could not be reached for comment. Lee declined to comment.

There was a slight pullback in oil prices following Wednesday’s highs, but the rally is still very much on and bullish sentiment is palpable as summer driving season nears.

Brent tested $70 per barrel on Wednesday but fell back on Thursday. Oil “had a great run, but it got a little bit ahead of itself,” Phil Streible, chief market strategist at Blue Line Futures LLC in Chicago, told Bloomberg. “We’ve hit resistance and prices pulled back,” but it’s hard to see a summer demand boost “being derailed,” he said. Oil is still set to close out the week with another gain.

Sempra to delay Port Arthur LNG. Sempra Energy (NYSE: SRE) said on Wednesday that it would delay its proposed Port Arthur LNG project until 2022 instead of this year, citing global energy markets and a focus on greenhouse gas reductions. 

Exxon to take $200 million charge related to job cuts. ExxonMobil (NYSE: XOM)expects a $200 million charge related to severance costs for laid-off workers. 

Copper hits record high. Copper price hit a record high on Thursday as Chinese investors unleashed fresh demand following a five-day holiday.

Pioneer says consolidation needed. Pioneer Natural Resources (NYSE: PXD)CEO Scott Sheffield said that the shale industry needs even more consolidation. “I hope other privates are taken out that are growing too much,” Sheffield told investors on an earnings call,” Sheffield said. 

Wind costs rise due to the commodity boom. The rising cost of steel is forcing Vestas (CHP: VWS) to hike its prices for wind turbines.

Exxon and Chevron cautious in Permian. Neither ExxonMobil (NYSE: XOM) nor Chevron (NYSE: CVX) are rushing to boost production in the biggest American shale play, the Permian, despite the oil price rally this year that has sent WTI prices to above $60 per barrel.

Winners of Texas freeze. Among the biggest winners of the Texas crisis in February were commodity trading major Vitol, pipeline operators including Kinder Morgan, Enterprise Products Partners, and Energy transfer, and lenders including Goldman Sachs, Bank of America, and Macquarie Group.

Energy Transfer made $2.4 billion in Texas crisis. Energy Transfer (NYSE: ETP) took in $2.4 billion from the Texas grid crisis, and the stock jumped nearly 5% on Thursday.

India to import more Saudi oil. After Saudi Aramco cut oil prices for June, Indian state refiners added more orders.

Peak LNG? The viability of LNG import terminals in Europe has dimmed and utilities are looking for alternative uses, according to Bloomberg. Last month, for example, Uniper SE said waning demand for new LNG led it to switch a project to a hydrogen hub. In Ireland, another project has been transformed into an offshore wind project.

LNG market to see deficit. Rystad Energy said that the global LNG market could see a supply deficit in the coming years due to inadequate investment, made worse by the delays in Total’s (NYSE: TOT) massive LNG project in Mozambique.

Commodity boom adds inflation risk. Tight inventories for a long list of commodities are pushing up prices, which is increasing the odds of rising inflation. U.S. Treasury Secretary Janet Yellen rattled markets on Tuesday when she said that interest rates might need to rise. 

IEA: metals shortage poses transition risk. The IEA came out with a new report warning that a shortage of critical minerals used in green technologies could slow the pace of energy transition and make it more expensive. The agency urged faster investment in new mining projects. 

U.S. shale pre-hedge revenue hits record high. If WTI futures continue their strong run and average at $60 per barrel this year and natural gas and NGL prices remain steady, producers can expect a record-high hydrocarbon revenue of $195 billion before factoring in hedges, a Rystad Energy analysis shows. The previous record of $191 billion was set in 2019.

UN: World needs to cut 40-45% methane. A new report from the UN finds that the global increase in methane emissions since 2010 is “primarily attributable” to the surge in oil and gas drilling – i.e., the U.S. shale boom. The report said cuts to methane emissions are actually inexpensive and achievable. 

Marathon Oil returns to Oklahoma drilling. Marathon Oil (NYSE: MRO) is returning to limited operations in Oklahoma and the Permian Basin’s western Delaware Basin in New Mexico before ramping up next year.

Michigan’s May 12 deadline for Line 5. Michigan has ordered Enbridge’s (NYSE: ENB) Line 5 pipeline shut down by May 12 – next week – but the company said it would defy the order. 

TC Energy takes $1.8 billion impairment on KXL. TC Energy (NYSE: TRP)announced a C$2.2 billion ($1.8 billion) impairment related to the suspension of the Keystone XL project. 

Half of Equinor’s profits came from renewables. Equinor (NYSE: EQNR) reported $2.6 billion in first-quarter earnings, and 49% came from renewables.

Mining majors earn more than oil majors. The top five iron ore miners are on track to earn $65 billion this year, or about 13% more than the top five oil majors, according to Bloomberg. A big reason for this is the soaring price of iron ore, which has climbed to around $200 per ton, a record set a decade ago.

EQT to buy Alta Resources for $3 billion. EQT (NYSE: EQT) said it would purchase Appalachian rival Alta Resources for $2.93 billion in cash and stock. EQT is already the nation’s largest natural gas producer, and a giant in Appalachia, but the acquisition expands its footprint. 

Germany accelerates climate targets. In the wake of a court decision ordering tougher action, the German government increased its 2030 emissions reduction target from 55% to 65% and moved up its net-zero target by five years to 2045.

Biden admin considers nuclear subsidy. The White House is considering a subsidy to keep existing nuclear power plants online to avoid a setback in its decarbonization goals if nuclear plants were to shut down.

Oil Price, by Tom Kool, May 10, 2021

We’ve all gotten used to the idea that much of our clothing and electronic gadgets are made in far corners of the world, where labor is cheaper and regulation may be less onerous. What’s less well-known is how dependent North America and Western Europe have become on foreign suppliers of the refined oil products on which we rely on for much of our power, heat and fuel for our cars, trucks and airplanes.

In the 40 years since 1980, refining capacity in the Asia Pacific region has risen by 23 million barrels a day, while rest of the world’s ability to turn raw crude into the products we rely on has fallen.

China’s refining capacity has nearly tripled in the past 20 years. It is set to overtake the U.S. as the world’s biggest crude processor this year, and it won’t stop there. The Asian nation will add another 2.6 million barrels a day by 2025 to take its processing capacity to about 20 million barrels a day. India is also growing rapidly and its capacity could jump by more than half to 8 million barrels a day in the same time.

That’s in part explained by the fact that oil demand has been growing far faster in Asia than anywhere else. It’s understandable the industrializing nations of the east would want to bring oil processing onshore, even if they’re still reliant on producers elsewhere to deliver the crude that’s helped power their expansion.

But recently there’s been a big, and largely unnoticed, shift. Those new refineries in Asia, and increasingly in the Middle East, are no longer only supplying local markets. They are starting to export increasing volumes of refined products to other markets.

Refiners in five countries — China, India, Saudi Arabia, Malaysia and, most recently, Brunei — have seen their combined share of global refined products exports almost double in the past decade, according to data from the Joint Organisations Data Initiative (see chart below). True, those figures aren’t complete. But the most obvious country missing, the United Arab Emirates, would probably add to the weight of these new refiners.

While most of the exports from Chinese refineries remain in Asia, the same is not true for plants in India or the Middle East. As my Bloomberg News colleague Jack Wittels noted here, the flow of clean petroleum products (mostly diesel, jet fuel and gasoil) from India to Europe hit a 13-month high in April as oil demand started recovering. Arrivals from the Middle East also rose sharply.

The biggest oil consumers in Europe — Germany, the U.K. and France, which eachconsume more than 1.5 million barrels a day of oil — have all been short of the refining capacity needed to meet demand for almost a decade. For Germany, it’s been much longer.

The U.S. is almost as dependent, regardless of successive shale booms that have boosted domestic crude production. The country has imported more than 2 million barrels a day of refined products over the past year. One foreign supplier sticks out — Russia — the second-largest shipper of refined oil products to the U.S. after Canada, according to the Department of Energy.

While U.S. refining capacity has risen steadily since the late 1990s, it hasn’t kept pace with the increase in oil demand. Only the successive slumps in consumption sparked by the 2008 financial crash and Covid-19 pandemic have brought the country anywhere close to meeting its needs.

The situation is only likely to get more pronounced as new oil refineries come into operation in Asia and the Middle East. Saudi Arabia’s new 400,000-barrel-a-day Jazan refinery is expected to start commercial operations next month. Neighboring Kuwait is expected to commence processing at its 615,000-barrel-a-day Al Zour plant later this year.

There’s unlikely to be investment in new refineries in Europe or the U.S. amid the shift away from fossil fuels. Tighter environmental restrictions on operations in these regions will make it increasingly expensive for ageing sites to meet limits on carbon emissions or other benchmarks. Several plants have already stopped processing crude, some to be reconfigured as biofuels plants, others to become storage terminals.

The outsourcing of manufacturing has led to job losses that have fueled voter anger and populist sentiment over the years. Outsourcing fuel production may be less visible, but it could bring similar backlash if we ever find ourselves short of the fuels we need to maintain our lifestyles.

Bloomberg, by Julian LeeBookmark , May 10, 2021

There are three key reasons why the development of a world-class petrochemicals (petchems) sector is vital to Iraq’s future.

First, its heavy reliance on crude oil exports makes it extremely financially vulnerable both to downturns in the oil price and to the political whims of its fellow OPEC members, especially Saudi Arabia. Second, plain crude oil exports, particularly in the depressed pricing environment that is likely to endure for some time, do not provide the much higher export value that petchems do. Third, Iraq has the natural resources of both oil and gas that can make it a world leader in the petchems sector.

This in turn would allow it to develop major trade with the big buyers of petchems products in Asia relatively independent of Iran, which would allow it to put more political distance between Baghdad and Tehran and this would encourage more sustained investment from the U.S. Recent developments in Iraq may portend such development of the petchems sector, with the long-stalled Nebras project being a prime beneficiary at last.

The recent tentative deal with Total, if finalised, will provide a major boost to the equally long-delayed efforts to meaningfully make use of Iraq’s massive associated gas resources. Official estimates are that Iraq’s proven reserves of conventional natural gas amount to at least 3.5 trillion cubic meters (tcm), or about 1.5 percent of the world’s total, placing Iraq 13th among global reserve-holders, with around three-quarters of this figure comprising associated gas.

The International Energy Agency, though, estimates that ultimately recoverable resources will be considerably larger, at 8.0 tcm, of which around 30 percent is thought to be in the form of non-associated gas. Although at the moment it is only a ‘heads-of-agreement’ deal – alternatively known as a ‘letter of intent’ agreement – that is not binding, and may yet become derailed by the sort of concerns over corruption that have deterred many other foreign firms from doing business in Iraq, it may be that Total sees a growing presence in Iraq as a promising substitute for its forced withdrawal by the U.S. from Iran’s coveted Phase 11 project of the supergiant South Pars non-associated natural gas field. This deal, together with the 25-year deal just announced that the China Petroleum & Chemical Corp. (Sinopec) is to take a 49 percent stake in the Mansuriya non-associated natural gas site, provides Iraq with a solid base upon which to move the development of its petchems sector into the next phase.

The core project that allows for the development of the petchems industry in Iraq is the US$17 billion 25-year Basra Gas Company (BGC) project with Royal Dutch Shell that began in 2013. A joint venture between Iraq’s South Gas Company (SGC), holding 51 percent, Shell (44 percent), and Mitsubishi Corporation (5 percent), the BGC currently captures associated gas from the three major oil fields of Rumaila, West Qurna 1, and Zubair. In December 2018, BGC reached a peak production rate of 1035 mmscf/d, the highest in Iraq’s history and sufficient gas to generate approximately 3.5 gigawatts (GW) of electricity – enough to power three million homes. BGC currently supplies 70 percent of Iraq’s LPG, and through expansion of its export capabilities, helped turn Iraq from a net importer to a net exporter of LPG as from 2017. Interestingly, and a sign of what can be achieved in Iraq – given the country’s huge resources but without any of the usual dodgy dealings – BGC and CitiBank signed a first credit agreement in February 2019, the first commercial loan extended by CitiBank to an Iraqi corporate entity.

Given this, the focus of Iraq’s petchems push has long been the Nebras petrochemical complex. The original design plans for Nebras – formulated between Shell and the Iraq Ministry of Oil and Ministry of Industry and Minerals in 2012 – were for a project that could produce at least 1.8 million metric tonnes per year (mtpa) of various petrochemicals. This would make it Iraq’s first major petrochemicals project since the early 1990s and one of only four major petchems complexes across the entire country.

The others – Khor al-Zubair in the south, Musayeb near Baghdad, and the Baiji refinery complex in the north – are operated by Iraq’s State Company for Petrochemical Industries. In January 2015, Shell released the statement that Iraq’s cabinet had authorised the Nebras project and that the company would work ‘jointly with the Ministries of Oil and Transport to develop a joint investment model for a world-scale petrochemical cracker and derivatives complex in the south of Iraq’. The then-Industry Minister, Nasser al-Esawi, told a news conference at the time that the Shell-run Nebras petrochemical complex would come online within five to six years and would make Iraq the largest petrochemical producer in the Middle East.

From 2012, though, the head of petrochemicals projects for a major international oil company operating in Iraq exclusively told OilPrice.com: “The development of Iraq’s hydrocarbons chain stalled in the upstream – and mainly crude oil – sector, with little impetus on the next stage that’s critical for both the petrochemical and refining sectors, which is a focus on the midstream to attract sufficient capital with the strategic objective of developing an integrated master gas system.” However, he added, since then Shell’s efforts on the BGC in the past three to four years in particular have changed the basic landscape for the future development prospects for Nebras. “Shell has done a really good job so far with the BGC, especially in getting the gas volumes up to over a billion standard cubic feet per day, which means that the ethane can be extracted on a sustainable and reliable basis, and that allows for sufficient volume for a major petchems plant to be viable,” he said.  “Ethane needs to be the initial feedstock for Iraq’s first few plants in the same way that it was in the development of Saudi Arabia’s master gas system that captured associated gas, which was then fractionated and supplied as primary feedstock to the flagship Jubail Industrial City,” he underlined.

“The highest concentration of ethane [10 percent plus] is usually found in associated gas streams, which Iraq has a lot of, and processing ethane produces ethylene with few by-products [mainly fuel gas] to process and manage,” he told OilPrice.com. “This reduces the capital required for construction and minimises the complexity of the logistics and distribution requirements, which will be important factors in Iraq’s early stage build-out of a viable petchems industry, but as the industry and corresponding infrastructure grows, heavier feed streams can be utilised, as happened with the use of propane, butane and naphtha in Jubail,” he said.

A world-scale facility for ethylene – one of the most in-demand petchems products in the world, especially from China – is in the range of 1.0 to 1.5 million tons of ethylene production and a 1.0 million ton per year ethylene facility would require a supply of roughly 1.3 million tons per year of ethane, he highlighted. “Additionally, this would need to be a sustainable and reliable supply for at least 20 to 25 years and, to build out all of the necessary parts for a functioning world-class petchems sector in Iraq would require around US$40-50 billion,” he concluded. As at the end of August, 2020, current Oil Minister, Ihsan Ismaael, stated that Iraq aims to ‘speed up plans’ for [Nebras] with Shell.

OilPrice, by Simon Watkins , May 10, 2021