Thursday, August 15, 2019

Gibraltar Releases Iranian Tanker U.S. Tried To Seize

A Royal Marine patrol vessel is seen beside Iran's Grace 1 tanker in the British territory of Gibraltar on July 4. The tanker was impounded, and the U.S. Justice Department applied to seize it, according to the Gibraltar government.
Marcos Moreno/AP


Gibraltar has released an Iranian oil tanker that was detained last month by Britain, despite a last-minute request by the U.S. to take possession of the vessel.

Grace 1 was raided on July 4 in the waters off the coast of Gibraltar, a British territory, by Britain's Royal Marines. The tanker was impounded on suspicion of transporting oil to Syria — a breach of European Union sanctions against Syrian President Bashar Assad's regime. It was said to be carrying 2.1 million barrels of crude oil.

Gibraltar's Chief Minister Fabian Picardo confirmed those suspicions on Thursday, but said in a statement that he had received "written assurance" from Iran that the tanker would not head to Syria with its cargo.

"In light of the assurances we have received, there are no longer any reasonable grounds for the continued legal detention of the Grace 1 in order to ensure compliance with the EU Sanctions Regulation," Picardo said.

The tanker's release from detention was decided Thursday afternoon local time by the Gibraltar Supreme Court.

A spokesperson with Gibraltar's government told NPR on Thursday that the Justice Department had applied to seize the vessel, providing "a number of allegations which are now being considered."

The U.S. Department of Justice did not immediately respond to NPR's request for comment.

Mohammad Javad Zarif, Iran's foreign minister, took to Twitter after the news of the release. 

"The US attempted to abuse the legal system to steal our property on the high seas," he wrote. "This piracy attempt is indicative of Trump admin's contempt for the law." 

According to a legal notice provided Thursday by the Gibraltar government, the Grace 1's passage plan plotted 38 specific waypoints for a route from the Persian Gulf to Baniyas, where a major oil refinery is located in northwestern Syria. 

"There were no plotted navigational charts, passage plans, plotted courses or underkeel clearance calculations on board the Vessel relating to a destination other than Syria," the notice said

Emails from April to July between the captain and managing agents showed permit requests and a directive to land the ship's waste at the discharge port — deemed to be Syria. The government of Gibraltar said it confirmed that the vessel was the property of the state-owned National Iranian Oil Company.

Days after the tanker was taken, Iran's Revolutionary Guard seized a British-flagged commercial oil tanker, called the Stena Impero, in the Strait of Hormuz — a vital shipping route linking the Middle East to the world. Iran also briefly detained a U.K.-owned oil tanker, Mesdar.

On Wednesday, Iranian Navy Commander Rear Admiral Hossein Khanzadi was quoted by Iran's Press TV with a warning that enemies should leave the region. "The era of hypocritical stunts and roaming freely around in the Persian Gulf is over," he said.

The seizures this summer have escalated relations between the West and Tehran. Tensions had already run high since President Trump's withdrawal last from the 2015 Iran nuclear deal.

Under the agreement, Iran said it would curb its nuclear programs in exchange for the U.S. easing of sanctions. The Trump administration has since imposed new economic sanctions on Iran, and Iran said it has begun to enrich uranium above the levels established in the agreement.

The Gibraltar Chronicle reported that the Grace 1's captain and three officers were released from arrest in a separate development. None of the crew were Iranian, according to The Associated Press.

Wednesday, August 14, 2019

Disruption In Global Crude Oil Production Spooks Refiners, Shippers

OIL


By Jet Encila


The global oil sector is struggling with unpredictability in supply and demand, but one big thing that is expected to make refineries and exporters paranoid is this: the new set of policies that will limit the usage of sulfur-laced fuels in shipping.
 
Analysts and investors anticipate that in less than two years, a major oil and refining companies will have embraced the new laws, but some market observers believe widespread shocks will be felt around the oil industry as soon as the new set of rules are imposed the first week of 2020.

Some market strategists have considered the new fuel shipping policies as the biggest "oil market disruptor" seen to jolt global supply routes in the shipping business, from producers of oil to traders, refineries, shippers, down to consumers.

Major shipping companies are bracing for a disturbance in the kinds of fuels they will be producing next year, but the oil market in general, including refineries, are also preparing for the worst.

Based on the new policies that will be implemented by the International Maritime Organization (IMO), less than 1% should be used on sulfur fuels on ships starting January next year, unless oil tankers are equipped with what engineers call as "scrubbers" - a technique that gets rid of sulfur from gas exhausted from bunkers.

In an interview with Forbes, Afab Salem, KPMG Risk Analytics director said that oil producers will offer arbitrage opportunities as the price margin between fuel oils with high sulfur content, and those with low-sulfur content, is projected to widen. Increased demand for very low-sulfur fuels, Salem said, will hike demand for crude grades.

According to latest estimates by the International Energy Agency (IEA), global demand for high-sulfur fuels will decrease from 3.4 million (barrels per day) to 1.3 million BPD, in just 12 months. A projected 4,000 fuel ships will be outfitted with scrubbers that will consume around 700,000 BPD of fuel by end of 2020.

Meanwhile, prices of oil in the global market were up nearly 5% late Tuesday, after the United States said it would defer the implementation of a 10% tax on selected goods coming from China, alleviating worries over an extended trade showdown that has battered markets in the past weeks.

The Sino-US trade conflict has diminished demand for energy stocks, and any ray of optimism resuscitates the notion of further positive demand possibilities, John Kelduff of New York-based energy hedge fund Capital Management, said.

Brent Futures made a quick 4.6% rally early Tuesday, at $61.21 per barrel, while US West Texas Intermediate (WTI) crude climbed 5%, at $57.12.

Tuesday, August 13, 2019

The World’s Newest Petrostate Isn’t Ready for a Tsunami of Cash

Image result for georgetown guyana oil

https://www.bloomberg.com/news/features/2019-08-13/guyana-isn-t-ready-for-its-pending-oil-riches-but-exxon-is

Guyana is investigating oil leases at a rocky political moment.

By Kevin Crowley

The Caribbean beats of reggae and soca ease into American hip-hop at a roadside bar in Georgetown, Guyana. Outside, teenagers hoot as they whiz past palm trees on mopeds. But for Gavin Singh, a 36-year-old investment banker, this is no time for play or relaxation. “People out there don’t really get it,” he says, pushing aside his mojito to emphasize his point. “We have a tsunami coming.”
A tsunami of what?

“Of cash. Of opportunity.”

This tiny nation on the north coast of South America is about to become the world’s newest petrostate—and potentially the richest. In 2015, Exxon Mobil Corp. made what one of its executives described as a “fairy tale” discovery in the vast Stabroek exploration block off the Guyanese coast. Since then, it’s found so much oil that by the mid-2020s Guyana, with a population of about 778,000, will probably produce more crude per citizen than any other country.

Crucially, however, Guyana—a poor former colony, first of the Dutch, then of the British—is unprepared for what’s coming. Its petroleum laws were written in the 1980s. The Department of Energy has an annual budget of $2 million. Five years after Exxon’s discovery, the country still hasn’t finished crafting relevant new laws or even established a regulatory body to oversee exploration and production. Last year the government set up a sovereign wealth fund to soak up as much as $5 billion in oil revenue per year by 2025, but there are no plans for how to spend it.

Even as the windfall approaches, more and more questions are being raised about how the country sold exploration rights off its coast—not just to Exxon, but also to other outfits that followed in the supermajor’s wake. The State Assets Recovery Agency (SARA), an anticorruption unit looking into the leases, hasn’t named any targets. It’s too early for that, says its director, Clive Thomas. “We’re building up a case,” he says.

Guyana’s oil age is dawning at a rocky political moment in this still-evolving democracy. The current president, David Granger, who heads a coalition government, lost a no-confidence ballot by a single vote in Parliament last December, triggering an election that as of late July hadn’t been scheduled. The parliamentary rebuff was a stinging reversal for Granger, who took office in May 2015, and the election could pave the way for the return of the People’s Progressive Party (PPP), which had held power for 23 years, including when Guyana first sold off its oil rights.

Then there’s the specter of Venezuela, which borders Guyana to the northwest and has historically laid claim to part of its rich offshore fields. Last year, Venezuelan gunboats sailed in to hinder Exxon’s activities, but drilling carried on to the south in the Stabroek block. So far Guyana has managed to weather its neighbor’s interference—no doubt aided by the cratering economy and widespread unrest that’s preoccupied Nicol├ís Maduro’s regime in Caracas.

When Mark Bynoe, the director of Guyana’s Department of Energy, was a boy, he used to play cricket barefoot with friends in his village outside Georgetown. At the end of the day, his feet “would be shiny at the bottom,” he remembers. “We knew oil was around.”

Bordered by Venezuela, Brazil, and Suriname—all producers—Guyana always held the promise of oil. But for decades after independence from Britain in 1966, explorers drilled nothing but dry holes. “We were practically begging people to take a block offshore,” says Jagdeo. “Nobody wanted to come.”

Then along came Exxon. It was 1999, and Jagdeo was heading the government. Guyana and Exxon signed a production-sharing agreement that covered a 26,800-square-kilometer (10,348-square-mile) deep-water area spanning virtually the entire width of the country’s maritime borders. Given all the unsuccessful exploration, Exxon secured the rights to Stabroek under terms so generous that they would come back to haunt the country.

The early years were frustrating for Exxon. Border disputes with Venezuela and Suriname impeded exploration. After the Suriname quarrel was settled in 2007, Exxon began gathering data and conducting seismic imaging along the eastern reaches of Stabroek. Then, in 2013, the Venezuelan navy boarded and for four days detained an exploration vessel contracted by Anadarko Petroleum Corp., another U.S. producer that was surveying in the area.

Exxon plowed on. In 2014 oil prices crashed, and its partner in Stabroek, Royal Dutch Shell Plc, pulled out. Unwilling to shoulder the financial risks on its own, Exxon remained the operator responsible for exploration but brought in New York-based Hess Corp. and China’s state-backed Cnooc Ltd., handing them 30% and 25% stakes, respectively, in exchange for sharing drilling costs.

When Exxon began drilling the wildcat well Liza-1 in March 2015, Guyana was just a couple months away from a general election. On May 20, four days after Granger emerged as the surprise winner, Exxon announced it had struck oil.

The timeline would later prove controversial and become a focus of the SARA investigation. But one thing was clear: Oil was coming.

When Mark Bynoe, the director of Guyana’s Department of Energy, was a boy, he used to play cricket barefoot with friends in his village outside Georgetown. At the end of the day, his feet “would be shiny at the bottom,” he remembers. “We knew oil was around.”

Bordered by Venezuela, Brazil, and Suriname—all producers—Guyana always held the promise of oil. But for decades after independence from Britain in 1966, explorers drilled nothing but dry holes. “We were practically begging people to take a block offshore,” says Jagdeo. “Nobody wanted to come.”

Then along came Exxon. It was 1999, and Jagdeo was heading the government. Guyana and Exxon signed a production-sharing agreement that covered a 26,800-square-kilometer (10,348-square-mile) deep-water area spanning virtually the entire width of the country’s maritime borders. Given all the unsuccessful exploration, Exxon secured the rights to Stabroek under terms so generous that they would come back to haunt the country.

The early years were frustrating for Exxon. Border disputes with Venezuela and Suriname impeded exploration. After the Suriname quarrel was settled in 2007, Exxon began gathering data and conducting seismic imaging along the eastern reaches of Stabroek. Then, in 2013, the Venezuelan navy boarded and for four days detained an exploration vessel contracted by Anadarko Petroleum Corp., another U.S. producer that was surveying in the area.

Exxon plowed on. In 2014 oil prices crashed, and its partner in Stabroek, Royal Dutch Shell Plc, pulled out. Unwilling to shoulder the financial risks on its own, Exxon remained the operator responsible for exploration but brought in New York-based Hess Corp. and China’s state-backed Cnooc Ltd., handing them 30% and 25% stakes, respectively, in exchange for sharing drilling costs.

When Exxon began drilling the wildcat well Liza-1 in March 2015, Guyana was just a couple months away from a general election. On May 20, four days after Granger emerged as the surprise winner, Exxon announced it had struck oil.

The timeline would later prove controversial and become a focus of the SARA investigation. But one thing was clear: Oil was coming.

When Liza-1 struck oil, Lars Mangal, one of Guyana’s foremost petroleum professionals, knew exactly what to do. He’d spent two decades working in oilfield services around the world for Houston-based Schlumberger Ltd. before ending up in the U.K. Now he needed to pack up his belongings, get back to Georgetown, lease a dockyard, and bid for the Exxon services contract. “This is the big one,” Mangal, who turns 54 in August, recalls thinking.

He was right. His company is now one of the lead local investors in Guyana Shore Base Inc., which acts as Exxon’s main service hub in Georgetown. He has no doubt that Guyana needs to embrace Exxon’s plans for Stabroek oil. “Damn it,” he says. “Get it out of the ground.”

Somebody has written a message on a whiteboard at Guyana Shore Base that reflects Mangal’s attitude. It reads, “Don’t obsess over who’s baking the cake. Figure out how to get a slice.”

Lars’s younger brother, Jan, would almost certainly take issue with that. Jan Mangal, who also has a long track record in the oil industry, has become a leading critic of exploration deals that Exxon and other companies cut with the government.

Jan, 49, worked at Chevron Corp. for 13 years after earning a doctorate in engineering at the University of Oxford. He became Granger’s energy adviser in 2017. From the start, he clashed with ministers who unsuccessfully resisted his call to have all of the country’s oil contracts published and open to public scrutiny. He didn’t last long in the role, leaving after a year when his contract wasn’t renewed. He’s now a consultant.

“Corruption is the main reason why countries like Guyana fail with oil and gas,” Jan says. “It undermines everything.” He says that Guyana didn’t get a fair deal from Exxon—he calls it a dated, “colonial contract”—and that other leases have been awarded without due process, potentially costing the country billions of dollars in lost revenue and exposing vulnerable Guyana to the so-called resource curse.

Exxon’s manager in Guyana, Rod Henson, disagrees. He says the contract reflects the high risk of drilling the first well. In any case, he says, “the revenues that are going to be generated from that give Guyana the flexibility and the opportunity to be anything they want to be.”

The months before Exxon struck oil in 2015 were an unsettled time in Guyana. Then-President Donald Ramotar had clashed with Parliament over government spending. Fearing a no-confidence vote and the end of his party’s 23-year rule, he dissolved the legislative body and called a general election for May.

At the same time, unbeknownst to the wider world, Exxon was getting ready to drill Liza-1. Other companies, smelling oil, were circling Guyana’s waters.

On March 4, Ramotar signed an exploration lease for the 6,100-square-kilometer Canje block with Mid-Atlantic Oil & Gas, a little-known company run by Guyanese businessman Edris Dookie. The next day, Exxon, whose Stabroek block abuts Canje, began drilling.

On April 28, Ramotar signed over another exploration lease, this time with the partnership of Tel Aviv-based Ratio Petroleum Energy Ltd. and Toronto-based Cataleya Energy Ltd. It covered the 13,535-square-kilometer Kaieteur block, also adjacent to Stabroek.

On May 7, then-Minister of Natural Resources Robert Persaud announced that Exxon had struck oil. The general election was four days later, and on May 16, Granger, leader of the then-opposition, was sworn in as president. Four days after that, Exxon confirmed the discovery to the stock market.

The award of oil leases in developing countries is one of the most secretive, competitive, and contested corners of the industry. Before oil is discovered, governments typically offer royalty rates and tax incentives that are favorable to exploration companies. As soon as a discovery is made, unsold leases nearby become extremely valuable overnight, allowing governments to set higher rates for them. This binary before-and-after phenomenon opens the door to abuse by people acting on inside information.

As Bloomberg News first reported in May, SARA is now probing the deals Guyana cut with oil companies over the years. “We’re investigating the issuance of the licenses, for example, and the various blocks,” says SARA chief Thomas. He stresses that the postmortem is in the very early stages, so he can’t disclose much except to say the investigation is focused on the runup to the 2015 election.

“There are so many red flags,” Jan Mangal says, looking back at that period. He says the government could have commanded much more favorable tax and royalty rates if the Canje and Kaieteur leases had been sold after Exxon’s Stabroek discovery was announced and not before. “The country could have got 10 or 100 times what it got for these massive, massive blocks,” he says.

Ramotar says he didn’t know about the Exxon find when the Canje and Kaieteur deals were signed, adding, however, “I was told that the indications were good.” He says that the SARA investigation is “politically motivated” and that contracts signed under the current government should be looked at as well. He says he welcomes “any impartial international inquiry.”

Persaud, the natural resources minister at the time, says focusing on the election timeline suggests “a wrong narrative.” He says the Canje and Kaieteur leases had been all but signed, sealed, and delivered in 2013. But then the Venezuelan navy boarded the Anadarko-contracted exploration vessel, spooking Guyanese authorities. Not wanting to provoke Venezuela further, Persaud says, the government put the contracts on hold.

The Canje lease, which was published on government websites, could be interpreted as backing this version of events: “2013” has been crossed out and replaced with a handwritten “2015.”

Representatives from Mid-Atlantic, Cataleya, and Ratio Petroleum concur with Persaud’s timeline. “We were working away steadily in good faith for many, many years,” Cataleya Chief Executive Officer Michael Cawood says. “This wasn’t something that popped up all of a sudden.”

About a year after the leases were signed, Exxon took a 50% stake in Kaieteur and a 35% stake in Canje and became the operator of both blocks. Cawood says his group took “no cash consideration” from Exxon for the stake in Kaieteur. Dookie says there were “terms” agreed to with Exxon for its Canje stake but declined to say what there were. Exxon wasn’t the recipient of the Canje and Kaieteur blocks initially and had nothing to do with the talks at the time. Exxon declined to comment on terms. All the companies involved say they have acted entirely properly.

In 2016, Exxon had a problem. Its deal with Guyana was 17 years old, and under the complex terms of the agreement, the supermajor was running out of time to find more oil. This was an opportunity for Guyana’s new government, now led by Granger, to update the 1999 contract and extract better terms. Such negotiations are a fine balancing act for governments: Push too little, and you get too little; push too hard, and the company might walk away.

Natural Resources Minister Trotman took a different route: no negotiation at all. He says Guyana was worried, once again, about Venezuela, fearing Exxon’s discovery would rile its prickly neighbor; neither Exxon nor the government wanted to get into a protracted negotiation.

Instead, in October 2016, the government and Exxon modified the terms of the existing 1999 deal.

This was a missed opportunity of epic proportions, says the PPP’s Jagdeo, the opposition leader and former president. “They had 3 billion barrels of proven reserves,” he says. “One would have thought you would have gotten a better contract.”

Trotman counters that the government’s overriding concern in the Exxon talks was finding “security in what it had.” That included getting an $18 million signing bonus that, Trotman says, “we believed we should use for … the prosecution of our case” against Venezuela to settle territorial claims.

There was one hitch—a big one. The bonus was kept secret from the public for what Trotman describes as “national security” reasons. The 2016 contract that modified the terms of the original wouldn’t be made public until 2017 (following the intercession of Jan Mangal), but in the small world of Guyana, it wasn’t long before word leaked out and caused an uproar. “If this is what they do with $18 million, what will they do with all the billions to come?” says Charles Ramson, 35, a PPP politician.

Bynoe, the current energy director, says it was a mistake not to be more open about the $18 million. In retrospect, Trotman agrees. “We should have confided in the people much earlier,” he says. In addition to the signing bonus, according to Exxon’s Henson, the government got more “rental type payments,” royalties, and commitments of local content as part of the deal. But, crucially, the modified terms also allowed Exxon more time to explore and develop Liza. Henson says that without the 2016 modifications he’s “absolutely certain we would not be producing oil in 2020.”

The controversy surrounding the 2016 contract doesn’t end there. According to an analysis of the agreement by Rystad Energy AS, an Oslo-based consultancy, Guyana will take about 60% of the oil’s profits, with the remainder going to Exxon, Hess, and Cnooc.

That’s considerably lower than the global average of 75% for offshore projects, Rystad said in a 2018 report. However, it also pointed out that countries in the early stages of oil and gas development, such as Mozambique and Mauritania, are often forced to “sweeten the pot” for the exploration companies. “Clearly we have to make a profit,” Henson says. “We understand there are benefits to us and our partners, but we truly want this to benefit the country.”

Bynoe takes a Goldilocks view of the whole affair. “Is it the greatest contract for government? I would say no,” he says. “Is it the worst contract? I would still say no.” Over time, he says, Guyana can “incrementally improve the conditions.”

With that in mind, he says, it’s time to look forward. “We have been looking back about the contract,” he says. “There’s been too little attention in how will we treat these resources when they begin to flow to us.”

At Exxon’s Investor Day meeting at the New York Stock Exchange in March, Guyana took center stage. It’s not hard to see why. Senior Vice President Neil Chapman—the exec who’d once described the Stabroek find as a “fairy tale”—pointed to a chart featuring estimates from Wood Mackenzie Ltd., an Edinburgh-based energy consulting firm. It showed that Exxon’s Guyana wells will be the most profitable of all new deep-water projects by major oil companies.

Exxon expects the first Stabroek oil to flow to the Liza Destiny, a storage and offloading vessel, in early 2020, with production quickly ramping up to 120,000 barrels a day and rising by 2025 to 750,000 a day (roughly on a par with last year’s daily output in Indonesia, which has a population of 264 million).
As for Guyana, the government estimates the Exxon deal will bring in $300 million in 2020, or about a third of the country’s entire tax revenue, and surge to $5 billion by 2025.

“They say Guyana will be one of the richest countries in the world,” says Melissa Garrett, a waitress who supplements her income by selling potatoes, eggplant, and plantains at a stall at Georgetown’s century-old Bourda market. “People are in the mood for change. They want it now.”

They also need to come to terms with the massive transformation coming their way, says Singh, the investment banker lingering over his mojito at the roadside bar. “Sitting back and doing nothing can be the worst mistake they can make,” he says.

Georgetown—its crumbling colonial buildings set amid canals built by the Dutch in the 18th century—resembles a developing-world Amsterdam that’s faded in the harsh sunlight. On its bustling narrow streets, Guyanese descendants of Indian indentured laborers and African slaves live and work side by side, shop at the same markets, and dream the same dreams of wonders coming their way thanks to oil.

Guyana’s political elite is torn over how to spend the money. The Granger government has said it wants to use the windfall to reshape the economy, pumping money into health and education, into the country’s vast natural resources, and into rail, road, and port projects that could provide an important pathway to the Atlantic for northern Brazil. Thomas, the head of SARA, favors bypassing government altogether in favor of a universal basic income-like stipend of $5,000 per family.

First things first, says Jan Mangal. “Guyana really needs to fix all of its existing problems now before the oil money flows,” he says. “If it doesn’t, the oil money will exacerbate the existing problems and make them worse.”

Chris Ram, a lawyer and former newspaper columnist (he broke the news about the $18 million signing bonus), worries that, rather than taking a leap forward propelled by oil, Guyana could slip backward. In the 1980s, under left-wing strongman Forbes Burnham, Guyana shared many traits with today’s Venezuela. Although democracy took root in the 1990s, Ram fears for its fragility.

“We don’t have a culture of democracy,” he says over a meal in one of Georgetown’s many Indian curry houses. “The constitution is weak and open to abuse. Problems are swept under the carpet. It’s frightening. All the elements of a resource curse are there.”
Crowley covers oil for Bloomberg in Houston.

Monday, August 12, 2019

ExxonMobil Earns $3.1 Billion in Q2 2019

Image result for exxon mobil

Exxon Mobil Corporation has estimated second quarter 2019 earnings of $3.1 billion, compared with $4 billion a year earlier.

Earnings included a favourable identified item of about $500 million, reflecting the impact of a tax rate change in Alberta, Canada. Capital and exploration expenditures were $8.1 billion, up 22 percent from the prior year, reflecting key investments in the Permian Basin.
 
“We continue to make significant progress toward delivering our long-term growth plans,” said Darren W. Woods, ExxonMobil chairman and chief executive officer. “Our new U.S. Gulf Coast steam cracker is exceeding design capacity by 10 percent, less than a year after startup. Our upstream liquids production increased by 8 percent from last year, driven by growth in the Permian Basin, and we are preparing to startup the Liza Phase 1 development in Guyana, where the estimated recoverable resource increased to more than 6 billion oil-equivalent barrels.
 
Downstream
Industry fuels margins, while remaining under pressure during the second quarter, improved from very low levels in the first quarter on stronger gasoline margins, mainly in the U.S.

Planned maintenance activity remained at a high level during the quarter, as the company successfully completed a significant turnaround at its Joliet, Illinois, refinery in the U.S. mid-continent region. Results were also impacted by unscheduled downtime at refineries in Baytown, Texas; Sarnia (Canada); and Yanbu (Saudi Arabia).

Strengthening the Portfolio

Mozambique Rovuma Venture S.p.A., an incorporated joint venture owned by ExxonMobil, Eni S.p.A. and China National Petroleum Corporation, announced that the government of Mozambique approved its development plan for the Rovuma LNG project. The project includes two liquefied natural gas trains with a combined annual capacity of more than 15 million metric tonnes. A final investment decision is expected later in 2019.

Investing for Growth

ExxonMobil and SABIC announced the decision to proceed with the Gulf Coast Growth Ventures project to construct a new chemical facility in San Patricio County, Texas. The new facility will include an ethane steam cracker with a capacity of 1.8 million metric tonnes per year, two polyethylene units and a monoethylene glycol unit.

The company also made a final investment decision on a multi-billion dollar expansion of its integrated manufacturing complex in Singapore to convert fuel oil and other bottom-of-the-barrel crude products into higher-value lube basestocks and distillates. The expansion will add 20,000 barrels per day of ExxonMobil Group II basestocks capacity and increase production of lower-sulphur fuels by 48,000 barrels per day.

ExxonMobil announced that it will proceed with a $2 billion expansion project at its Baytown, Texas, chemical plant. The expansion will add annual production of about 400,000 metric tonnes of Vistamaxx performance polymers, and about 350,000 metric tonnes of linear alpha olefins.

The company reached a final investment decision to upgrade its Fawley refinery in the United Kingdom to increase production of ultra-low sulphur diesel by almost 45 percent, or 38,000 barrels per day, along with logistics improvements. The more than $1 billion investment includes a hydrotreater unit to remove sulphur from fuel, supported by a hydrogen plant which will improve the refinery’s overall energy efficiency.

Wednesday, August 7, 2019

OPEC Oil Production Drops To Eight-Year Low

OPEC logo


Deeper production cuts at leading producer Saudi Arabia, lower output at sanctions-hit Iran, and outages in Libya and Venezuela sent OPEC’s crude oil production in July falling to its lowest level since 2011, the monthly Reuters survey found.   

In July, OPEC’s fourteen members pumped a combined 29.42 million bpd, a decline of 280,000 bpd compared to June, according to the Reuters survey that tracks supply to the market from shipping data and sources at OPEC, oil companies, and consulting firms.
While Saudi Arabia continued to cut even deeper than it had done earlier this year in its efforts to ‘do whatever it takes’ to reduce oversupply and bolster oil prices, the three OPEC members exempt from the OPEC+ pact—Iran, Venezuela, and Libya—all saw lower production in July compared to June, the Reuters survey found.

The Saudis pumped 9.65 million bpd in July, after OPEC and its allies extended the production cuts into 2020 at the beginning of the month.

That’s a deeper cut compared to the 9.813 million bpd Saudi production in June that OPEC reported in its official figures. In June, the Saudis had lifted production from May by 126,000 bpd, but they were still producing less than their 10.311-million-bpd quota under the pact.

The Reuters survey for July suggests that the Saudis are trying hard to tighten the market by deepening the cuts.
Elsewhere in the group, the three members exempted from the pact—Iran, Venezuela, and Libya—involuntarily reduced their respective production in July. Iran’s output further dropped due to the U.S. sanctions, Libya briefly shut down its largest oil field Sharara, while another blackout in Venezuela impacted oil production which has been steadily declining amid the economic and political crisis.

OPEC will release its official crude oil production data for July in the Monthly Oil Market Report (MOMR) on Tuesday, August 13.  

By Tsvetana Paraskova for Oilprice.com

Monday, August 5, 2019

Oil prices could crash by $30 if China buys Iranian crude: BofA

AP: Iran oil tanker in China 
Tugboats dock the oil tanker “Daniel” carrying crude oil imported from Iran at the Port of Zhoushan in Zhoushan city, east China’s Zhejiang province, 8 March 2018. 
Imaginechina | AP Images

https://www.cnbc.com/2019/08/05/brent-and-wti-price-could-crash-if-china-buys-iranian-oil.html
  • Bank of America Merrill Lynch warns the oil price could slip sharply if China buys Iranian oil.
  • Beijing could undermine Washington’s foreign policy stance by ignoring U.S. sanctions placed on Iran.
  • BofA is keeping its $60 per barrel price estimate in place for 2020.
Crude oil prices could sink by as much as $30 a barrel if China decides to buy Iranian crude oil in retaliation to the latest U.S. tariff measures, according to Bank of America Merrill Lynch.

“While we retain our $60 a barrel Brent forecast for next year, we admit that a Chinese decision to reinitiate Iran crude purchases could send oil prices into a tailspin,” a BofA Merrill Lynch Global Research report said Friday, warning that prices could sink by as much as $20-30 a barrel in that scenario.

The Chinese Ministry of Commerce has threatened countermeasures after President Donald Trump threatened to slap a 10% tariff on $300 billion dollars of Chinese goods. The decision Thursday floored oil markets and sent crude plunging 8% — the most in four years.

Analysts warn that “oil volatility is set to rise again” as markets wait for a Chinese response to the latest US tariff threat, which could include purchasing Iranian oil.

“This decision would both undermine US foreign policy and cushion the negative terms-of-trade effects on the Chinese economy of rising US tariffs,” the report added.

Iranian oil exports slide

Shipments of Iranian oil fell below 550,000 b/d (barrels per day) in June from about 875,000 b/d in May and about 2.5 million b/d in June 2018, according to data from S&P Global Platts. Roughly half of Iran’s exports were shipped to China in June and July, according to the firm.

But a Chinese decision to purchase Iranian oil in a further defiance of U.S. sanctions could act as a double edged sword, according to other analysts.

“Iran would welcome any opportunity to increase its production whether or not it breaches the terms of the U.S. sanctions, but the strategy there would introduce China to a partner over which it doesn’t have an enormous amount of control,” Edward Bell, Director of Commodities Research at Emirates NBD told CNBC’s “Capital Connection.”

“Don’t forget there are other producers that would also be targeting that trade with China, so for instance you could see Iraq or Saudi Arabia step in and try and discount the volumes that they would be exporting to China as a way to circumvent Iran getting that extra market share,” he added.

Traders fret on crude demand

Crude oil prices slumped further on Monday, as traders focused on a deteriorating demand outlook.

Analysts at BofA Merrill Lynch said the latest round of US tariffs could reduce global oil demand by 250,000-500,000 barrels per day, adding to worries about a demand slowdown that is challenging the fundamentals for crude.

“The kind of deterioration in global trade volumes that we’ve seen this year does mathematically lead into lower demand for crude oil,” Bell added.

“If that carries on through the end of 2019 or perhaps even 2020 as we enter the firm end of the US election cycle when Trump is likely to want to maintain that hard stance on China, then it could be a very difficult barrier for crude to try and break through some of those demand concerns.”

Brent crude was trading at $60.94 early Monday, down around 1.5%, while WTI traded at $54.81, again slipping around 1.5% for the session.