Friday, March 22, 2019

Replacing Iranian barrels

OPEC crude production fell by 240,000 barrels per day in February to 30.68 mill barrels, the lowest level in four years.
February numbers show a significant cut over compliance, with Saudi Arabia leading the way with a 153% compliance rate, already some 170,000 barrels per day below the overall target. Iraq and Saudi Arabia contributed 170,000 barrels in additional cuts between them in February alone, Gibson Shipbrokers said in a report.

However, having already cut production close to their original 2019 target, they may now be missing the opportunity to capture market share in the face of rising demand.

The impact of sanctions on crude supply may soon increase. Although Iran is exempt from OPEC’s cuts, in seven weeks waivers for Iranian crude are set to expire.

Some of Iran’s biggest customers - China, India, Japan and South Korea - are all partially exempt from the current US oil sanctions on Iran, however this may soon change.

Last week, IEA data showed Iranian crude production had fallen to 2.85 mill barrels per day in February, its lowest level since the first quarter of 2015, when Iran was under previous sanctions.

In 2018, Iran exports averaged almost 2.5 mill barrels per day, with over 1 mill  going to China and India. The US Administration has not yet revealed whether any of these waivers will be extended, leaving those countries potentially having to replace over 1 mill barrels per day from elsewhere.

However, this may not be as easy as it sounds. Obvious sources, such as Venezuela and Iraq, are already under sanctions or participating in OPEC cuts. This may now leave OPEC wondering whether deeper cuts are appropriate considering many refineries in the region are optimised for heavier crudes.

The tightness in the heavy crude market is also exacerbated by greater US appetite to replace Venezuelan barrels with heavy grades already in short supply. Incremental supplies from Canada are also limited, owing to government enforced production cuts.

Recent reports from Reuters said that the US aims to cut Iran’s exports by a further 20% to below 1 mill barrels per day, saying that they were unwilling to cut anymore over price hike fears, backtracking on previous statements to cut their exports to as close to zero as possible.

However, analysts have indicated that India could be willing to cut all Venezuelan crude imports to satisfy US sanctions in return for further waivers on importing Iranian crude.

This would potentially starve Venezuela of its last major‘cash’ buyer although simultaneously, it would cause a headache for some Indian refiners that prefer Venezuelan grades. However, the situation in Venezuela looks like it will get worse before it gets better.

The heavy crude market is already incredibly tight and production cuts come at a time when demand for heavy grades is rising.This is significant, as greater demand for heavy grade crudes will have to be sourced from elsewhere, especially when we start to exit the Asia/Pacific maintenance season and new refineries come online.

With production cuts coming from the main heavy grade producing regions, refiners may have to look West to replace their missing barrels thus supporting tonne/mile demand from West to the East.
With US production posting strong growth this year, OPEC cuts are to be largely offset, perhaps justifying the organisation’s current stance even if there’s a mismatch of grades.

Meanwhile, Reuters has reported that the Maritime Authority of Panama (AMP) has removed 59 Iranian-linked ships from its registry, quoting ShareAmerica, the US State Department-run platform.

The move came after Juan Carlos Varela, Panamanian President, issued a presidential decree last month, allowing the AMP to de-register the vessels.

Out of these, at least 21 Iranian-owned tankers have had their registration revoked, Reuters reported.

In 2016, Iran and Panama agreed to add Iranian tankers to the Panamanian flag, which has now been dissolved due to the sanctions.

Thursday, March 21, 2019

Reliance sends fuel from India, Europe to Venezuela to sidestep U.S. sanctions

mukesh ambani
Mukesh Dhirubhai Ambani

NEW DELHI/MEXICO CITY (Reuters) - India's Reliance Industries is selling fuels to Venezuela from India and Europe to sidestep sanctions that bar U.S.-based companies from dealing with state-run PDVSA, according to trading sources and Refinitiv Eikon data.

Reliance had been supplying alkylate, diluent naphtha and other fuel to Venezuela through its U.S.-based subsidiary before Washington in late January imposed sanctions aimed at curbing the OPEC member's oil exports and ousting Socialist President Nicolas Maduro.

At least three vessels chartered by the Indian conglomerate supplied refined products to Venezuela in recent weeks, and another vessel carrying gasoil is expected to set sail to the South American nation as well, according to the sources and data.

A Reliance spokesman wrote to Reuters in an email and said: "Reliance is and will remain in compliance with the sanctions and shall work with the concerned authorities."

He also said "the volume of products supplied to and crude oil imported from Venezuela have not increased."

Reliance, an Indian conglomerate controlled by billionaire Mukesh Ambani, has significant exposure to the financial system of the United States, where it operates subsidiaries linked to its oil and telecom businesses, among others.

The Indian market is crucial for Venezuela's economy because it has historically been the second-largest cash-paying customer for the OPEC country's crude, behind the United States.

Additional sanctions against Venezuela are possible in the future, as U.S. President Donald Trump's administration has not yet tried to prevent companies based outside the United States from buying Venezuelan oil, a strategy known as "secondary sanctions."

Refinitiv Eikon trade data shows that Reliance shipped alkylate, a component for motor gasoline, to Venezuela on vessels Torm Mary and Torm Anabel in recent weeks. Those originated in India and passed through the Suez Canal.

It also shipped a gasoline cargo using tanker Torm Troilus to Venezuela and is preparing to send 35,000 tonnes of gasoil in a vessel called Vukovar to the South American nation.

"Reliance is also supplying some products from its Rotterdam storage," a source familiar with Reliance's operation said.

PDVSA did not reply to a request for comment.

In a statement last week, Reliance said its U.S. unit has completely stopped all business with PDVSA. Reliance also halted all supply of diluents including heavy naphtha to Venezuela and does not plan to resume such sales until sanctions are lifted, according to the release.

Venezuela has overall imported some 160,000 barrels per day of fuel and diluents for its extra heavy oil output since the U.S. measures were imposed, according to PDVSA and Refinitiv data, below levels prior to the sanctions but still enough to supply gas stations and power plants.

Reliance is among the biggest buyers of Venezuelan oil, although the company has recently said it has not increased crude purchases from Venezuela. In 2012, Reliance signed a 15-year deal to buy between 300,000 to 400,000 bpd of heavy crude from PDVSA.

Ship tracking data obtained by Reuters showed that Reliance's average purchases from Venezuela were less than 300,000 bpd in 2018 and in the first two months of this year.

Venezuela continues to supply at least some oil to India. A very large crude carrier (VLCC) is anchored off Venezuela's Jose port waiting to load oil bound for India, and at least six other vessels of the same size are underway to India's Sikka and Vadinar ports, according to the Refinitiv data.

PDVSA's second-largest customer in India is Nayara Energy, partially owned by Russian energy firm Rosneft, one of PDVSA's primary allies.

By Nidhi Verma and Marianna Parraga

(Reporting by Nidhi Verma in NEW DELHI and Marianna Parraga in MEXICO CITY; Editing by Henning Gloystein and Tom Hogue)

Wednesday, March 20, 2019

Citigroup Settles Venezuela Gold Swap Transaction

Citigroup Settles Venezuela Gold Swap Transaction

(Bloomberg) -- Citigroup Inc. has settled a Venezuela gold swap transaction and plans to sell the metal it received as collateral while also depositing about $260 million into a U.S. account formerly controlled by President Nicolas Maduro’s central bank, according to four people with direct knowledge of the matter.

After Venezuela’s Central Bank missed a March 11 deadline to buy back gold from Citigroup for nearly $1.1 billion as part of a financing agreement signed in 2015, the difference in price from when the gold was acquired to current levels will be deposited into an account, said the people, who asked not to be named speaking about a private transaction.

The development represents another financial blow to the embattled Maduro regime. It won’t be able to access the cash deposited in the U.S. account and could ultimately see the money be handed over to the parallel government being formed opposition leader Juan Guaido.

While Maduro has managed to maintain a stranglehold on power on the ground -- he still controls the military, the courts and government bureaucracy -- Guaido is leveraging the support he has from dozens of countries to slowly seize Venezuela’s financial assets abroad. Guaido, who’s seeking to topple the autocratic Maduro, has wrested control of Houston-based refiner Citgo Petroleum Corp from Petroleos de Venezuela SA and is also taking over diplomatic real estate. More importantly, he has gained access to cash, which he’s vowing to use to relieve a humanitarian crisis at home.

While no details about the U.S. accounts have been given, Venezuela’s opposition-controlled National Assembly said it identified $3.2 billion of funds being held at 20 bank accounts in the U.S. belonging to Maduro’s government. Earlier this year, the Bank of England refused to give back $1.2 billion worth of gold.

In response to Citigroup’s settlement, the central bank is weighing options including a declaration of force majeure -- a legal status commonly used in the commodities industry protecting it from liability if it can’t fulfill a contract for reasons beyond its control -- arguing U.S. sanctions prevented it from raising the cash it needed to pay for the gold. Another swap comes due next year, one of the people said.

Citigroup spokesman Daniel Diaz declined to comment. A press official for Venezuela’s central bank didn’t respond to requests for comment.

Maduro blew through more than 40 percent of Venezuela’s gold reserves last year, selling to firms in the United Arab Emirates and Turkey in a desperate bid to fund government programs and pay creditors. Pressure from Guaido and the U.S. derailed his administration’s plans to ship more gold to buyers in the UAE last month.

The U.S. sanctioned the state-run gold producer, Minerven, on Tuesday and described the precious metal trading as being essential to Maduro’s ability to keep loyalty from the military. Venezuela’s central bank has $8.7 billion of international reserves remaining, much of which is held in physical gold.

Citigroup, which has been in Venezuela since 1917, serves top multinational companies and affluent clients, according to its website.

--With assistance from Fabiola Zerpa.

To contact the reporters on this story: Patricia Laya in Caracas at;Jenny Surane in New York at

To contact the editors responsible for this story: Daniel Cancel at;David Papadopoulos at

Oil majors rush to dominate U.S. shale as independents scale back

EDDY COUNTY, NEW MEXICO (Reuters) - In New Mexico’s Chihuahuan Desert, Exxon Mobil Corp is building a massive shale oil project that its executives boast will allow it to ride out the industry’s notorious boom-and-bust cycles.

Workers at its Remuda lease near Carlsbad - part of a staff of 5,000 spread across New Mexico and Texas - are drilling wells, operating fleets of hydraulic pumps and digging trenches for pipelines. 

The sprawling site reflects the massive commitment to the Permian Basin by oil majors, who have spent an estimated $10 billion buying acreage in the top U.S. shale field since the beginning of 2017, according to research firm Drillinginfo Inc. 

The rising investment also reflects a recognition that Exxon, Chevron, Royal Dutch Shell and BP Plc largely missed out on the first phase of the Permian shale bonanza while more nimble independent producers, who pioneered shale drilling technology, leased Permian acreage on the cheap. 

Now that the field has made the U.S. the world’s top oil producer, Exxon and other majors are moving aggressively to dominate the Permian and use the oil to feed their sprawling pipeline, trading, logistics, refining and chemicals businesses. The majors have 75 drilling rigs here this month, up from 31 in 2017, according to Drillinginfo. Exxon operates 48 of those rigs and plans to add seven more this year. 

The majors’ expansion comes as smaller independent producers, who profit only from selling the oil, are slowing exploration and cutting staff and budgets amid investor pressure to control spending and boost returns. 

Exxon Chief Executive Darren Woods said on March 6 that Exxon would change “the way that game is played” in shale. Its size and businesses could allow Exxon to earn double-digit percentage returns in the Permian even if oil prices - now above $58 per barrel - crashed to below $35, added Senior Vice President Neil Chapman. 

Exxon’s 1.6 million acres in the Permian means it can approach the field as a “megaproject,” said Staale Gjervik, the head of shale subsidiary XTO Resources, whose headquarters was recently relocated to share space with its logistics and refining businesses. The firm also recently outlined plans to nearly double the capacity of a Gulf Coast refinery to process shale oil.
“It sets us up to take a longer-term view,” Gjervik said.

The majors’ Permian investments position the field to compete with Saudi Arabia as the world’s top oil-producing region and solidifies the United States as a powerhouse in global oil markets, said Daniel Yergin, an oil historian and vice chairman of consultancy IHS Markit. 

“A decade ago, capital investment was leaving the U.S.,” he said. “Now it’s coming home in a very big way.” 

The Permian is expected to generate 5.4 million barrels per day (bpd) by 2023 - more than any single member of the Organization of the Petroleum Exporting Countries (OPEC) other than Saudi Arabia, according to IHS Markit. Production this month, at about 4 million bpd, will about double that of two years ago. 

Exxon, Chevron, Shell and BP now hold about 4.5 million acres in the Permian Basin, according to Drillinginfo. Chevron and Exxon are poised to become the biggest producers in the field, leapfrogging independent producers such as Pioneer Natural Resources. 

Pioneer recently dropped a pledge to hit 1 million bpd by 2026 amid pressure from investors to boost returns. It shifted its emphasis to generating cash flow and replaced its chief executive after posting fourth quarter profit that missed Wall Street earnings targets by 36 cents a share. 

Shell, meanwhile, is considering a multi-billion dollar deal to purchase independent producer Endeavor Energy Resources, according to people familiar with the talks. Shell declined to comment and Endeavor did not respond to a request. 

Chevron said it would produce 900,000 bpd by 2023, while Exxon forecast pumping 1 million barrels per day by about 2024. That would give the two companies one-third of Permian production within five years.


At first, the rise of the Permian was driven largely by nimble explorers that pioneered new technology for hydraulic fracturing, or fracking, and horizontal drilling to unlock oil from shale rock, slashing production costs.

The advances by smaller companies initially left the majors behind. Now, those technologies are easily copied and widely available from service firms. 

Surging Permian production has overwhelmed pipelines and forced producers to sell crude at a deep discount, sapping cash and profits of independents who, unlike the majors, don’t own their own pipeline networks. 

Even as the majors have ramped up operations, the total number of drilling rigs at work in the Permian has dropped to 464, from 493 in November, as independent producers have slowed production, according to oilfield services provider Baker Hughes. 

Shell, by contrast, plans to keep expanding even if prices fall further, said Amir Gerges, Shell’s Permian general manager. 

“We have a bit more resilience” than the independents, Gerges said. 

In west Texas, the firm drills four to six wells at a time next to one another, a process called cube development that targets multiple layers of shale as deep as 8,000 feet. 

Cube development is expensive and can take months, making it an option only for the majors and the largest independent producers. Shell has used the tactic to double production in two years, to 145,000 bpd.
The largest oil firms can also take advantage of their volume-buying power even if service companies raise prices for supplies or drilling and fracking crews, said Andrew Dittmar, a Drillinginfo analyst.
“It’s like buying at Costco versus a neighborhood market,” Dittmar said. 

The majors’ rush into the market means smaller companies are going to struggle to compete for service contracts and pay higher prices, said Roy Martin, analyst with energy consultancy Wood Mackenzie.

“When you’re sitting across the negotiating table from the majors, the chips are stacked on their side,” he said.


The revival of interest in the Permian marks a reversal from the late 1990s, when production had been falling for two decades. 

“All the majors and all the companies with names you’ve heard left with their employees,” said Karr Ingham, an oil and gas economist. “Conventional wisdom was this place was going to dry up.” 

Chevron was the only major that stayed in the Permian. It holds 2.3 million acres and owns most of its mineral rights, too, but until recently left drilling to others. 

But this month, Chief Executive Mike Wirth called the Permian its best bet for delivering profits “north of 30 percent at low oil prices.” 

“There’s nothing we can invest in that delivers higher rates of return,” Wirth said this month at its annual investor meeting in New York.


Matt Gallagher, CEO of Parsley Energy Inc, calls the majors’ investments “the best form of flattery” for independents operating here. 

Parsley holds 192,000 Permian acres - most of which was snatched up on the cheap during oil busts - and sees its smaller size as an advantage in shale.

“We’re not finished yet,” Gallagher said. “We can move very quickly.”
The majors have greater infrastructure, but independents continue to innovate and design better wells, said Allen Gilmer, a co-founder of Drillinginfo. 

“Nothing is a bigger motivator than, ‘Am I going to be alive tomorrow?’” Gilmer said. “Hunger and fear is something that every independent oil-and-gas person knows - and that something no major oil-and-gas person has ever felt in their career.”

Tuesday, March 19, 2019

Venezuela may divert U.S.-bound oil to Rosneft, says Jose generator working

Venezuela may divert oil originally bound for the United States to Russian oil company Rosneft or other destinations due to U.S. sanctions, Venezuelan oil minister and president of state-run oil company PDVSA Manuel Quevedo said on Monday. 

Speaking at a gathering of OPEC and other oil ministers in Baku, Azerbaijan, Quevedo added that the generator at Venezuela’s primary Jose oil terminal was now working after a blackout that halted crude exports last week. 

Quevedo said Caracas would decide where to ship its own oil and that its main goal was to strengthen ties with Russia, pledging to abide by oil supply contracts with Moscow. 

Rosneft, a state-owned company which has oil joint ventures with PDVSA in Venezuela, buys crude from PDVSA within the framework of oil-for-loan contracts and redirects the barrels to customers around the world, with Indian refineries key buyers. 

Asked about a Reuters report saying Rosneft believed it was owed hundreds of billions of dollars from the joint ventures because oil output was far lower than projected, Quevedo said Venezuela was “up to date” on its debts to Russia. 

“The contracts are being fulfilled,” he said. “We can send the oil which has been allocated for the United States to Russia or other clients.”

Earlier this year, the United States imposed heavy sanctions on Venezuela’s oil industry, looking to cut off President Nicolas Maduro’s primary source of revenue as part of efforts to oust the socialist leader from power. That cut off Venezuela’s largest export market of around 400,000 barrels per day, Quevedo said. 

Venezuela has responded by trying to boost crude exports to India, another top importer. But the U.S. government has pressed India to stop buying Venezuelan oil. 

“Now they have started persecuting our long-term commercial partners, they are threatening them,” Quevedo told reporters. 

Much of Venezuela, including parts of the capital Caracas, was left without power for several days, leaving people struggling to obtain water and food. That affected the Jose terminal, whose generator was not working at the time.

“At the moment, (Jose) is fully functioning,” Quevedo said via an interpreter. 

“It has suffered a lot from the blackout ... the oil industry of Venezuela suffered significantly,” he added.

Monday, March 18, 2019

Shell, HES to Start Low-Sulphur Bunker Fuel Project

HES Wilhemshaven

Shell and bulk-handling company HES International are planning to restart an oil refinery in Germany to produce low-sulphur bunker fuel ahead of new regulations going into force next year, Kallanish Energy learns.

The International Maritime Organization (IMO) approved the ban on high sulphur fuel oil (Hsfo) for vessels beginning in 2020. The International Energy Agency (IEA) expects a shake-up in the industry, as demand for Hsfo will fall from 3.5 million barrels per day (Mmbpd), to 1.4 Mmbpd.

HES is reinstalling the vacuum distillation unit (VDU) at Wilhelmshaven Tank Terminal, in order to produce low-sulphur bunker fuels to distribute as an alternative to Hsfo. Reuters reported they reached an agreement with Shell, under which the oil company provides the feedstock and receives the final product.

The terminal is located on Germany’s North Sea coast and is the largest independent liquid bunker terminal in the country. It has a 45-million-cubic-foot capacity and it holds several products, such as crude oil or liquefied petroleum gas.

Shell and HES said via email they aren’t commenting on the project.

Venezuela to Pay ConocoPhillips $8.7bn for Unlawful Expropriation of Oil Investments

Hugo Chavez and Nicolas Maduro, pictured together in 2006

ConocoPhillips has announced that an international arbitration tribunal constituted under the auspices of the International Centre for Settlement of Investment Disputes (ICSID) has unanimously ordered the government of Venezuela to pay the company the amount of $8.7 billion in compensation for the government’s unlawful expropriation of ConocoPhillips’ investments in Venezuela in 2007, plus interest.

The ICSID tribunal ruled in 2013 that the expropriation of ConocoPhillips’ substantial investments in the Hamaca and Petrozuata heavy crude oil projects and the offshore Corocoro development project violated international law. The current ruling addresses compensation, and the timing and manner of collection remain to be determined.

We welcome the ICSID tribunal’s decision, which upholds the principle that governments cannot unlawfully expropriate private investments without paying compensation,” said Kelly Rose, Senior Vice President, Legal, General Counsel and Corporate Secretary of ConocoPhillips.

In April 2018, in a separate and independent legal action, an international arbitration tribunal constituted under the rules of the International Chamber of Commerce (ICC) awarded ConocoPhillips approximately $2 billion from PetrĂ³leos de Venezuela, S.A. (PDVSA), Venezuela’s state-owned oil company, and two of its subsidiaries. The ICC tribunal’s ruling arose out of PDVSA’s failure to uphold its contractual commitments in response to Venezuela’s unlawful expropriation of ConocoPhillips’ investments in the Hamaca and Petrozuata projects. In August 2018, ConocoPhillips announced that it entered into a settlement agreement with PDVSA to recover the full amount owed under that award.

ConocoPhillips also has a pending contractual ICC arbitration against PDVSA related to the Corocoro project.

In the early 1990s, Venezuela created a new fiscal framework to induce foreign investment in its heavy oil projects in the Orinoco Belt and elsewhere. Relying on these terms, ConocoPhillips helped Venezuela develop the Petrozuata, Hamaca and Corocoro projects by providing industry-leading technology and substantial long-term investments to the government of Venezuela. However, in the summer of 2007, the Venezuelan government expropriated ConocoPhillips’ investments in their entirety without compensation.

Friday, March 15, 2019

Another attempt to repeal the Jones Act

Photo of Sen. Mike Lee [R-UT]
US Senator Mike Lee (Republican-Utah)

US Senator Mike Lee (Republican-Utah) has introduced the ‘Open America’s Water Act of 2019’, a bill which would repeal the Jones Act if passed.
In essence, it would allow all qualified vessels to engage in domestic trade between US ports.
“Restricting trade between US ports is a huge loss for American consumers and producers. It is long past time to repeal the Jones Act entirely so that Alaskans, Hawaiians, and Puerto Ricans aren’t forced to pay higher prices for imported goods—and so they rapidly receive the help they need in the wake of natural disasters,” he said.
In 1920, Congress passed the Merchant Marine Act (more widely known as the Jones Act), which requires all goods transported by water between US ports to be carried on a vessel constructed in the US, registered in the US, owned by US citizens, and crewed primarily by US citizens.
US-based Cato Institute estimates that after accounting for the inflated costs of transportation and infrastructure, the forgone wages and output, the lost domestic and foreign business revenue, and the monetised environmental toll, the annual cost of the Jones Act is in the tens of billions of dollars. And that figure doesn’t even include the annual administration and oversight costs of the law.

Thursday, March 14, 2019

U.S. says Iran has lost $10 billion in oil revenue due to sanctions

Iran okays 29 companies for oil and gas projects

Iran has lost $10 billion in revenue since U.S. sanctions in November have removed about 1.5 million barrels per day (bpd) of Iranian crude from global markets, a U.S. State Department official said on Wednesday.

Brian Hook, the State Department’s special representative on Iran, said in remarks at the CERAWeek energy conference that due to a global oil surplus - in part due to record U.S. production - the United States is accelerating its plan of bringing Iranian crude exports to zero. 

U.S. sanctions on Iran and Venezuela, two of the largest oil producers in the Organization of the Petroleum Exporting Countries, and production cuts by OPEC and Russia have boosted global oil prices to near four-month highs.

Iran reached an agreement with world powers in 2015 over its nuclear program which led to the lifting of sanctions in 2016 but U.S. President Donald Trump pulled out of the deal in May last year and reimposed restrictions in November. 

Trump “has made it very clear that we need to have a campaign of maximum economic pressure” on Iran, Hook said, “but he also doesn’t want to shock oil markets, he wants to ensure a stable and well-supplied oil market. That policy has not changed.” 

The global oil market is looking for signs that Washington may extend sanctions waivers for Iran’s key customers in early May. The United States surprised the market in November last year by allowing eight countries to keep importing Iranian oil - in part causing Brent crude futures, the international benchmark, to fall to near $50 a barrel in late December after surpassing $86 a barrel in October.

The U.S. Energy Information Administration (EIA) has projected that world supply will exceed demand in 2019 by 440,000 bpd, Hook said. 

“When you have a better supplied oil market it enables us to accelerate our path to zero. But we also know that there are a lot of variables that go into a well-supplied and stable oil market,” said Hook, a senior policy adviser to U.S. Secretary of State Mike Pompeo. 

Washington sanctioned Venezuelan oil exports in January in an effort to oust President Nicolas Maduro and a massive power outage since last week halted crude exports from its primary port, essentially crippling the South American country’s principal industry. 

“We are aware that our diplomatic and economic pressure, the timing and the pace of that affects Venezuela’s oil industry,” Hook said.

He said the United States is monitoring global supplies for impact from sanctions. “I’ve met a few times with (Saudi Energy Minister) Khalid al-Falih over the last year when we knew we were taking a lot of oil, we wanted to ensure that we’re doing this in a responsible way,” he said. 

Falih said on Sunday that OPEC’s production-curbing agreement likely would last until at least June. OPEC and its allies agreed late in 2018 to cut output by 1.2 million bpd.

Tuesday, March 12, 2019

Citgo, Valero try to return Venezuelan oil following sanctions: document

FILE PHOTO: Crude oil tankers are docked at Isla Oil Refinery PDVSA terminal in Willemstad on the island of Curacao, February 22, 2019. REUTERS/Henry Romero

The top U.S. buyers of Venezuelan oil are in the unusual position of trying to return millions of barrels of crude they need but cannot accept because of U.S. sanctions on the South American nation and its state-run energy firm PDVSA.

The Houston-based Citgo cut ties with its parent company in compliance with U.S. measures that halted its purchases of PDVSA’s oil, the documents said. 

A U.S. Treasury spokesperson declined to comment on the requests to pay PDVSA for the cargoes. 

As of March 8, the 11 loaded vessels remained anchored off ports in Venezuela. Two other Chevron-chartered cargoes were stuck off the U.S. Gulf Coast and a third was returned to Venezuela’s Amuay terminal, according to Refinitiv Eikon vessel-tracking data. 

PDVSA does not expect Citgo or Valero to accept the cargos and intends to “commercially reallocate the volumes onboard so tankers can be freed,” a Feb. 21 trade and supply document showed. The same document expressed worry over demurrage fees - the daily cost for storing the oil on tankers - which have been accumulating for over a month.


Separately, a days-long blackout across the country has halted exports from Jose port, the nation’s primary crude export terminal. PDVSA on Monday was trying to restart operations.

The Venezuelan company has been forced to redesign its production and export logistics in recent weeks to avoid halting operations, including formulating new crude blends, swapping a large portion of its oil for imported fuel, selling through intermediaries and finding new customers. 

But the efforts have not been enough to avoid an export decline. The OPEC-member country’s oil shipments fell to some 920,000 barrels per day (bpd) in February according to Refinitiv Eikon data. 

PDVSA exports could fall further due to a lack of imported naphtha, a light distillate, needed to dilute its extra heavy oil as the company has been able to secure only two 500,000-barrel cargoes versus 2-3 million barrels per month needed, according to the document. 

If it cannot import enough naphtha to formulate its oil for export, PDVSA plans to start mixing other domestic fuels to ready oil for export. 

Lack of maritime crews to take PDVSA tankers idled due to unpaid shipping fees is also hampering oil deliveries between domestic ports and to the Caribbean, where PDVSA stores and ships much of its export barrels. 

Some shipping firms’ reluctance to work in Venezuela after sanctions have stopped PDVSA from using leased tankers to ease storage bottlenecks at its Orinoco Belt’s joint ventures. The ones willing to work with PDVSA are charging high prices and extra fees, the document added. 

On March 4, PDVSA completely shut output at its Corocoro oilfield, which was producing some 12,000 bpd, due to lack of storage capacity. Its Pedernales oilfield could follow due to similar issues, according to the report. The four Orinoco upgraders were working at minimum on Monday.

Monday, March 11, 2019

Venezuela crisis: No running water, no power, no medicine

ExxonMobil to Build New Polypropylene Unit in Louisiana

Exxon chemical

Oil and gas firm ExxonMobil revealed plans Friday to construct a new 450,000 tn/yr polypropylene production unit at the company’s complex in Baton Rouge, LA. Slated to become operational by 2021, the new facility is expected to create about 65 new permanent jobs.

“Growth in feedstock supply along with the increase in global demand for chemical products continues to drive our strategic investments and expansion along the Gulf Coast,” the president of the ExxonMobil Chemical Company, John Verity, said in a company press release. “We’re well positioned to meet the demand for these high-performance products and investing further in Baton Rouge enhances our facility’s competitiveness.”

Engineering, procurement, and construction (EPC) contracts have been awarded to Jacobs Engineering and Turner Industries for the polypropylene unit in Baton Rouge. The complex in Louisiana houses a 502,000 barrel/day refinery and production plants for lubricants, chemicals, and polyethylene, which are staffed by over 2500 workers. 

ExxonMobil's project come on the heels of the firm’s $20 billion “Growing the Gulf” initiative to improve its manufacturing footprint in the region. The effort includes a new aviation lubricants blending, packaging, and distribution facility in Baton Rouge, expansions of chemical and refining assets at the firm's Baytown and Beaumont plants, a planned 1.8 million mt ethane cracker in Texas, and a LNG export project in Sabine Pass, Texas.

Friday, March 8, 2019

Seafarers abducted from tanker in Gulf of Guinea

Sea piracy: Three Romanian sailors kidnapped off Lome, Togo

Three Romanian seafarers on board the 2006-built Handysize product tanker ‘Histria Ivory’ were alleged to have been kidnapped by pirates off Togo, according to Romania's Free Trade Union of Navigators (SLN) and the Romanian Ministry of Foreign Affairs (MAE). 
At about 19.30 hours last Sunday, pirates attacked the tanker about 20 miles off  Lome, Togo. The majority of the crew took shelter in the ship's citadel, but three Romanian nationals were abducted. The pirates fled the scene after the kidnapping, and local authorities escorted ‘Histria Ivory’ to a safe anchorage.
The vessel was reportedly damaged during the attack, but none of the crew was injured, according to the MAE.
"The Free Trade Union of Navigators warns that in the Gulf of Guinea, the rate of pirate incidents is increasing in intensity, which affects seafarers and global shipping," the SLN said in a statement. "In high-risk areas, it is necessary to increase vigilance on the bridge and tune radar for small distances to prevent any attempted attack to succeed. Also, the piracy procedures must be well received by each crew member and followed precisely in case of piracy incidents."

Thursday, March 7, 2019

The road to Exxon’s long-awaited stock buybacks is paved with billions in asset sales

CNBC: Darren Woods, Exxon Mobil CEO 170301-004
Darren Woods, Chairman and CEO, Exxon Mobil.
Katie Kramer | CNBC
  • Exxon expects to restart its share buyback program once $15 billion of asset sales gets under way, CEO Darren Woods says. 
  • Exxon is holding its fire even as its peers are once again enriching shareholders by purchasing their own stock.
  • Woods says the company’s priorities are reinvesting to replenish its reserves and growing its dividend.
Exxon Mobil’s plan to sell billions of dollars in assets may pave the way for the company to return cash to stockholders through a long-awaited share buyback program, says Chairman and CEO Darren Woods.

On Wednesday, the energy giant forecast it could generate $15 billion in cash through 2025 by selling assets. Woods say the company expects some of that cash will go towards repurchasing stock from shareholders.

But today, the company’s main priority is reinvesting in its business and replenishing its oil and natural gas reserves.

“We’ve got a balance sheet that allows us to continue to do that, and so we’ve looked at our balance sheet, our objectives to grow dividends ... and to maintain a strong balance sheet,” he said in an interview with CNBC’s Becky Quick.

“We can do all that in a pretty wide range of price environments, so the additional money coming in from divestments we can use for buybacks.”

Exxon is reviewing its global portfolio for divestment opportunities, and will prune assets that don’t fit its strategic priorities, says Woods. The company will also look for tactical opportunities to offload assets at good value, he added.

But it remains unclear when the divestments will give way to share repurchases, and some investors appear to be growing impatient. Exxon saw its stock price slump on Wednesday, despite the company issuing improved guidance for profits and cash flow during its annual investor day.

Analysts say one reason for the pullback is disappointment that Exxon did not launch a buyback program, even as its peers have begun enriching investors by once again repurchasing stock.

“Exxon has been the only supermajor in recent quarters without an active buyback program,” said Raymond James equity analyst Pavel Molchanov.

“Interestingly enough, a decade ago this company had the largest buyback amounts in the entire S&P 500.”

Exxon spent about $210 billion on share buybacks over a decade before halting share repurchases three years ago, except to offset dilution. Now, Exxon has fallen behind its peers like Chevron, Royal Dutch Shell and BP, who have all restarted their share buyback programs following the punishing 2014-2016 oil price downturn.

Pressed on the buyback issue, Woods said Exxon remains focused on generating value for shareholders over the short- and long-term, and in the current cycle, that means investing while others are pulling back spending.

The most exciting part of the multi-year road map Exxon revealed on Wednesday is the opportunities executives have identified to build on last year’s long-term plan, Woods said. That plan called for doubling earnings in Exxon’s chemicals and refining segments and tripling profit in its business producing oil and gas by 2025.

By spending another $4 billion between 2019-2025, Exxon believes it can improve net present value by $40 billion, drum up $9 billion of extra earnings and $24 billion of added cash flow during the period.

“The projects that we put into the portfolio have very good returns, are accretive and are advantaged versus the rest of the competition,” Woods said.
“What we’ve found over time as we’re talking to investors is they like the plan.”

John Kilduff, founding partner at energy hedge fund Again Capital, says it’s the right time for Exxon to double down on its bets.

“This is a low-cost environment. The cost of rigs — offshore rigs — have basically been cut in half from two years ago,” he told CNBC’s “Squawk Box”  “I mean, you want to be buying low and selling high.”

Kilduff said Exxon had done the opposite over the last few years, for example acquiring U.S. shale driller XTO Energy near the top of the market.

“The company, it seemed to be in sort of a funk,” he said. “But this new CEO is doing some things. They’re actually going to get more active in trading, as well, so I think it’s a good future. I think it’s a great move for them.”

Wednesday, March 6, 2019

Falling gasoline crack spreads hit Gulf Coast refiners

U.S. Gulf Coast refineries saw gasoline crack spreads, a key marker for profitability, plummet in January as prices for heavy crude rose and gasoline inventories climbed.

U.S. Gulf Coast refineries saw gasoline crack spreads – a key marker for profitability – drop in late January to their lowest levels since 2014, the U.S. Energy Department said in a report issued Tuesday. The dip in margins came as gasoline inventories jumped and supplies of heavy crude tightened as OPEC slowed production and Venezuelan sanctions took effect.

The gasoline crack spread is the difference between the spot prices of gasoline and crude oil. The spread approximates the profit margin that an oil refinery can expect to make by "cracking" the long-chain hydrocarbons of crude oil into useful shorter-chain petroleum products.

On the Gulf Coast, gasoline crack spreads have steadily dropped since mid-2018 and briefly went negative in January and early February before rising, while distillate crack spreads remained relatively stable, the Energy Information Administration said.

Gulf Coast refineries usually benefit from some of the strongest crack spreads because they've spent decades upgrading their equipment to refine relatively lower cost heavy crude oil into gasoline or other valuable products.

But since December the price of medium and heavy crude oils with higher sulfur content have climbed relative to prices for light, sweet crude oil. The EIA said the price spike is likely because OPEC and Canadian producers reduced output just as the threat of production disruptions from Venezuela took effect. Those countries all produce medium and/or heavy crude grades with high sulfur content.

Beyond higher crude oil costs, U.S. high gasoline inventories have pushed down Gulf Coast crack spreads. The Gulf Coast – which has 34 percent of U.S. motor gasoline storage capacity – saw inventories hit an all-time high of nearly 91 million barrels in mid January. Gasoline inventories are also high outside the U.S., further adding to low gasoline crack spreads.

Monday, March 4, 2019

Saudi Arabia's Crude Supply to U.S. Gulf Falling Fast and Hard

Saudi Arabia sliced its crude supply to plants located on the U.S. Gulf Coast, the world’s largest refining center, by more than half from a year ago. And shipments may grind to a complete halt soon.

The Middle East’s largest producer is making good on its pledge to reduce deliveries to its biggest American customers in an effort to comply with OPEC’s deal to cut output. Saudi Aramco shipped just 1.6 million barrels of its oil to U.S. Gulf Coast buyers this month compared with 5.75 million a year ago, according to U.S. Customs data compiled by Bloomberg. In January, shipments were at 2.69 million.

"We could see Saudi oil imports declining to zero into the U.S. Gulf Coast," said Andy Lipow, president of Lipow Oil Associates in Houston. U.S. President Donald Trump’s recent comment via Twitter that oil prices are too high won’t stem the current declining trend, as "OPEC and non-OPEC members feel prices are too low, and they will do what it takes to put the market back in balance."
Government data showed Wednesday that total Saudi crude imports to the U.S dropped to 346,000 barrels a day last week, the lowest in data going back to 2010.
However, total Saudi oil flows to America won’t likely flatten out completely because there will be demand from U.S. West Coast refiners, who are faced with limited supply options, Lipow said.

Friday, March 1, 2019

More on the Scrubber conundrum

Innovative marine exhaust gas cleaning system (EGCS) and electric solutions by FUJI ELECTRIC

As shipping enters the final lap in the race towards meeting the IMO sulfur cap by January 2020, the industry faces an expensive dilemma in making ships more environmentally sustainable, a meeting was told.
Some 112 delegates debated the potential of exhaust gas cleaning systems (EGCS) or scrubbers addressing the emissions regulations, at an IMarEST UAE branch seminar sponsored by Kamelia Cleantech, a Unique Group company.

Nikeel Idnani, IMarEST UAE’s branch Honorary Secretary, in his opening introduction, said that shipowners tread with caution in an industry that is no longer awash with money, yet must comply with what the regulators of the IMO have pledged to deliver against a firm timescale.

Idnani argued that scrubber bans ordered by some countries appeared to be merely ‘politically correct’ to follow by environmentalists, without necessarily having a scientific base to back up the decision. Nevertheless, he emphasised that this does not shred the economics of installing the systems, on a ship-specific basis.

In a double presentation, Kaisa Marton (Kamelia Cleantech managing director) and Dr Sharad Kumar (Group Director, Unique Group and Kamelia Cleantech COO) outlined the alternative solutions to comply with the IMO 2020 legislation, including OPEX, CAPEX and opportunity losses for the solutions. They then highlighted the cleaning efficiency required in 2020, including the washwater discharge rules.

While explaining the reaction chemistry between exhaust sulfur in contact with water, Marton admitted that the pH of the scrubbing effluent can be between 2.4 - 4.5 depending on the fuel sulfur content, scrubbing efficiency, amount of water used and engine load.

This could have corrosion implications and environmental challenges in selected locations with brackish waters, such as the Baltic Sea.

The use of closed loop scrubbing can be justified for these areas because the lack of natural alkalinity can be compensated by the addition of chemicals. Nonetheless, Seawater has excellent capacity to buffer changes in pH due to its alkalinity. Seawater salinity is a good indication of its alkalinity.

Dr Kumar explained the pros & cons of U-type and inline, as well as the working principle of open loop, closed loop and hybrid scrubbers.

Following best industry practices, he proposed a holistic and integrated approach to scrubber delivery, including contracting a shipyard for the installation work, an engineering company for the integration engineering, contracting a naval architect to check the designs and vessel integrity enabling seamless co-ordination of the four different parties resulting in an efficient working solution.
Marton highlighted that critical design factors to consider were engine sizes and performance criteria, funnel dimensions and existing space on the vessel, ship systems, ship geometry, class and flag.

For the project planning stage, it is important to factor ship operation patterns and schedules, drydocking schedules, opportunity losses if the ship is taken out of operation, possibilities to carry out as much work as possible while the vessel is in service, available accommodation on board for the riding gang, plus lifting arrangements on board and at strategic ports.

On a practical note, she shared Kamelia Cleantech’s experience with challenges faced during installation and operation and potential solutions and commented on Kamelia’s capability to offer turnkey solutions and on the voyage installation options available.

She admitted that heavy fuel consuming ships, mostly on long ocean passages, were the low hanging fruit from an economic perspective to install scrubbers. With a payback period ranging from six to 18 months, depending on the LSFO premium, amid the commercial realities facing the industry, this option is the more financially astute choice.

Thursday, February 28, 2019

Citgo formally cuts ties with Venezuela-based parent company: sources

The Citgo Petroleum Corporation headquarters are pictured in Houston, Texas, U.S., February 19, 2019. REUTERS/Loren Elliott

(Reuters) - U.S. refiner Citgo Petroleum Corp is formally cutting ties with its parent, state-run oil firm Petroleos de Venezuela SA, to meet U.S. sanctions imposed on the OPEC country, two people close to the decision told Reuters on Tuesday.

Executives at the Houston-based firm set a Feb. 26 deadline to end relationships with PDVSA following sanctions designed to curb oil revenues to socialist President Nicolas Maduro and support the nation's transition government formed by Venezuelan congress head Juan Guaido.

The United States, Canada and dozens of other nations have recognized Guaido as Venezuela's legitimate president, but Maduro still controls the military, public institutions and PDVSA, which provides 90 percent of the country's export revenue.

Citgo has halted payments to its parent, subscriptions to corporate services, email communications and minimized mentions to PDVSA on marketing materials and its website.

Expatriate Venezuelan employees this month returned to Venezuela and a procurement subsidiary operating from Citgo's headquarters, PDVSA Services, was shut, the people familiar with the matter said.

A Citgo spokeswoman did not respond to requests for comment.

The company is trying to free itself of sanctions that have hampered access to financing. It is prioritizing refinancing a revolving credit and term loan by the end of July, the sources said. Credit rating firm Fitch on Monday placed Citgo on rating watch citing heightened refinancing risk due to sanctions.

"We have been told that we have to organize the house by Feb. 26 to avoid conflicts with sanctions," one of the sources said.

A new Citgo board of directors was appointed this month by the Venezuelan congress under Chairwoman Luisa Palacios, who last week named a management team under Rick Esser, the company's new executive vice president. New boards for PDVSA and subsidiaries, PDV Holding and Citgo Holding, also have been appointed by the Venezuelan National Assembly.

Citgo is Venezuela's main foreign asset. It is the eighth largest U.S. refiner, with a 750,000-barrel-per-day refining network capable of supplying 4 percent of the country's fuel through a network of some 5,000 gas stations in 30 states.

The Venezuelan congress has been researching the South American nation's assets and bank account around the globe in an effort to gain access to cash and foreign facilities.

It is unclear if Citgo's new board has completed a registration process in Delaware to legally take control of the company. The new board could face a legal challenge by PDVSA's current leadership if the board was not legally constituted.