Monday, April 22, 2019

Oil market is up as US announces Iranian oil sanctions

U.S. to impose sanctions on allies in drive to push Iranian oil sales to zero

Secretary of State Mike Pompeo speaks during a news conference on April 22 at the State Department in Washington. (Sait Serkan Gurbuz/AP)

“This decision is intended to bring Iran’s oil exports to zero, denying the regime its principal source of revenue,” a statement from the White House said. It said the United States, Saudi Arabia and the United Arab Emirates would ensure global demand is met.

Pompeo said Iran had been taking in $50 billion a year in oil revenue before the sanctions were reimposed. He estimated that U.S. sanctions have cost the Islamic republic $10 billion so far.

“This decision is intended to bring Iran’s oil exports to zero, denying the regime its principal source of revenue,” a statement from the White House said. It said the United States, Saudi Arabia and the United Arab Emirates would ensure global demand is met.

Pompeo said Iran had been taking in $50 billion a year in oil revenue before the sanctions were reimposed. He estimated that U.S. sanctions have cost the Islamic republic $10 billion so far.

“The regime would have used that money to support terror groups like Hamas and Hezbollah and continue with its missile development in defiance of U.N. Security Council Resolution 2231,” he told reporters. “And it would have perpetuated a humanitarian crisis in Yemen.”

Last November, the administration reimposed sanctions that had been lifted with the 2015 nuclear agreement. President Trump granted waivers to eight of Iran’s biggest customers, allowing them a six-month grace period to wind down their purchases. The big buyers are China, India, Japan, South Korea, Italy, Greece, Turkey and Taiwan.

The waivers expire May 2, one year after the United States withdrew from the Iran nuclear deal. Initially, countries were given six months to wean themselves from oil, but seven countries and Taiwan could not meet the target and were given another six months.

Some of them expected another extension, but none will be granted, Pompeo said.

“We’re going to zero,” Pompeo said. “We're going to zero across the board. We will continue to enforce sanctions and monitor compliance. Any nation or entity interacting with Iran should do its diligence and err on the side of caution. The risks are simply not going to be worth the benefits.”

Friday, April 19, 2019

U.S. refiners planning major plant overhauls in second quarter

HOUSTON (Reuters) - U.S. oil refiners are planning a heavy slate of plant overhauls in the second quarter, with total production this month off 8.5 percent compared with the start of the year, according to data from the U.S. Energy Information Administration.

Early spring and winter traditionally are heavy periods for U.S. refinery maintenance. But refiners are planning more upgrades than usual in the first half of 2019 to avoid fall and winter shutdowns as they prepare to meet coming low-sulfur standards. 

This year’s maintenance schedule and higher crude prices helped push U.S. gasoline prices to a national average of $2.83 a gallon last week, up 26 percent since the start of the year, according to data from the American Automobile Association. U.S. crude futures rose 32 percent in the first quarter. 

International Maritime Organization (IMO) 2020 is a standard for maritime diesel that takes effect on Jan. 1 and is designed to reduce air pollution. Refiners have been revamping their plants to make IMO 2020 compliant fuel. 

“They will push (winter) turnarounds later into 2020 to take advantage of that margin bump from the switch to IMO 2020,” said Susan Bell, a senior associate at energy consultancy IHS Markit.

Most U.S. refiners typically ramp up production of motor fuel during the second quarter to build inventories for the summer driving season. But Bell said an average of 1 million barrels per day (bpd) of crude oil refining capacity could be offline through the second quarter. 

Work on refiners’ crude distillation units (CDUs) and catalytic crackers helped send volumes down to 15.85 million bpd in the last week of March, from 17.5 million bpd in the first week of January, the EIA said. CDUs generate feedstocks for fuel processing units such as catalytic crackers. 

Among the refiners scheduling major maintenance this month are Valero Energy Corp and BP Plc. Valero’s Memphis, Tennessee, refinery will shut its 65,000 bpd gasoline producing fluidic catalytic cracking unit for a 60-day overhaul the last week of April. 

BP is shutting one of two small CDUs at its 413,500 bpd Whiting, Indiana, refinery on Monday for 30 days of work. The Whiting refinery is BP’s largest in North America. 

Work also is continuing this month on a planned overhaul of the 112,000 bpd gasoline-producing residual catalytic cracking unit at Royal Dutch Shell Plc’s 218,200 bpd Norco, Louisiana, refinery. That unit is expected to restart in the first full week of May.

Two other major overhauls finished during the switchover between the quarters. 

Exxon Mobil Corp recently finished CDU overhauls at two plants: its 560,500 bpd Baytown, Texas, refinery wrapped up work on its largest CDU in late March and the company’s 502,500 bpd Baton Rouge, Louisiana, refinery restarted its second-largest crude unit on Monday.

Thursday, April 18, 2019

PB Tankers takes issue with US blacklisting

Italian-based PB Tankers has expressed concern at being included on the US Office of Foreign Assets Control (FAC) blacklist for allegedly trading with Venezuela.
FAC recently issued its latest list of tanker companies and vessels to be blacklisted for trading with Venezuela.
The following companies were added to the list - Jennifer Navigation Ltd, Large Range Ltd, Lima Shipping Corp, and PB Tankers.
As for the ships involved, they were named as ‘Alba Marina’, a floating storage tanker claimed to be attached to PB Tankers; ‘Gold Point’, ‘Ice Point’,’Indian Point’, ‘Iron Point’ and ‘Silver Point’, all attached to PB Tankers; ‘Nedas’ attached to Jennifer Navigation; ‘New Hellas’ attached to Lima Shipping and S-Trotter, attached to Large Range.
In response, PB Tankers said it was shocked and concerned by the action taken by OFAC in adding the company and a number of the its vessels to the current SDN (Specially Designated Nationals) list in relation to trade with Venezuela.
This was done without any notification or contact with the company, who only became aware through the media. As a consequence, we will be taking immediate steps to ensure that both are de-listed as a matter of urgency, the company said.
PB Tankers, also said that as an Italian shipping company with more than 100 years of service to the international community, has been taking regular advice from both its UK and US lawyers and has been diligent in taking all possible steps to ensure compliance with current US sanctions including, but not limited to, possible restriction of trade under a single timecharter contract, which pre-dates the current sanctions regime.
The company further claimed that it does not have any ships in Venezuela, nor will be trading into or out of Venezuela.
PB Tankers will continue to meet its obligations as a matter of international law, the company stressed.

Wednesday, April 17, 2019

Red Hot Permian Set To Jolt U.S. Shale Output To New Record

Permian Basin.jpg

Crude oil production from the seven key shale regions in the United States is expected to increase by 80,000 bpd from April to hit a record 8.46 million bpd in May, with the Permian accounting for half of the monthly growth, the EIA said in its latest Drilling Productivity Report.

Crude oil production from the seven major shale producing regions is set to increase from 8.38 million bpd this month to 8.46 million bpd next month. The fastest-growing region, the Permian, is expected to see its crude oil production jump by 42,000 bpd from April to hit a record high of 4.136     million bpd in May, according to the EIA estimates—a figure that would place the US hotspot as OPEC’s third-largest producer behind only Saudi Arabia (9.79 bpd) and Iraq (4.52 bpd).
In the report forecasting production in May, the EIA sees the Niobrara region adding 22,000 bpd to reach oil production of 764,000 bpd in May—this would be the second-largest growth after the one in the Permian. The Bakken, the Eagle Ford, and Appalachia regions are also expected to see higher production in May compared to April, while Anadarko region’s crude oil production is forecast to drop slightly next month.

After oil prices collapsed by some 40 percent in the fourth quarter of 2018, U.S. shale drillers put some brakes on drilling activities. U.S. oil production growth has slowed, with average daily U.S. crude oil production slipping in January from the previous month for the first time in nearly six months, according to the EIA’s report from end-March.

In terms of total U.S. crude oil production, the EIA estimated in its April Short-Term Energy Outlook last week that U.S. crude oil production averaged 12.1 million bpd in March, up by 300,000 bpd from the February average. EIA now expects U.S. crude oil production to average 12.4 million bpd this year and 13.1 million bpd next year, chiefly driven by the Permian production growth. 

By Tsvetana Paraskova for

Tuesday, April 16, 2019

Citgo's future at stake as creditor seeks $1.4B from PDVSA in lawsuit

Flags fly outside Citgo Petroleum Corp. headquarters stands in Houston, Texas, U.S., on Thursday, Feb. 14, 2019.

NEXT: See the world's largest oil refineries. Photo: Loren Elliot, Bloomberg

The future of Houston's Citgo Petroleum is taking center stage in a federal appeals court this week as creditors for its parent company, Venezuela state-owned PDVSA, continue attempt to recoup billions of dollars in debt owed by the Venezuelan government.

Oral arguments were heard Monday afternoon in the U.S. Third Circuit Court of Appeals in Philadelphia the case involving one of PDVSA's creditors, Crystallex International Corp. a defunct Canadian gold mining company seeking to collect on $1.4 billion award owed by Venezuela.

Crystallex has targeted the Houston refiner Citgo Petroleum Corp. because it is the biggest U.S. asset of the crisis-ridden, cash-strapped Venezuelan government. In August 2018, a federal judge agreed that PDVSA's assets in the United States., namely Citgo, could be used to satisfy Venezuela's debts owed to Crystallex and now that decision is under appeal.It could take weeks for the panel of three judges to make a decision on the appeal.

Last month, the court approved Venezuela's opposition government, led by interim president Juan Guaidó,to intervene in the case. Guaidó is trying to stop Crystallex and other creditors from carving up the country's foreign assets. His administration is arguing Citgo's loss could harm the country's chances of political and economic recovery.

Venezuela already has paid Crystallex $500 million  and attorneys for Guaidó's administration argued in court documents that Crystallex's additional attempts "ignore the economic reality of the Republic's humanitarian and economic crisis." They also said it could upset U.S. foreign policy.

Guaidó, who is recognized by the United States as Venezuela's legitimate leader, is trying to consolidate control over the country's assets abroad as he seeks to setup  his government-in-waiting for rebuilding the country once it wrestles control away from Nicolas Maduro's regime. In February, Guaidó successfully replaced Citgo Petroleum's board of directors with new leaders in Houston.

For the past few years creditors have  circled Citgo, which is valued at up to $8 billion by some analysts, as they seek to recoup billions owed to them by PDVSA and the Venezuelan government. Venezuela previously has settled similar debt-collecting lawsuits with Houston company ConocoPhillips and Rusoro Mining Ltd. Similar to Crystallex, these companies sought to enforce arbitration awards after a nationalization campaign expropriated their Venezuelan investments.

But the Trump administration wants to keep Citgo intact to help the new government rebuild the country ravaged by economic and political turmoil, hyperinflation and shortages in food, water and electricity. The Trump administration has granted Citgo certain exemptions from U.S. oil sanctions against Venezuela and PDVSA to allow  Citgo to continue operating and preserve at least 3,400 jobs in the U.S., including about 800 in the Houston area.

Citgo has distanced itself from the Maduro regime and recently secured a $1.2 billion loan help fund its daily operations.

Separately, Citgo is also under threat in a 2020 bond PDVSA took out with Citgo as collateral. PDVSA has an April 27 deadline to pay $71.6 million for a 2020 bond; it default bondholders could exercise a lien to sell 50.1 percent of Citgo Holding to recover their losses, according to the international investment bank and consulting firm Caracas Capital Markets.

Monday, April 15, 2019

Sinopec continued to lead the world’s biggest oil and gas companies in 2018, enjoying a double-digit revenue growth when compared to 2017.

The majority of the ten biggest witnessed a similar double-digit growth, which was as high as 31.4% for Rosneft. profiles the ten biggest oil and gas companies by 2018 revenues, excluding the state-owned Saudi Aramco.
Index of this series of articles covering the top 10 Oil & Gas companies:
  • 10. Phillips 66
  • 9. Lukoil
  • 8. Rosneft
  • 7. Chevron
  • 6. Total
  • 5. ExxonMobil
  • 4. BP
  • 3. China National Petroleum Corp (CNPC)
  • 2. Royal Dutch Shell
  • 1. China Petroleum & Chemical Corporation (Sinopec)

Series: The Biggest Oil & Gas Companies in 2018

Read the 1st piece of this series of articles; which shows the revenue of Phillips 66, Lukoil and Rosneft.

Read the 2nd piece of this series of articles; which shows the revenue of Total, Chevron and ExxonMobi

4. BP Plc – $298.75bn

British multinational oil and gas company BP registered a 24.37% year-on-year revenue growth in 2018, earning $298.75bn. Revenues from its downstream business increased by 23.88% to $270.11bn, whereas the upstream segment’s revenues witnessed a 30.92% growth to reach $27.83bn.

The company’s upstream production increased by 8.2% to an average of 3.7 million barrels of oil-equivalent a day (Mboed) in 2018. Crude oil sales contributed $65.27bn of revenue, whereas oil products contributed $195.466bn and natural gas, LNG, and natural gas liquids (NGLs) contributed $21.74bn to the revenue.

BP established six major upstream projects in 2018, namely Clair Ridge, Western Flank B, Thunder Horse Northwest Expansion, Shah Deniz Stage Two, Taas-Yuryakh Expansion, and Atoll Phase One.

3. China National Petroleum Corp (CNPC) – $346bn

State-owned China National Petroleum Corp (CNPC) reported a 25% year-on-year growth to achieve $346bn operating revenue in 2027, out of which CNPC’s listed unit PetroChina contributed $298bn.

The biggest oil and gas producer of the country, PetroChina produced 1.1 billion barrels of oil and gas-equivalent in the first three quarters of 2018, which was a 2.2% increase compared with the same period in 2017. The company’s marketable gas output increased by 4.8% to 2.66 trillion cubic feet (tcf) during the same period.

CNPC operates 26 refineries with a combined crude processing capacity of 152 million tonnes per year (Mtpa) and an oil and gas pipeline infrastructure spanning 85,582km. Its overseas exploration and production activities are also spread across 38 countries in Africa, Central Asia, Russia, South America, the Middle East, and Asia-Pacific.

2. Royal Dutch Shell – $388.37bn

British-Dutch oil and gas company Royal Dutch Shell’s operating revenue was up by 27.26% to reach $388.37bn in 2018. The company’s downstream business registered a 26.42% year-over-year growth to reach $334.68bn and accounted for 86.17% of the total revenue.

The company’s integrated gas business, which includes liquid natural gas (LNG) marketing and trading, as well as gas-to-liquids projects grew by 25.34% to $43.764bn and accounted for 11.27% of the total operating revenue.

Shell’s upstream earnings increased by 1.99% to $9.89bn because of the higher realised oil and gas prices during the year, despite the 2% reduction in its upstream production.

1. China Petroleum & Chemical Corporation (Sinopec) – $426bn

China Petroleum & Chemical Corporation, also known as Sinopec Group, registered a 22.09% year-over-year growth to achieve RMB2.8tn ($426bn) of operating revenue in 2018. The company’s refinery and distribution segment accounted for approximately 60% of the revenue. Its refinery throughput during the year increased by 2.31% to 244 million tonnes (Mt). The total domestic sales volume of refined oil products increased by 1.4% to 180.24Mt.

The other business segments of the company include oil and gas exploration and production, petroleum engineering, chemical marketing, petrochemical refining and refined products marketing, engineering and construction, and international trade.

Sinopec’s crude oil production decreased by 1.75% to 288.51 million barrels, while natural gas production increased by 7.08% to 977bcf during the year. Sinopec is an integrated energy and chemical company incorporated in the People’s Republic of China.

Saturday, April 13, 2019

Exxon and Others Say U.S. Government Sold Toxic Crude Oil

Oil pipelines at the Bryan Mound Strategic Petroleum Reserve in Freeport, Texas. Oil pipelines at the Bryan Mound Strategic Petroleum Reserve in Freeport, Texas.Photographer: Luke Sharrett/Bloomberg
  • Energy Department paid $1 million to clean one oil cargo
  • Exxon, Shell, Macquarie and Petrochina all complained to DOE
(Bloomberg) -- Exxon Mobil Corp. is the latest company to raise concerns that a stockpile of U.S. government crude is tainted with poisonous gas.

The American energy giant said some of the oil it purchased last year from the Energy Department’s Strategic Petroleum Reserve, or SPR, contained "extremely high levels" of hydrogen sulfide, according to emails obtained by Bloomberg under the Freedom of Information Act. In some cases, the gas level was 250 times higher than government safety standards allow.

"The Department of Energy takes safety, security and environmental impacts involving SPR activities very seriously," agency spokeswoman Jess Szymanski said. "Last fall, an SPR cargo received by Exxon Mobil was found to contain higher-than-expected levels of hydrogen sulfide. Since then, the Department has worked with Exxon to resolve this concern, and find alternate options for the cargo’s delivery."

Spurious Claims?

Analysts have pointed to the stockpile as a safeguard against tightening crude supplies after U.S. sanctions on Iran and Venezuela curbed their oil exports. But Exxon’s discovery, which follows complaints by Royal Dutch Shell Plc, Macquarie Group Ltd and PetroChina Co., suggest that the reserve may not offer refiners as much insurance against diminishing volumes of higher sulfur, or sour, crude as previously thought.

The Energy Department disputed claims that it repeatedly sold tainted crude, saying that some companies’ high hydrogen sulfide readings were "spurious" or the result of contamination during shipping. In PetroChina’s case, however, the agency acknowledged spending around $1 million to clean up a contaminated cargo.

The prospect of tainted crude in the reserve complicates future sales of U.S. oil, a key tool for funding government programs. A 5 million-barrel sale is planned for 2019, and 221 million barrels of oil are planned for sale from 2020 to 2027.

Safety Risks

While hydrogen sulfide occurs naturally in crude, producers often take pains to remove it because it can put workers at risk and corrode pipelines and refineries. Many pipelines have capped the permitted amount of hydrogen sulfide, or H2S, at 10 parts per million (ppm).

"Refineries don’t want high H2S in their plants for safety reasons, especially with personnel having to access storage tanks where the oil is stored,” said John Auers, executive vice president at energy consultant Turner Mason & Co.

Exxon’s Discovery

Exxon was one of five companies that purchased oil in an Energy Department sale in August. Exxon took 1.5 million barrels of Bryan Mound sour crude -- a high sulfur oil that’s recently become more expensive as global supply shrink -- by pipeline to Texas City. There, the company discovered hydrogen sulfide levels that were at 5,000 ppm, according to emails sent to the department in November by Mattias Bruno, a lead oil trader at Exxon Mobil.

The exposure limit set by the Occupational Safety and Health Administration is 20 ppm. Exposure at 500-700 ppm could cause a person to collapse in five minutes and die within an hour. After discovering high levels of the gas, Exxon launched an investigation, according to the emails.

The Energy Department in a statement suggested that Exxon’s readings were possibly erroneous, noting that the facility where the contamination was discovered was not "H2S qualified." Oil was delivered through other facilities without incident, the agency said.

An Exxon spokesman declined to comment.

Other Complaints

Shell, Macquarie and PetroChina have also complained about hydrogen sulfide levels in government crude. In those cases, the oil was pumped from Bryan Mound to the Freeport, Texas, terminal owned by Seaway Crude Pipeline LLC -- a joint venture between Enterprise Products Partners LP, the operator, and Enbridge Inc. -- before being loaded onto vessels.

In a statement to Bloomberg, the Energy Department dismissed Shell’s complaint as spurious and attributed the Macquarie incident to a paperwork error. No payment was made to either company.

However, the agency verified PetroChina’s concerns and paid to clean up the contaminated oil at a cost of around $1 million.

Macquarie declined comment. Representatives from Shell and PetroChina did not respond to requests for comment. Enterprise did not immediately respond to a request for comment.

If the stockpiles are contaminated, the elevated levels of hydrogen sulfide could be the result of a high-sulfur oil put into the reserve years ago that’s blended with newer oil, according to chemical engineers and testing experts. It could also be the result of a naturally occurring bacteria that reduces sulfur to hydrogen sulfide, which could have grown in the caverns over decades.
Price Questions

So far, the quality concerns raised by companies haven’t affected bid prices for SPR oil, according to the Energy Department. But if crude quality issues persist, that could have implications for the future sales of oil from the SPR, which is about 60 percent sour crude.

“The Congressional Budget Office might conceivably set a lower price deck for future sales to account for discounts associated with crude quality,” said Kevin Book, managing director of ClearView Energy Partners LLC.

(Updates to include all firms owning the Freeport terminal in 13th paragraph.)
--With assistance from Dave Merrill.

To contact the reporter on this story: Catherine Ngai in New York at

To contact the editors responsible for this story: David Marino at, Catherine Traywick, Joe Ryan

For more articles like this, please visit us at

Friday, April 12, 2019

Chevron to Acquire Anadarko in Mega Billion Transaction

In one of the most high-profile acquisitions in recent years, Chevron Corp. announced today that it has entered into a definitive agreement with Anadarko Petroleum Corporation to acquire all of the outstanding shares of Anadarko in a stock and cash transaction valued at $33 billion, or $65 per share. Based on Chevron’s closing price on April 11, 2019 and under the terms of the agreement, Anadarko shareholders will receive 0.3869 shares of Chevron and $16.25 in cash for each Anadarko share. The total enterprise value of the transaction is $50 billion.

The acquisition of Anadarko will significantly enhance Chevron’s already advantaged Upstream portfolio and further strengthen its leading positions in large, attractive shale, deepwater and natural gas resource basins. Furthermore, Western Midstream Partners, LP (NYSE: WES) is a successful midstream company whose assets are well aligned with the combined companies’ upstream positions, which should further enhance their economics and execution capabilities.

“This transaction builds strength on strength for Chevron,” said Chevron’s Chairman and CEO Michael Wirth. “The combination of Anadarko’s premier, high-quality assets with our advantaged portfolio strengthens our leading position in the Permian, builds on our deepwater Gulf of Mexico capabilities and will grow our LNG business. It creates attractive growth opportunities in areas that play to Chevron’s operational strengths and underscores our commitment to short-cycle, higher-return investments.”

“This transaction will unlock significant value for shareholders, generating anticipated annual run-rate synergies of approximately $2 billion, and will be accretive to free cash flow and earnings one year after close,” Wirth concluded.

“The strategic combination of Chevron and Anadarko will form a stronger and better company with world-class assets, people and opportunities,” said Anadarko Chairman and CEO Al Walker. “I have tremendous respect for Mike and his leadership team and believe Chevron’s strategy, scale and operational capabilities will further accelerate the value of Anadarko’s assets.”

Transaction Benefits
  • Strong Strategic Fit: Anadarko’s assets will enhance Chevron’s portfolio across a diverse set of asset classes, including:
    • Shale & Tight – The combination of the two companies will create a 75-mile-wide corridor across the most attractive acreage in the Delaware basin, extending Chevron’s leading position as a producer in the Permian.
    • Deepwater – The combination will enhance Chevron’s existing high-margin position in the deepwater Gulf of Mexico(GOM), where it is already a leading producer, and extend its deepwater infrastructure network.
    • LNG –Chevron will gain another world-class resource base in Mozambique to support growing LNG demand. Area 1 is a very cost-competitive and well-prepared greenfield project close to major markets.

  • Significant Operating and Capital Synergies: The transaction is expected to achieve run-rate cost synergies of $1 billionbefore tax and capital spending reductions of $1 billion within a year of closing.
  • Accretive to Free Cash Flow and EPS: Chevron expects the transaction to be accretive to free cash flow and earnings per share one year after closing, at $60 Brent.
  • Opportunity to High-Grade Portfolio: Chevron plans to divest $15 to $20 billion of assets between 2020 and 2022. The proceeds will be used to further reduce debt and return additional cash to shareholders.
  • Increased Shareholder Returns: As a result of higher expected free cash flow, Chevron plans to increase its share repurchase rate from $4 billion to $5 billion per year upon closing the transaction.
Transaction Details

The acquisition consideration is structured as 75 percent stock and 25 percent cash, providing an overall value of $65 per share based on the closing price of Chevron stock on April 11, 2019. In aggregate, upon closing of the transaction, Chevron will issue approximately 200 million shares of stock and pay approximately $8 billion in cash. Chevron will also assume estimated net debt of $15 billion. Total enterprise value of $50 billion includes the assumption of net debt and book value of non-controlling interest.

The transaction has been approved by the Boards of Directors of both companies and is expected to close in the second half of the year. The acquisition is subject to Anadarko shareholder approval. It is also subject to regulatory approvals and other customary closing conditions.

Upon closing, the Company will continue be led by Michael Wirth as Chairman and CEO. Chevron will remain headquartered in San Ramon, California.

Thursday, April 11, 2019

Venezuela reports collapse in oil supply, tightening global market: OPEC

FILE PHOTO: An oil pumpjack painted with the colors of the Venezuelan flag is seen in Lagunillas, Venezuela January 29, 2019. REUTERS/Isaac Urrutia/File Photo

LONDON (Reuters) - Venezuela’s oil output sank to a new long-term low last month due to U.S. sanctions and blackouts, the country told OPEC, deepening the impact of a global production curb and further tightening supplies.

Supply cuts by OPEC and partners led by Russia, plus involuntary reductions in Venezuela and Iran, have helped drive a 32 percent rally in crude prices this year, prompting pressure from U.S. President Donald Trump for the group to ease its market-supporting efforts. 

In a monthly report released on Wednesday, the Organization of the Petroleum Exporting Countries said Venezuela told the group that it pumped 960,000 barrels per day (bpd) in March, a drop of almost 500,000 bpd from February. 

The figures could add to a debate within the so-called OPEC+ group of producers on whether to maintain oil supply cuts beyond June. A Russian official indicated this week Moscow wanted to pump more, although OPEC has been saying the curbs must remain. 

OPEC, Russia and other non-member producers are reducing output by 1.2 million bpd from Jan. 1 for six months. The producers are due to meet on June 25-26 to decide whether to extend the pact. 

One of the key Russian officials to foster the pact with OPEC, Kirill Dmitriev, signaled on Monday that Russia wanted to raise output when it meets OPEC in June because of improving market conditions and falling stockpiles.

OPEC+ returned to supply cuts in 2019 out of concern that slowing economic growth and demand would lead to a new supply glut. OPEC’s report said the economic backdrop was weakening and lowered its estimate of global growth in demand by 30,000 bpd to 1.21 million bpd. 

“Newly available data has confirmed the recently observed downward trend in global economic activities,” the report said. 

In a development that will ease OPEC concern about a new glut, the report also said inventories in developed economies fell in February, after rising in January. 

Stocks in February exceeded the five-year average - a yardstick OPEC watches closely - by 7.5 million barrels, less than in January. 

The report suggests that if OPEC kept pumping at March’s rate it would slightly undersupply the world market in 2019, even with the lower demand outlook.


Venezuela’s production figure brings its numbers closer to outside estimates, which have been saying the country’s economic collapse has taken a bigger toll on its oil industry. 

Output in Venezuela, once a top-three OPEC producer, has been declining for years due to economic collapse. In March, supply dropped due to U.S. sanctions on state oil company PDVSA designed to oust President Nicolas Maduro, and power blackouts. 

Venezuela, plus Iran and Libya, were exempted from making voluntary curbs under the OPEC+ deal, on the basis that their output would probably fall anyway. 

OPEC’s share of the cut is 800,000 bpd from in most cases October 2018 levels, and other figures in the report showed producers were removing far more than agreed. 

The group uses two sets of figures to monitor its output — figures provided by each country and by secondary sources that include industry media. This is a legacy of old disputes over how much countries were really pumping. 

Overall OPEC output fell by a further 534,000 bpd to 30.022 million bpd, according to the secondary-source figures. This was led not by Venezuela but by Saudi Arabia, which has voluntarily cut supply by more than it agreed to support the market.

As a result, the 11 OPEC members required to cut output achieved 155 percent compliance in March with pledged curbs, according to a Reuters calculation, up from February. 

OPEC estimates that it needs to provide an average of 30.30 million bpd in 2019 to balance the market, a figure lowered by 160,000 bpd month-on-month partly due to weaker demand. 

Even so, the report indicates there will be a small 2019 deficit if OPEC keeps pumping at March’s rate of just over 30 million bpd and other things remain equal. Last month’s report had indicated a small surplus. 

Editing by Dale Hudson and Frances Kerry

Wednesday, April 10, 2019

This Oil Spill Has Been Leaking Into The Gulf For 14 Years

The National Oceanic and Atmospheric Administration and the Bureau of Safety and Environmental Enforcement are using Ian MacDonald's data to estimate the amount of oil being spilled at the Taylor Energy site.
Tegan Wendland/WWNO

Ten miles out in the Gulf of Mexico, off the tip of Louisiana, the fumes become overwhelming. "See how it's all rainbow sheen there? So that's oil," says Ian MacDonald, who's guiding us in a tiny fishing boat that's being tossed around by 6-foot waves.

MacDonald is a scientist at Florida State University where he studies oil spills. This one is not a black, sticky slick, but it stretches on for miles. And here, where the murky Mississippi River dumps into the Gulf, it's been leaking for more than 14 years. 

The Coast Guard has just begun to intervene to try and clean up this spill. But it faces challenges. And MacDonald sees the spill as a warning for regulators, just as the Trump administration pushes to expand offshore oil drilling in the Atlantic
A hurricane, an oil rig, an underwater mudslide

The spill began in 2004, when Hurricane Ivan toppled an oil rig into the Gulf. The rig was owned by Taylor Energy, a New Orleans-based company, which managed to plug some of the 25 broken pipes, but the leak continued.

Jonathan Henderson runs an environmental nonprofit called Vanishing Earth and worries about the impact on marine life. "Everything that lives and breathes in the Gulf of Mexico travels back and forth through that zone," he says. "Fish, seabirds, turtles, dolphins."

The government is studying the impact on marine life, but even they can't figure out exactly how much oil is leaking. Neither can the company. 

Henderson has been trying to monitor it himself by doing regular flyovers and reporting what he sees. He's frustrated at the government's response. "If we can put a man on the moon, we can figure out how to, like, grab oil that's coming up from the seafloor and 400 feet of water," he says. 

The Department of the Interior and the Coast Guard have been working with the company to try to stop the leak for years, but it poses a major engineering challenge. The wells were buried under hundreds of feet of mud in an underwater mudslide, which are common in the area, where the mouth of the Mississippi has built up hundreds of feet of silt on the bottom of the ocean floor. 

"This is a well-known, high-risk area," says Ed Richards, a law professor at Louisiana State University. He says it raises questions about offshore development. "Should they have built the rig the way they built it? Should it have been permitted that way?"

Taylor Energy has spent about $500 million to try to stop the spill, and it's paying for pilots to fly over and monitor it. The company has reported less than a barrel of oil a day on the surface, but estimates vary widely. 

Contractors hired by the Coast Guard survey the Taylor Energy leak in March 2019.
Courtesy of Jonathan Henderson/Vanishing Earth 
Hundreds of barrels each day

Ian MacDonald visits the site of the Taylor Energy oil spill regularly. He's helping measure the size of the spill for the government. He estimates that about 100 barrels of oil are spilling into the Gulf each day, what he calls a sobering finding, "and neither the government nor the responsible parties have been able to stop it, or even acknowledge that it really existed until now." 

MacDonald says the situation should serve as a warning to regulators as they attempt to expand oil and gas drilling in the Atlantic, where underwater canyons pose a threat to underwater infrastructure.
"The idea that we would be building in deep water, and making pipelines going back to land in an area that's susceptible to those kinds of accidents," he says, "is something that we should take into account as we do our planning." 

But he worries that's not happening. The Trump administration has rolled back offshore safety rules, even as it works to open up more areas to drilling.

A giant containment dome

Earlier this year, the Coast Guard began hiring contractors to try to stop the spill by dropping a giant metal containment dome over the wells in order to collect the leaking oil. Taylor Energy says this could make the leak worse, so it has sued the Coast Guard. 

Neither the government nor the company agreed to go on record, saying litigation is ongoing.
Back on the boat in the Gulf, MacDonald remains hopeful. 

"I'm really glad to be out here and to see this operation," he says, " because it's been a long time coming, and there's a lot riding on it."

But he says it might be that no one is able to stop the oil from bubbling up into the Gulf. If that's the case, according to government estimates, the leak could go on for 100 more years.

Tuesday, April 9, 2019

Oil slips from five-month high as Russia signals output boost

Libyan tribesmen staged a protest on Saturday at the giant El Sharara oilfield aiming to shut down the facility. The oilfield pictured in 2014. (Reuters)

LONDON (Reuters) - Oil slipped from a five-month high above $71 a barrel on Tuesday as Russian comments signaling the possible easing of a supply-cutting deal with OPEC countered concern that violence in Libya could further tighten global markets.

Supply curbs led by the Organization of the Petroleum Exporting Countries have underpinned a more than 30 percent rally this year for Brent crude, despite downward pressure from fears of an economic slowdown and weaker demand. 

Brent, the global benchmark, rose to $71.34 a barrel, the highest since November, but by 1349 GMT was down 59 cents at $70.51. U.S. crude also hit a November 2018 high of $64.79 but was later down 23 cents at $64.17. 

“The mood is increasingly turning bullish, but several feedback loops are about to start spinning that stand in the way of a prolonged oil rally,” said Norbert Ruecker of Swiss bank Julius Baer. 

“Russia already signaled its willingness to raise oil output from June. Fuel remains costly in emerging markets, with soft currencies adding to high oil prices.” 

Russia, a participant in the OPEC-led supply cuts that expire in June, signaled on Monday it wants to raise output when it next meets with OPEC because of falling stockpiles.

On Tuesday, President Vladimir Putin said Russia did not support an uncontrollable rise in oil prices and that the current price suited Moscow. 

U.S. sanctions on Iran and Venezuela have deepened the OPEC supply cut and concern has grown this week about the stability of Libyan output. The OPEC member pumps around 1.1 million barrels per day, just over 1 percent of global supply. 

“The oil market is already undersupplied, so if supply from Libya also falls away the supply deficit will become even bigger,” said Carsten Fritsch, oil analyst at Commerzbank. 

On Monday, a warplane attacked Tripoli’s only functioning airport as eastern forces advancing on the Libyan capital disregarded international appeals for a truce. 

Yet despite generally bullish sentiment, concerns that an economic slowdown this year will hit fuel consumption have been preventing crude prices from rising even higher, traders said. 

The International Monetary Fund on Tuesday cut its global economic growth forecast for 2019.

Increases in U.S. crude inventories have also put a lid on gains. U.S. crude stocks are forecast to have risen by 2.5 million barrels last week, the third straight weekly addition. 

The American Petroleum Institute, an industry group, issues its supply report at 2030 GMT, ahead of Wednesday’s official figures. 

Additional reporting by Henning Gloystein; Editing by Dale Hudson and David Evans

Monday, April 8, 2019

The Biggest Oil & Gas Companies in 2018

 Sinopec logo. Picture: Twitter.

Sinopec continued to lead the world’s biggest oil and gas companies in 2018, enjoying a double-digit revenue growth when compared to 2017.

The majority of the ten biggest witnessed a similar double-digit growth, which was as high as 31.4% for Rosneft. profiles the ten biggest oil and gas companies by 2018 revenues, excluding the state-owned Saudi Aramco.

Index of this series of articles covering the top 10 Oil & Gas companies:
  • 10. Phillips 66
  • 9. Lukoil
  • 8. Rosneft
  • 7. Chevron
  • 6. Total
  • 5. ExxonMobil
  • Numbers 4, 3, 2 and 1 will be published on April 9nd, 2019

7. Chevron – $158.9bn

US-based multinational energy corporation Chevron reported a 17.99% year-on-year revenue growth to $158.90bn in 2018. The company’s net oil-equivalent production in 2018 averaged at 2.93Mbpd, compared with 2.73Mbpd in 2017. The net liquid production was 1.78Mbpd, whereas the net natural gas production was 6.9bcfd.

With an average refinery input of 1.61Mbpd, the company’s sales of refined products stood at 2.6Mbpd. The company’s top six refineries in Singapore, Thailand and South Korea, as well as the US states of California and Mississippi, comprise more than 90% of its total crude oil refining capacity.

The company’s ongoing flagship projects include Gorgon, Wheatstone, Tengiz Expansion, Big Foot, Mafumeira Sul, Alder, and Angola LNG. In December 2018Chevron announced a $20bn ($17.3bn upstream and $2.5bn downstream) investment programme for 2019.

6. Total – $209.36bn

French energy company Total’s revenues increased by 22.08% to $209.36bn in 2018. The refinery and chemical segment contributed 44%, while the marketing and services segment accounted for 43%, and the exploration and production segment had a 5.25% share of the total revenue.

The company’s total hydrocarbon production increased by 8.1% to 2.78Mboe/d in 2018. Liquids production increased by 16% to 1.56Mbpd, while gas production decreased by 1% to 6.59bcfd. Its refinery throughput increased by 1% to 1.85Mbpd in the year.

The major project start-ups and ramp-ups during the year included the Egina field, Yamal LNG, Moho Nord, Fort Hills, Kashagan, Kaombo Norte, and Ichthys.

5. ExxonMobil – $290.2bn

US-based oil and gas major ExxonMobil’s revenue increased by 18.76% to reach $290.2bn in 2018. The company produced 2.26Mbpd of liquids and 9.4 billion cubic metres (bcm) of natural gas a day in 2018.

With a refinery throughput of 4.27Mbpd, ExxonMobil reported average petroleum product sales of 5.5Mbpd in 2018. The US market accounted for 2.2Mbpd of the company’s petroleum product sales, while 1.55Mbpd was sold in the European market.

ExxonMobil made its final investment decision to develop the West Barracouta gas field in Bass Strait to bring gas supplies to the Australian domestic market. It also secured LNG offtake commitments for its upcoming Rovuma LNG project in Mozambique during the year.

Saturday, April 6, 2019

Instagram playboy is also the vice-president of Equatorial Guinea | The ...

The Permian Basin Is Now The World's Top Oil Producer

 uncaptioned image
Pump jacks extract crude oil from oil wells in Midland, Texas, U.S., on Monday, Dec. 17, 2018. Recent reports indicate that the Permian Basin underlying Midland may now be the world's most productive oil-producing region. Photographer: Angus Mordant/Bloomberg
© 2018 Bloomberg Finance LP

Last week Saudi Aramco -- the national oil company of Saudi Arabia and the world's largest oil company -- lifted a veil of secrecy around the company's operations. For the first time in decades, operational details for Saudi Aramco were revealed in a bond offering. (A PDF link of the prospectus is here).

The immediate takeaway -- which I covered in the previous article -- was that the breakeven costs for Saudi Aramco were higher than the numbers that are frequently reported. However, other news stories have focused on an apparent bombshell around production at the Saudi Ghawar oilfield, which is the world’s largest conventional onshore oil field.

Conventional wisdom held that Ghawar has been producing 5 million barrels per day (BPD) of crude oil for decades. The prospectus notes that Ghawar has produced more than half of the Kingdom's cumulative oil production to date, but it reported that 2018 production was only 3.8 million BPD.

That number resulted in several stories that suggested that Ghawar production has peaked and is falling fast. (For example: The Biggest Saudi Oil Field Is Fading Faster Than Anyone Guessed).

I don't believe this number alone supports such conclusions. I think it is an example of confirmation bias, which refers to a person's tendency to interpret information as confirmation of existing beliefs.

There is another possible interpretation. Saudi Arabia has long played the role of the world's swing producer in the oil markets. They maintain spare production capacity. This has allowed them to raise and lower production according to their views of market demand and agreed-upon OPEC quotas. 
So, it is quite possible that Ghawar is simply not operating at full capacity. Given the information from the prospectus, one can just as easily make this conclusion as to conclude that Ghawar production is in decline. I don't know which interpretation is correct, but we shouldn't make hasty conclusions based on limited information.

Notably, the people most likely to accept the interpretation that Ghawar is rapidly declining are the same people who reject Saudi Arabia's claim -- repeated in the prospectus -- that its oil and gas reserves are equivalent to 257 billion barrels. Again, unless there is good objective reasoning for rejecting a reserves number while embracing a production number, this may be confirmation bias in action.

The prospectus breaks up Saudi reserves into six different categories. Ghawar is the second-largest, with a reported 58 billion barrels of combined (oil and gas) reserves. The largest category is "Other", with 100 billion barrels of reported reserves and 3.6 million BPD of reported production in 2018. That suggests that Saudi is producing a lot of oil outside of the well-known fields.

So, we can't know for sure whether Ghawar is declining (which would indeed be huge news), but there are two significant conclusions we can make based on the reported production number.

One is that if Ghawar is declining, Saudi has managed to more than make up for the loss of production in other oil fields. Saudi Aramco has increased production by about 2 million BPD since 2010.

But the second conclusion may be of more immediate interest to Americans.

Last December I wrote Why The Permian Basin May Become The World's Most Productive Oil Field. In the article, I listed three reasons that I thought the Permian Basin would eventually push Ghawar for the title of the world's top-producing oil field.

We don't know for certain the reasons, but we now have this report from Saudi Aramco that Ghawar produced 3.8 million BPD in 2018. The Energy Information Administration reports that the Permian Basin is now producing 4.2 million BPD. For all of 2018 the Permian Basin averaged 3.4 million BPD, but production during the year increased by 1.1 million BPD. Production hit the 3.8 million BPD mark in October and has risen in every month since then.

So, we can reasonably conclude that right now -- regardless of the reason -- the Permian Basin has overtaken Ghawar as the world's top oil-producer. That may not last if Saudi is constraining production in Ghawar, or if Permian production slows down anytime soon. But it marks the first time in decades that Ghawar wasn't the top-producing oil field in the world.

Robert Rapier has over 25 years of experience in the energy industry as an engineer and an investor. Follow him on Twitter @rrapier or at Investing Daily.

Friday, April 5, 2019

Markets - recycling slowing down


After a frantic period of activity throughout most of March, sales slowed last week.
Surprisingly, India lost several high profile HKC SoC vessels for green recycling to the only RINA approved yard in Bangladesh, GMS said in its weekly report.
However, given that this yard has taken in its quota, India returned to buying last week with a few interesting (market and private) green recycling sales reported.
At Gadani, since a majority of the local recycling yards have been empty for some time, we finally witnessed the Pakistani market waking up as appetite seemed to grow last week.
Even though the price gap remains significant at present, it may not be long before we see Gadani buyers competing against their Indian counterparts, on standard vessels once again, GMS said.
Bangladesh remained the point of reference for most of the market tonnage – with rates almost $20 per ldt above their nearest competitors.
However, as has been expected for some time, Bangladesh maybe due for a breather in the month(s) ahead and we may see the focus start to shift back to the Indian and Pakistani markets once again.
Meanwhile, the Indian market has been enjoying its share of cheaper priced units this year, with many offshore vessels and rigs heading its way, in addition to those units intended for strictly HKC SoC green recycling.
The only competitive RINA approved HKC yard in Bangladesh is now full, having secured two large ldt vessels, including a Vale capesize sold recently.
Turkish steel plate prices fell again last week, although prices managed to stay buoyant amidst strong local demand on the back of a dearth of tonnage, that has kept Aliaga buyers surprisingly aggressive in recent weeks.
With the first quarter of 2019 now concluded and charter rates, particularly in the dry sector, still in the doldrums, the supply of tonnage (older Capes in particular) is set to continue, as we head into the second quarter of the year, GMS concluded.
Brokers reported the sale of the 1999-built OBOs - ‘SKS Tanaro’ and ‘SKS Tiete’ - to Indian interests for just over $430 per ldt per vessel.

Second attack in Venezuelan waters in a week

Oil History in Venezuela

Armed robbers boarded a tanker at Anchorage on 28th March, the IMB Piracy Reporting Centre reported.
Five persons armed with knives and a pipe wrench boarded the tanker and tied up the aft watch keeper.

They subsequently broke into the ship’s paint store, the IMB said.

Once the alarm was raised and crew mustered, the robbers escaped with some of the  ship’s stores.
This is the second robber attack on a tanker to take place at the same anchorage within seven days.

The first occured on 21st March when three robbers boarded a crude oil tanker.

They threatened a crew member with a knife and stole his radio before escaping.

Thursday, April 4, 2019

Key OPEC oil producer Libya is on the brink of war as general orders forces into Tripoli

Members of a brigade headed by field commander Salah Bogheib and loyal to Khalifa Haftar -a retired general and former chief of staff for Moamer Kadhafi- hold up their guns as they fight alongside Libyan army troops against Islamist gunmen in the eastern Libyan city of Benghazi.
Abdullah Doma | AFP | Getty Images
  • Libya's eastern military leader orders his forces to march into Tripoli, the seat of a rival United Nations-recognized government.
  • "Those who lay down their weapons are safe, and those who raise the white banner are safe," Haftar says.
  • General Khalifa Haftar holds the nation's eastern oil terminals and his forces have moved south recently to secure Libya's oil fields.

Members of a brigade headed by field commander Salah Bogheib and loyal to Khalifa Haftar -a retired general and former chief of staff for Moamer Kadhafi- hold up their guns as they fight alongside Libyan army troops against Islamist gunmen in the eastern Libyan city of Benghazi.
Libya's eastern military leader has ordered his forces to march on Tripoli, sparking concerns that open war could soon break out between the main political factions in a key oil-producing nation.

The OPEC member state has been riven by conflict since the fall of dictator Muammar Qaddafi in 2011. For much of that time, General Khalifa Haftar has held the country's east, drawing support from Egypt and the United Arab Emirates and serving as a foil to the United Nations-recognized government in the capital of Tripoli.

The two sides have been engaged in UN-sponsored power-sharing talks. But on Wednesday, Haftar's Libyan National Army unexpectedly advanced towards Tripoli. Skirmishes between the LNA and forces loyal to Prime Minister Fayez al-Serraj have since been reported.

Earlier, it remained unclear whether Haftar intended to bring the west under his grip or merely increase his leverage ahead of a national conference later this month. UN Secretary-General Antonio Guterres, who is in Libya to meet with leaders, called for calm and restraint.

But the order to enter Tripoli came in the early evening in Libya in a voice recording from Haftar posted online, the Associated Press reported. The general told his troops only to raise their weapons "in the face of those who seek injustice and prefer confrontation and fighting," according to AP.

"Those who lay down their weapons are safe, and those who raise the white banner are safe," he said.
This year, Haftar's LNA forces have already sought to bring order to the restive southern oil-producing region. But a campaign to take Tripoli could be even more grueling, says Hamish Kinnear, senior analyst for the Middle East and North Africa at Verisk Maplecroft.

"Our base case is that the LNA will soon find itself bogged down in heavy fighting near Tripoli," Kinnear said in an email briefing. "Unlike its recent advance in the south, the LNA will face more determined resistance from larger and better organised militias in the western region."

The LNA's strategy of bringing the south's small, opportunistic militias under its umbrella through negotiation and bribes would not be effective in the east, Kinnear says. Despite controlling oil terminals, Haftar's forces would also struggle to finance a prolonged conflict because his eastern faction does not hold sway over Libya's National Oil Corporation and the central bank, he added.

The advance of Haftar's LNA answers the "million dollar question" Libya watchers have been asking for years, says Helima Croft, global head of commodity strategy at RBC Capital Markets. Will Haftar finally seek to consolidate control over Libya's northern coast, leaving the nation's eastern oil terminals vulnerable to his rivals?

"Certainly, if he's going to take control of Tripoli by force, the question is what does that mean for these sizable energy assets that are under his control in the east?" Croft said.

The looming conflict comes at a time when global crude supplies are tightening and oil prices are steadily advancing towards $70 a barrel. On the demand side, global consumption is growing faster than many expected. On the supply side, OPEC and its allies led by Russia are cutting output while the U.S. is poised to tighten energy sanctions on Iran and Venezuela.

Analysts and traders keep a close eye on Libya because its oil production has been one of the biggest wild cards in the oil market in recent years. Its output has fluctuated wildly as the nation's southern oil fields have frequently gone offline amid fighting among Libya's patchwork of militias and tribal and ethnic groups. Haftar also briefly lost control of the Ras Lanuf and Sidra oil terminals last year.

If Haftar takes control of the west, it could be negative for oil prices because consolidated leadership could allow more crude to flow to the market from Libya, says Croft.

However, Croft cautions that it would be difficult for any leader to impose order across the fractious country, and a battle in Tripoli could be a prelude to prolonged fighting. Holding Tripoli, the east and the south could stretch the LNA's capacity to the breaking point.

"The problem with the south is it's like the Wild West down there," she said. "There are so many competing militias down there. You have a community that feels so marginalized, that is heavily armed."

"To me, that's a powder keg."

Pence calls on Venezuela to release US workers

Wednesday, April 3, 2019

The Biggest Saudi Oil Field Is Fading Faster Than Anyone Guessed

Saudi Aramco's Shaybah Oil Field 
 Flames burn off at an oil processing facility at Saudi Aramco’s Shaybah oil field.Photographer: Simon Dawson/Bloomberg
  • Ghawar can pump 3.8 million barrels a day, less than expected
  • Bond prospectus give details of the kingdom’s largest fields
It was a state secret and the source of a kingdom’s riches. It was so important that U.S. military planners once debated how to seize it by force. For oil traders, it was a source of endless speculation.

Now the market finally knows: Ghawar in Saudi Arabia, the world’s largest conventional oil field, can produce a lot less than almost anyone believed.

When Saudi Aramco on Monday published its first ever profit figures since its nationalization nearly 40 years ago, it also lifted the veil of secrecy around its mega oil fields. The company’s bond prospectus revealed that Ghawar is able to pump a maximum of 3.8 million barrels a day -- well below the more than 5 million that had become conventional wisdom in the market.

“As Saudi’s largest field, a surprisingly low production capacity figure from Ghawar is the stand-out of the report,” said Virendra Chauhan, head of upstream at consultant Energy Aspects Ltd. in Singapore.

The Energy Information Administration, a U.S. government body that provides statistical information and often is used as a benchmark by the oil market, listed Ghawar’s production capacity at 5.8 million barrels a day in 2017. Aramco, in a presentation in Washington in 2004 when it tried to debunk the “peak oil” supply theories of the late U.S. oil banker Matt Simmons, also said the field was pumping more than 5 million barrels a day, and had been doing so since at least the previous decade.

In his book “Twilight in the Desert,” Simmons argued that Saudi Arabia would struggle to boost production due to the imminent depletion of Ghawar, among other factors. “Field-by-field production reports disappeared behind a wall of secrecy over two decades ago,” he wrote in his book in reference to Aramco’s nationalization.

The new details about Ghawar prove one of Simmons’s points but he missed other changes in technology that allowed Saudi Arabia -- and, more importantly, U.S. shale producers -- to boost output significantly, with global oil production yet to peak.

The prospectus offered no information about why Ghawar can produce today a quarter less than 15 years ago -- a significant reduction for any oil field. The report also didn’t say whether capacity would continue to decline at a similar rate in the future.

In response to a request for comment, Aramco referred back to the bond prospectus without elaborating.

Lost Crown

The new maximum production rate for Ghawar means that the Permian in the U.S., which pumped 4.1 million barrels a day last month according to government data, is already the largest oil production basin. The comparison isn’t exact -- the Saudi field is a conventional reservoir, while the Permian is an unconventional shale formation -- yet it shows the shifting balance of power in the market.

Ghawar, which is about 174 miles long -- or about the distance from New York to Baltimore -- is so important for Saudi Arabia because the field has “accounted for more than half of the total cumulative crude oil production in the kingdom,” according to the bond prospectus. The country has been pumping since the discovery of the Dammam No. 7 well in 1938.

On top of Ghawar, which was found in 1948 by an American geologist, Saudi Arabia relies heavily on two other mega-fields: Khurais, which was discovered in 1957, and can pump 1.45 million barrels a day, and Safaniyah, found in 1951 and still today the world’s largest offshore oil field with capacity of 1.3 million barrels a day. In total, Aramco operates 101 oil fields.

The 470-page bond prospectus confirms that Saudi Aramco is able to pump a maximum of 12 million barrels a day -- as Riyadh has said for several years. The kingdom has access to another 500,000 barrels a day of output capacity in the so-called neutral zone shared with Kuwait. That area isn’t producing anything now due a political dispute with its neighbor.

While the prospectus confirmed the overall maximum production capacity, the split among fields is different to what the market had assumed. As a policy, Saudi Arabia keeps about 1 million to 2 million barrels a day of its capacity in reserve, using it only during wars, disruptions elsewhere or unusually strong demand. Saudi Arabia briefly pumped a record of more than 11 million barrels a day in late 2018.

“The company also uses this spare capacity as an alternative supply option in case of unplanned production outages at any field and to maintain its production levels during routine field maintenance,” Aramco said in its prospectus.

Costly Strategy

For Aramco, that’s a significant cost, as it has invested billions of dollars into facilities that aren’t regularly used. However, the company said the ability to tap its spare capacity also allows it to profit handsomely at times of market tightness, providing an extra $35.5 billion in revenue from 2013 to 2018. Last year, Saudi Energy Minister Khalid Al-Falih said maintaining this supply buffer costs about $2 billion a year.

Aramco also disclosed reserves at its top-five fields, revealing that some of them have shorter lifespans than previously thought. Ghawar, for example, has 48.2 billion barrels of oil left, which would last another 34 years at the maximum rate of production. Nonetheless, companies are often able to boost the reserves over time by deploying new techniques or technology.

In total, the kingdom has 226 billion barrels of reserves, enough for another 52 years of production at the maximum capacity of 12 million barrels a day.

The Saudis also told the world that their fields are aging better than expected, with “low depletion rates of 1 percent to 2 percent per year,” slower than the 5 percent decline some analysts suspected.

Yet, it also said that some of its reserves -- about a fifth of the total -- had been drilled so systematically over nearly a century that more than 40 percent of their oil has been already extracted, a considerable figure for an industry that usually struggles to recover more than half the barrels in place underground.