The next OPEC meeting on the 2 June will act as little more than a forum for continued altercations between Saudi Arabia and Iran.
The 2 June 2016 OPEC meeting will be held amid a backdrop of oil prices near US$50 per barrel, a sharp drop in Nigerian production due to sabotage, turmoil in Venezuela, Saudi Arabia operating with a new oil minister, and Iran aggressively pumping close to pre-sanction levels.
OPEC interactions have become a direct altercation between Saudi Arabia and Iran, with the remaining members reduced to mere observers.
The new Saudi oil minister, Khalid al-Falih, will be attending his first OPEC meeting, but experts doubt he will have the same clout and skills as the outgoing Saudi oil minister, Ali bin Ibrahim Al-Naimi.
"OPEC's unity is now in the spotlight more than ever," said an OPEC official. "Would we ever see a minister that carries the same weight as Naimi? I don't think so, especially as it is clear now that decisions are in the hands of the deputy crown prince," reports The Wall Street Journal.
The Prince outlined his strategy in "Vision 2030", and a major step in that direction is the listing of the state-owned oil company Aramco.
In order to gain additional traction for the proposed listing, the Saudis will continue their aggressive stance in OPEC, and keep all the oil producers on the hook, a glimpse of which was given by the new Saudi Aramco Chief Executive Amin Nasser.
"Whatever the call on Saudi Aramco, we will meet it," Mr. Nasser said. "There will always be a need for additional production. Production will increase upward in 2016," reports The Financial Times.
Though Mr. Nasser did not hint at the percentage increase, even a small increase will add to the supply glut, because Aramco produces around 9.54 MM bopd.
On the other hand, its adversary—Iran—has quickly ramped up production to 3.56 MM bopd and is on course to reach its targeted output of 4 MM bopd. Iran has increased its market share in the excess supply environment by offering large discounts, undercutting the Saudi and Iraqi prices for their deliveries to Asia. Though Iran had initially hinted at joining any production freeze once it reached its target of 4 MM bopd, the heightened tensions with Saudi show no signs of abating.
"Our main competitor is Saudi Arabia," Amir Hossein Zamaninia, Iran's deputy oil minister for international affairs, said in an interview with The Wall Street Journal.
Mr. Zamaninia said Iran disapproves of increased politicisation of the OPEC. "In the Southern Persian Gulf, oil is becoming a political commodity, more than an economic commodity," he said. "OPEC is in a difficult situation."
He said that without solutions to the conflicts in Syria and Yemen, an agreement is unlikely.
The relations between the two warring nations have reached a new low, with Iran refusing participation in the Hajj pilgrimage. The negotiations between the delegates of the two nations ended in conflict. Considering the existing tensions between Iran and Saudi Arabia, if the OPEC meeting ends without a fight, it should be considered an achievement.
The proposal by the Kuwaiti deputy foreign minister Khaled Jarallah for the member nations to freeze production is a feeble attempt to support prices.
"It is clear that Mohammed bin Salman wants to confront Iran not just in the Middle East but in the energy markets," Amir Handjani, a member of the Board of Directors of the Dubai-based RAK Petroleum, told RT. He said that it was unlikely that Prince Salman will back down now. "And certainly the Iranians are not going to back down either," reports Hellenic Shipping News.
While these two nations continue their slugfest in the OPEC meeting, the smaller nations have no choice but to remain mute spectators, dreaming of their glory days.
Rakesh Upadhyay, Oilprice.com, 23 May 2016
Something interesting to share?
Join NrgEdge and create your own NrgBuzz today
Headline crude prices for the week beginning 12 August 2019 – Brent: US$58/b; WTI: US$54/b
Headlines of the week
The momentum for crude prices abated in the second quarter of 2019, providing less cushion for the financial results of the world’s oil companies. But while still profitable, the less-than-ideal crude prices led to mixed results across the boards – exposing gaps and pressure points for individual firms masked by stronger prices in Q119.
In a preview of general performance in the industry, Total – traditionally the first of the supermajors to release its earnings – announced results that fell short of expectations. Net profits for the French firm fell to US$2.89 billion from US$3.55 billion, below analyst predictions. This was despite a 9% increase in oil and gas production – in particularly increases in LNG sales – and a softer 2.5% drop in revenue. Total also announced that it would be selling off US$5 billion in assets through 2020 to keep a lid on debt after agreeing to purchase Anadarko Petroleum’s African assets for US$8.8 billion through Occidental.
As with Total, weaker crude prices were the common factor in Q219 results in the industry, though the exact extent differed. Russia’s Gazprom posted higher revenue and higher net profits, while Norway’s Equinor reported falls in both revenue and net profits – leading it to slash investment plans for the year. American producer ConocoPhillips’ quarterly profits and revenue were flat year-on-year, while Italy’s Eni – which has seen major success in Africa – reported flat revenue but lower profits.
After several quarters of disappointing analysts, ExxonMobil managed to beat expectations in Q219 – recording better-than-expected net profits of US$3.1 billion. In comparison, Shell – which has outperformed ExxonMobil over the past few reporting periods – disappointed the market with net profits halving to US$3 billion from US$6 billion in Q218. The weak performance was attributed (once again) to lower crude prices, as well as lower refining margins. BP, however, managed to beat expectations with net profits of US$2.8 billion, on par with its performance in Q218. But the supermajor king of the quarter was Chevron, with net profits of US$4.3 billion from gains in Permian production, as well as the termination fee from Anadarko after the latter walked away from a buyout deal in favour of Occidental.
And then, there was a surprise. In a rare move, Saudi Aramco – long reputed to be the world’s largest and most profitable energy firm – published its earnings report for 1H19, which is its first ever. The results confirmed what the industry had long accepted as fact: net profit was US$46.9 billion. If split evenly, Aramco’s net profits would be more than the five supermajors combined in Q219. Interestingly, Aramco also divulged that it had paid out US$46.4 billion in dividends, or 99% of its net profit. US$20 billion of that dividend was paid to its principle shareholder – the government of Saudi Arabia – up from US$6 billion in 1H18, which makes for interesting reading to potential investors as Aramco makes a second push for an IPO. With Saudi Aramco CFO Khalid al-Dabbagh announcing that the company was ‘ready for the IPO’ during its first ever earnings call, this reporting paves the way to the behemoth opening up its shares to the public. But all the deep reservoirs in the world did not shield Aramco from market forces. As it led the way in adhering to the OPEC+ club’s current supply restrictions, weaker crude prices saw net profit fall by 11.5% from US$53 billion a year earlier.
So, it’s been a mixed bunch of results this quarter – which perhaps showcases the differences in operational strategies of the world’s oil and gas companies. There is no danger of financials heading into the red any time soon, but without a rising tide of crude prices, Q219 simply shows that though the challenges facing the industry are the same, their approaches to the solutions still differ.
Supermajor Financials: Q2 2019
Source: U.S. Energy Information Administration, CEDIGAZ, Global Trade Tracker
Australia is on track to surpass Qatar as the world’s largest liquefied natural gas (LNG) exporter, according to Australia’s Department of Industry, Innovation, and Science (DIIS). Australia already surpasses Qatar in LNG export capacity and exported more LNG than Qatar in November 2018 and April 2019. Within the next year, as Australia’s newly commissioned projects ramp up and operate at full capacity, EIA expects Australia to consistently export more LNG than Qatar.
Australia’s LNG export capacity increased from 2.6 billion cubic feet per day (Bcf/d) in 2011 to more than 11.4 Bcf/d in 2019. Australia’s DIIS forecasts that Australian LNG exports will grow to 10.8 Bcf/d by 2020–21 once the recently commissioned Wheatstone, Ichthys, and Prelude floating LNG (FLNG) projects ramp up to full production. Prelude FLNG, a barge located offshore in northwestern Australia, was the last of the eight new LNG export projects that came online in Australia in 2012 through 2018 as part of a major LNG capacity buildout.
Source: U.S. Energy Information Administration, based on International Group of Liquefied Natural Gas Importers (GIIGNL), trade press
Note: Project’s online date reflects shipment of the first LNG cargo. North West Shelf Trains 1–2 have been in operation since 1989, Train 3 since 1992, Train 4 since 2004, and Train 5 since 2008.
Starting in 2012, five LNG export projects were developed in northwestern Australia: onshore projects Pluto, Gorgon, Wheatstone, and Ichthys, and the offshore Prelude FLNG. The total LNG export capacity in northwestern Australia is now 8.1 Bcf/d. In eastern Australia, three LNG export projects were completed in 2015 and 2016 on Curtis Island in Queensland—Queensland Curtis, Gladstone, and Australia Pacific—with a combined nameplate capacity of 3.4 Bcf/d. All three projects in eastern Australia use natural gas from coalbed methane as a feedstock to produce LNG.
Source: U.S. Energy Information Administration
Most of Australia’s LNG is exported under long-term contracts to three countries: Japan, China, and South Korea. An increasing share of Australia’s LNG exports in recent years has been sent to China to serve its growing natural gas demand. The remaining volumes were almost entirely exported to other countries in Asia, with occasional small volumes exported to destinations outside of Asia.
Source: U.S. Energy Information Administration, based on International Group of Liquefied Natural Gas Importers (GIIGNL)
For several years, Australia’s natural gas markets in eastern states have been experiencing natural gas shortages and increasing prices because coal-bed methane production at some LNG export facilities in Queensland has not been meeting LNG export commitments. During these shortfalls, project developers have been supplementing their own production with natural gas purchased from the domestic market. The Australian government implemented several initiatives to address domestic natural gas production shortages in eastern states.
Several private companies proposed to develop LNG import terminals in southeastern Australia. Of the five proposed LNG import projects, Port Kembla LNG (proposed import capacity of 0.3 Bcf/d) is in the most advanced stage, having secured the necessary siting permits and an offtake contract with Australian customers. If built, the Port Kembla project will use the floating storage and regasification unit (FSRU) Höegh Galleon starting in January 2021.