The aftermath of Hurricane Harvey has left devastation in its wake. It dumped some 27 trillion gallons of water on the states of Texas and Louisiana, causing an estimated US$75 billion in damages. From the energy perspective, there were worries that coastal refining centres would be swamped, taking out some of America’s largest refineries, which had shut down as the storm approached. In the immediate wake of the storm, WTI crude oil prices dipped while gasoline prices jumped – as the market predicted that Gulf refineries would be shut for a long while, which would reduce crude intake and cause gasoline shortages.
That didn’t really happen. By Monday, WTI and US gasoline prices were getting back to pre-Harvey levels. It’s true that some two million b/d of refining capacity was disrupted by Harvey, but half of that is already back. All major sites in Houston and Corpus Christi have either restarted or in the process of restarting. The second largest site in the US, ExxonMobil’s Baytown, is already ramping back up to full production. Motiva in Port Arthur, the largest in the US, is still offline, but processing is expected to resume soon. The Doomsday scenario of the Gulf refining network been taken out for months was avoided. The refining business is getting back to usual. On the demand side, it is estimated that some 500,000 cars were flooded across Texas by Harvey. Those cars won’t be driving again. Their owners won’t be in a position to purchase a new car again soon as well. Worries that gasoline would be at a severe shortage, therefore, were unfounded.
In fact, where Harvey is having the most impact is in a surprising place – onshore. This is the first major storm to hit since the shale revolution took off. Gulf hurricanes are not surprise to offshore producers – 20% of offshore Gulf production was shuttered over the weekend, but no lasting damage was suffered with production resuming and losses estimated at a mere 330 kb/d. It is true that the US is a lot less dependent on offshore Gulf production since inland shale production started booming. But for shale players, Harvey is their first taste of Mother Nature’s wrath. The Eagle Ford shale field in Texas was in direct path of Harvey, with some 500,000 b/d of output taken offline – almost half of its usual production. Even when the storm moved away, it left flooded roads and muddy fields in its wake. These will have to subside before production can resume, which could affect 10% of US shale output for at least a month. Further afield, while Harvey didn’t affect the prodigious Permian basin, output there is dependent on pipelines and ports that pass through Houston. Magellan Midstream, for example, closed its Longhorn and Bridgetex pipelines during the storm. It has since restarted them, along with Colonial Pipelines’ Line 1 gasoline pipe, but it is a reminder that so much of American production, refining and export capacity straddles a long coastline that is vulnerable to storms more than a quarter of the year. That applies as much to the string of LNG terminals being built on the coast, as it does to the shale drilling sites far inland.
There is more to come. Harvey was the first major hurricane to make landfall since Wilma in 2005, but it was actually a Category 4. There is a Category 5 – the highest level – currently barreling through the Caribbean. Hurricane Irma is on a course to hit Puerto Rico, Dominica, Cuba and eventually Florida. The governor Florida has already declared a state of emergency. Though there are no major US refining centres in Irma’s path (but some 450 kb/d in the Caribbean will be closed), the storm would sap gasoline demand in its wake – weakening gasoline prices at a time when refining margins are still dicey. And the hurricane season isn’t even over yet.
Harvey, while devastating to the population, turned out to be relatively harmless on the energy infrastructure front. The US Gulf will be hoping it stays that way for the rest of 2017.
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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.