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 20 May 2019 – Brent: US$73/b; WTI: US$63/b
Headlines of the week
Midstream & Downstream
At first, it seemed like a done deal. Chevron made a US$33 billion offer to take over US-based upstream independent Anadarko Petroleum. It was a 39% premium to Anadarko’s last traded price at the time and would have been the largest industry deal since Shell’s US$61 billion takeover of the BG Group in 2015. The deal would have given Chevron significant and synergistic acreage in the Permian Basin along with new potential in US midstream, as well as Anadarko’s high potential projects in Africa. Then Occidental Petroleum swooped in at the eleventh hour, making the delicious new bid and pulling the carpet out from under Chevron.
We can thank Warren Buffet for this. Occidental Petroleum, or Oxy, had previously made several quiet approaches to purchase Anadarko. These were rebuffed in favour of Chevron’s. Then Oxy’s CEO Vicki Hollub took the company jet to meet with Buffet. Playing to his reported desire to buy into shale, Hollub returned with a US$10 billion cash infusion from Buffet’s Berkshire Hathaway – which was contingent on Oxy’s successful purchase of Anadarko. Hollub also secured a US$8.8 billion commitment from France’s Total to sell off Anadarko’s African assets. With these aces, she then re-approached Anadarko with a new deal – for US$38 billion.
This could have sparked off a price war. After all, the Chevron-Anadarko deal made a lot of sense – securing premium spots in the prolific Permian, creating a 120 sq.km corridor in the sweet spot of the shale basin, the Delaware. But the risk-adverse appetite of Chevron’s CEO Michael Wirth returned, and Chevron declined to increase its offer. By bowing out of the bid, Wirth said ‘Cost and capital discipline always matters…. winning in any environment doesn’t mean winning at any cost… for the sake for doing a deal.” Chevron walks away with a termination fee of US$1 billion and the scuppered dreams of matching ExxonMobil in size.
And so Oxy was victorious, capping off a two-year pursuit by Hollub for Anadarko – which only went public after the Chevron bid. This new ‘global energy leader’ has a combined 1.3 mmb/d boe production, but instead of leveraging Anadarko’s more international spread of operations, Oxy is looking for a future that is significantly more domestic.
The Oxy-Anadarko marriage will make Occidental the undisputed top producer in the Permian Basin, the hottest of all current oil and gas hotspots. Oxy was once a more international player, under former CEO Armand Hammer, who took Occidental to Libya, Peru, Venezuela, Bolivia, the Congo and other developing markets. A downturn in the 1990s led to a refocusing of operations on the US, with Oxy being one of the first companies to research extracting shale oil. And so, as the deal was done, Anadarko’s promising projects in Africa – Area 1 and the Mozambique LNG project, as well as interest in Ghana, Algeria and South Africa – go to Total, which has plenty of synergies to exploit. The retreat back to the US makes sense; Anadarko’s 600,000 acres in the Permian are reportedly the most ‘potentially profitable’ and it also has a major presence in Gulf of Mexico deepwater. Occidental has already identified 10,000 drilling locations in Anadarko areas that are near existing Oxy operations.
While Chevron licks its wounds, it can comfort itself with the fact that it is still the largest current supermajor presence in the Permian, with output there surging 70% in 2018 y-o-y. There could be other targets for acquisitions – Pioneer Natural Resources, Concho Resources or Diamondback Energy – but Chevron’s hunger for takeover seems to have diminished. And with it, the promises of an M&A bonanza in the Permian over 2019.
The Occidental-Anadarko deal:
Source: U.S. Energy Information Administration, Short-Term Energy Outlook
In April 2019, Venezuela's crude oil production averaged 830,000 barrels per day (b/d), down from 1.2 million b/d at the beginning of the year, according to EIA’s May 2019 Short-Term Energy Outlook. This average is the lowest level since January 2003, when a nationwide strike and civil unrest largely brought the operations of Venezuela's state oil company, Petróleos de Venezuela, S.A. (PdVSA), to a halt. Widespread power outages, mismanagement of the country's oil industry, and U.S. sanctions directed at Venezuela's energy sector and PdVSA have all contributed to the recent declines.
Source: U.S. Energy Information Administration, based on Baker Hughes
Venezuela’s oil production has decreased significantly over the last three years. Production declines accelerated in 2018, decreasing by an average of 33,000 b/d each month in 2018, and the rate of decline increased to an average of over 135,000 b/d per month in the first quarter of 2019. The number of active oil rigs—an indicator of future oil production—also fell from nearly 70 rigs in the first quarter of 2016 to 24 rigs in the first quarter of 2019. The declines in Venezuelan crude oil production will have limited effects on the United States, as U.S. imports of Venezuelan crude oil have decreased over the last several years. EIA estimates that U.S. crude oil imports from Venezuela in 2018 averaged 505,000 b/d and were the lowest since 1989.
EIA expects Venezuela's crude oil production to continue decreasing in 2019, and declines may accelerate as sanctions-related deadlines pass. These deadlines include provisions that third-party entities using the U.S. financial system stop transactions with PdVSA by April 28 and that U.S. companies, including oil service companies, involved in the oil sector must cease operations in Venezuela by July 27. Venezuela's chronic shortage of workers across the industry and the departure of U.S. oilfield service companies, among other factors, will contribute to a further decrease in production.
Additionally, U.S. sanctions, as outlined in the January 25, 2019 Executive Order 13857, immediately banned U.S. exports of petroleum products—including unfinished oils that are blended with Venezuela's heavy crude oil for processing—to Venezuela. The Executive Order also required payments for PdVSA-owned petroleum and petroleum products to be placed into an escrow account inaccessible by the company. Preliminary weekly estimates indicate a significant decline in U.S. crude oil imports from Venezuela in February and March, as without direct access to cash payments, PdVSA had little reason to export crude oil to the United States.
India, China, and some European countries continued to receive Venezuela's crude oil, according to data published by ClipperData Inc. Venezuela is likely keeping some crude oil cargoes intended for exports in floating storageuntil it finds buyers for the cargoes.
Source: U.S. Energy Information Administration, Short-Term Energy Outlook, and Clipper Data Inc.
A series of ongoing nationwide power outages in Venezuela that began on March 7 cut electricity to the country's oil-producing areas, likely damaging the reservoirs and associated infrastructure. In the Orinoco Oil Belt area, Venezuela produces extra-heavy crude oil that requires dilution with condensate or other light oils before the oil is sent by pipeline to domestic refineries or export terminals. Venezuela’s upgraders, complex processing units that upgrade the extra-heavy crude oil to help facilitate transport, were shut down in March during the power outages.
If Venezuelan crude or upgraded oil cannot flow as a result of a lack of power to the pumping infrastructure, heavier molecules sink and form a tar-like layer in the pipelines that can hinder the flow from resuming even after the power outages are resolved. However, according to tanker tracking data, Venezuela's main export terminal at Puerto José was apparently able to load crude oil onto vessels between power outages, possibly indicating that the loaded crude oil was taken from onshore storage. For this reason, EIA estimates that Venezuela's production fell at a faster rate than its exports.
EIA forecasts that Venezuela's crude oil production will continue to fall through at least the end of 2020, reflecting further declines in crude oil production capacity. Although EIA does not publish forecasts for individual OPEC countries, it does publish total OPEC crude oil and other liquids production. Further disruptions to Venezuela's production beyond what EIA currently assumes would change this forecast.