Total global oil production could decline for the next several years in a row as scarce new sources of supply come online.
According to data from Rystad Energy, overall global oil output will fall this year as natural depletion overwhelms all new sources of supply. But the deficit will only widen in the years ahead due to the dramatic scaling back in spending on new exploration and development.
Statoil says that global capex is set to fall for two years in a row, and is on track to fall for a third year in 2017 as more spending cuts are likely. "For the first time in history, we've seen cutting of capex two years in a row and potentially we risk a third year as well for 2017," Statoil's Chief Financial Officer Hans Jakob Hegge told Bloomberg in a recent interview. "It might be that we see quite a dramatic reduction in replacing the capacity and of course that will have an impact, eventually, on price."
Oil companies are making painful cuts to spending, which will translate into much lower production than expected in the years ahead.
Although markets have dealt with the supply overhang for the better part of two years, the surplus could flip to a deficit as early as this year, as declines exceed new sources of production by a few hundred thousand barrels per day. That widens to more than a million barrels per day in both 2017 and 2018. To be sure, there are extremely large volumes of oil sitting in storage, which will take a few years to work through. That will prevent any short-term price spike even if depletion surpasses new production. But Statoil's CFO said the world could start to see supply problems by 2020.
According to a separate report from SAFE, a Washington-based think tank, the oil industry has cut somewhere around US$225 billion in capex in 2015 and 2016, which will lead to global supplies 4 MM bopd lower in 2018-2020, compared to what market analysts expected as of 2014.
Of course, these figures are not inevitable. A sharp rise in oil prices would spur new investment and new drilling. In other words, deficits create profit opportunities for drillers, ushering in new supplies. The price acts as a self-correcting mechanism.
The problem is that, unlike many other industries, resource extraction is extremely volatile, with supply responses very delayed. Many oil projects, after all, take years to develop. Supply overshot demand, crashed prices, and in response, supplies will undershoot demand in the next few years. The industry has always suffered from booms and busts, and there is little reason to think that it will change, at least in the short run.
But we tend to have a myopic view on what to expect. When oil prices go up, people buy fuel efficient cars. When they go down, SUVs are back in style. When the world is dealing with too much supply, market watchers predict oil prices will stay low for years to come. If spot oil prices suddenly rise, forecasts are revised sharply upwards.
Here's another example: the WSJ reports that oil prices are entering a 'sweet spot,' a range between US$50 and US$60 per barrel that could finally be good for the global economy – low enough to provide consumers with a bit of a stimulus, but high enough to keep the industry and capital spending afloat.
Also, crude at US$50, as opposed to US$30, can provide a bit of inflation to the deflation-beset economies in Europe and Japan. "Crude between US$50 and US$60 would be the absolute sweet spot," Mark Watkins, regional investment manager at US Bank Wealth Management, told the WSJ. "Everybody wins there."
That is all well and good, but who expects oil to trade between US$50 and US$60 for any lengthy period of time? If there is one thing that we have learned over the past two years, it is that nobody has a crystal ball on prices. And if the industry indeed cuts capex for three consecutive years, at a time when demand continues to rise, the one thing we can be sure of is more volatility.
Nick Cunningham, Oilprice.com; additional material: Brian Wickins, 1 Jun 2016
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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.