Crude prices are heading lower again, rounding out a downbeat week, as the expectation of an OPEC production cut extension is more than outweighed by an ongoing lopsided market. As oversupply fears enter the fray once more, hark, here are five things to consider in oil markets today:
1) OPEC crude exports so far this month are down compared to March, led by a drop from Saudi Arabia and Iran. Nonetheless, total global crude loadings continue to tick higher, holding above 50 million barrels per day.
As our ClipperData illustrate below, global loadings continue to grow - and strongly - on a year-over-year basis, as global producers have ratcheted up output, and more recently, on signs of crude potentially shifting out of onshore storage.
2) While there has been considerable focus of late on the elevated nature of OECD inventories, there has also been the suggestion that crude is instead being drawn down from areas where there is less transparancy and visibility, such as the Caribbean.
Six locations in the Carribbean export crude (not including Curacao, as it is a stepping stone for Venezuelan exports): Trinidad & Tobago, St. Lucia, St. Croix, Cayman Islands, the Bahamas and Aruba. Loadings from these six averaged 400,000 bpd last year. Year-to-date, this number is slightly lower, at 380,000 bpd - but this is due to a slow start to the year; March and April loadings are picking up. There has been one particularly interesting development of late.
Arclight Capital / Freepoint took over the Hovensa refinery complex in St. Croix in early 2016 after a period of inactivity, and is transforming it into a storage hub. We can see from our ClipperData that it started pulling in crude for storage in mid-last year, receiving regular deliveries each month of mostly heavier grades - such as Castilla Blend and Maya.
Its appetite changed this year, pulling in lighter crude instead such as Ekofisk from the North Sea, and WTI in recent months. This makes sense, given that lighter grades are more readily available this year, as heavier and sour crude gets bid up amid the OPEC production cut deal.
In terms of exports from St. Croix, we saw a loading bound for Portugal in November, then a three-month absence. Since the start of March, however, we have seen three loadings. Combine this with a tick higher in loadings from Aruba and St Lucia, and a trend may be potentially emerging.
3) Since the start of the year, non-Canadian companies have sold more than $20 billion of Canadian oil sands assets, as companies switch their focus to short-cycle oil projects instead, such as U.S. shale.
This drying up of international investment has been offset by Canadian companies such as Cenovus Energy, Suncor and Canadian Natural Resources stepping up instead, with the expectation that their local knowledge, relationships and sharing of proprietary technologies will make the oil sands a much more viable option going forward.
Oil sands accounted for 2.4 million barrels per day of production in 2015 (hark, below), accounting for nearly two-thirds of Canadian output.
According to OPEC, total Canadian production rose a further 80,000 bpd last year to average 4.5mn bpd. Ongoing production growth is expected this year, with an increase of 210,000 bpd to average 4.71mn bpd - driven by production ramp ups for both bitumen and synthetic oil projects.
4) Yesterday we looked at drilled but uncompleted wells (DUCs, quack) in the Permian basin. The chart below adds a bit more color, showing both drilled and completed wells. As a reader rightly commented on yesterday's blog, this rise in DUCs is likely due to operators ensuring they maintain their land leases.
The rise in the drilled wells is likely a response to improving confidence in the oil sector, while the rising DUCs point to higher production ahead when market conditions become more favorable (think: services costs and/or oil prices).
The graphic below is also from the Dallas Fed's latest energy indicators, showing the change in the Texas rig count by county from May 2016 to March 2017. The Permian Basin, not surprisingly, has been the biggest beneficiary, accounting for the three counties with the biggest rig count increases: Reeves (+31), Martin (+15) and Howard (+14).
5) Finally, stat of the day comes from this WSJ article, which highlights that Chinese refining capacity has tripled this century, now accounting for 15 percent of the global total (at the end of 2015). This is ~20 percent higher than Chinese domestic demand. CNPC, China's largest oil company, project that refining capacity will increase by 5 percent in 2017, leading to higher product exports going forward.
Countering this view is the implementation of a consumption tax in China on mixed aromatics, light cycle oil and bitumen blend, which could ultimately hit exports of oil products.
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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.