The US Federal Reserve – the arbiter of American monetary policy – has just cut its headline interest rates. It is the first time that the Fed has cut rates in over a decade since the Great Financial Crisis– a sign that a global recession could be impending and that the authorities are preparing for that scenario. Yet oil prices retreated on the move when it should be beneficial to them. Is this move not enough to calm the market, and if so, why?
To understand this, the mechanism of the Fed’s interest rate is key. This is the rate that regulates all other interest rates within the American financial system. Raise it, and all other banks and financial institutions will – theoretically - raise theirs in turn. Lower it, and interest rates across the board should be lowered as well. What just happened is the latter. The Fed has judged that the American economy is slowing down and inflation was too low to support sustained growth. By cutting its rate by 25 points (or 0.25%), the Fed hopes that this will ignite economic activity and rekindle demand. Hypothetically, at least, it will now be cheaper to take out business loans or refinance old ones, creating additional investment. Lower interest rates also make it easier for private borrowing, which should trigger a rise in spending activity, either in consumer goods or in real estate. This expands the market and an expanding market means greater demand for oil, which filters into every part of the economy from manufacturing to transport.
On the surface, then, this Fed move should be positive for oil prices. In particular, US shale producers. Facing a tough situation where shale oil prices are depressed due to a lack of infrastructure to send them to the US Gulf Coast for processing and export, independent US shale drillers are facing financial pressure as loans are no longer handed out like candy and investors are demanding results. Onshore drilling activity in the US has slowed down significantly this year as shale players pull back. A number are actually facing the prospect of bankruptcy. With the Fed rate cut, they now have some breathing space to refinance their existing loans or take new ones to tough it out over.
The last time the US Fed began to cut rates, it was a sustained drop as the headline interest rate fell from 5.25% in September 2007 to 0.25% in December 2008, which paralleled the implosion of the global financial system. After a bleak period, it worked, and the global economy slowly got back on better footing. With interest rates at effectively zero, financing was incredibly cheap – which allowed the US shale revolution to kick off. But so much oil was being produced that it led to a glut, creating the oil shock of 2014. In 2015, the Fed raised interest rates for the first time as the economy recovered, reaching 2.5% in December 2019. In the meantime, US shale – powered by previously cheap loans – grew in such power that it upended the balance of oil power in the world, creating an oversupply situation that persists.
A rate cut at this points alludes to the fragile state of the US and global economy – an admission that things are about to get worse. But US Fed Chairman Jerome Powell was at pains to explain that this wasn’t the start of an extended cycle of monetary policy easing, ruling out further cuts in the immediate future. As crude prices fell in response, the market clearly believes that this small cut will not be enough to stabilise the situation. More cuts may be necessary.
But they might not even be necessary at all, since the world is in a unprecedented quandary. The US is currently waging trade wars with key economic partners and imposing sanctions on key oil producers, disrupting the market even further. The OPEC+ club is aiming to mitigate the situation, but US policies make this tough. The damage this global uncertainty has – and continues to do – is enough to put off any planned investment or consumption. Interest rates could move to zero tomorrow, and American and global businesses still may not be compelled to invest due to the erratic direction of US trade policy. Adding fuel to this fire is the ongoing issue of Brexit, which will deepen the economic woes of the UK and Europe. The US Fed move is a warning signal, but that can only effect known unknowns. The world is currently facing unknown unknowns and that is leading the economy – and oil prices with it – into dangerous territory where conventional policy tools are losing potency.
US Federal Reserve Interest Rate Policy
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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.