At the start of 2019, Brent crude was trading at US$55/b. Twelve months later, it looks like Brent will end 2019 at some US$65/b. That’s not a vast difference, but that’s been the case for oil prices in 2019 generally: stubbornly range bound on rising supply. Upward spikes in May – when Iranian tensions peaked, and in September – when an attack briefly took out 50% of Saudi Arabia’s crude processing capacity, were nothing compared to previous geopolitical oil spikes. And that has much to do with the persistent rise (and rise) of US crude production.
So what will 2020 hold? By all accounts, everyone with a stake in the market – from producers to banks – agree that the global glut of crude will continue, at least in the first half. Attempts by the wider OPEC+ club to minimise the growing glut have only mitigated the situation; the power of these producers to influence the market has diminished as US production has risen. And this will get worse in 2020. Because not only will US crude output continue to rise – albeit at a slower pace – the tide will be lifted by additional volumes elsewhere. The giant Johan Sverdrup field in Norway has just started up, delivering its first crude ahead of schedule. Brazilian production will grow, as the upstream industry there recalibrates to be more open to foreign operators. And the first commercial crude will appear from Guyana, where a streak of recent discoveries could start the small country at initial production levels of 150,000 b/d, moving up to as much as 750,000 b/d by 2025. There will be so much more oil sloshing around oil tankers and refineries worldwide in 2020, and there is little that OPEC can do to stop that.
Not that OPEC isn’t doing anything. The OPEC+ club recently agreed to an additional symbolic cut that will only last through March 2020, while placing emphasis on adherence if future cuts are to be made. And it looks like it may have to continue. As long as OPEC+ tries to play the good cop in the market – yielding volumes to coerce trends – crude prices will remain stable at best, because its moves are neutralised by growing non-OPEC+ production. But what if OPEC+ decides not to yield market share anymore, unleashing a flood of output it has held back? Saudi Arabia could easily do this alone. But the situation is very different from 2014, when the Saudis turned the spigot onto to full blast in an attempt to wipe out the nascent US shale oil revolution. With Saudi Aramco now publicly traded and facing budget constraints, that weapon is no longer available to Saudi Arabia. OPEC+ will play ball, because it has to.
The nature of the US shale revolution is changing as well. Characterised by small nimble players that strike oil hard and fast, US shale is also marked by steep drop-off rates after the first year. In essence, it means that US shale players need to keep drilling more simply to stay afloat – especially since most are heavily indebted. With the flow of credit now drying up, many of these smaller firms are now going bankrupt or consolidating to survive. With the arrival of the supermajors in the US onshore shale patch, most of these small players will be hovered up, and the industry is likely to prioritise steady growth and practice some restraint.
All of this means that the supply glut will continue, as the necessity to keep producing continues for a while in US shale and OPEC+’s efforts to ensure compliance to quotas is offset by growing output elsewhere. But what about demand? Six months ago, the outlook was bleak. With the US instigating trade tiffs and wars – spilling over into nationalistic trade fervour elsewhere like India – a recession was predicted. But while the slowdown has already happened, a recent thaw in US-China trade relations and improving economic indicators suggest that the worst could be over. That’s important, because the only way to wipe up oversupply is to ensure that it is consumed somewhere. And given the current outlook on the global economy, steady crude prices are perhaps the best that the market can hope for.
Crude Oil Forecast for 1H 2020:
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Headline crude prices for the week beginning 13 January 2020 – Brent: US$64/b; WTI: US$59/b
Headlines of the week
Source: U.S. Energy Information Administration, Short-Term Energy Outlook, January 2020
In its latest Short-Term Energy Outlook (STEO), released on January 14, the U.S. Energy Information Administration (EIA) forecasts that generation from natural gas-fired power plants in the electric power sector will grow by 1.3% in 2020. This growth rate would be the slowest growth rate in natural gas generation since 2017. EIA forecasts that generation from nonhydropower renewable energy sources, such as solar and wind, will grow by 15% in 2020—the fastest rate in four years. Forecast generation from coal-fired power plants declines by 13% in 2020.
During the past decade, the electric power sector has been retiring coal-fired generation plants while adding more natural gas generating capacity. In 2019, EIA estimates that 12.7 gigawatts (GW) of coal-fired capacity in the United States was retired, equivalent to 5% of the total existing coal-fired capacity at the beginning of the year. An additional 5.8 GW of U.S. coal capacity is scheduled to retire in 2020, contributing to a forecast 13% decline in coal-fired generation this year. In contrast, EIA estimates that the electric power sector has added or plans to add 11.4 GW of capacity at natural gas combined-cycle power plants in 2019 and 2020.
Generating capacity fueled by renewable energy sources, especially solar and wind, has increased steadily in recent years. EIA expects the U.S. electric power sector will add 19.3 GW of new utility-scale solar capacity in 2019 and 2020, a 65% increase from 2018 capacity levels. EIA expects a 32% increase of new wind capacity—or nearly 30 GW—to be installed in 2019 and 2020. Much of this new renewables capacity comes online at the end of the year, which affects generation trends in the following year.
Forecast generation mix varies in each of the 11 STEO electricity supply regions. A large proportion of the retired coal-fired capacity is located in the mid-Atlantic area, where PJM manages the dispatch of electricity. EIA forecasts that coal generation in the mid-Atlantic will decline by 37 billion kilowatthours (kWh) in 2020. Some of this decline is offset by more generation from mid-Atlantic natural gas-fired power plants; EIA expects generation from these plants to grow by 23 billion kWh.
Source: U.S. Energy Information Administration, Short-Term Energy Outlook, January 2020
In the Midwest, where the Midcontinent ISO (MISO) manages electricity, EIA expects coal generation to fall in 2020 by 33 billion kWh. This decline is offset by an increase in natural gas electricity generation (12 billion kWh) and by nonhydropower renewable energy sources (13 billion kWh). The regional increase in renewables is primarily a result of new wind generating capacity.
The electric power sector in the area of Texas managed by the Electric Reliability Council of Texas (ERCOT) is planning to see large increases in generating capacity from both wind and solar. EIA expects this new capacity will increase generation from nonhydropower renewable energy sources by 24 billion kWh this year. EIA expects the increased ERCOT renewable generation will lead to a regional decline of natural gas-fired generation and coal generation of 14 billion kWh for each fuel source in 2020.
EIA expects these trends to continue into 2021. EIA forecasts U.S. generation from nonhydropower renewable energy sources will grow by 17% next year as the electric power sector continues expanding solar and wind capacity. This increase in renewables, along with forecast increases in natural gas fuel costs, contributes to EIA’s forecast of a 2.3% decline in natural gas-fired generation in 2021. U.S. coal generation in 2021 is forecast to fall by 3.2%.