Events that happen today don’t always show their impact until later. Sometimes much, much later. Tsunamis can occur several hours after the initial earthquake. And, as much as markets have access to an over-abundance of information, the impacts of trends currently happening on the ground (or rather, under the ground) aren’t always obvious until they hit.
Take US crude production, for example. The story over 2018 and 2019 was the quick acceleration of American crude output, powered by the shale revolution. The US has now overtaken Saudi Arabia and Russia as the world’s number 1 oil producer. Total production blasted past the 12 mmb/d level in 2018, and heady forecasts predicted that output could comfortably reach 14 mmb/d by the end of 2020. The amount of US crude flowing – onshore and offshore – has upended world crude price dynamics, and also bestowed cheap fuel on the US, powering its economy. The trends have also spilled over in the gas markets, where the US is currently enjoying historically low natural gas prices domestically and in the process of transforming itself a major LNG exporter.
To assume this will continue is a fallacy. The scenario occurring today is happening because of what happened several years ago. Looking at the data of active US oil rigs available from Baker Hughes – which is taken as a proxy for the level of upstream activity in the country – and the US crude production numbers from the EIA shows an evident lag between the two indicators. There appears to be a two-year lag between activities in the drilling sector with impact on output. Between December 2016 and December 2017, when the active oil rig count increased by 272, crude oil production only increased by 1.18 mmb/d; but between December 2017 and December 2018, crude oil production jumped by 2.06 mmb/d. Between December 2017 and December 2018, when the active oil rig count growth slowed down to 128, crude oil production growth also slowed down to only 800,000 b/d between December 2018 and estimates for November 2019.
To be fair, there are many other factors that impact production. But the active oil rig count is a significant indicator, and indeed predictor, of future output. Which is why current trends in the US active rig count are worrying. Between December 2018 and November 2018, Baker Hughes reports that the active oil rig count in the US declined by 206 – a 31-month low. And the decline seems chronic. Within that data, much of that decline comes from onshore rigs, particularly in the Permian and Eagle Ford basins. At current trends, the oil rig count could fall below 600 by early 2020. Given that shale fields have a prolific initial production period, followed by a sharp decline, this is worrying. US oil production could actually decline in late 2020, early 2021.
Of course, there are other things to consider. Consolidation is ongoing in the Permian, which may be reducing rig count but increasing productivity. With the investment community has turned against shale, drying up capital, some small- and medium-scale drillers are going bust. These assets, sometimes in high-opportunity areas, are being plucked off, as the big guys – the ExxonMobils, the Chevrons and the BPs – move in. There are many reasons why the active rig count might be dropping, but the main reasons remains that drilling just isn’t as attractive anymore. That itself will never translate 1-to-1 to production trends, but it will have a definite material impact. A reversal in US oil production growth is unlikely; what’s more likely is that the explosive growth will slow down. In fact, it already is. An average production level of 13 mmb/d is still achievable within six months, but the 14 mmb/d level looks very far off. Don’t be fooled by the surface image of current US oil output. Trying times are coming, and if you paid attention to the indicators, you would have known it is coming… and can prepare for it.
US Active Oil Rig Count vs US Crude Production
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In 2020, renewable energy sources (including wind, hydroelectric, solar, biomass, and geothermal energy) generated a record 834 billion kilowatthours (kWh) of electricity, or about 21% of all the electricity generated in the United States. Only natural gas (1,617 billion kWh) produced more electricity than renewables in the United States in 2020. Renewables surpassed both nuclear (790 billion kWh) and coal (774 billion kWh) for the first time on record. This outcome in 2020 was due mostly to significantly less coal use in U.S. electricity generation and steadily increased use of wind and solar.
In 2020, U.S. electricity generation from coal in all sectors declined 20% from 2019, while renewables, including small-scale solar, increased 9%. Wind, currently the most prevalent source of renewable electricity in the United States, grew 14% in 2020 from 2019. Utility-scale solar generation (from projects greater than 1 megawatt) increased 26%, and small-scale solar, such as grid-connected rooftop solar panels, increased 19%.
Coal-fired electricity generation in the United States peaked at 2,016 billion kWh in 2007 and much of that capacity has been replaced by or converted to natural gas-fired generation since then. Coal was the largest source of electricity in the United States until 2016, and 2020 was the first year that more electricity was generated by renewables and by nuclear power than by coal (according to our data series that dates back to 1949). Nuclear electric power declined 2% from 2019 to 2020 because several nuclear power plants retired and other nuclear plants experienced slightly more maintenance-related outages.
We expect coal-fired electricity generation to increase in the United States during 2021 as natural gas prices continue to rise and as coal becomes more economically competitive. Based on forecasts in our Short-Term Energy Outlook (STEO), we expect coal-fired electricity generation in all sectors in 2021 to increase 18% from 2020 levels before falling 2% in 2022. We expect U.S. renewable generation across all sectors to increase 7% in 2021 and 10% in 2022. As a result, we forecast coal will be the second-most prevalent electricity source in 2021, and renewables will be the second-most prevalent source in 2022. We expect nuclear electric power to decline 2% in 2021 and 3% in 2022 as operators retire several generators.
Source: U.S. Energy Information Administration, Monthly Energy Review and Short-Term Energy Outlook (STEO)
Note: This graph shows electricity net generation in all sectors (electric power, industrial, commercial, and residential) and includes both utility-scale and small-scale (customer-sited, less than 1 megawatt) solar.
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The tizzy that OPEC+ threw the world into in early July has been settled, with a confirmed pathway forward to restore production for the rest of 2021 and an extension of the deal further into 2022. The lone holdout from the early July meetings – the UAE – appears to have been satisfied with the concessions offered, paving the way for the crude oil producer group to begin increasing its crude oil production in monthly increments from August onwards. However, this deal comes at another difficult time; where the market had been fretting about a shortage of oil a month ago due to resurgent demand, a new blast of Covid-19 infections driven by the delta variant threatens to upend the equation once again. And so Brent crude futures settled below US$70/b for the first time since late May even as the argument at OPEC+ appeared to be settled.
How the argument settled? Well, on the surface, Riyadh and Moscow capitulated to Abu Dhabi’s demands that its baseline quota be adjusted in order to extend the deal. But since that demand would result in all other members asking for a similar adjustment, Saudi Arabia and Russia worked in a rise for all, and in the process, awarded themselves the largest increases.
The net result of this won’t be that apparent in the short- and mid-term. The original proposal at the early July meetings, backed by OPEC+’s technical committee was to raise crude production collectively by 400,000 b/d per month from August through December. The resulting 2 mmb/d increase in crude oil, it was predicted, would still lag behind expected gains in consumption, but would be sufficient to keep prices steady around the US$70/b range, especially when factoring in production increases from non-OPEC+ countries. The longer term view was that the supply deal needed to be extended from its initial expiration in April 2022, since global recovery was still ‘fragile’ and the bloc needed to exercise some control over supply to prevent ‘wild market fluctuations’. All members agreed to this, but the UAE had a caveat – that the extension must be accompanied by a review of its ‘unfair’ baseline quota.
The fix to this issue that was engineered by OPEC+’s twin giants Saudi Arabia and Russia was to raise quotas for all members from May 2022 through to the new expiration date for the supply deal in September 2022. So the UAE will see its baseline quota, the number by which its output compliance is calculated, rise by 330,000 b/d to 3.5 mmb/d. That’s a 10% increase, which will assuage Abu Dhabi’s itchiness to put the expensive crude output infrastructure it has invested billions in since 2016 to good use. But while the UAE’s hike was greater than some others, Saudi Arabia and Russia took the opportunity to award themselves (at least in terms of absolute numbers) by raising their own quotas by 500,000 b/d to 11.5 mmb/d each.
On the surface, that seems academic. Saudi Arabia has only pumped that much oil on a handful of occasions, while Russia’s true capacity is pegged at some 10.4 mmb/d. But the additional generous headroom offered by these larger numbers means that Riyadh and Moscow will have more leeway to react to market fluctuations in 2022, which at this point remains murky. Because while there is consensus that more crude oil will be needed in 2022, there is no consensus on what that number should be. The US EIA is predicting that OPEC+ should be pumping an additional 4 million barrels collectively from June 2021 levels in order to meet demand in the first half of 2022. However, OPEC itself is looking at a figure of some 3 mmb/d, forecasting a period of relative weakness that could possibly require a brief tightening of quotas if the new delta-driven Covid surge erupts into another series of crippling lockdowns. The IEA forecast is aligned with OPEC’s, with an even more cautious bent.
But at some point with the supply pathway from August to December set in stone, although OPEC+ has been careful to say that it may continue to make adjustments to this as the market develops, the issues of headline quota numbers fades away, while compliance rises to prominence. Because the success of the OPEC+ deal was not just based on its huge scale, but also the willingness of its 23 members to comply to their quotas. And that compliance, which has been the source of major frustrations in the past, has been surprisingly high throughout the pandemic. Even in May 2021, the average OPEC+ compliance was 85%. Only a handful of countries – Malaysia, Bahrain, Mexico and Equatorial Guinea – were estimated to have exceeded their quotas, and even then not by much. But compliance is easier to achieve in an environment where demand is weak. You can’t pump what you can’t sell after all. But as crude balances rapidly shift from glut to gluttony, the imperative to maintain compliance dissipates.
For now, OPEC+ has managed to placate the market with its ability to corral its members together to set some certainty for the immediate future of crude. Brent crude prices have now been restored above US$70/b, with WTI also climbing. The spat between Saudi Arabia and the UAE may have surprised and shocked market observers, but there is still unity in the club. However, that unity is set to be tested. By the end of 2021, the focus of the OPEC+ supply deal will have shifted from theoretical quotas to actual compliance. Abu Dhabi has managed to lift the tide for all OPEC+ members, offering them more room to manoeuvre in a recovering market, but discipline will not be uniform. And that’s when the fireworks will really begin.
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