The last two months have been a tumultuous time for the oil industry. First stricken by the Covid-19 pandemic that destroyed a significant amount of demand, Saudi Arabia and Russia then went to war over oil production causing oil prices to collapse by half. As the combination of the two factors conspired to take US oil prices (briefly) into the negative, the oil industry upstream, midstream and downstream are still reeling from the blow. Quarterly results for the first three months of 2020 are rolling out, which will show the first signs of damage on publicly-traded oil companies. The verdict is expected to be dire. But the situation, though grim, will eventually improve. However, that is not the case for the other side of the industry that doesn’t attract as many headlines, but is no less crucial to everyone’s bottom line: oilfield services.
An entire phalanx of upstream service companies help build, operate and maintain the critical infrastructure necessary to extract oil in its natural form from deep below the ground and send it on its merry way to be turned into fuel for consumption. The life of these service companies depends on one thing: the level of activity in the upstream sector. The more drilling and operating there is, the more work there is, and therefore the more revenue. When contracted activity dries up, so does the work and the cash flow. With all companies slashing upstream capex and activities planned for at least the next two years on depressingly low oil prices, the pool of work has shrunk. And when the pool shrinks, the fish are threatened.
Take the two largest oilfield services companies in the world: Schlumberger and Halliburton. The industry gorilla, Schlumberger declared a net loss of US$7.38 billion for Q1 2020, down from a net profit of US$421 million in Q1 2019. Revenue from its US operations was down by 17%, offsetting a 2% growth in international revenue; but the main cause of the huge loss was a US$8.5 billion impairment charge on assets. Schlumberger’s CEO is calling the current situation ‘the most challenging environment for the industry in many decades’ and that the next quarter is ‘likely to be the most uncertain and disruptive quarter the industry has ever seen.’ Halliburton, Schlumberger’s main rival is also in a period of pain. Having wiped out US$1 billion in asset write downs, Halliburton reported a net loss of US$1.02 billion for the quarter and warned of revenue dropping by ‘at least’ 30% for the full year. Particularly because Halliburton is pulling out of the Venezuelan services sector, tired of tethering on a knife’s edge every 3 months on if the US White House would renew its waiver to operate there.
Elsewhere in the services sector, results were equally bleak. Petrofac (services arm) is slashing jobs, having been terminated from ADNOC’s US$1.65 billion Dalma Gas Development Project, while Baker Hughes reported a mammoth US$10.2 billion net loss on major write downs. The market had already anticipated the stark results, but the scale of Schlumberger’s and Baker Hughes’ net loss was still a surprise while Halliburton managed to exceed analyst expectations.
But these are the big guys, and they have enough cash reserves and favourable debt ratios to weather the storm. Further down the pecking order, however, the situation is far more existentially threatening. Particularly in the US, where a meadow of small- and medium-sized service operators bloomed in the wake of the shale revolution. Times were good for a while, but started turning sour in mid-2019. The problems of the US shale industry are well documented already, and that is also true for their service companies. Recently, Whiting Petroleum Corp became the first major post-Covid 19 victim in the shale patch, declaring bankruptcy. Its downfalls also took down Pioneer Energy Services, forced to abandon its final 6 rigs in the Bakken formation and filing for Chapter-11 bankruptcy protection as well.
Indications show that since the start of 2019, the US oilfield services sector lost almost 50,000 jobs or 13% of the entire workforce. A significant amount of this was in 2019 itself, when the shine went off the shale patch as unsustainable debt ratios rose. Bankruptcies in the US shale patch are now averaging 8 per quarter, compared to 2 in 2018. While the situation is still fluid, it is expected that at least half of the remaining work (and therefore, firms and workforce) will evaporate through the end of 2020, putting a quarter of a million jobs out.
Even if oil prices do recovery to, say, US$40/b by June 2020, this will not be enough to prop up the services sector. The industry has now retreated back to 2015 levels of caution and cost-cutting, focusing on austerity after a period of fattening up. That’s not good news for services companies, whose existence is tied to the level of industry activity. If the ExxonMobils and Saudi Aramacos of the world are hurting, then the Schlumbergers and Halliburtons are in a far worst position. Many won’t survive, to be absorbed into the few remaining that will hopefully become leaner and meaner in preparation for the next unexpected shock on the horizon.
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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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