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 a few days, the bi-annual OPEC meeting will take place on November 30, leading into a wider OPEC+ meeting on December 30. This is what all the political jostling and negotiations currently taking place is leading up to, as the coalition of major oil producers under the OPEC+ banner decide on the next step of its historic and ambitious supply control plan. Designed to prop up global oil prices by managing supply, a postponement of the next phase in the supply deal is widely expected. But there are many cracks appearing beneath the headline.
A quick recap. After Saudi Arabia and Russia triggered a price war in March 2020 that led to a collapse in oil prices (with US crude prices briefly falling into negative territory due to the technical quirk), OPEC and its non-OPEC allies (known collectively as OPEC+) agreed to a massive supply quota deal that would throttle their production for 2 years. The initial figure was 10 mmb/d, until Mexico’s reticence brought that down to 9.7 mmb/d. This was due to fall to 7.7 mmb/d by July 2020, but soft demand forced a delay, while Saudi Arabia led the charge to ensure full compliance from laggards, which included Iraq, Nigeria and (unusually) the UAE. The next tranche will bring the supply control ceiling down to 5.7 mmb/d. But given that Covid-19 is still raging globally (despite promising vaccine results), this might be too much too soon. Yes, prices have recovered, but at US$40/b crude, this is still not sufficient to cover the oil-dependent budgets of many OPEC+ nations. So a delay is very likely.
But for how long? The OPEC+ Joint Technical Committee panel has suggested that the next step of the plan (which will effectively boost global supply by 2 mmb/d) be postponed by 3-6 months. This move, if adopted, will have been presaged by several public statements by OPEC+ leaders, including a pointed comment from OPEC Secretary General Mohammad Barkindo that producers must be ready to respond to ‘shifts in market fundamentals’.
On the surface, this is a necessary move. Crude prices have rallied recently – to as high as US$45/b – on positive news of Covid-19 vaccines. Treatments from Pfizer, Moderna and the Oxford University/AstraZeneca have touted 90%+ effectiveness in various forms, with countries such as the US, Germany and the UK ordering billions of doses and setting the stage for mass vaccinations beginning December. Life returning to a semblance of normality would lift demand, particularly in key products such as gasoline (as driving rates increase) and jet fuel (allowing a crippled aviation sector to return to life). Underpinning the rally is the understanding that OPEC+ will always act in the market’s favour, carefully supporting the price recovery. But there are already grouses among OPEC members that they are doing ‘too much’. Led by Saudi Arabia, the draconian dictates of meeting full compliance to previous quotas have ruffled feathers, although most members have reluctantly attempt to abide by them. But there is a wider existential issue that OPEC+ is merely allowing its rivals to resuscitate and leapfrog them once again; the US active oil rig count by Baker Hughes has reversed a chronic decline trend, as WTI prices are at levels above breakeven for US shale.
Complaints from Iran, Iraq and Nigeria are to be expected, as is from Libya as it seeks continued exemption from quotas due to the legacy of civil war even though it has recently returned to almost full production following a truce. But grievance is also coming from an unexpected quarter: the UAE. A major supporter in the Saudi Arabia faction of OPEC, reports suggest that the UAE (led by the largest emirate, Abu Dhabi) are privately questioning the benefit of remaining in OPEC. Beset by shrivelling oil revenue, the Emiratis have been grumbling about the fairness of their allocated quota as they seek to rebuild their trade-dependent economy. There has been suggestion that the Emiratis could even leave OPEC if decisions led to a net negative outcome for them. Unlike the Qatar exit, this will not just be a blow to OPEC as a whole, questioning its market relevance but to Saudi Arabia’s lead position, as it loses one of its main allies, reducing its negotiation power. And if the UAE leaves, Kuwait could follow, which would leave the Saudis even more isolated.
This could be a tactic to increase the volume of the UAE’s voice in OPEC+, which has been dominated by Saudi Arabia and Russia. But it could also be a genuine policy shift. Either way, it throws even more conundrums onto a delicate situation that could undermine an already fragile market. Despite the positive market news led by Covid-19 vaccines and demand recovery in Asia, American crude oil inventories in Cushing are now approaching similar high levels last seen in April (just before the WTI crash) while OPEC itself has lowered its global demand forecast for 2020 by 300,000 b/d. That’s dangerous territory to be treading in, especially if members of the OPEC+ club are threatening to exit and undermine the pack. A postponement of the plan seems inevitable on December 1 at this point, but it is what lies beyond the immediate horizon that is the true threat to OPEC+.
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In the U.S. Energy Information Administration’s (EIA) November Short-Term Energy Outlook (STEO), EIA forecasts that U.S. crude oil production will remain near its current level through the end of 2021.
A record 12.9 million barrels per day (b/d) of crude oil was produced in the United States in November 2019 and was at 12.7 million b/d in March 2020, when the President declared a national emergency concerning the COVID-19 outbreak. Crude oil production then fell to 10.0 million b/d in May 2020, the lowest level since January 2018.
By August, the latest monthly data available in EIA’s series, production of crude oil had risen to 10.6 million b/d in the United States, and the U.S. benchmark price of West Texas Intermediate (WTI) crude oil had increased from a monthly average of $17 per barrel (b) in April to $42/b in August. EIA forecasts that the WTI price will average $43/b in the first half of 2021, up from our forecast of $40/b during the second half of 2020.
The U.S. crude oil production forecast reflects EIA’s expectations that annual global petroleum demand will not recover to pre-pandemic levels (101.5 million b/d in 2019) through at least 2021. EIA forecasts that global consumption of petroleum will average 92.9 million b/d in 2020 and 98.8 million b/d in 2021.
The gradual recovery in global demand for petroleum contributes to EIA’s forecast of higher crude oil prices in 2021. EIA expects that the Brent crude oil price will increase from its 2020 average of $41/b to $47/b in 2021.
EIA’s crude oil price forecast depends on many factors, especially changes in global production of crude oil. As of early November, members of the Organization of the Petroleum Exporting Countries (OPEC) and partner countries (OPEC+) were considering plans to keep production at current levels, which could result in higher crude oil prices. OPEC+ had previously planned to ease production cuts in January 2021.
Other factors could result in lower-than-forecast prices, especially a slower recovery in global petroleum demand. As COVID-19 cases continue to increase, some parts of the United States are adding restrictions such as curfews and limitations on gatherings and some European countries are re-instituting lockdown measures.
EIA recently published a more detailed discussion of U.S. crude oil production in This Week in Petroleum.
The U.S. Energy Information Administration (EIA) forecasts that members of the Organization of the Petroleum Exporting Countries (OPEC) will earn about $323 billion in net oil export revenues in 2020. If realized, this forecast revenue would be the lowest in 18 years. Lower crude oil prices and lower export volumes drive this expected decrease in export revenues.
Crude oil prices have fallen as a result of lower global demand for petroleum products because of responses to COVID-19. Export volumes have also decreased under OPEC agreements limiting crude oil output that were made in response to low crude oil prices and record-high production disruptions in Libya, Iran, and to a lesser extent, Venezuela.
OPEC earned an estimated $595 billion in net oil export revenues in 2019, less than half of the estimated record high of $1.2 trillion, which was earned in 2012. Continued declines in revenue in 2020 could be detrimental to member countries’ fiscal budgets, which rely heavily on revenues from oil sales to import goods, fund social programs, and support public services. EIA expects a decline in net oil export revenue for OPEC in 2020 because of continued voluntary curtailments and low crude oil prices.
The benchmark Brent crude oil spot price fell from an annual average of $71 per barrel (b) in 2018 to $64/b in 2019. EIA expects Brent to average $41/b in 2020, based on forecasts in EIA’s October 2020 Short-Term Energy Outlook (STEO). OPEC petroleum production averaged 36.6 million barrels per day (b/d) in 2018 and fell to 34.5 million b/d in 2019; EIA expects OPEC production to decline a further 3.9 million b/d to average 30.7 million b/d in 2020.
EIA based its OPEC revenues estimate on forecast petroleum liquids production—including crude oil, condensate, and natural gas plant liquids—and forecast values of OPEC petroleum consumption and crude oil prices.
EIA recently published a more detailed discussion of OPEC revenue in This Week in Petroleum.