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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The constant domestic fighting in Libya – a civil war, to call a spade a spade, has taken a toll on the once-prolific oil production in the North African country. After nearly a decade of turmoil, it appears now that the violent clash between the UN-recognised government in Tripoli and the upstart insurgent Libyan National Army (LNA) forces could be ameliorating into something less destructive with the announcement of a pact between the two sides that would to some normalisation of oil production and exports.
A quick recap. Since the 2011 uprising that ended the rule of dictator Muammar Gaddafi, Libya has been in a state of perpetual turmoil. Led by General Khalifa Haftar and the remnants of loyalists that fought under Gaddafi’s full-green flag, the Libyan National Army stands in direct opposition to the UN-backed Government of National Accord (GNA) that was formed in 2015. Caught between the two sides are the Libyan people and Libya’s oilfields. Access to key oilfields and key port facilities has changed hands constantly over the past few years, resulting in a start-stop rhythm that has sapped productivity and, more than once, forced Libya’s National Oil Corporation (NOC) to issue force majeure on its exports. Libya’s largest producing field, El Sharara, has had to stop production because of Haftar’s militia aggression no fewer than four times in the past four years. At one point, all seven of Libya’s oil ports – including Zawiyah (350 kb/d), Es Sider (360 kb/d) and Ras Lanuf (230 kb/d) were blockaded as pipelines ran dry. For a country that used to produce an average of 1.2 mmb/d of crude oil, currently output stands at only 80,000 b/d and exports considerably less. Gaddafi might have been an abhorrent strongman, but political stability can have its pros.
This mutually-destructive impasse, economically, at least might be lifted, at least partially, if the GNA and LNA follow through with their agreement to let Libyan oil flow again. The deal, brokered in Moscow between the warlord Haftar and Vice President of the Libyan Presidential Council Ahmed Maiteeq calls for the ‘unrestrained’ resumption of crude oil production that has been at a near standstill since January 2020. The caveat because there always is one, is that Haftar demanded that oil revenues be ‘distributed fairly’ in order to lift the blockade he has initiated across most of the country’s upstream infrastructure.
Shortly after the announcement of the deal, the NOC announced that it would kick off restarting oil production and exports, lifting an 8-month force majeure situation, but only at ‘secure terminals and facilities’. ‘Secure’ in this cases means facilities and fields where NOC has full control, but will exclude areas and assets that the LNA rebels still have control. That’s a significant limitation, since the LNA, which includes support from local tribal groups and Russian mercenaries still controls key oilfields and terminals. But it is also a softening from the NOC, which had previously stated that it would only return to operations when all rebels had left all facilities, citing safety of its staff.
If the deal moves forward, it would certainly be an improvement to the major economic crisis faced by Libya, where cash flow has dried up and basic utilities face severe cutbacks. But it is still an ‘if’. Many within the GNA sphere are critical of the deal struck by Maiteeq, claiming that it did not involve the consultation or input of his allies. The current GNA leader, Prime Minister Fayyaz al Sarraj is also stepping down at the end of October, ushering in another political sea change that could affect the deal. Haftar is a mercurial beast, so predictions are difficult, but what is certain is that depriving a country of its chief moneymaker is a recipe for disaster on all sides. Which is why the deal will probably go ahead.
Which is bad news for the OPEC+ club. Because of its precarious situation, Libya has been exempt for the current OPEC+ supply deal. Even the best case scenarios within OPEC+ had factored out Libya, given the severe uncertainty of the situation there. But if the deal goes through and holds, it could potentially add a significant amount of restored crude supply to global markets at a time when OPEC+ itself is struggling to manage the quotas within its own, from recalcitrant members like Iraq to surprising flouters like the UAE.
Mathematically at least, the ceiling for restored Libyan production is likely in the 300-400,000 b/d range, given that Haftar is still in control of the main fields and ports. That does not seem like much, but it will give cause for dissent within OPEC on the exemption of Libya from the supply deal. Libya will resist being roped into the supply deal, and it has justification to do so. But freeing those Libyan volumes into a world market that is already suffering from oversupply and weak prices will be undermining in nature. The equation has changed, and the Libyan situation can no longer be taken for granted.
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According to 2018 data from the U.S. Energy Information Administration (EIA) for newly constructed utility-scale electric generators in the United States, annual capacity-weighted average construction costs for solar photovoltaic systems and onshore wind turbines have continued to decrease. Natural gas generator costs also decreased slightly in 2018.
From 2013 to 2018, costs for solar fell 50%, costs for wind fell 27%, and costs for natural gas fell 13%. Together, these three generation technologies accounted for more than 98% of total capacity added to the electricity grid in the United States in 2018. Investment in U.S. electric-generating capacity in 2018 increased by 9.3% from 2017, driven by natural gas capacity additions.
The average construction cost for solar photovoltaic generators is higher than wind and natural gas generators on a dollar-per-kilowatt basis, although the gap is narrowing as the cost of solar falls rapidly. From 2017 to 2018, the average construction cost of solar in the United States fell 21% to $1,848 per kilowatt (kW). The decrease was driven by falling costs for crystalline silicon fixed-tilt panels, which were at their lowest average construction cost of $1,767 per kW in 2018.
Crystalline silicon fixed-tilt panels—which accounted for more than one-third of the solar capacity added in the United States in 2018, at 1.7 gigawatts (GW)—had the second-highest share of solar capacity additions by technology. Crystalline silicon axis-based tracking panels had the highest share, with 2.0 GW (41% of total solar capacity additions) of added generating capacity at an average cost of $1,834 per kW.
Total U.S. wind capacity additions increased 18% from 2017 to 2018 as the average construction cost for wind turbines dropped 16% to $1,382 per kW. All wind farm size classes had lower average construction costs in 2018. The largest decreases were at wind farms with 1 megawatt (MW) to 25 MW of capacity; construction costs at these farms decreased by 22.6% to $1,790 per kW.
Compared with other generation technologies, natural gas technologies received the highest U.S. investment in 2018, accounting for 46% of total capacity additions for all energy sources. Growth in natural gas electric-generating capacity was led by significant additions in new capacity from combined-cycle facilities, which almost doubled the previous year’s additions for that technology. Combined-cycle technology construction costs dropped by 4% in 2018 to $858 per kW.
Fossil fuels, or energy sources formed in the Earth’s crust from decayed organic material, including petroleum, natural gas, and coal, continue to account for the largest share of energy production and consumption in the United States. In 2019, 80% of domestic energy production was from fossil fuels, and 80% of domestic energy consumption originated from fossil fuels.
The U.S. Energy Information Administration (EIA) publishes the U.S. total energy flow diagram to visualize U.S. energy from primary energy supply (production and imports) to disposition (consumption, exports, and net stock additions). In this diagram, losses that take place when primary energy sources are converted into electricity are allocated proportionally to the end-use sectors. The result is a visualization that associates the primary energy consumed to generate electricity with the end-use sectors of the retail electricity sales customers, even though the amount of electric energy end users directly consumed was significantly less.
Source: U.S. Energy Information Administration, Monthly Energy Review
The share of U.S. total energy production from fossil fuels peaked in 1966 at 93%. Total fossil fuel production has continued to rise, but production has also risen for non-fossil fuel sources such as nuclear power and renewables. As a result, fossil fuels have accounted for about 80% of U.S. energy production in the past decade.
Since 2008, U.S. production of crude oil, dry natural gas, and natural gas plant liquids (NGPL) has increased by 15 quadrillion British thermal units (quads), 14 quads, and 4 quads, respectively. These increases have more than offset decreasing coal production, which has fallen 10 quads since its peak in 2008.
Source: U.S. Energy Information Administration, Monthly Energy Review
In 2019, U.S. energy production exceeded energy consumption for the first time since 1957, and U.S. energy exports exceeded energy imports for the first time since 1952. U.S. energy net imports as a share of consumption peaked in 2005 at 30%. Although energy net imports fell below zero in 2019, many regions of the United States still import significant amounts of energy.
Most U.S. energy trade is from petroleum (crude oil and petroleum products), which accounted for 69% of energy exports and 86% of energy imports in 2019. Much of the imported crude oil is processed by U.S. refineries and is then exported as petroleum products. Petroleum products accounted for 42% of total U.S. energy exports in 2019.
Source: U.S. Energy Information Administration, Monthly Energy Review
The share of U.S. total energy consumption that originated from fossil fuels has fallen from its peak of 94% in 1966 to 80% in 2019. The total amount of fossil fuels consumed in the United States has also fallen from its peak of 86 quads in 2007. Since then, coal consumption has decreased by 11 quads. In 2019, renewable energy consumption in the United States surpassed coal consumption for the first time. The decrease in coal consumption, along with a 3-quad decrease in petroleum consumption, more than offset an 8-quad increase in natural gas consumption.
EIA previously published articles explaining the energy flows of petroleum, natural gas, coal, and electricity. More information about total energy consumption, production, trade, and emissions is available in EIA’s Monthly Energy Review.
Principal contributor: Bill Sanchez