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Unprecedented is a word that has captured headlines since January 2020, when the Covid-19 pandemic first began to accelerate in China. Unprecedented contagion, unprecedented lockdowns, unprecedented demand destruction, all leading up to what could be the worst economic recession since the Great Depression almost a century ago. And now, unprecedented oil prices, as the WTI crude price marker slipped into negative territory for the first time ever.
Not just any negative territory, but double digits negative. The front month WTI contract for deliveries in May fell as low as -US$37.63.b on Monday. The discount between WTI and Brent also crashed to its lowest point ever, at a peak of -US$62/b, as Brent continues to trade in the mid-US$20/b level. That’s unprecedented. It isn’t just WTI; other US grades are also deep in the negative, as well as Western Canada Select. This essentially means American and Canadian producers are paying to offload their crude oil to (a thin pool) of potential buyers.
There are many reasons for this. Demand for refined fuels has virtually dried up as the US imposed strict lockdown conditions to contain the virus. Jet travel has evaporated, and though gasoline prices have reportedly fallen by 75% in some parts of the US, there is nowhere to drive to. At least three North American refineries have been idled in the face of oil demand destruction, and there are certainly more to come. Try as much as President Donald Trump wants to re-open the US economy, the threat of the virus re-accelerating is worse. This huge dip in demand and refining meant that all the crude and shale oil being produced had nowhere to go but into storage. But storage is rapidly getting maxed out; spare capacity in the main hub of Cushing is fast depleting, and there are even plans to store oil in train cars and in halted pipelines. Storage in the US Strategic Petroleum Reserve is available, but even that is limited.
What makes this even more unprecedented is that much of this oil is onshore, very far inland. This had the same effect, though different contributing factors in 2019, when WTI prices were depressed because demand was high but pipeline capacity was insufficient to carry crude to refining centres along the US Gulf Coast, creating a shale glut. In a way, that paved the way to the current catastrophe; many shale producers picked up a lot of debt during this time, and were forced to pump oil even more aggressively just to stay alive. In the world of a growing oversupply, inland oil is overflowing as storage fills to the brim. Offshore production doesn’t face the same issue. As long as crude can be delivered on the coast, it can be placed on a tanker and stored offshore indefinitely, especially with so many ships idled due to the slowdown in economic activity. This is already happening in Singapore, in Fujairah, in the North Sea, and is the reason that the global crude marker, Brent, has not collapsed.
But the main reason for the unprecedented demolition of US crude prices hinges on a technicality. The Brent NYMEX contract is settled in cash. WTI contracts, however, are settled physically; those holding the contract must therefore take physical delivery at expiry. That expiry date for May contracts is April 21. The dive into deep red territory came because of extreme selling pressure to avoid have to physically receive the oil, especially with nowhere onshore to store it. News that large cargoes of Saudi crude were heading to the US Gulf made matters worse. However, further WTI futures contracts for June and beyond, are still trading at a far more normal range of US$20-30/b; there is still enough time for demand to recover (or for more storage to be found) for these contracts. But for the May contract? It is a bloodbath.
The situation certainly isn’t as dire as it seems, though the headlines might seem apocalyptic. This knee-jerk reaction will almost certainly sort itself out over the medium term. Already, the expiring May WTI contract recovered to -US$6/b in after-hours trading. WTI should return to a more normal range with the switchover to the June benchmark contract on Wednesday. Economic pressure will keep prices low, but not that low. At least not yet. But it will be a whole new galaxy of pain for the US oil industry, especially those that are completely reliant on shale and those that service them. The Saudi-Russia oil price war may have begun as a battle for market share, but might have inadvertently achieved a secondary objective, wiping out US shale production that was undermining supply control efforts. In just three months, the entire oil world has been turned upside down. In response, the industry is recalibrating. There will be some winners, and some losers. In these unprecedented times, expect unprecedented things.
WTI’s Great Fall:
-Traded prices on NYMEX, 20 April 2020
- 10am: US$11.28/b
- 2pm: US$4.88/b
- 2.30pm: -US$0.02/b
- 3pm: -US$.6.89/b
- 4pm: -US$37.63/b
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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.
Market Outlook:
END OF ARTICLE
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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.
Solar
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.
Source: U.S. Energy Information Administration, Electric Generator Construction Costs and Annual Electric Generator Inventory
Wind
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.
Source: U.S. Energy Information Administration, Electric Generator Construction Costs and Annual Electric Generator Inventory
Natural gas
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.
Source: U.S. Energy Information Administration, Electric Generator Construction Costs and Annual Electric Generator Inventory
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
