Consensus estimates indicate that the full extent of the Covid-19 pandemic will wipe out at least 18.5 mmb/d of oil demand in 2020 alone. Some analysts have gone even further, suggesting that the number could go as high as 30 mmb/d. As supply reacts to demand, there is no doubt that producers must throttle back production to avoid a destructive oversupply that has already decimated crude oil prices. OPEC+’s new two-year supply deal promises to take 9.7 mmb/d off the market through June 2020, then declining gently. At its best, this will only account for half of the demand shortfall, leaving an excess of at least another 9 mmb/d. In the extraordinary OPEC+ and G20 meetings that surrounded the coordinated deal, it was stated that the free market producers – mainly the US, Canada, Brazil and Norway – would make up a further cut of 5 mmb/d through natural ‘market adjustments’. The question, then, is how?
For the OPEC nations, this is relatively easy. Most are oligarchies, controlled environments where difficult decisions can be implemented swiftly. In many cases, there is only a single firm controlling its vast oil wealth. Thus, Saudi Arabia, though it may have joint ventures with foreign firms, has full control over the entire Saudi crude oil production mechanism. The dictate to reduce production by 2.5 mmb/d is a (relatively) straight forward matter of recalibrating the Kingdom’s integrated production infrastructure. This applies to OPEC states as well, such as Kuwait, the UAE and Angola, where Kuwait Petroleum, ADNOC or Sonangol have tightly integrated crude production infrastructure where control of national output levels is centralised.
Even in countries within OPEC or OPEC+ where the industry is more competitive, this holds true. In Russia, Rosneft, Gazprom and Lukoil may all compete with each other, but they will not ignore an order from the Kremlin to reduce output proportionately in accordance to the supply deal. In OPEC countries such as Iran and Iraq, the small number of national producers makes collusion easier. This even applies in countries within OPEC+ where free market ideals hold more strongly. Petronas may not be able to dictate the output levels of PTTEP, Shell or ConocoPhillips’ Malaysian assets, but it owns enough control in key assets to influence the national output level. Ditto for Azerbaijan, Kazakhstan and Oman, even if the state oil firms there have extensive partnerships with supermajors such as BP, Chevron and Shell.
Adherence aside, it should be relatively easy for the OPEC+ club to meet their target of 9.7 mmb/d if the temptation to cheat doesn’t take hold. But what about the large free market producers? The pact between these countries and OPEC+ calls for the former to reduce production ‘naturally’ according to market pressure. That, again, is relatively easier for Norway and Brazil, where the reins of production are concentrated in the hands of Equinor and Petrobras. But what about the thorn in the oil industry’s side, the USA? There is no American state oil firm, and neither is there a federal body tasked to coordinate national output levels. It can happen on a state-level, like the Alberta state government in Canada or the Texas Railroad Commission – but players in these markets still cannot be compelled to follow through. The US oil industry is a matrix of many, many private players large, medium and small, each driven by a capitalist drive for profit, which is counter intuitive to controlling output.
So, in the absence of top-level control, each player in the US is left to their own devices to control their own output, in hope that each of its rivals will do the same to allow an optimal level of national output. A true expression of game theory. So what is going to happen?
Well, the first – and quickest – way to reduce output is to target onshore wells, particularly in the shale patch. This can happen voluntarily, or enforced through the growing number of bankruptcies. In North Dakota, where the shale revolution took root early, some 6200 wells have been shut, almost a third of all wells. Stopping wells temporarily is easy, but halting them forever is considerably tougher. So the question facing these producers is: which wells to shut, and for how long? For most, the target will be painted on newer wells, where the marginal cost to extract abundant oil is lower, essentially saving the crude for a better price. And running older, less productive wells, with the idea of closing those fully once the resources expire, rather than going through the expensive stop-and-restart process in newer wells. It is a strategy that supermajors ExxonMobil and Chevron have taken in the US shale patch, who announced that they would be slashing rigs in the prolific Permian Basin by 75% (to 15 sites) and 71% (to 5 sites) over 2020. Closures will be on the newer, more prolific wells – a testament to shale’s steep production drop-off curve and, as ExxonMobil put it, ‘better off deferring higher production rates into a period with better pricing.’ This strategy seems to be replicated across the American club of producers, from the giants to regional players such as Continental Resources. And once again, the American shale patch’s flexibility can run both ways, as easy as it is to close down an onshore shale rig (compared to a vast offshore rig), it is equally easy to restart them once market conditions change.
In April alone, estimates from the IEA show that the US, Canada and Brazil accounted for most of the month’s 2.2 mmb/d decline in production. That’s nearly half of what was requested of the free market oil producers. With the OPEC+ deal entering force in May and US oil prices in the doldrums, it would seem that there is enough political will and market pressure to enforce nearly 15 mmb/d of output cuts across the industry. That will go a long way to supporting prices in their current weak state. The hope is that this bitter pill won’t have to last long, and once demand improves and economies re-open, oil producers from across the spectrum will be able to return to business as usual. Or, at least, business as usual in the new normal.
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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