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Last Updated: April 24, 2020
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Headline crude prices for the week beginning 20 April 2020 – Brent: US$26/b; WTI: -US$4/b

  • This week has been a wild ride for crude oil prices, exposing the intricate nature of futures contracts and highlighting technicalities in trading that could, bizarrely, cause crude oil prices – or any futures contracts – to turn negative
  • That is exactly what happened with WTI at the start of the week, where pessimism over steep demand declines that would not be offset by OPEC+’s new landmark supply deal, drove front-month prices into the red
  • The action was focused on the expiring contract for May delivery, with traders scrambling to offload contracts to avoid having to receive the oil physically amid a severe shortage of onshore storage space; at one point, the May contract plunged as low as -US$37/b, but recovered to -USS4/b
  • With the expiry of the May WTI contract, the US crude benchmark has returned to a more normal level; while the May contract was active, the June contract was trading in the US$20/b range and with the expiry of the May contract, the June contract remains firmly in the black as traders still have time to ascertain the situation until storage becomes an issue once again on 20 May
  • WTI prices still remain weak, trading at US$17/b since the changeover, with Brent also falling below the US$20/b level to a 22-year low, but has since recovered slightly to some US$22/b
  • Although the new OPEC+ supply deal only kicks in on May 1, Kuwait has already started reducing its crude oil supply to the new quota levels; Saudi Arabia, however, is reportedly still pumping at full volume, loading a large amount of cargoes to the US Gulf that exacerbated the WTI price meltdown
  • Within OPEC+, Saudi Arabia and Russia are also hinting at further output cuts; unlike the market-based players like the US, Canada, Brazil and Norway – where the expected production cuts will come ‘automatically’ from market conditions – the OPEC+ group must coordinate any new supply restrictions
  • Russia will be distributing its 2.5 mmb/d cut proportionally across its oil companies, with Rosneft taking up 40% of the total reduction
  • OPEC announced that it expects global demand for OPEC crude to fall to its lowest level in three decades over Q2 2020, at just under 20 mmb/d, or roughly half of its normal production levels
  • Meanwhile, the Covid-19 pandemic is hitting projects in development; hundreds of workers at Novatek’s Arctic LNG 2 export project in Russia have tested positive, while work at Total’s Afungi LNG site in Mozambique’s Cabo Delgado was halted and closed off as two-thirds of the country’s confirmed Covid-19 cases were detected at the site
  • Amid the catastrophic price environment for US crude, the active rig count fell by another 73 rigs (66 oil, 7 gas) to 529 sites, its lowest level since July 2016
  • In the aftermath of the WTI price meltdown, oil prices have recovered somewhat but still remain weak, although traders also seem confident that market forces will trigger faster-than-expected declines in output; with that, Brent should be trading in the US$20-22/b range, with WTI recovering to the US$15-17/b range


Headlines of the week

Upstream

  • Petrobras has begun hibernating 62 of its platforms operating in offshore shallow water fields in Brazil, affecting the Campos, Sergipe, Potiguar and Ceara basins, and collectively removing some 23,000 b/d of crude output
  • In addition to Petrobras, Equinor is also halting production at its Peregrino field in Brazil’s Campos basin, though this seems to be linked to safety issues
  • Shell and ExxonMobil have halted output at two offshore assets in the US Gulf of Mexico – the 100,000 b/d Perdido hub and the Hoover platform – following the discovery of a leak on the Hoover Offshore Oil Pipeline System (HOOPS) that connects the fields to the Quintana Terminal in Freeport, Texas
  • More details have emerged from the US government’s negotiations to rent out storage capacity in the federal Strategic Petroleum Reserve, with nine companies in the running to rent an initial 23 million barrels of space
  • Oklahoma is formerly contemplating implementing crude output curbs, joining Texas as the state claims its crude is ‘wasted at current prices’
  • Shell has lifted force majeure on exports of Forcados crude in Nigeria as the Trans Forcados pipeline was re-opened after a two-week shutdown, the second time in a year that the pipeline’s closure has affected Forcados exports
  • ExxonMobil is conducting field trials of 8 new methane detection technologies – including satellite and aerial surveillance monitoring – at some 1000 sites in Texas in an attempt to reduce methane emissions
  • TC Energy’s Keystone XL oil pipeline connecting Canada to the US has hit yet another setback as a US court rules against a permit to allow the pipeline to cross bodies of water in the US without sufficient environmental review

Midstream/Downstream

  • Refineries and petchem plants worldwide – from Russia to the US – have recalibrated their operations to switch away from conventional production to focus on producing raw materials for critical Personal Protective Equipment (PPE) like sanitisers, antiseptics, medical masks and gowns
  • Shell has restarted its heavy oil hydrocracker at the 211,270 b/d Convent refinery in Louisiana after several days of outage following a malfunction

Natural Gas/LNG

  • Qatar Petroleum has begun its drilling campaign at the giant offshore North Field East gas project, spudding the first of 80 planned wells that is expected to boost Qatar’s LNG capacity from 77 mtpa to 110 mtpa
  • BP has signed an agreement with China’s Foran Energy to supply some 600,000 tons per annum of LNG to the industrial Guangdong province
  • Canada’s Pieridae has delayed FID on the Goldboro LNG export project in Nova Scotia to an unspecified period beyond the initial date of 30 September
  • Israel’s Energean Oil and Gas has increased estimated recoverable reserves at its Karish North field by 32% to some 1.2 tcf of gas and 39 mmboe of liquids
  • Russia’s Parliament has passed amendments to the country’s Law on Gas Exports that would ease restrictions on LNG exports that could encourage the development of more LNG exporters and export projects
  • ADNOC has cancelled two EPC contracts awarded to Petrofac related to its giant Dalma Gas Development Project in an apparent attempt to reduce spending against the backdrop of the Covid-19 pandemic
  • Singapore’s LNG-9 has reportedly withdrawn from a planned acquisition of Australia’s LNG Ltd, which is planning the Magnolia LNG project in Louisiana

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Libya & OPEC’s Quota

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:

  •  Crude price trading range: Brent – US$41-43/b, WTI – US$39-41/b
  • While a resurgence in Covid-19 cases globally is undermining faith that the ongoing oil demand recovery will continue unabated, crude markets have been buoyed by a show of force by Saudi Arabia and US supply disruptions from Tropical Storm Sally
  • In a week when Iraq’s OPEC+ commitments seem even more distant with signs of its crude exports rising and key Saudi ally the UAE admitting it had ‘pumped too much recently’, the Saudi Energy Minister issued a force condemnation on breaking quotas
  • On the demand side, the IEA revised its forecast for oil demand in 2020 to an annual decline of 8.4 mmb/d, up from 8.1 mmb/d in August, citing Covid resurgences
  • In a possible preview of the future, BP issued a report stating that the ‘relentless growth of oil demand is over’, offering its own vision of future energy requirements that splits the oil world into the pro-clean lobby led by Europeans and the prevailing oil/gas orthodoxy that remains in place across North America and the rest of the world

END OF ARTICLE

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September, 22 2020
Average U.S. construction costs for solar and wind generation continue to fall

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.

average construction costs for solar photovoltaic electricity generators

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.

average construction costs for wind farms

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.

average construction costs for natural gas-fired electricity generators

Source: U.S. Energy Information Administration, Electric Generator Construction Costs and Annual Electric Generator Inventory

September, 17 2020
Fossil fuels account for the largest share of U.S. energy production and consumption

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.

U.S. primary energy production by source

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.

U.S. primary energy overview and net imports share of consumption

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.

U.S. primary energy consumption by source

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

September, 15 2020