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Last Updated: August 12, 2020
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Forecast Highlights

  • The August Short-Term Energy Outlook (STEO) remains subject to heightened levels of uncertainty because mitigation and reopening efforts related to the 2019 novel coronavirus disease (COVID-19) continue to evolve. Reduced economic activity related to the COVID-19 pandemic has caused changes in energy demand and supply patterns in 2020. Uncertainties persist across the U.S. Energy Information Administration’s (EIA) outlook for all energy sources, including liquid fuels, natural gas, electricity, coal, and renewables. The STEO is based on U.S. macroeconomic forecasts by IHS Markit, which assume U.S. gross domestic product declined by 5.2% in the first half of 2020 from the same period a year ago and will rise from the third quarter of 2020 through 2021.
  • Daily Brent crude oil spot prices averaged $43 per barrel (b) in July, up $3/b from the average in June and up $25/b from the multiyear low monthly average price in April. EIA expects monthly Brent spot prices will average $43/b during the second half of 2020 and rise to an average of $50/b in 2021.
  • U.S. regular gasoline retail prices averaged $2.18 per gallon (gal) in July, an increase of 10 cents/gal from the average in June but 56 cents/gal lower than at the same time last year. EIA expects that gasoline prices will gradually decrease through the rest of the summer to reach an average of $2.04/gal in September before falling to an average of $1.99/gal in the fourth quarter. Forecast U.S. regular gasoline retail prices will average $2.23/gal in 2021, compared with an average of $2.12/gal in 2020.
  • EIA expects high inventory levels and surplus crude oil production capacity will limit upward price pressures in the coming months, but as inventories decline into 2021, those upward price pressures will increase. EIA estimates global liquid fuels inventories rose at a rate of 6.4 million barrels per day (b/d) in the first half of 2020 and expects they will decline at a rate of 4.2 million b/d in the second half of 2020 and then decline by 0.8 million b/d in 2021.
  • EIA estimates that demand for global petroleum and liquid fuels averaged 93.4 million b/d in July. Demand was down 9.1 million b/d from July 2019, but it was up from an average of 85.0 million b/d during the second quarter of 2020, which was down 15.8 million b/d from year-ago levels. EIA forecasts that consumption of petroleum and liquid fuels globally will average 93.1 million b/d for all of 2020, down 8.1 million b/d from 2019, before increasing by 7.0 million b/d in 2021. Reduced economic activity related to the COVID-19 pandemic has caused changes in energy supply and demand patterns in 2020.
  • EIA estimates that global liquid fuels production averaged 91.8 million b/d in the second quarter of 2020, down 8.6 million b/d year over year. The decline reflects voluntary production cuts by the Organization of the Petroleum Exporting Countries (OPEC) and partner countries (OPEC+), and reductions in drilling activity and production curtailments in the United States because of low oil prices. In the forecast, the global supply of oil continues to decline to 90.4 million b/d in the third quarter of 2020 before rising to an annual average of 99.4 million b/d in 2021.
  • EIA estimates that U.S. liquid fuels consumption averaged 16.2 million b/d in the second quarter of 2020, down 4.1 million b/d (20%) from the same period in 2019. The decline reflects travel restrictions and reduced economic activity related to COVID-19 mitigation efforts. EIA expects U.S. oil consumption will generally rise through the end of 2021. EIA forecasts U.S. liquid fuels consumption will average 18.9 million b/d in the third quarter of 2020 (down 1.8 million b/d year over year) before rising to an average of 20.0 million b/d in 2021. Although the 2021 forecast level is 1.6 million b/d more than EIA’s forecast 2020 consumption, it is 0.4 million b/d less than the 2019 average.
  • EIA has lowered U.S. crude oil production estimates for 2020 by 370,000 b/d from the previous STEO. EIA expects crude production to average 11.3 million b/d in 2020 and 11.1 million b/d in 2021, down from 12.2 million b/d in 2019. Recently released EIA data show that average monthly U.S. oil production for May was 1.2 million b/d lower than the July STEO forecast, indicating more extensive production curtailments than previously estimated. Also, EIA’s August STEO assumes that the Dakota Access Pipeline will remain operational. A U.S. District Court ordered on July 6 the temporary closure of the Dakota Access Pipeline beginning in early August. A U.S. appeals court has overturned the lower court decision, allowing the pipeline to remain running while further litigation proceedings continue.
  • In July, the Henry Hub natural gas spot price averaged $1.77 per million British thermal units (MMBtu). EIA expects natural gas prices will generally rise through the end of 2021 but the sharpest increases will be during this fall and winter when they rise from an average of $2.11/MMBtu in September to $3.14/MMBtu in February. EIA expects that rising demand heading into winter, combined with reduced production, will cause upward price pressures. EIA forecasts that Henry Hub natural gas spot prices will average $2.03/MMBtu in 2020 and $3.14/MMBtu in 2021.
  • EIA estimates that total U.S. working natural gas in storage ended July at about 3.3 trillion cubic feet (Tcf), 15% more than the five-year (2015–19) average. In the forecast, inventories rise by 2.0 Tcf during the April-through-October injection season to reach nearly 4.0 Tcf on October 31.
  • EIA expects that total U.S. consumption of natural gas will average 82.4 billion cubic feet per day (Bcf/d) in 2020, down 3.0% from 2019. The largest decline in consumption occurs in the industrial sector, which EIA forecasts will average 22.0 Bcf/d in 2020, down 1.0 Bcf/d from 2019, as a result of reduced manufacturing activity. The decline in total U.S. consumption also reflects lower heating demand in early 2020, contributing to residential and commercial demand in 2020 averaging 12.8 Bcf/d (down 0.9 Bcf/d from 2019) and 8.8 Bcf/d (down 0.8 Bcf/d from 2019), respectively.
  • U.S. dry natural gas production set an annual record in 2019, averaging 92.2 Bcf/d. EIA forecasts dry natural gas production will average 88.7 Bcf/d in 2020, with monthly production falling from its monthly average peak of 96.2 Bcf/d in November 2019 to 82.7 Bcf/d by April 2021, before increasing slightly. Natural gas production declines the most in the Permian region, where EIA expects low crude oil prices will reduce associated natural gas output from oil-directed rigs. EIA’s forecast of dry natural gas production in the United States averages 84.0 Bcf/d in 2021. EIA expects production to begin rising in the second quarter of 2021 in response to higher natural gas and crude oil prices.
  • EIA estimates that U.S. liquefied natural gas (LNG) exports will average 5.5 Bcf/d in 2020 and will average 7.3 Bcf/d in 2021. EIA expects that U.S. LNG exports will decline through the end of the summer as a result of reduced global demand for natural gas. U.S. exports of LNG in July 2020 averaged 3.1 Bcf/d, which is about the same as in May 2018, when the available liquefaction capacity was about one-third of the current capacity. Declines in global natural gas demand associated with COVID-19 mitigation efforts, high natural gas storage inventories in Europe and Asia, and an on-going expansion in LNG liquefaction capacity have contributed to natural gas and LNG prices reaching all-time historical lows. Low international prices have affected the economic competitiveness of U.S. LNG exports and have led to numerous cargo cancellations, particularly at the Sabine Pass, Corpus Christi, and Freeport LNG export terminals. EIA expects LNG exports from the United States to remain low in the next few months. Based on numerous trade press reports, EIA estimates about 45 cargoes have been canceled for upcoming August shipments and about 30 cargoes have been canceled for September shipments.
  • EIA forecasts 3.6% less electricity consumption in the United States in 2020 compared with 2019. The largest decline on a percentage basis is in the commercial sector, where EIA expects retail sales of electricity to fall by 7.4% this year. Forecast industrial retail electricity sales fall by 5.8%. EIA forecasts residential sector retail sales will increase by 2.0% in 2020. Milder winter temperatures earlier in the year led to lower consumption for space heating, but that factor is offset by increased summer cooling demand and an assumed increase in electricity use by more people working from home. In 2021, EIA forecasts total U.S. electricity consumption will rise by 0.8%.
  • EIA expects the share of U.S. electric power sector generation from natural gas-fired power plants will increase from 37% in 2019 to 40% this year. In 2021, the forecast natural gas share declines to 35% in response to higher natural gas prices. Coal’s forecast share of electricity generation falls from 24% in 2019 to 18% in 2020 and then increases to 22% in 2021. Electricity generation from renewable energy sources rises from 17% in 2019 to 20% in 2020 and to 22% in 2021. The increase in the share from renewables is the result of expected additions to wind and solar generating capacity. EIA expects a decline in nuclear generation in both 2020 and 2021, reflecting recent and upcoming retirements of nuclear generating capacity.
  • EIA forecasts that renewable energy will be the fastest-growing source of electricity generation in 2020. EIA expects the electric power sector will add 23.2 gigawatts (GW) of new wind capacity and 12.9 GW of utility-scale solar capacity in 2020. However, these future capacity additions are subject to a high degree of uncertainty, and EIA continues to monitor reported planned capacity builds.
  • U.S. coal consumption, which dropped to its lowest point since April, totaled 95 MMst in the second quarter of 2020. EIA expects coal consumption to rise to a seasonal peak of 127 MMst in the third quarter but remain lower than 2019 levels through the end of 2020. EIA estimates that U.S. coal consumption will decrease by 26% in 2020 and increase by 20% in 2021. EIA estimates that total U.S. coal production in 2020 will decrease by 29% from 2019 levels to 502 MMst. In 2021, EIA expects higher demand and rising natural gas prices to a lead to a recovery in coal production of 12%, with a total annual production level of 564 MMst.
  • EIA forecasts that U.S. energy-related carbon dioxide (CO2) emissions, after decreasing by 2.8% in 2019, will decrease by 11.5% (588 million metric tons) in 2020. This record decline is the result of less energy consumption related to restrictions on business and travel activity and slowing economic growth related to COVID-19 mitigation efforts. CO2 emissions decline with reduced consumption of all fossil fuels, particularly coal (24.9%) and petroleum (11.6%). In 2021, EIA forecasts that energy-related CO2 emissions will increase by 5.6%, as the economy recovers and stay-at-home orders are lifted. Energy-related CO2 emissions are sensitive to changes in weather, economic growth, energy prices, and fuel mix.

STEO Forecast Covid-19 Short Term Energy Outlook EIA USA gas oil coal consumption demand supply oil prices market Brent
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December, 01 2021
Royal Dutch Shell Poised To Become Just Shell

On 10 December 2021, if all goes to plan Royal Dutch Shell will become just Shell. The energy supermajor will move its headquarters from The Hague in The Netherlands to London, UK. At least three-quarters of the company’s shareholders must vote in favour of the change at the upcoming general meeting, which has been sold by Shell as a means of simplifying its corporate structure and better return value to shareholders, as well as be ‘better positioned to seize opportunities and play a leading role in the energy transition’. In doing so, it will no longer meet Dutch conditions for ‘royal’ designation, dropping a moniker that has defined the company through decades of evolution since 1907.

But why this and why now?

There is a complex web of reasons why, some internal and some external but the ultimate reason boils down to improving growth sustainability. Royal Dutch Shell was born through the merger of Shell Transport and Trading Company (based in the UK) and Royal Dutch (based in The Netherlands) in 1907, with both companies engaging in exploration activities ranging from seashells to crude oil. Unified across international borders, Royal Dutch Shell emerged as Europe’s answer to John D Rockefeller’s Standard Oil empire, as the race to exploit oil (and later natural gas) reserves spilled out over the world. Along the way, Royal Dutch Shell chalked up a number of achievements including establishing the iconic Brent field in the North Sea to striking the first commercial oil in Nigeria. Unlike Standard Oil which was dissolved into 34 smaller companies in 1911, Royal Dutch Shell remained intact, operating as two entities until 2005, when they were finally combined in a dual-nationality structure: incorporated in the UK, but residing in the Netherlands. This managed to satisfy the national claims both countries make on the supermajor, second only to ExxonMobil in revenue and profits but proved to be costly to maintain. In 2020, fellow Anglo-Dutch conglomerate Unilever also ditched its dual structure, opting to be based fully out of the City of London. In that sense, Shell is following the direction of the wind, as forces in its (soon to be former) home country turn sour.

There is a specific grievance that Royal Dutch Shell has with the Dutch government, the 15% dividend tax collected for Dutch-domiciled companies. It is the reason why Unilever abandoned Rotterdam and is now the reason why Shell is abandoning The Hague. And this point is particularly existentialist for Shell, since its share prices has been battered in recent years following the industry downturn since 2015, the global pandemic and being in the crosshairs of climate change activists as an emblem of why the world’s average temperatures are going haywire. The latter has already caused the largest Dutch state pension fund ABP to stop investing in fossil fuels, thereby divesting itself of Royal Dutch Shell. This was largely a symbolic move, but as religious figures will know, symbols themselves carry much power. To combat this, Shell has done two things. First, it has positioned itself to be at the forefront of energy transition, announcing ambitious emissions reductions plans in line with its European counterparts to become carbon neutral by 2050. Second, it is looking to bump up its dividend payouts after slashing them through the depths of the Covid-19 pandemic and accelerating share buybacks to remain the bluest of blue-chip stocks. But then, earlier this year, a Dutch court ruled that Shell’s emissions targets were ‘not ambitious enough’, ordering a stricter aim within a tighter timeframe. And the 15% dividend tax remains – even though Prime Minister Mark Rutte’s coalition government has been attempting to scrap it, with (it is presumed) some lobbying from Royal Dutch Shell and Unilever.

As simplistic it is to think that Shell is leaving for London believes the citizens of the Netherlands has turned its back on the company, the ultimate reason was the dividend tax. Reportedly, CEO Ben van Buerden called up Mark Rutte on Sunday informing him of the planned move. Rutte’s reaction, it is said was of dismay. And he embarked on a last-ditch effort to persuade Royal Dutch Shell to change its mind, by immediately lobbying his government’s coalition partners to back an abolition of the dividend tax. The reaction was perhaps not what he expected, with left-wing and green parties calling Shell’s threat ‘blackmail’. With democracy drawing a line, Shell decided to walk; or at least present an exit plan endorsed by its Board to be voted by shareholders. Many in the Netherlands see Shell’s exit and the loss of the moniker Royal Dutch – as a blow to national pride, especially since the country has been basking in the glow of expanded reputation as a result of post-Brexit migration of financial activities to Amsterdam from London. The UK, on the other hand, sees Shell’s decision and Unilever’s – as an endorsement of the country’s post-Brexit potential.

The move, if passed and in its initial stages, will be mainly structural, transferring the tax residence of Shell to London. Just ten top executives including van Buerden and CFO Jessica Uhl will be making the move to London. Three major arms – Projects and Technology, Global Upstream and Integrated Gas and Renewable Energies – will remain in The Hague. As will Shell’s massive physical reach on Dutch soil: the huge integrated refinery in Pernis, the biofuels hub in Rotterdam, the country’s first offshore wind farm and the mammoth Porthos carbon capture project that will funnel emissions from Rotterdam to be stored in empty North Sea gas fields. And Shell’s troubles with activists will still continue. British climate change activists are as, if not more aggressive as their Dutch counterpart, this being the country where Extinction Rebellion was born. Perhaps more of a threat is activist investor Third Point, which recently acquired a chunk of Shell shares and has been advocating splitting the company into two – a legacy business for fossil fuels and a futures-focused business for renewables.

So Shell’s business remains, even though its address has changed. In the grand scheme of things, never mind the small matter of Dutch national pride – Royal Dutch Shell’s roadmap to remain an investment icon and a major driver of energy transition will continue in its current form. This is a quibble about money or rather, tax – that will have little to no impact on Shell’s operations or on its ambitions. Royal Dutch Shell is poised to become just Shell. Different name and a different house, but the same contents. Unless, of course, Queen Elizabeth II decides to provide royal assent, in which case, Shell might one day become Royal British Shell.

End of Article 

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