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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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The United States installed more wind turbine capacity in 2020 than in any other year

U.S. wind turbine electricity generating capacity additions

Source: U.S. Energy Information Administration, Preliminary Monthly Electric Generator Inventory

In both 2019 and 2020, project developers in the United States installed more wind power capacity than any other generating technology. According to data recently published by the U.S. Energy Information Administration (EIA) in its Preliminary Monthly Electric Generator Inventory, annual wind turbine capacity additions in the United States set a record in 2020, totaling 14.2 gigawatts (GW) and surpassing the previous record of 13.2 GW added in 2012. After this record year for wind turbine capacity additions, total wind turbine capacity in the United States is now 118 GW.

The impending phaseout of the full value of the U.S. production tax credit (PTC) at the end of 2020 primarily drove investments in wind turbine capacity that year, just as previous tax credit reductions led to significant wind capacity additions in 2012 and 2019. In December 2020, Congress extended the PTC for another year.

net electricity generation from wind and other sources in selected states

Source: U.S. Energy Information Administration, Electric Power Monthly

Texas has the most wind turbine capacity among states: 30.2 GW were installed as of December 2020. In 2020, Texas generated more electricity from wind than the next three highest states (Iowa, Oklahoma, and Kansas) combined. However, Texas generates and consumes more total electricity than any other state, and wind remains slightly less than 20% of the state’s electricity generation mix.

In two other states—Iowa and Kansas—wind is the most prevalent source of in-state electricity generation. In both states, wind surpassed coal as the state’s top electricity generation source in 2019.

wind's share of in-state utility-scale electricity generation

Source: U.S. Energy Information Administration, Electric Power Monthly

Nationally, 8.4% of utility-scale electricity generation in 2020 came from wind turbines. Many of the turbines added in late 2020 will contribute to increases in wind-powered electricity generation in 2021. EIA expects wind’s share of electricity generation to increase to 10% in 2021, according to forecasts in EIA’s most recent Short-Term Energy Outlook.

March, 05 2021
Myanmar’s Coup and Repercussions to Its Oil Industry

It was a good run while it lasted. Almost exactly a decade ago, the military junta in Myanmar was dissolved, following civilian elections. The country’s figurehead, Aung San Suu Kyi, was released from house arrest to lead, following in the footsteps of her father. Although her reputation has since been tarnished with the Rohingya crisis, she remains beloved by most of her countrymen, and her installation as Myanmar’s de facto leader lead to a golden economic age. Sanctions were eased, trade links were restored, and investment flowed in, not least in the energy sector. Yet the military still remained a powerful force, lurking in the background. In early February, they bared their fangs. Following an election in November 2020 in which Aung San Suu Kyi’s National League for Democracy (NLD) won an outright majority in both houses of Parliament. A coup d’etat was instigated, with the Tatmadaw – the Burmese military – decrying fraud in the election. Key politicians were arrested, and rule returned to the military.

For many Burmese, this was a return to a dark past that many thought was firmly behind them. Widespread protests erupted, quickly turning violent. The Tatmadaw still has an iron grip, but it has created some bizarre situations – ordinary Burmese citizens calling on Facebook and foreign governments to impose sanctions on their country, while the Myanmar ambassador to the United Nations was fired for making an anti-army speech at the UN General Assembly.

The path forward for Myanmar from this point is unclear. The Tatmadaw has declared a state of emergency lasting up to a year, promising new elections by the end of 2021. There is little doubt that the NLD will win yet another supermajority in the election, IF they are fair and free. But that is a big if. Meanwhile, the coup threatens to return Myanmar to the pariah state that it was pre-2010. And threatens to abort all the grand economic progress made since.

In the decade since military rule was abolished, development in Myanmar has been rapid. In the capital city Yangon, glittering new malls have been developed. The Ministry of Energy in 2009 was housed in a crumbling former high school; today, it occupies a sprawling complex in the new administrative capital of Naypyidaw. While not exactly up to the level of the Department of Energy in Washington DC, it is certainly no longer than ministry that was once reputed to take up to three years to process exploration licences for offshore oil and gas blocks.

And it is that very future that is now at stake. Energy has been a great focus for investment in Myanmar, drawn by the rich offshore deposits in the Andaman Sea and the country’s location as a possible pipeline route between the Middle East and inland China. Estimates suggest that – based on pre-coup trends – Myanmar was likely to attract over US$1.1 billion in upstream investment in 2023, more than four times projected for 2021 and almost 20 times higher than 2011. The funds would not only be directed at maintaining production at the current Yadana, Yetagun, Zawtika and Shwe gas fields – where offshore production is mainly exported to Thailand, but also upcoming megaprojects such as Woodside and Total’s A-6 deepwater natural gas and PTTEP’s Aung Sinka Block M3 developments.

The coup now presents foreign investors in Myanmar’s upstream energy sector with a conundrum and reputational risk. Stay, and risk being seen as abetting an undemocratic government? Or leave, and risk being flushing away years of hard work? The home governments of foreign investors such as Total, Chevron, PTTEP, Woodside, Petronas, ONGC, Nippon Oil, Kogas, POSCO, Sumitomo, Mitsui and others have already condemned the coup. For now these companies are hoping that foreign pressure will resolve the situation in a short enough timeframe to allow business to resume. Australia’s Woodside Petroleum has already called the coup a ‘transitionary issue’ claiming that it will not affect its exploration plans, while other operators such as Total and Petronas have focused on the safety of their employees as they ‘monitor the evolving situation’.

But the longer the coup lasts without a resolution satisfactory to the international community and the longer the protests last (and the more deaths that result from that), the more untenable the position of the foreign upstream players will be. Asian investors, especially the Chinese, mainly through CNPC/PetroChina, and the Thais, through PTTEP - will be relatively insulated, but American and European majors face bigger risks. This could jeopardise key projects such as the Myanmar-to-China crude oil and natural gas pipeline project (a 771km connection to Yunnan), two LNG-to-power projects (Thaketa and Thilawa, meant to deal with the country’s chronic blackouts) and the massive Block A-6 gas development in the Shwe Yee Htun field by Woodside which just kicked off a fourth drilling campaign in December.

It is a big unknown. The Tatmadaw has proven to be impervious to foreign criticism in the past, ignoring even the most stringent sanctions thrown their way. In fact, it was a huge surprise that the army even relinquished power back in 2010. But the situation has changed. The Myanmar population is now more connected and more aware, while the army has profited off the opening of the economy. The economic consequences of returning to its darker days might be enough to trigger a resolution. But that’s not a guarantee. What is certain is that the coup will have a lasting effect on energy investment and plans in Myanmar. How long and how deep is a question that only the Tatmadaw can answer. 

Market Outlook:

  • Crude price trading range: Brent – US$63-65/b, WTI – US$60-63/b
  • The slow-but-sure recovery in Texan energy infrastructure following the big freeze has caused crude oil benchmarks to retreat somewhat, with all eyes now focusing on OPEC+ as it meets to decide its supply quotas for April and beyond
  • Some form of supply easing is expected, given that the market is showing signs of tight supply, but OPEC+ is still split on how aggressive it can be; Saudi Arabia is advocating caution while most others, led by Russia, favour a bolder easing given current prices
  • While OPEC+ supply will be keenly watched as an indicator of future crude trends, supply elsewhere is picking up, with the Baker Hughes survey of active oil and gas rigs in the USA crossing the 400-site level for the first time in over a year, with gains mainly from onshore shale drillers tempted back after being wiped up last year

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March, 03 2021
The Competition For The LNG Crown

The year 2020 was exceptional in many ways, to say the least. All of which, lockdowns and meltdowns, managed to overshadow a changing of the guard in the LNG world. After leapfrogging Indonesia as the world’s largest LNG producer in 2006, Qatar was surpassed by Australia in 2020 when the final figures for 2019 came in. That this happened was no surprise; it was always a foregone conclusion given Australia’s massive LNG projects developed over the last decade. Were it not for the severe delays in completion, Australia would have taken the crown much earlier; in fact, by capacity, Australia already sailed past Qatar in 2018.

But Australia should not rest on its laurels. The last of the LNG mega-projects in Western Australia, Shell’s giant floating Prelude and Inpex’s sprawling Ichthys onshore complex, have been completed. Additional phases will provide incremental new capacity, but no new mega-projects are on the horizon, for now. Meanwhile, after several years of carefully managing its vast capacity, Qatar is now embarking on its own LNG infrastructure investment spree that should see it reclaim its LNG exporter crown in 2030.

Key to this is the vast North Field, the single largest non-associated gas field in the world. Straddling the maritime border between tiny Qatar and its giant neighbour Iran to the north, Qatar Petroleum has taken the final investment decision to develop the North Field East Project (NFE) this month. With a total price tag of US$28.75 billion, development will kick off in 2021 and is expected to start production in late 2025. Completion of the NFE will raise Qatar’s LNG production capacity from a current 77 million tons per annum to 110 mmtpa. This is easily higher than Australia’s current installed capacity of 88 mmtpa, but the difficulty in anticipating future utilisation rates means that Qatar might not retake pole position immediately. But it certainly will by 2030, when the second phase of the project – the North Field South (NFS) – is slated to start production. This would raise Qatar’s installed capacity to 126 mmtpa, cementing its lead further still, with Qatar Petroleum also stating that it is ‘evaluating further LNG capacity expansions’ beyond that ceiling. If it does, then it should be more big leaps, since this tiny country tends to do things in giant steps, rather than small jumps.

Will there be enough buyers for LNG at the time, though? With all the conversation about sustainability and carbon neutrality, does natural gas still have a role to play? Predicting the future is always difficult, but the short answer, based on current trends, it is a simple yes. 

Supermajors such as Shell, BP and Total have set carbon neutral targets for their operations by 2050. Under the Paris Agreement, many countries are also aiming to reduce their carbon emissions significantly as well; even the USA, under the new Biden administration, has rejoined the accord. But carbon neutral does not mean zero carbon. It means that the net carbon emissions of a company or of a country is zero. Emissions from one part of the pie can be offset by other parts of the pie, with the challenge being to excise the most polluting portions to make the overall goal of balancing emissions around the target easier. That, in energy terms, means moving away from dirtier power sources such as coal and oil, towards renewables such as solar and wind, as well as offsets such as carbon capture technology or carbon trading/pricing. Natural gas and LNG sit right in the middle of that spectrum: cleaner than conventional coal and oil, but still ubiquitous enough to be commercially viable.

So even in a carbon neutral world, there is a role for LNG to play. And crucially, demand is expected to continue rising. If ‘peak oil’ is now expected to be somewhere in the 2020s, then ‘peak gas’ is much further, post-2040s. In 2010, only 23 countries had access to LNG import facilities, led by Japan. In 2019, 43 countries now import LNG and that number will continue to rise as increased supply liquidity, cheaper pricing and infrastructural improvements take place. China will overtake Japan as the world’s largest LNG importer soon, while India just installed another 5 mmtpa import terminal in Hazira. More densely populated countries are hopping on the LNG bandwagon soon, the Philippines (108 million people), Vietnam (96 million people), to ensure a growing demand base for the fuel. Qatar’s central position in the world, sitting just between Europe and Asia, is a perfect base to service this growing demand.

There is competition, of course. Russia is increasingly moving to LNG as well, alongside its dominant position in piped natural gas. And there is the USA. By 2025, the USA should have 107 mmtpa of LNG capacity from currently sanctioned projects. That will be enough to make the USA the second-largest LNG exporter in the world, overtaking Australia. With a higher potential ceiling, the USA could also overtake Qatar eventually, since its capacity is driven by private enterprise rather than the controlled, centralised approach by Qatar Petroleum. The appearance of US LNG on the market has been a gamechanger; with lower costs, American LNG is highly competitive, having gone as far as Poland and China in a few short years. But while the average US LNG breakeven cost is estimated at around US$6.50-7.50/mmBtu, Qatar’s is even lower at US$4/mmBtu. Advantage: Qatar.

But there is still room for everyone in this growing LNG market. By 2030, global LNG demand is expected to grow to 580 million tons per annum, from a current 360 mmtpa. More LNG from Qatar is not just an opportunity, it is a necessity. Traditional LNG producers such as Malaysia and Indonesia are seeing waning volumes due to field maturity, but there is plenty of new capacity planned: in the USA, in Canada, in Egypt, in Israel, in Mozambique, and, of course, in Qatar. In that sense, it really doesn’t matter which country holds the crown of the world’s largest exporter, because LNG demand is a rising tide, and a rising tide lifts all 😊

Market Outlook:

  • Crude price trading range: Brent – US$64-66/b, WTI – US$60-63/b
  • Despite the thaw after Texas saw a devastating big freeze, the slow ramp-up in restoring US Gulf Coast oil production and refining has supported crude oil prices, with Brent moving above the US$65/b level and WTI now in the low US$60/b level
  • Some Wall Street analysts, including Goldman Sachs, are predicting that oil prices could climb above US$70/b level based on current fundamentals, as the short-term spike gives ways to accelerating consumption trends
  • However, much will depend on OPEC+’s approach to managing supply in Q2, with a meeting set for early March; Saudi Arabia is once again urging caution, but there are many other members of the club champing at the bit to increase output and capitalise on the rising price environment


March, 01 2021