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Forecast HighlightsGlobal liquid fuels

  • Brent crude oil spot prices averaged $63 per barrel (b) in November, up $3/b from October. EIA forecasts Brent spot prices will average $61/b in 2020, down from a 2019 average of $64/b. EIA forecasts that West Texas Intermediate (WTI) prices will average $5.50/b less than Brent prices in 2020. EIA expects crude oil prices will be lower on average in 2020 than in 2019 because of forecast rising global oil inventories, particularly in the first half of next year.
  • On December 6, the Organization of the Petroleum Exporting Countries (OPEC) and a group of other oil producers announced they were deepening production cuts originally announced in December 2018. The group is now targeting production that is 1.7 million barrels per day (b/d) lower than in October 2018, compared with the former target reduction of 1.2 million b/d. OPEC announced that the cuts would be in effect through the end of March 2020. However, EIA assumes that OPEC will limit production through all of 2020, amid a forecast of rising oil inventories. EIA forecasts OPEC crude oil production will average 29.3 million b/d in 2020, down by 0.5 million b/d from 2019.
  • Beginning on January 1, 2020, the International Maritime Organization (IMO) is set to enact Annex VI of the International Convention for the Prevention of Pollution from Ships (MARPOL Convention), which lowers the maximum sulfur content of marine fuel oil used in ocean-going vessels from 3.5% of weight to 0.5%. EIA expects that starting in the fourth quarter of 2019, this regulation will encourage global refiners to increase refinery runs and maximize upgrading of high-sulfur heavy fuel oil into low-sulfur distillate fuel to create compliant bunker fuels. EIA forecasts that U.S. refinery runs will rise by 3% from 2019 to a record level of 17.5 million b/d in 2020, resulting in refinery utilization rates that average 93% in 2020. EIA expects one of the most significant effects of the regulation to be on diesel wholesale margins, which rise from an average of 45 cents per gallon (gal) in 2019 to a forecasted peak of 61 cents/gal in the first quarter of 2020 and an average of 57 cents/gal in 2020.
  • EIA data show that the United States exported 90,000 b/d more total crude oil and petroleum products in September than it imported. This is the first month recorded in U.S. data that the United States exported more crude oil and petroleum products than it imported. U.S. imports and exports records of crude oil and petroleum products started on an annual basis in 1949 and on a monthly basis in 1973. EIA expects total crude oil and petroleum net exports to average 570,000 b/d in 2020 compared with average net imports of 490,000 b/d in 2019.
  • EIA expects U.S. crude oil production to average 13.2 million b/d in 2020, an increase of 0.9 million b/d from the 2019 level. Expected 2020 growth is slower than 2018 growth of 1.6 million b/d and 2019 growth of 1.3 million b/d. Slowing crude oil production growth results from a decline in drilling rigs over the past year that EIA expects to continue into 2020. Despite the decline in rigs, EIA forecasts production will continue to grow as rig efficiency and well-level productivity rises, offsetting the decline in the number of rigs.
  • EIA estimates that propane inventories in the Midwest—Petroleum Administration for Defense District (PADD) 2—were 22.0 million barrels at the end of November, 17% lower than the five-year (2014–18) average for the end of November. Colder-than-normal temperatures and strong grain drying demand in November contributed to large draws on Midwest propane inventories. Also, Western Canadian rail shipments of propane to the Midwest have declined since the opening of a new propane export terminal in Western Canada in May. EIA forecasts Midwest inventories at the end of March will be 32% lower than the five-year (2015–19) average and the lowest for that time of year since 2014.

West Texas Intermediate (WTI) crude oil price

Natural gas
  • EIA estimates that the U.S. total working gas inventories were 3,616 billion cubic feet (Bcf) at the end of November. This level was about equal to the five-year (2014–18) average and 19% higher than a year ago. EIA expects storage withdrawals to total 1.9 trillion cubic feet (Tcf) from the end of October to the end of March, which is less than the five-year average winter withdrawal. A withdrawal of this amount would leave the end-of-March inventories at almost 1.9 Tcf, which would be 8% higher than the five-year (2015–19) average.
  • The U.S. benchmark Henry Hub natural gas spot price averaged $2.64 per million British thermal units (MMBtu) in November, up 31 cents/MMBtu from October. Prices increased as a result of November temperatures that were colder than the 10-year (2009–18) average. EIA forecasts the Henry Hub spot price to average $2.45/MMBtu in 2020, down 14 cents/MMBtu from the 2019 average.
  • EIA forecasts that annual U.S. dry natural gas production will average 92.1 billion cubic feet per day (Bcf/d) in 2019, up 10% from 2018. EIA expects that natural gas production will grow much less in 2020 because of the lag between changes in price and changes in future drilling activity. Low prices in the third quarter of 2019 will reduce natural gas-directed drilling in the first half of 2020. EIA forecasts natural gas production in 2020 will average 95.1 Bcf/d.

World liquid fuels production and consumption balance

Electricity, coal, renewables, and emissions
  • EIA expects the share of U.S. total utility-scale electricity generation from natural gas-fired power plants will rise from 34% in 2018 to 37% in 2019 and to 39% in 2020. EIA forecasts the share of U.S. electric generation from coal to average 25% in 2019 and 22% in 2020, down from 28% in 2018. EIA’s forecast nuclear share of U.S. generation remains at about 20% in 2019 and in 2020. Hydropower averages a 7% share of total U.S. generation in the forecast for 2019 and 2020, similar to 2018. Wind, solar, and other nonhydropower renewables provided 9% of U.S. total utility-scale generation in 2018. EIA expects they will provide 10% in 2019 and 12% in 2020.
  • EIA expects U.S. coal production in 2019 to total 697 million short tons (MMst), which would be an 8% decline from the 2018 level. In 2020, EIA expects a further decrease in total U.S. coal production of 14%, to an annual total of 601 MMst, reflecting continued idling and closures of mines as a result of declining domestic demand.
  • EIA expects U.S. coal exports to total 93 MMst in 2019, and then decline by 8 MMst to 85 MMst in 2020. U.S. coking coal currently faces challenges from a global oversupply of steel, particularly in the fourth quarter of 2019. Steam coal exports have been dampened by high stockpiles in Europe and India, a top destination for U.S. shipments.
  • EIA expects U.S. electric power sector generation from renewables other than hydropower—principally wind and solar—to grow from 411 billion kilowatthours (kWh) in 2019 to 471 billion kWh in 2020. In EIA’s forecast, Texas accounts for 20% of the U.S. nonhydropower renewables generation in 2019 and 22% in 2020. California’s forecast share of nonhydropower renewables generation falls from 15% in 2019 to 14% in 2020. EIA expects that the Midwest and Central power regions will see shares in the 16% to 18% range for 2019 and 2020.
  • EIA forecasts that, after rising by 2.9% in 2018, U.S. energy-related carbon dioxide (CO2) emissions will decline by 1.4% in 2019 and by 2.2% in 2020, partly as a result of lower forecast energy consumption. For 2019, EIA estimates there was less demand for space cooling because of cooler summer months, with an estimated 5% decline in U.S. cooling degree days from 2018, when temperatures were significantly higher than the previous 10-year (2008–17) average. In addition, EIA also expects U.S. CO2 emissions in 2019 to decline because the forecast share of electricity generated from natural gas and renewables will increase, and the share generated from coal, which is a more carbon-intensive energy source, will decrease.

U.S. natural gas prices

U.S. residential electricity price

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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