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Last Updated: February 12, 2020
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Forecast Highlights

Global liquid fuels

  • EIA expects global petroleum and liquid fuels demand will average 100.3 million barrels per day (b/d) in the first quarter of 2020. This demand level is 0.9 million b/d less than forecast in the January STEO and reflects both the effects of the coronavirus and warmer-than-normal January temperatures across much of the northern hemisphere. EIA now expects global petroleum and liquid fuels demand will rise by 1.0 million b/d in 2020, which is lower than the forecast increase in the January STEO of 1.3 million b/d in 2020, and by 1.5 million b/d in 2021.
  • EIA’s global petroleum and liquid fuels supply forecast assumes that the Organization of the Petroleum Exporting Countries (OPEC) will reduce crude oil production by 0.5 million b/d from March through May because of lower expected global oil demand in early 2020. This OPEC reduction is in addition to the cuts announced at the group’s December 2019 meeting. EIA now forecasts OPEC crude oil production will average 28.9 million b/d in 2020, which is 0.3 million less than forecast in the January STEO. In addition to these production cuts, EIA’s lower forecast OPEC production reflects ongoing crude oil production outages in Libya during the first quarter. In general, EIA assumes that OPEC will limit production through all of 2020 and 2021 to target relatively balanced global oil markets.
  • Global liquid fuels inventories fell by roughly 0.1 million b/d in 2019, and EIA expects they will grow by 0.2 million b/d in 2020. Although EIA expects inventories to rise overall in 2020, EIA forecasts inventories will build by 0.6 million b/d in the first half of the year because of slow oil demand growth and strong non-OPEC oil supply growth. Firmer demand growth as the global economy strengthens and slower supply growth later in the year contribute to forecast inventory draws of 0.1 million b/d in the second half of 2020. EIA expects global liquid fuels inventories will decline by 0.2 million b/d in 2021.
  • Brent crude oil spot prices averaged $64 per barrel (b) in January, down $4/b from December. Brent prices fell steadily through January and into the first week of February, closing at less than $54/b on February 4, the lowest price since December 2018, reflecting market concerns about oil demand. EIA forecasts Brent prices will average $61/b in 2020; with prices averaging $58/b during the first half of the year and $64/b during the second half of the year. EIA forecasts the average Brent prices will rise to an average of $68/b in 2021.

Natural gas

  • In January, the Henry Hub natural gas spot price averaged $2.02 per million British thermal units (MMBtu), as warm weather contributed to below-average inventory withdrawals and put downward pressure on natural gas prices. As of February 6, the Henry Hub spot price had fallen to $1.86/MMBtu, and EIA expects prices will remain below $2.00/MMBtu in February and March. EIA forecasts that prices will rise in the second quarter of 2020, as U.S. natural gas production declines and natural gas use for power generation increases the demand for gas. EIA expects prices to average $2.36/MMBtu in the third quarter of 2020. EIA forecasts that Henry Hub natural gas spot prices will average $2.21/MMBtu in 2020. EIA expects that natural gas prices will then increase in 2021, reaching an annual average of $2.53/MMBtu.
  • U.S. dry natural gas production set a record in 2019, averaging 92.1 billion cubic feet per day (Bcf/d). Although EIA forecasts dry natural gas production will average 94.2 Bcf/d in 2020, a 2% increase from 2019, EIA expects monthly production to generally decline through 2020, falling from an estimated 95.4 Bcf/d in January to 92.5 Bcf/d in December. The falling production mostly occurs in the Appalachian and Permian regions. In the Appalachia region, low natural gas prices are discouraging natural gas-directed drilling, and in the Permian, low oil prices are expected to reduce associated gas output from oil-directed wells. In 2021, EIA forecasts dry natural gas production to stabilize near December 2020 levels at an annual average of 92.6 Bcf/d, a 2% decline from 2020, which would be the first decline in annual average natural gas production since 2016.
  • EIA estimates that U.S. working natural gas inventories ended January at more than 2.6 trillion cubic feet (Tcf), 9% higher than the five-year (2015–19) average. EIA forecasts that total working inventories will end March at almost 2.0 Tcf, 14% higher than the five-year average. In the forecast, inventories rise by a total of 2.1 Tcf during the April through October injection season to reach almost 4.1 Tcf on October 31, which would be the highest end-of-October inventory level on record.

Electricity, coal, renewables, and emissions

  • EIA expects the share of U.S. utility-scale electricity generation from natural gas-fired power plants will remain relatively steady; it was 37% in 2019, and EIA forecasts it will be 38% in 2020 and 37% in 2021. Electricity generation from renewable energy sources will rise from a share of 17% last year to 20% in 2020 and 21% in 2021. The increase in the renewables share is the result of expected use of additions to wind and solar generating capacity. Coal’s forecast share of electricity generation will fall from 24% in 2019 to 21% in both 2020 and 2021. The nuclear share of generation, which averaged slightly more than 20% in 2019 will be slightly lower than 20% by 2021, consistent with upcoming reactor retirements.
  • EIA forecasts that U.S. coal production will total 595 million short tons (MMst) in 2020, down 95 MMst (14%) from 2019. Lower production reflects declining demand for coal in the electric power sector and lower demand for U.S. exports. EIA forecasts that electric power sector demand for coal will fall by 81 MMst (15%) in 2020. EIA expects that coal production will stabilize in 2021 as export demand stabilizes and U.S. power sector demand for coal increases because of rising natural gas prices.
  • After decreasing by 2.3% in 2019, EIA forecasts that energy-related carbon dioxide (CO2) emissions will decrease by 2.7% in 2020 and by 0.5% in 2021. Declining emissions in 2020 reflect forecast declines in total U.S. energy consumption because of increases in energy efficiency and weather effects, particularly as a result of warmer-than-normal January temperatures. A forecast return to normal temperatures in 2021 results in a slowing decline in emissions. Energy-related CO2 emissions are sensitive to changes in weather, economic growth, energy prices, and fuel mix.

STEO Short-Term Energy Outlook liquid fuels EIA Brent Natural Gas Coal renewables emissions electricity
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EIA forecasts natural gas inventories will reach record levels later this year

In the U.S. Energy Information Administration’s (EIA) February Short-Term Energy Outlook (STEO), EIA forecasts that the Lower 48 states’ working natural gas in storage will end the 2019–20 winter heating season (November 1–March 31) at 1,935 billion cubic feet (Bcf), with 12% more inventory than the previous five-year average. This increase is the result of mild winter temperatures and continuing strong production. EIA forecasts that net injections during the refill season (April 1–October 31) will bring the total working gas in storage to 4,029 Bcf, which, if realized, would be the largest monthly inventory level on record.

Mild winter temperatures for the current winter have put downward pressure on natural gas prices and led to smaller withdrawals from natural gas into storage. Year-over-year growth in dry natural gas production and natural gas exports—especially liquefied natural gas (LNG)—throughout 2019 also affected natural gas storage levels. On October 11, 2019, the total natural gas in storage surpassed the previous five-year average—an indicator of typical storage levels—for the first time since mid-2017.

lower 48 states working natural gas in storage

Source: U.S. Energy Information Administration, Natural Gas Monthly, Weekly Natural Gas Storage Report, and Short-Term Energy Outlook

The total natural gas in storage at the start of this heating season was 3,725 Bcf on October 31, 2019. EIA expects withdrawals from working natural gas storage to total 1,790 Bcf at the end of March 2020. If realized, this would be the least natural gas withdrawn during a heating season since the winter of 2015–16, when temperatures were also mild.

Injections into and withdrawals from natural gas storage balance seasonal and other fluctuations in consumption. Natural gas demand is greatest in the winter months, when residential and commercial demand for natural gas for space heating increases. Natural gas consumption in the power sector is greatest in summer months, when overall electricity demand is relatively high because of air conditioning.

monthly U.S. natural gas supply and disposition

Source: U.S. Energy Information Administration, Short-Term Energy Outlook

In the latest STEO, EIA expects the total working natural gas in storage will exceed the previous five-year average for the remainder of 2020, despite declines in dry natural gas production, increases in natural gas consumption in the electric power sector, and increases in natural gas exports. EIA expects monthly natural gas production to decline from last year’s record levels in 2020 as lower natural gas prices reduce incentives for natural gas-directed drilling and as lower crude oil prices reduce incentives for oil-directed drilling and associated gas production.

February, 25 2020
The World’s Largest Natural Gas Discovery Since 2005

At the start of February, a major new find was jointly announced by the two largest emirates within the UAE: the oil-rich Abu Dhabi and the ambitious Dubai. Between them, they literally made the world’s largest natural gas discovery since 2005. Located at the border between the two sheikdoms, the Jebel Ali field is estimated to contain some 80 trillion scf of natural gas, the largest global find since the Galkynysh field in Turkmenistan.

Stretching over 5,000 square km, an exploration campaign by Abu Dhabi involving over 10 wells confirmed the enormous discovery in early January 2020. The shallow nature of the onshore reserves should make it easier to extract gas at lower costs, hastening the time-to-market. At current estimated figures, Jebel Ali would be the fourth-largest gas field in the Middle East, behind Qatar’s North Field, Iran’s South Pars and Abu Dhabi’s own Bab field.

The politics of the UAE can be complicated; each emirate is essentially self-governing with federal oversight, which is dominated by Abu Dhabi and Dubai (which always hold the President and Prime Minister roles, according to convention). This essentially means that each emirate has grew quite independently. Fujairah, for example, developed into a bunkering port, while Sharjah went into industry and manufacturing. Dubai is globally famous for its titanic real estate projects, pursued finance, services and media, while Abu Dhabi, the largest and most blessed of all with hydrocarbon resources, turned into an energy powerhouse. Oil & gas wealth in the UAE is mainly in Abu Dhabi; so while the Jebel Ali discovery is a welcome addition for Abu Dhabi, it is a game changer for Dubai, which imports most of its energy needs.

Speculation has raised that possibility that the Jebel Ali field could vault the UAE into gas self-sufficiency, because even Abu Dhabi imports gas. The UAE has a stated goal to be gas independent by 2030. On paper, that’s possible. Abu Dhabi’s ADNOC has agreed to develop the field with Dubai’s gas supplier, the Dubai Supply Authority (DUSUP), with the entire supply will be channel to DUSUP for use in Dubai. Jebel Ali could begin producing gas by 2023, and will likely be distributed domestically through pipeline. The enormous reserves could supply the entire UAE’s gas demand for nearly 30 years, assuming optimal recovery conditions. However, in practice, self-sufficiency might take longer to achieve.

Dubai and indeed, Abu Dhabi are currently reliant on Qatar for their gas supply. An existing sales agreement that expires in 2032 sees Qatar pipe 2 bcf/d of gas to the UAE through Abu Dhabi. The problem is that these neighbours are erstwhile friends. A division in the Middle East between the pro-Saudi Arabia and pro-Iran blocs has caused a rift. Led by Saudi Arabia, several Persian Gulf states  including the UAE implemented a diplomatic and trade blockade on Qatar, isolating it. The blockade, slightly weakened, still continues today. Even now, planes flying into Qatar have to make strange manoeuvres when approaching to avoid encroaching on Saudi and UAE airspace. However, the gas supply arrangement remains in place.

And this is where the Jebel Ali discovery could come in handy. Qatar is already on track to be self-sufficient in gas terms by 2025, but will probably honour the Qatar deal until expiration. Dubai has been increasingly reliant on LNG  through an FSRU for power generation, but has attempted over the years to kick-start a number of coal or solar-power projects. Jebel Ali won’t kick the addiction, but it could definitely reduce Dubai’s reliance on Qatari gas.

Jebel Ali wasn’t the only recent gas discovery made in the UAE. Further north, the Sharjah National Oil Corp and Italy’s Eni announced a new onshore gas and condensate discovery. Though tiny in comparison to Jebel Ali, some 50 mscf/d of lean gas and condensate. The cumulative effects of these discoveries could make gas self-sufficiency a reality sooner. At this point, the UAE consumes some 7.4 bcf gas per day, while marketed production is some 6.2 bcf/d. An ambitious plan to develop Abu Dhabi’s large gas fields was the rationale behind naming the 2030 self-sufficiency deadline. With the discovery of Jebel Ali, that can now be brought forward by a couple of years at least. And there might even be some left over to be exported as LNG

The UAE Major Gas Projects:

  • Estimated reserves: 273 tcf of conventional gas, 160 tcf of unconventional gas (Abu Dhabi)
  • Ghasha ultra-sour gas field (Abu Dhabi) – 1.5 bcf, by 2025
  • Shah sour gas field (Abu Dhabi) – 1.5 bcf/d

February, 23 2020
Your Weekly Update: 17 - 21 February 2020

Market Watch   

Headline crude prices for the week beginning 17 February 2020 – Brent: US$53/b; WTI: US$49/b

  • As the Covid-19 pandemic seems to be coming increasingly under control, crude oil prices are recovering some ground as the market moves into speculative mode given the availability of cheap crude cargoes
  • Case in point, while the fear was of widespread demand destruction in China, a sudden buying spree by Chinese independent teapot refineries – attracted by cheap spot cargoes – surprised the market, being a sign that Chinese private refiners are anticipating a rebound in demand sooner rather than later
  • Despite this, the pandemic is still recalibrating Chinese energy demand in a dramatic way, with reports of four LNG tanker bound for northern China from Oman and Qatar diverted as CNOOC invoked force majeure on its contracts
  • China’s pain is also India’s gain, with so-called ‘distressed cargoes’ originally intended for China now offered to India at attractive terms from all over the world, including grades from the Caspian Sea to Latin America and West Africa
  • Based on the situation in China, the IEA is forecasting the first annual decline in quarterly global oil demand for the first time in over a decade, and dragging overall 2020 growth down by 30% to 825,000 b/d; the EIA followed suit as well, cutting its Brent price forecast for 2020 from US$64.83 to US$61.25
  • China and key Asian hubs impacted by the virus like Hong Kong and Singapore have pledged to provide extra fiscal stimulus to counteract the impact of the pandemic, possibly setting the stage for a rebound in Q2 2020
  • Saudi Arabia’s attempt to cajole the OPEC+ club into extending its supply cuts until June 2020 through an emergency February meeting has faded, with Russia being the main holdout
  • Amid the turmoil in the markets, the US active rig count remained unchanged for the week, adding two oil sites but losing gas and miscellaneous sites for a total of 790
  • Oil prices gained over the week as the Covid-19 pandemic looks to be contained; Brent should trade in a higher US$57-59/b range and WTI at US$43-55/b


Headlines of the week

Upstream

  • Saudi Arabia and Kuwait have officially restarted production from their shared Wafra field in the Neutral after five years of halted output
  • Despite being hampered by quarterly waivers that are subject to renewals by the US government, Chevron has ramped up production at its Petropiar crude upgrader plant in Venezuela to 130,000 b/d after being closed for most of 2019
  • Canada’s Alberta province’s plan to ease its crude glut through rail shipments has hit a snag, as protestors blocked train lines and the provincial government ordered trains to reduce speeds after a major derailment and fire
  • Tullow Oil reports that it has received approval from Ghana to flare gas ‘when necessary’ from its offshore fields, which should help the beleaguered company support production levels after a set of disappointing results for 2019
  • Somalia has passed a new petroleum bill into law, with the aim of setting up a regulatory framework to attract foreign upstream investment; Somalia currently does not produce any oil but estimates suggest significant reserves
  • As Uganda prepares to start producing oil for the first time, distribution and transport infrastructure remain an issue, with the state recently tapping a Chinese lender to build three roads to connect to its western oilfields
  • After a challenging few years of scandals and a subsequent refocusing on upstream, Petrobras has now hit a new upstream production record, with the ramp-up in pre-salt basins contributing to 3.025 mmboe/d in Q4 2019
  • CNOOC has commenced production at the offshore Bozhong 34-9 field in the Bohai Sea, with peak output expected at 22,500 b/d of crude by 2022

Midstream/Downstream

  • The Covid-19 Wuhan outbreak has claimed a few more refinery scalps, with ChemChina shutting down its 100 kb/d Zhenghe refinery in Shandong and reducing processing at its Changyi and Huaxing refineries by 10%; Hengli Petrochemical has cut utilisation rates at its new 400 kb/d Dalian refinery by some 17% as well, as petchem demand dries up
  • The 120,000 b/d Azzawiya Oil Refining Company refinery in Libya has been forced to halt all operations, as a prolonged conflict in the country has dried up the availability of crude for export or local refining
  • Egypt has given the go-ahead for a US$2.5 billion, 65 kb/d oil refinery in the Upper Egypt region, focusing on hydrocracking mazut – heavy, low quality fuel oil typically used for power generation – into high-value fuels
  • The Bangladesh Petroleum Corp has awarded a tender to supply some 1.06 million tons of gasoil, jet fuel, fuel oil and gasoline to Unipec and Vitol
  • Vietnam’s Nghi Son refining has offered a cargo of gasoil for export for the first time – an indication of slowing domestic demand from the Covid-19 outbreak that is hitting most major East and Southeast Asian economies

Natural Gas/LNG

  • NextDecade Corp’s US$15 billion, 26 million tons per annum Rio Grande LNG facility in Texas has been cleared for LNG exports by the US DoE
  • Portugal’s Sines port is being eyed by US energy companies as a strategic landing point for US LNG exports to Europe, as American LNG exporters race to lock down customers amid a supply glut that could last for years
  • Shell has acquired a 50% stake in Ecopetrol’s Fuerte Sur, Purple Angel and COL-5 gas blocks located in Colombia’s Caribbean deepwater region
February, 21 2020