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Last Updated: October 6, 2017
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Business Trends

Last week in World oil:


  • With OPEC production rising in September as supplies from Nigeria and Libya recover, and US drilling numbers also show improvement, crude oil prices fell slightly from their recent highs – with Brent trading at about US$56/b and WTI at US$50/b.


  • Chevron is committing some US$4 billion to ramp up crude production in the Permian Basin, aiming to grow its production there from 90,000 b/d in 2016 to over 400,000 b/d over the next five years. With a report calling the Permian a ‘super basin’ with some 60-70 billion barrels yet unpumped, Chevron expects production across all producers in the Permian to rise to 3.8 mmb/d in 2020, from a present 2.4 mmb/d.
  • Brazil’s latest round of oil block auctions revealed one very big winner – ExxonMobil – and one very big loser – the Santos basin. ExxonMobil bet big on the offshore pre-salt Campos basin, taking its first Brazilian blocks in five years. A total of eight blocks were handed to ExxonMobil, six in partnership with Petrobras, with changes in Brazilian regulations allowing private players to operate blocks on their own now. This could make ExxonMobil the pre-eminent pre-salt crude producer in Brazil. Meanwhile, of the 76 blocks offered in the prized offshore Santos basin, only one received a bid – by Australia’s Karoon Gas – a sign that in a persistent low oil price environment, upstream companies are still wary.
  • American drillers added oil rigs for the first time in seven weeks, as six new sites (mostly in Utah) brought the total oil rig count to 750 and the total rig count to 940.

Downstream & Midstream

  • Pemex’s largest Mexican refinery– the 330 kb/d Salina Cruz site – will remain offline until the third week of October, as a series of natural disasters including flooding, storms and two earthquakes devastated its refining production, causing product shortages across Mexico.

Natural Gas and LNG

  • The Ruby well in the Dutch North Sea cold hold more gas than previously anticipated, which would be a shot in the arm for waning gas production in the Netherlands. Flows from the well 20km offshore have been encouraging; with estimates suggesting it could contain some 2 trillion cubic feet of gas, more than the country’s current annual production. The partners on the Ruby well as Oranje-Nassau Energie, Energie Beheer Nederland, Hansa Hydrocarbons and Avista Capital Partners.
  • Trader Glencore has agreed to purchase Angola LNG in a multi-year deal that represents a new foray for the country. Angolan LNG has mainly been sold on the spot market – as the shale boom curtailed Angola’s initial plan of shipping LNG to the US – but the Glencore deal joins similar longer-term contracts signed by Angola with Vitol and Germany’s RWE, as jitters about Angola LNG’s reliability as a supplier fade. Russia major Gazprom has also signed a recent long-term deal, with Ghana National Petroleum Corp, to purchase LNG over a 12 year period beginning 2019. Details on volumes, however, were not released.

Last week in Asian oil

Downstream & Midstream

  • Petronas Chemicals has agreed to sell a 50% stake in its PRPC Polymers subsidiary to Saudi Aramco for some US$900 million. The sale will be completed by 15 March, 2018, when the new shareholding structure for the previously wholly-owned company takes effect. Devoted to developing, constructing and operating polymers and glycol plants in Malaysia, but having yet started operations, the tie-up with Saudi Aramco bring in a deep-pocketed partner for Petronas, while being part of Aamco’s diversification plan. Aramco and Petronas are already partners in the massive US$27 billion RAPID project in the southern state of Johor.

Natural Gas & LNG

  • Australia has let Shell, ConocoPhillips, Origin and Santos off the hook for the current gas shortage in the eastern states for now. The government had threatened to impose export curbs on the four producers if they did not redirect supplies meant for LNG export to the domestic market. There are three LNG export plants currently on Australia’s east coast, and the deal with the government will see the plants act on their promise to provide supplies to meet the government’s projected shortfall of up to 17% of domestic demand in 2018.
  • Woodside is partnering with Chevron to pick up three new exploration blocks off the north-west coast of Australia. With equal stakes in the permits, both companies are eyeing gas from the WA-528-P, WA-529-P and WA-530-P permits in the Carnarvon Basin to supply their respective – and competing – LNG plants in Western Australia. Operated by Chevron, the gas blocks are ideally placed some 250km north-west of the existing Pluto, Gorgon and Wheatstone plants, increasingly important as an LNG supply point to East Asia.
  • Thailand has decided to delay its auctions for the Erawan and Bongkot gas concessions for at least another month, expecting to only announce the winners in the middle of 2018. Chevron currently operates Erawan and state firm PTTEP operates Bongkot, with licenses set to expire in 2022 and 2023. Combined, both fields account for some 76% of Gulf of Thailand output, with the delay stemming from a government review of the new PSC terms to be used for the new licences. Chevron and PTTEP are bidding to keep the fields, while local firms Bangchak and Palang Sophon, along with Abu Dhabi’s Mubadala Petroleum and Japan’snMitsui Oil Exploration, are also in the running.
  • South Korea’s KOGAS is planning to build the country’s fifth LNG import terminal, targeting operational usage by 2025. The plant – which is planned to have ten 200,000 cbm storage tanks and associated infrastructure at the port of Dangjin near Incheon - will join the existing terminals at Incheon, Pyengtaek, Tongyeong and Samcheok.
  • India’s Reliance has outbid its rivals in a competitive auction for coal-bed methane produced from its own blocks in central India until at least March 2021. Reliance will purchase up to 3 million cbm/d of coal seam gas from its blocks in Sohagpur East and Sohagpur West in Madhya Pradesh, to be used as petrochemical feedstock.

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EIA expects U.S. crude oil production to remain relatively flat through 2021

In the U.S. Energy Information Administration’s (EIA) November Short-Term Energy Outlook (STEO), EIA forecasts that U.S. crude oil production will remain near its current level through the end of 2021.

A record 12.9 million barrels per day (b/d) of crude oil was produced in the United States in November 2019 and was at 12.7 million b/d in March 2020, when the President declared a national emergency concerning the COVID-19 outbreak. Crude oil production then fell to 10.0 million b/d in May 2020, the lowest level since January 2018.

By August, the latest monthly data available in EIA’s series, production of crude oil had risen to 10.6 million b/d in the United States, and the U.S. benchmark price of West Texas Intermediate (WTI) crude oil had increased from a monthly average of $17 per barrel (b) in April to $42/b in August. EIA forecasts that the WTI price will average $43/b in the first half of 2021, up from our forecast of $40/b during the second half of 2020.

The U.S. crude oil production forecast reflects EIA’s expectations that annual global petroleum demand will not recover to pre-pandemic levels (101.5 million b/d in 2019) through at least 2021. EIA forecasts that global consumption of petroleum will average 92.9 million b/d in 2020 and 98.8 million b/d in 2021.

The gradual recovery in global demand for petroleum contributes to EIA’s forecast of higher crude oil prices in 2021. EIA expects that the Brent crude oil price will increase from its 2020 average of $41/b to $47/b in 2021.

EIA’s crude oil price forecast depends on many factors, especially changes in global production of crude oil. As of early November, members of the Organization of the Petroleum Exporting Countries (OPEC) and partner countries (OPEC+) were considering plans to keep production at current levels, which could result in higher crude oil prices. OPEC+ had previously planned to ease production cuts in January 2021.

Other factors could result in lower-than-forecast prices, especially a slower recovery in global petroleum demand. As COVID-19 cases continue to increase, some parts of the United States are adding restrictions such as curfews and limitations on gatherings and some European countries are re-instituting lockdown measures.

EIA recently published a more detailed discussion of U.S. crude oil production in This Week in Petroleum.

November, 19 2020
OPEC members' net oil export revenue in 2020 expected to drop to lowest level since 2002

The U.S. Energy Information Administration (EIA) forecasts that members of the Organization of the Petroleum Exporting Countries (OPEC) will earn about $323 billion in net oil export revenues in 2020. If realized, this forecast revenue would be the lowest in 18 years. Lower crude oil prices and lower export volumes drive this expected decrease in export revenues.

Crude oil prices have fallen as a result of lower global demand for petroleum products because of responses to COVID-19. Export volumes have also decreased under OPEC agreements limiting crude oil output that were made in response to low crude oil prices and record-high production disruptions in Libya, Iran, and to a lesser extent, Venezuela.

OPEC earned an estimated $595 billion in net oil export revenues in 2019, less than half of the estimated record high of $1.2 trillion, which was earned in 2012. Continued declines in revenue in 2020 could be detrimental to member countries’ fiscal budgets, which rely heavily on revenues from oil sales to import goods, fund social programs, and support public services. EIA expects a decline in net oil export revenue for OPEC in 2020 because of continued voluntary curtailments and low crude oil prices.

The benchmark Brent crude oil spot price fell from an annual average of $71 per barrel (b) in 2018 to $64/b in 2019. EIA expects Brent to average $41/b in 2020, based on forecasts in EIA’s October 2020 Short-Term Energy Outlook (STEO). OPEC petroleum production averaged 36.6 million barrels per day (b/d) in 2018 and fell to 34.5 million b/d in 2019; EIA expects OPEC production to decline a further 3.9 million b/d to average 30.7 million b/d in 2020.

EIA based its OPEC revenues estimate on forecast petroleum liquids production—including crude oil, condensate, and natural gas plant liquids—and forecast values of OPEC petroleum consumption and crude oil prices.

EIA recently published a more detailed discussion of OPEC revenue in This Week in Petroleum.

November, 16 2020
The United States consumed a record amount of renewable energy in 2019

In 2019, consumption of renewable energy in the United States grew for the fourth year in a row, reaching a record 11.5 quadrillion British thermal units (Btu), or 11% of total U.S. energy consumption. The U.S. Energy Information Administration’s (EIA) new U.S. renewable energy consumption by source and sector chart published in the Monthly Energy Review shows how much renewable energy by source is consumed in each sector.

In its Monthly Energy Review, EIA converts sources of energy to common units of heat, called British thermal units (Btu), to compare different types of energy that are more commonly measured in units that are not directly comparable, such as gallons of biofuels compared with kilowatthours of wind energy. EIA uses a fossil fuel equivalence to calculate primary energy consumption of noncombustible renewables such as wind, hydro, solar, and geothermal.

U.S. renewable energy consumption by sector

Source: U.S. Energy Information Administration, Monthly Energy Review

Wind energy in the United States is almost exclusively used by wind-powered turbines to generate electricity in the electric power sector, and it accounted for about 24% of U.S. renewable energy consumption in 2019. Wind surpassed hydroelectricity to become the most-consumed source of renewable energy on an annual basis in 2019.

Wood and waste energy, including wood, wood pellets, and biomass waste from landfills, accounted for about 24% of U.S. renewable energy use in 2019. Industrial, commercial, and electric power facilities use wood and waste as fuel to generate electricity, to produce heat, and to manufacture goods. About 2% of U.S. households used wood as their primary source of heat in 2019.

Hydroelectric power is almost exclusively used by water-powered turbines to generate electricity in the electric power sector and accounted for about 22% of U.S. renewable energy consumption in 2019. U.S. hydropower consumption has remained relatively consistent since the 1960s, but it fluctuates with seasonal rainfall and drought conditions.

Biofuels, including fuel ethanol, biodiesel, and other renewable fuels, accounted for about 20% of U.S. renewable energy consumption in 2019. Biofuels usually are blended with petroleum-based motor gasoline and diesel and are consumed as liquid fuels in automobiles. Industrial consumption of biofuels accounts for about 36% of U.S. biofuel energy consumption.

Solar energy, consumed to generate electricity or directly as heat, accounted for about 9% of U.S. renewable energy consumption in 2019 and had the largest percentage growth among renewable sources in 2019. Solar photovoltaic (PV) cells, including rooftop panels, and solar thermal power plants use sunlight to generate electricity. Some residential and commercial buildings heat with solar heating systems.

October, 20 2020