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Last Updated: December 14, 2018
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Headline crude prices for the week beginning 10 December 2018 – Brent: US$62/b; WTI: US$52/b

  • Crude prices strengthened at the start of this week, with OPEC delivering an agreement that will see production across the OPEC+ alliance decline by 1.2 mmb/d beginning January 2019
  • Two-thirds or 800,000 b/d of the cut will be borne by OPEC – with most of it taken up by Saudi Arabia – while the non-OPEC group will take up a cut of 400,000 b/d, most of which will be taken up by Russia
  • Skepticism has reigned before the supply deal was reached, as the first day of the OPEC meeting in Vienna closed without consensus and the threads holding OPEC together showed some stress when Qatar decided to quit the group
  • Crude prices were also boosted by Libya declaring force majeure at its largest oil field at El Sharara over arm protests, while Canada’s Alberta province announced plans to pare back some 325,000 b/d of output to ease a huge glut
  • The coordinated supply deal by OPEC ‘was not easy’ according to UAE Minister of Energy and Industry, with Iran in particular balking at being asked to sign up to a symbolic cut; this might not augur well for future supply deals that might be necessary given current trends
  • However, the supply cut will only last until April 2019, when the terms are due for a review, which would give OPEC+ enough time to consider and deal with the expiration of American waivers for eight countries over continued import of Iranian crude in May
  • Meanwhile, America became a net oil exporter for the first time in almost 75 years, as the unprecedented boom in US crude oil fuelled by the shale revolution powers on, a development that could dilute OPEC+’s attempt to support global crude prices
  • The recent weakening of WTI prices saw the US lose 10 active oil rigs last week, however, the addition of 9 new gas rigs led to a net loss of only 1 in the Baker Hughes active US rig count
  • Crude price outlook: OPEC+’s decision might have provided some relief, but may not be enough to keep crude oil prices trending upwards. Expect prices to moderate to US$60-61/b for Brent and US$50-51/b for WTI

Headlines of the week

Upstream

  • ExxonMobil’s winning streak in Guyana continues, as it announces its 10th offshore discovery at the Pluma-1 well, boosting estimated recoverable resources in the Stabroek block by almost 1 mmb/d to over 5 mmb/d
  • Apache has initiated production at the Garten field in the UK North Sea, with an output rate of 13,700 b/d and 15.7 bcf/d of natural gas
  • Chevron has raised its capital expenditure for the first time since 2014 into US$20 billion, with a major focus on expanding operations in the Permian Basin as well as on the Tengiz megaproject in Kazakhstan
  • Canada’s Alberta province, weighed down by a supply glut caused by pipeline bottlenecks, has announced moves to reduce the region’s output by 325,000 b/d
  • Equinor and Faroe Petroleum have agreed to trade a number of assets in the Norwegian Sea and the Norwegian Continental Shelf North Sea, encompassing the Njord, Bauge Hyme, Vilje Ringhome, Marulk and Alve fields, with the deal described as a ‘balanced swap’ in terms of value with no cash consideration

Downstream

  • CNPC’s US$9.53 billion joint venture integrated 400 kb/d petrochemicals/refinery project with PDVSA in Jieyang, China has been reactivated, and is now expected to begin operations in late 2021
  • French president Emmanuel Macron has backtracked and suspended a planned fuel-tax hike, after weeks of violent riots by the so-called Yellow Vests grassroot groups of up to 300,000 protestors
  • Limetree Bay Ventures has secured US$1.25 billion in financing that paves the way for the Limetree Bay refinery in the US Virgin Islands to restart after being idled for years, partnering with BP Products North America on the project

Natural Gas/LNG

  • Equinor has received permission from the Norwegian government to proceed with the development of Troll Phase 3, delivering an additional 2.2 billion boe/d of natural gas with a planned start-up timeframe of 1H2021
  • Shell has completed the construction of Gibraltar’s first LNG regasification facility, a small-scale project that will feed a new power plant in the territory
  • Trinidad and Tobago has agreed to allow BP and Shell to extend the operational life of the Atlantic LNG Train 1 in Point Fortin by five years, with the country receiving the ability to sell LNG cargoes through its state gas firm
  • Tokyo Gas and the Philippines’ First Gen Corporation have signed a joint development agreement to build and operate an LNG receiving terminal, as the three-horse race narrows over the country’s first LNG import facility
  • American LNG player Tellurian has agreed to supply trader Vitol with some 1.5 mtpa of LNG over 15 years from its 27.6 mtpa Driftwood LNG export terminal currently being developed in Calcasiue River, Louisiana
  • Tanzania is opening talks with Equinor and ExxonMobil to launch the East African nation’s first LNG project, likely to derive gas from the Equinor-operated offshore Block 2
  • Shell is expecting to produce its first cargo of LNG from its Prelude FLNG facility in Australia before the end of 2018

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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
Natural gas generators make up largest share of U.S. electricity generation capacity

operating natural-gas fired electric generating capacity by online year

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

Based on the U.S. Energy Information Administration's (EIA) annual survey of electric generators, natural gas-fired generators accounted for 43% of operating U.S. electricity generating capacity in 2019. These natural gas-fired generators provided 39% of electricity generation in 2019, more than any other source. Most of the natural gas-fired capacity added in recent decades uses combined-cycle technology, which surpassed coal-fired generators in 2018 to become the technology with the most electricity generating capacity in the United States.

Technological improvements have led to improved efficiency of natural gas generators since the mid-1980s, when combined-cycle plants began replacing older, less efficient steam turbines. For steam turbines, boilers combust fuel to generate steam that drives a turbine to generate electricity. Combustion turbines use a fuel-air mixture to spin a gas turbine. Combined-cycle units, as their name implies, combine these technologies: a fuel-air mixture spins gas turbines to generate electricity, and the excess heat from the gas turbine is used to generate steam for a steam turbine that generates additional electricity.

Combined-cycle generators generally operate for extended periods; combustion turbines and steam turbines are typically only used at times of peak load. Relatively few steam turbines have been installed since the late 1970s, and many steam turbines have been retired in recent years.

natural gas-fired electric gnerating capacity by retirement year

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

Not only are combined-cycle systems more efficient than steam or combustion turbines alone, the combined-cycle systems installed more recently are more efficient than the combined-cycle units installed more than a decade ago. These changes in efficiency have reduced the amount of natural gas needed to produce the same amount of electricity. Combined-cycle generators consume 80% of the natural gas used to generate electric power but provide 85% of total natural gas-fired electricity.

operating natural gas-fired electric generating capacity in selected states

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

Every U.S. state, except Vermont and Hawaii, has at least one utility-scale natural gas electric power plant. Texas, Florida, and California—the three states with the most electricity consumption in 2019—each have more than 35 gigawatts of natural gas-fired capacity. In many states, the majority of this capacity is combined-cycle technology, but 44% of New York’s natural gas capacity is steam turbines and 67% of Illinois’s natural gas capacity is combustion turbines.

October, 19 2020
EIA’s International Energy Outlook analyzes electricity markets in India, Africa, and Asia

Countries that are not members of the Organization for Economic Cooperation and Development (OECD) in Asia, including China and India, and in Africa are home to more than two-thirds of the world population. These regions accounted for 44% of primary energy consumed by the electric sector in 2019, and the U.S. Energy Information Administration (EIA) projected they will reach 56% by 2050 in the Reference case in the International Energy Outlook 2019 (IEO2019). Changes in these economies significantly affect global energy markets.

Today, EIA is releasing its International Energy Outlook 2020 (IEO2020), which analyzes generating technology, fuel price, and infrastructure uncertainty in the electricity markets of Africa, Asia, and India. A related webcast presentation will begin this morning at 9:00 a.m. Eastern Time from the Center for Strategic and International Studies.

global energy consumption for power generation

Source: U.S. Energy Information Administration, International Energy Outlook 2020 (IEO2020)

IEO2020 focuses on the electricity sector, which consumes a growing share of the world’s primary energy. The makeup of the electricity sector is changing rapidly. The use of cost-efficient wind and solar technologies is increasing, and, in many regions of the world, use of lower-cost liquefied natural gas is also increasing. In IEO2019, EIA projected renewables to rise from about 20% of total energy consumed for electricity generation in 2010 to the largest single energy source by 2050.

The following are some key findings of IEO2020:

  • As energy use grows in Asia, some cases indicate more than 50% of electricity could be generated from renewables by 2050.
    IEO2020 features cases that consider differing natural gas prices and renewable energy capital costs in Asia, showing how these costs could shift the fuel mix for generating electricity in the region either further toward fossil fuels or toward renewables.
  • Africa could meet its electricity growth needs in different ways depending on whether development comes as an expansion of the central grid or as off-grid systems.
    Falling costs for solar photovoltaic installations and increased use of off-grid distribution systems have opened up technology options for the development of electricity infrastructure in Africa. Africa’s power generation mix could shift away from current coal-fired and natural gas-fired technologies used in the existing central grid toward off-grid resources, including extensive use of non-hydroelectric renewable generation sources.
  • Transmission infrastructure affects options available to change the future fuel mix for electricity generation in India.
    IEO2020 cases demonstrate the ways that electricity grid interconnections influence fuel choices for electricity generation in India. In cases where India relies more on a unified grid that can transmit electricity across regions, the share of renewables significantly increases and the share of coal decreases between 2019 and 2050. More limited movement of electricity favors existing in-region generation, which is mostly fossil fuels.

IEO2020 builds on the Reference case presented in IEO2019. The models, economic assumptions, and input oil prices from the IEO2019 Reference case largely remained unchanged, but EIA adjusted specific elements or assumptions to explore areas of uncertainty such as the rapid growth of renewable energy.

Because IEO2020 is based on the IEO2019 modeling platform and because it focuses on long-term electricity market dynamics, it does not include the impacts of COVID-19 and related mitigation efforts. The Annual Energy Outlook 2021 (AEO2021) and IEO2021 will both feature analyses of the impact of COVID-19 mitigation efforts on energy markets.

Asia infographic, as described in the article text


Source: U.S. Energy Information Administration, International Energy Outlook 2020 (IEO2020)
Note: Click to enlarge.

With the IEO2020 release, EIA is publishing new Plain Language documentation of EIA’s World Energy Projection System (WEPS), the modeling system that EIA uses to produce IEO projections. EIA’s new Handbook of Energy Modeling Methods includes sections on most WEPS components, and EIA will release more sections in the coming months.

October, 16 2020