Easwaran Kanason

Co - founder of NrgEdge
Last Updated: July 17, 2020
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Business Trends

In good times, the instinct of any company is to expand. In bad times, that instinct reverses to consolidation. This cycle is no more apparent anywhere else than in the oil and gas sector, where periodic boom-bust periods have been a regular feature since David Beaty drilled the first modern oilfield back in 1875 in Pennsylvania. The year 2020 is proving to be a year of reckoning for the entire industry, for obvious reasons, with all firms of all sizes announcing or preparing to announce major impairments. What follows is usually a swathe of divestments.

Two major sales by supermajors have captured the headlines recently: BP’s exit from the petrochemicals sector through a sale to INEOS, and Shell reaffirming its desire to sell its 35% stake in the Abadi LNG project in Indonesia. Both deals paint a picture of companies retreating from peripheral, though still profitable activities, in order to focus on core activities.

In BP’s case, it will be selling its last remaining petrochemical sites to INEOS, owned by UK billionaire Jim Ratcliffe. The sale encompasses 15 sites in the Americas, Europe and Asia focused on aromatics, acetyls and related businesses for US$5 billion, to be paid in US$1 billion instalments after an initial US$400 million deposit. Charmingly, it brings the INEOS story full circle: INEOS was first formed in 1998 to buy out a BP petrochemicals business in Belgium, and in 2005, paid US$9 billion to purchase Innovene, another BP subsidiary that made up a large proportion of BP’s then-existing chemicals assets.

For INEOS, it’s a great win as it adds aromatics and acetyl capacity where it is lacking, and significantly boosts presence in Asia, described as ‘two big pieces of chemistry in (that) portfolio that (INEOS) didn’t have before, completing the set’. From BP’s perspective, however, the sale runs counter to the prevailing trend in the energy sector where firms are actively expanding their petrochemicals presence, from China to the US Gulf Coast, seeing it as a stable and lower-carbon alternative to complement zero-carbon operational transformations. But BP’s footprint in the petrochemicals business has been shrinking over the past two decades, ceding ground to Shell, ExxonMobil, Total and other national players. It might prove to be a canny move, there has been a massive surge in capacity for petrochemicals recently, with huge oversupply in certain grades that has placed major pressure on petchems profit margins. Global campaigns to reduce single-use plastics also blunted growth prospects. A global pandemic further tarnished the lustre of the sector. For BP, it would have been easy to say yes to pocketing a pretty penny from Jim Ratcliffe, which would allow it to, in the words of CEO Bernard Looney – ‘build a more focused, more integrated BP, (with) other opportunities that are more aligned with our future direction’.

Unlike BP, Shell has announced no intention to reduce its presence in petrochemicals. But it is looking to divest its stake in the Abadi LNG project in Indonesia led by Japan’s Inpex. Why it wants to do that might throw up some questioning looks. Shell through its takeover of natural gas giant BG Group is the world’s largest LNG trader by far. Surely, then, retaining a 35% stake in a large natural gas project would be a good thing. Right?

Perhaps not. Reports that Shell has been wanting to sell its 35% stake in the Abadi LNG project surfaced in 2019. The Abadi LNG project centred on the Masela gas block deep in the Arafura Sea has had a particularly chequered past. Debates between Japan’s Inpex and the Indonesian government over the direction and location of the project has plagued it with delays. Inpex and Shell had favoured floating LNG plant but Joko Widodo’s government was pushing for an onshore plant, tempted by better local employment prospects. The government won out in the end, finally confirming in 2019 an offshore production facility and a 9.5 mtpa onshore plant that would be operational in 2028, extending the Masela PSC by 20 years. Negotiations, it was reported, were particularly strenuous. And perhaps Shell lost patience.

Shell could sell its stake, valued at up to U$2 billion to Inpex, which owns the remaining 65%, or to other players. But few players have the appetite to navigate Indonesia’s complicated upstream sector. For Shell, the exit may be a relief. Particularly since it already has other, equally gigantic LNG assets nearby in Australia. Those LNG assets are expected to take a US$8-9 billion hit as part of a potential US$15-22 billion impairment charge for Q2 2020 on low gas prices. Shell’s view on long-term gas prices is alreadt on the bleaker side. So why not divest now for ready cash, instead of waiting 8 more years for an asset that might be worth even less then?

BP and Shell have offered up an intriguing preview of where the industry could go in these trying times, exits and consolidations, and we expect that there will be a lot more similar divestment announcements to roll out over the remainder of 2020 and in 2021.

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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