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Last week, Spanish utility Naturgy Energy Group cancelled two LNG cargoes set to be delivered to Spain from the US Gulf Coast through Cheniere Energy. Scheduled to be loaded at the Texas Corpus Christi facility, Naturgy cancelled the cargoes by exercising its option not to lift under its 20-year contract with Cheniere, as its Spanish clients Repsol and Endesa forgo-ed the fuel. If this was an isolated incident, it could be ignored. But it isn’t. At least half a dozen buyers are reportedly considering cancelling cargoes from the US, including two Japanese powerhouses. It is not that the LNG isn’t required, though a mild winter in Northeast Asia did sap spot demand – it is simply that there is too much LNG sloshing around the world currently.
Consider this. In 2017, global LNG capacity was some 290 million tons per annum. In 2019, this had risen to some 393 million tons, a startling jump over two years, as the last few LNG megaprojects in Australia and the first few US Gulf LNG projects started up. And it will only go up. Based on approvals in 2019, global LNG liquefaction capacity could grow to 843 million tons per annum by the mid-2020s, propelled by additional volumes from the US, Russia, Papua New Guinea, the Eastern Mediterranean and West Africa. That’s a lot of capacity. Not all of it will make it past the planning stage and certainly not the 250 mtpa planned in the US but enough it will. And for a while, there was a lot of demand. But in a classic case of ‘if we build it, they will buy it’, supply has outstripped demand. And therein lies the problem.
The gap between LNG supply and demand has driven prices to record lows. US prices are currently at some US$2.60 per mmBtu for spot cargoes, margins so low that it may not even be profitable to sell cargoes to Europe. Part of this is due to the shale revolution, which created so much gas that it drove Henry Hub gas prices to a major discount against other natural gas benchmarks. But the US has to export its natural gas, because there is nowhere else for it to go. Europe itself isn’t in a position to take more, as stockpiles are brimming. In Asia, severe winters usually spike demand for spot cargoes, but two consecutive mild winters have created a glut.
Add to this the Covid-19 coronavirus situation. China has already declared force majeure on receiving some cargoes of LNG (though this was rejected by Shell and Total), turning an already weak year into a bloodbath. It has always been taken that China would be the LNG market’s great hope; and indeed, many US Gulf LNG exporters have been rushing to sign agreements with Chinese importers. But Donald Trump’s trade war has dried that trade up, and even with a Phase 1 trade deal, China is not in a position to ramp up at all.
Despite all the (short term) gloom, the long term prognosis for LNG demand remains slightly healthier. Shell, which became the world’s largest LNG trader with its purchase of the BG Group, is predicting that global LNG trade will double by 2040, as ‘policy meets reality’ for countries aiming to move to cleaner energy from coal switching in Europe to growing populations in China. LNG demand as of 2019 was an estimated 360 million tons, having grown 12.5% y-o-y. If that projection holds through, it will still be a situation of oversupply but one that should be manageable. But even Shell, as positive as it is only expects the situation to improve in the mid-2020s, as a ‘combination of continued demand growth and reduction in new supply coming on-stream’ changes the market yet again.
With eroding demand and ample supply, LNG is in a painful place right now. Too much supply has entered the market at a time when demand is taking a hit; with more supply on the way, it will be a painful adjustment period for the industry. But LNG is a long game. And the future looks to be brighter, as long as players can get through the current huge hump in the road ahead.
Global LNG benchmark prices:
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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.
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.
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.
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.
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.
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.
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:
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.
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.
