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Source: U.S. Energy Information Administration, Annual Energy Outlook 2019
EIA’s long-term projections show that most of the electricity generating capacity additions installed in the United States through 2050 will be natural gas combined-cycle and solar photovoltaic (PV). Onshore wind looks to be competitive in only a few regions before the legislated phase-out of the production tax credit (PTC), but it becomes competitive later in the projection period as demand increases and the cost for installing wind turbines continues to decline.
For EIA’s Annual Energy Outlook 2019 (AEO2019), EIA calculates two measures that, when used together, provide an intuitive framework for understanding the capacity expansion decisions modeled for utility-scale power plants—those with a capacity rating of 1 megawatt (MW) or greater.
The levelized cost of electricity (LCOE) represents the cost to build and operate a power plant, converted to a level stream of payments over the plant’s assumed financial lifetime. Installed capital costs include construction costs and financing costs. Operating costs include fuel costs (for power plants that consume fuel) and expected maintenance costs. LCOEs may also include other applicable tax credits or subsidies.
The levelized avoided cost of electricity (LACE) accounts for the differences in the grid services each generating technology is providing (a power plant’s value) to the grid. For example, natural gas combined-cycle plants and coal plants provide dispatchable baseload services to the grid and thus have similar LACE values, even if their LCOE values differ. A generator’s avoided cost provides a proxy for the potential revenues from sales of electricity generated. As with LCOE, these revenues are converted to a level stream of payments over the plant’s assumed financial lifetime.
The ratio of these two measures serves as a value-to-cost ratio. Power plants are considered economically attractive when their projected LACE exceeds their projected LCOE, meaning their value-cost ratio exceeds one.
The relative costs and values of several technology options are calculated for each of the 22 electricity regions in the modeling system used to inform EIA’s Annual Energy Outlook. Calculations start in 2021 because that is the first feasible year that all three technologies are available to come online in the model, given the assumed construction lead-time and licensing requirements.
Source: U.S. Energy Information Administration, Annual Energy Outlook 2019 and Levelized Cost and Levelized Avoided Cost of New Generation Resources in the Annual Energy Outlook 2019
Because both LCOE and LACE are levelized over the lifetime of the plant, these values change over time. Natural gas combined-cycle units’ LCOEs increases gradually as natural gas prices rise. Utility-scale solar photovoltaic (PV) and onshore wind’s LCOEs initially increase as a result of the loss of the tax credits but then decrease because of the continued decline in installed costs. Wind’s LCOE may also increase as the best wind resource sites are built out and new projects must be installed in areas that have either lower wind resources or less ease of access.
Natural gas combined-cycle units are considered, on average, the marginal source of electricity generation through 2050, meaning the cost of electricity generation from this technology is most often the basis of comparison for new power plants. As natural gas prices increase, the marginal source becomes more expensive to operate, and the value to the grid of avoiding this cost by building new capacity increases, as seen in the general upward trend in LACE for natural gas combined-cycle and onshore wind.
Conversely, solar PV’s LACE is generally flat to declining during the projection period. As solar penetration in the grid increases, solar capacity saturates during the midday hours, causing the value of electricity delivered in those hours to decrease.
In the AEO2019 Reference case, natural gas combined-cycle’s value-cost ratio is closest to 1.0 throughout the projection, indicating that its value just covers its costs. Natural gas combined-cycle units account for the largest share of new power plants (43% of the utility-scale total from 2021 through 2050). Solar PV’s value-cost ratio is slightly less than 1.0, indicating that, on average, its value does not cover its costs, but capacity is still added. In some cases, these solar PV additions may be uneconomic, but they still occur to satisfy the renewable portfolio standard (RPS) requirements in 29 states and the District of Columbia.
Onshore wind’s value-cost ratio remains lower than 1.0 throughout the projection period and lower than solar PV. Consequently, little onshore wind is installed in the Reference case, except in the near term when wind capacity is built to take advantage of the available PTC.
More information about LCOE, LACE, and economic competitiveness of electricity generating technologies is available in EIA’s Levelized Cost and Levelized Avoided Cost of New Generation Resources in the Annual Energy Outlook 2019 report.
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Recent headlines on the oil industry have focused squarely on the upstream side: the amount of crude oil that is being produced and the resulting effect on oil prices, against a backdrop of the Covid-19 pandemic. But that is just one part of the supply chain. To be sold as final products, crude oil needs to be refined into its constituent fuels, each of which is facing its own crisis because of the overall demand destruction caused by the virus. And once the dust settles, the global refining industry will look very different.
Because even before the pandemic broke out, there was a surplus of refining capacity worldwide. According to the BP Statistical Review of World Energy 2019, global oil demand was some 99.85 mmb/d. However, this consumption figure includes substitute fuels – ethanol blended into US gasoline and biodiesel in Europe and parts of Asia – as well as chemical additives added on to fuels. While by no means an exact science, extrapolating oil demand to exclude this results in a global oil demand figure of some 95.44 mmb/d. In comparison, global refining capacity was just over 100 mmb/d. This overcapacity is intentional; since most refineries do not run at 100% utilisation all the time and many will shut down for scheduled maintenance periodically, global refining utilisation rates stand at about 85%.
Based on this, even accounting for differences in definitions and calculations, global oil demand and global oil refining supply is relatively evenly matched. However, demand is a fluid beast, while refineries are static. With the Covid-19 pandemic entering into its sixth month, the impact on fuels demand has been dramatic. Estimates suggest that global oil demand fell by as much as 20 mmb/d at its peak. In the early days of the crisis, refiners responded by slashing the production of jet fuel towards gasoline and diesel, as international air travel was one of the first victims of the virus. As national and sub-national lockdowns were introduced, demand destruction extended to transport fuels (gasoline, diesel, fuel oil), petrochemicals (naphtha, LPG) and power generation (gasoil, fuel oil). Just as shutting down an oil rig can take weeks to complete, shutting down an entire oil refinery can take a similar timeframe – while still producing fuels that there is no demand for.
Refineries responded by slashing utilisation rates, and prioritising certain fuel types. In China, state oil refiners moved from running their sites at 90% to 40-50% at the peak of the Chinese outbreak; similar moves were made by key refiners in South Korea and Japan. With the lockdowns easing across most of Asia, refining runs have now increased, stimulating demand for crude oil. In Europe, where the virus hit hard and fast, refinery utilisation rates dropped as low as 10% in some cases, with some countries (Portugal, Italy) halting refining activities altogether. In the USA, now the hardest-hit country in the world, several refineries have been shuttered, with no timeline on if and when production will resume. But with lockdowns easing, and the summer driving season up ahead, refinery production is gradually increasing.
But even if the end of the Covid-19 crisis is near, it still doesn’t change the fundamental issue facing the refining industry – there is still too much capacity. The supply/demand balance shows that most regions are quite even in terms of consumption and refining capacity, with the exception of overcapacity in Europe and the former Soviet Union bloc. The regional balances do hide some interesting stories; Chinese refining capacity exceeds its consumption by over 2 mmb/d, and with the addition of 3 new mega-refineries in 2019, that gap increases even further. The only reason why the balance in Asia looks relatively even is because of oil demand ‘sinks’ such as Indonesia, Vietnam and Pakistan. Even in the US, the wealth of refining capacity on the Gulf Coast makes smaller refineries on the East and West coasts increasingly redundant.
Given this, the aftermath of the Covid-19 crisis will be the inevitable hastening of the current trend in the refining industry, the closure of small, simpler refineries in favour of large, complex and more modern refineries. On the chopping block will be many of the sub-50 kb/d refineries in Europe; because why run a loss-making refinery when the product can be imported for cheaper, even accounting for shipping costs from the Middle East or Asia? Smaller US refineries are at risk as well, along with legacy sites in the Middle East and Russia. Based on current trends, Europe alone could lose some 2 mmb/d of refining capacity by 2025. Rising oil prices and improvements in refining margins could ensure the continued survival of some vulnerable refineries, but that will only be a temporary measure. The trend is clear; out with the small, in with the big. Covid-19 will only amplify that. It may be a painful process, but in the grand scheme of things, it is also a necessary one.
Infographic: Global oil consumption and refining capacity (BP Statistical Review of World Energy 2019)
| Region | Consumption (mmb/d)* | Refining Capacity (mmb/d) |
| North America | 22.71 | 22.33 |
| Latin America | 6.5 | 5.98 |
| Europe | 14.27 | 15.68 |
| CIS | 4.0 | 8.16 |
| Middle East | 9.0 | 9.7 |
| Africa | 3.96 | 3.4 |
| Asia-Pacific | 35 | 34.75 |
| Total | 95.44 | 100.05 |
*Extrapolated to exclude additives and substitute fuels (ethanol, biodiesel)
Market Outlook:
End of Article
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Source: U.S. Energy Information Administration, based on Bloomberg L.P. data
Note: All prices except West Texas Intermediate (Cushing) are spot prices.
The New York Mercantile Exchange (NYMEX) front-month futures contract for West Texas Intermediate (WTI), the most heavily used crude oil price benchmark in North America, saw its largest and swiftest decline ever on April 20, 2020, dropping as low as -$40.32 per barrel (b) during intraday trading before closing at -$37.63/b. Prices have since recovered, and even though the market event proved short-lived, the incident is useful for highlighting the interconnectedness of the wider North American crude oil market.
Changes in the NYMEX WTI price can affect other price markers across North America because of physical market linkages such as pipelines—as with the WTI Midland price—or because a specific price is based on a formula—as with the Maya crude oil price. This interconnectedness led other North American crude oil spot price markers to also fall below zero on April 20, including WTI Midland, Mars, West Texas Sour (WTS), and Bakken Clearbrook. However, the usefulness of the NYMEX WTI to crude oil market participants as a reference price is limited by several factors.
Source: U.S. Energy Information Administration
First, NYMEX WTI is geographically specific because it is physically redeemed (or settled) at storage facilities located in Cushing, Oklahoma, and so it is influenced by events that may not reflect the wider market. The April 20 WTI price decline was driven in part by a local deficit of uncommitted crude oil storage capacity in Cushing. Similarly, while the price of the Bakken Guernsey marker declined to -$38.63/b, the price of Louisiana Light Sweet—a chemically comparable crude oil—decreased to $13.37/b.
Second, NYMEX WTI is chemically specific, meaning to be graded as WTI by NYMEX, a crude oil must fall within the acceptable ranges of 12 different physical characteristics such as density, sulfur content, acidity, and purity. NYMEX WTI can therefore be unsuitable as a price for crude oils with characteristics outside these specific ranges.
Finally, NYMEX WTI is time specific. As a futures contract, the price of a NYMEX WTI contract is the price to deliver 1,000 barrels of crude oil within a specific month in the future (typically at least 10 days). The last day of trading for the May 2020 contract, for instance, was April 21, with physical delivery occurring between May 1 and May 31. Some market participants, however, may prefer more immediate delivery than a NYMEX WTI futures contract provides. Consequently, these market participants will instead turn to shorter-term spot price alternatives.
Taken together, these attributes help to explain the variety of prices used in the North American crude oil market. These markers price most of the crude oils commonly used by U.S. buyers and cover a wide geographic area.
Principal contributor: Jesse Barnett
Key findings