The aftermath of Hurricane Harvey has left devastation in its wake. It dumped some 27 trillion gallons of water on the states of Texas and Louisiana, causing an estimated US$75 billion in damages. From the energy perspective, there were worries that coastal refining centres would be swamped, taking out some of America’s largest refineries, which had shut down as the storm approached. In the immediate wake of the storm, WTI crude oil prices dipped while gasoline prices jumped – as the market predicted that Gulf refineries would be shut for a long while, which would reduce crude intake and cause gasoline shortages.
That didn’t really happen. By Monday, WTI and US gasoline prices were getting back to pre-Harvey levels. It’s true that some two million b/d of refining capacity was disrupted by Harvey, but half of that is already back. All major sites in Houston and Corpus Christi have either restarted or in the process of restarting. The second largest site in the US, ExxonMobil’s Baytown, is already ramping back up to full production. Motiva in Port Arthur, the largest in the US, is still offline, but processing is expected to resume soon. The Doomsday scenario of the Gulf refining network been taken out for months was avoided. The refining business is getting back to usual. On the demand side, it is estimated that some 500,000 cars were flooded across Texas by Harvey. Those cars won’t be driving again. Their owners won’t be in a position to purchase a new car again soon as well. Worries that gasoline would be at a severe shortage, therefore, were unfounded.
In fact, where Harvey is having the most impact is in a surprising place – onshore. This is the first major storm to hit since the shale revolution took off. Gulf hurricanes are not surprise to offshore producers – 20% of offshore Gulf production was shuttered over the weekend, but no lasting damage was suffered with production resuming and losses estimated at a mere 330 kb/d. It is true that the US is a lot less dependent on offshore Gulf production since inland shale production started booming. But for shale players, Harvey is their first taste of Mother Nature’s wrath. The Eagle Ford shale field in Texas was in direct path of Harvey, with some 500,000 b/d of output taken offline – almost half of its usual production. Even when the storm moved away, it left flooded roads and muddy fields in its wake. These will have to subside before production can resume, which could affect 10% of US shale output for at least a month. Further afield, while Harvey didn’t affect the prodigious Permian basin, output there is dependent on pipelines and ports that pass through Houston. Magellan Midstream, for example, closed its Longhorn and Bridgetex pipelines during the storm. It has since restarted them, along with Colonial Pipelines’ Line 1 gasoline pipe, but it is a reminder that so much of American production, refining and export capacity straddles a long coastline that is vulnerable to storms more than a quarter of the year. That applies as much to the string of LNG terminals being built on the coast, as it does to the shale drilling sites far inland.
There is more to come. Harvey was the first major hurricane to make landfall since Wilma in 2005, but it was actually a Category 4. There is a Category 5 – the highest level – currently barreling through the Caribbean. Hurricane Irma is on a course to hit Puerto Rico, Dominica, Cuba and eventually Florida. The governor Florida has already declared a state of emergency. Though there are no major US refining centres in Irma’s path (but some 450 kb/d in the Caribbean will be closed), the storm would sap gasoline demand in its wake – weakening gasoline prices at a time when refining margins are still dicey. And the hurricane season isn’t even over yet.
Harvey, while devastating to the population, turned out to be relatively harmless on the energy infrastructure front. The US Gulf will be hoping it stays that way for the rest of 2017.
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In its latest Short-Term Energy Outlook (STEO), released on January 14, the U.S. Energy Information Administration (EIA) forecasts year-over-year decreases in energy-related carbon dioxide (CO2) emissions through 2021. After decreasing by 2.1% in 2019, energy-related CO2 emissions will decrease by 2.0% in 2020 and again by 1.5% in 2021 for a third consecutive year of declines.
These declines come after an increase in 2018 when weather-related factors caused energy-related CO2 emissions to rise by 2.9%. If this forecast holds, energy-related CO2 emissions will have declined in 7 of the 10 years from 2012 to 2021. With the forecast declines, the 2021 level of fewer than 5 billion metric tons would be the first time emissions have been at that level since 1991.
After a slight decline in 2019, EIA expects petroleum-related CO2 emissions to be flat in 2020 and decline slightly in 2021. The transportation sector uses more than two-thirds of total U.S. petroleum consumption. Vehicle miles traveled (VMT) grow nearly 1% annually during the forecast period. In the short term, increases in VMT are largely offset by increases in vehicle efficiency.
Winter temperatures in New England, which were colder than normal in 2019, led to increased petroleum consumption for heating. New England uses more petroleum as a heating fuel than other parts of the United States. EIA expects winter temperatures will revert to normal, contributing to a flattening in overall petroleum demand.
Natural gas-related CO2 increased by 4.2% in 2019, and EIA expects that it will rise by 1.4% in 2020. However, EIA expects a 1.7% decline in natural gas-related CO2 in 2021 because of warmer winter weather and less demand for natural gas for heating.
Changes in the relative prices of coal and natural gas can cause fuel switching in the electric power sector. Small price changes can yield relatively large shifts in generation shares between coal and natural gas. EIA expects coal-related CO2 will decline by 10.8% in 2020 after declining by 12.7% in 2019 because of low natural gas prices. EIA expects the rate of coal-related CO2 to decline to be less in 2021 at 2.7%.
The declines in CO2 emissions are driven by two factors that continue from recent historical trends. EIA expects that less carbon-intensive and more efficient natural gas-fired generation will replace coal-fired generation and that generation from renewable energy—especially wind and solar—will increase.
As total generation declines during the forecast period, increases in renewable generation decrease the share of fossil-fueled generation. EIA estimates that coal and natural gas electric generation combined, which had a 63% share of generation in 2018, fell to 62% in 2019 and will drop to 59% in 2020 and 58% in 2021.
Coal-fired generation alone has fallen from 28% in 2018 to 24% in 2019 and will fall further to 21% in 2020 and 2021. The natural gas-fired generation share rises from 37% in 2019 to 38% in 2020, but it declines to 37% in 2021. In general, when the share of natural gas increases relative to coal, the carbon intensity of the electricity supply decreases. Increasing the share of renewable generation further decreases the carbon intensity.
Source: U.S. Energy Information Administration, Short-Term Energy Outlook, January 2020
Note: CO2 is carbon dioxide.
GEO ExPro Vol. 16, No. 6 was published on 9th December 2019 bringing light to the latest science and technology activity in the global geoscience community within the oil, gas and energy sector.
This issue focusses on oil and gas exploration in frontier regions within Europe, with stories and articles discussing new modelling and mapping technologies available to the industry. This issue also presents several articles discussing the discipline of geochemistry and how it can be used to further enhance hydrocarbon exploration.
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Headline crude prices for the week beginning 13 January 2020 – Brent: US$64/b; WTI: US$59/b
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