Will the Drop in U.S. Oil Demand Due Mostly to Coronavirus Inadvertently Increase Natural Gas Demand in the Short-to-Mid Term? It Seems Likely (April 23, 2020)
The profound drop in U.S. oil demand due to Coronavirus and to a lesser extent the OPEC-plus, Russia-Saudi oil war, has caused oil prices to crater to below zero (at least on paper). A big emerging issue in the U.S. is simply where to store the unused oil. Storage hubs are filling fast. The Trump administration plan to add 75MM Bbls to the Strategic Petroleum Reserve (SPR) will help a little but as RBN Energy CEO Rusty Braziel points out, that will take time, and storage will remain an issue in the meantime and maybe even after the SPR is filled if demand remains stagnant. Braziel suggests that the problem is 85% Coronavirus and 15% OPEC-plus, but others see OPEC-plus having a bigger influence.
It seems likely that wells in the Permian Basin will be shut-in and the Texas Railroad Commission is still evaluating whether mandatory curtailments will occur. On average those Permian Basin oil wells make about 10% of the natural gas that wells in Appalachia do, but there are many more of those oil wells than Appalachian shale gas wells. As a result, Permian Basin gas production is over half of overall Appalachian gas production. The Permian produces somewhere around 12% or more of total U.S. gas. If a significant amount of those oil wells is shut-in, the gas they produce will be shut-in as well. How much gas will be shut-in is the question. That also means that when oil demand picks up, the gas will come back online, which could bode for a future drop in natural gas demand. But that could be far off and less impactful. The oil shut-in is likely to be widespread and across several oil basins.
There is little doubt that globally there is way too much oil so demand will be slow in any case to return to normal levels. With the possibility of the coronavirus continuing to wreak havoc for months and perhaps even a year or more, there is little reason to think that oil demand will return any time soon. The Seeking Alpha article referenced below suggests that shut-ins could take 500BCF out of commission between May and November. That equates to an average of about 2.7BCF/day avg. over that time period. They noted that the shut-ins could take up to 14BCF/day off the market in the short-term but with LNG export gas also shut-in the total impact would be about 8BCF/day in a two-month period. That would certainly affect natural gas prices positively going forward.
LNG export demand is another variable that could influence gas futures. European gas storage, like U.S. gas storage is at high levels, but in recent years more European gas is coming from the U.S. than before. BTU Analytics noted that LNG imports to Europe increased from about 6BCF/day avg in 2017 and 2018 to 13.3 BCF/day in the first quarter of 2020. During the same time period the amount of LNG exported from the U.S. to Europe has increased from 0.3 BCF/day to about 3.7BCF/day. Its attractive price has cut into pipeline imports from Russia. More contracted U.S. LNG export capacity is expected to come online in 2020 and 2021 but it is likely that it will not be utilized at high levels so some drop in overall LNG export demand from the U.S. is expected. Although European gas demand from the U.S. will surely drop in the short-term, its long-term prospects remain good with the so-called Wave 2 of U.S. LNG export expected to increase exports to Europe. WoodMac suggests that with three months of “lockdown” in Europe, 16.9 BCM (~600 BCF) of gas demand is in jeopardy. With more renewables on the European market in 2020, they are pushing fossil fuel demand down and having a bigger influence on power markets in general. Add in coronavirus and a significant drop in European LNG import demand is certain.
According to the EIA, natural gas demand has not been affected very much by the coronavirus. People still need heat and electricity and shuttered business need some too. March 2020 natural gas consumption was significantly higher than March 2019 consumption. Low natural gas prices make it more competitive against coal, so more gas gets burned. More coal plants being shuttered and more gas plants being built and set to come online will also positively affect demand.
EIA (Henry Hub) predictions for Jan 2021 range from $2.70 to more than as $4.00 per mcf and a $3.00 or more avg. for 2021 bodes well for gas drillers, at least for 2021. But in the near-term getting back to $2.00 per mcf is the hope. Yesterday’s Henry Hub index was at $1.87 per MMBtu. Futures for NYMEX 12-month strip avg. from May 2020 to April 2021 was at $2.55 per MMBtu. By summer as virus-related travel limitations perhaps become clearer and perhaps a better picture of natural gas supply and demand emerges, the predictions for 2021 should be narrowed a bit, perhaps. There is still some wildcard-ness but it should be in the general range.
Ga drillers had already tapped the brakes on growing production as prices declined in mid-2019 and production peaked in late Dec. 2019 and DUCs are quite low in the major shale gas basins but quite high in the Permian. Thus, gas drillers were pre-poised for a recovery some time in 2021. With the potential loss of significant gas production that rebound should perhaps begin sooner.
References:
Natural Gas is the Clear Winner from the Oil Blow-Up – by HFIR Energy, in Seeking Alpha, April 20, 2020
Energy Information Administration (EIA) – Short-Term Energy Outlook: Natura Gas, April 7, 2020
RBN Energy CEO Breaks Down the Meltdown in the Oil Market – interview with Rusty Braziel, in Cramer’s Mad Money, CNBC, April 20, 2020
Coronavirus: Tracking the Impact on European Gas, Power, and Chemicals – by Hadrien Collineau, in WoodMackenzie, April 22, 2020
European LNG Imports Holding Strong – by Connor McLean, in BTU Analytics, April 7, 2020
Take Me to the Other Side – Oil, Natural Gas, and NGLs in Post-COVID 2021-25 Markets – by Rusty Braziel, in RBN Energy, April 2020
No comments:
Post a Comment