Henry Hub, the US natural gas benchmark price, closed below $2 per 1,000 cubic feet on January 21 and has remained there ever since. It opens this morning down 12.7% for the rolling month (adding the latest day’s close while deleting the earliest). The last time the price breached $3 was over a year ago (January 25, 2019).
The lack of a major weather-induced uptick in demand this winter certainly hasn’t helped. On the other hand, unlike the picture conveyed in the crude oil market, that demand has been rising in a range of end uses other than for heating: electricity generation; petrochemical and industrial; transport; and export is liquefied natural gas (LNG).
Combined, the Energy Information Administration (EIA) estimates that U.S. natural gas consumption will increase in 2020 by 1.4 billion cubic feet per day (bcf/d), or about 1.7% year-on-year, from the 85.3 bcf/d registered for 2019.
Now I have had occasional disagreements with the way EIA calculates crude oil figures. But the agency’s track record on natural gas has been quite good.
Natural Gas Is Being Used Differently
The way usage breaks down is illustrative of how much the American natural gas market has changed. Overall, EIA estimates that:
- While electricity generation consumed an average 31.0 bcf/d in 2019, up 7.0% from 2018 because of new natural gas-fired electric generation capacity and competitive natural gas prices, the forecast calls for the growth in power sector consumption of natural gas to slow in 2020, increasing by only 1.3%.
- Meanwhile, combined residential and commercial natural gas consumption will average 23.2 bcf/d in 2020, down 1.0 % from 2019. This is largely a result of forecasts by the National Oceanic and Atmospheric Administration (NOAA), calling for milder winter temperatures. This further resulted in EIA calling for 1.8% fewer heating degree days (HDD) in 2020 compared with 2019.
The real alteration in usage is found in two non-heating categories. In these, EAI calls for:
- A U.S. industrial sector consumption to increase by 4.6 % in 2020.
- Net natural gas exports will rise to average 7.3 bcf/d this year and 8.9 bcf/d in 2021. EIA estimated that US LNG exports averaged 5.0 bcf/d in 2019. Even with the uncertainties surrounding global economics and coronavirus outbreaks expectations are for U.S. LNG exports to increase to 6.5 bcf/d in 2020 and 7.7 bcf/d in 2021.
This last factor is the largest single change in the country’s natural gas outlook. Accelerating exports – both of LNG and via pipelines to Mexico – have transformed the U.S. from a traditional net importer of natural gas, an environment still existing barely three years ago, to a net exporter.
However, there is a dark side as well.
While the overall market rise in demand for natural gas will justify some additional supply, there is a ceiling forming for LNG exports. Analysts at Morgan Stanley say selected U.S. LNG export terminals could face periodic shutdowns in 2020 as a result of lack in global demand. As is the case in several other regions of the world, American LNG export terminal capacity will exceed anticipated export demand by about 37% at the end of 2020 (8.9 versus 6.5 bcf/d).
The most significant element has a direct connection to domestic oil production. Associated gas accounts for a rising amount of shale gas production in the U.S.. This is gas present at what are primarily oil fields. If the gas is not also extracted well pressure will decline below levels at which the oil can be lifted.
As oil production volume increases, therefore, so does the need to produce the associated gas. This has already become a problem in the Permian Basin of West Texas and Eastern New Mexico. Permian gas production now accounts for about 16% of all U.S. shale volume with most of that being associated gas.
There is still not enough pipeline takeaway capacity in the Permian. A new major gas pipeline should come online late this year and is expected to provide an additional 2 bcf/d of Permian gas takeaway. That should bring aggregate Permian gas takeaway to 11.9 bcf/d. Current natural gas output in the Permian is about 11.2 bcf/d, according to EIA data.
That leaves very little margin for a supply increase from the Permian with the larger picture indicating nationwide a relatively flat production picture for 2020. Moving forward, several analysts have concluded two matters are becoming paramount.
First, operating companies will have to cut capital expenditures (capex) before there is any material improvement in revenues from natural gas production. That seems certain to lower the likelihood of major new field development.
Second, at current trends, Permian gas production alone is likely to overtake the total coming from the Northeast US – primarily from the Marcellus and Utica Basins – meaning a rather significant revision in sourcing scenarios is underway.
The Permian production level is largely independent of either the actual market price for natural gas or what s happening with the weather. Rather, given the rising amount of associated gas in the mix, the levels are dictated by how much oil is coming out of the basin.
On balance, analysis seems to indicate the following. EIA tells us there was a 2019 oversupply of about 1.43 bcf/d. Anticipated growth in total consumption and the net trade volumes (1.4+2=3.4 bcf/d) looks enough to cover this number and some limited output growth (primarily from the Permian). Medium-term, this appears to allow a manageable, although not robust, situation even allowing for a weaker LNG export scenario.
I expect natural gas prices to remain bounded or most of 2020, although a slight rise may occur should operators outside the Permian reduce expected volume increases as capex tightens.
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