Energy

Will The Global Energy Crunch Hit U.S. Natural Gas Prices?


Energy headlines are suggesting a new global energy crisis and talk of $100 oil for next year has been heard. More worryingly, the possibility that overseas energy shortages will raise U.S. energy prices, especially for natural gas, has been suggested. Worthy of note, though, is that many of the problems are transient, such as lack of gasoline at retail outlets in the U.K. Natural gas market fundamentals are very bullish, especially in Europe and Asia, where LNG prices have recently been as high as $25/MMBtu (roughly equal to Mcf);, while they have pulled back recently the tightness in those markets is likely to persist. At the same time, U.S. natural gas prices have tripled from recent lows—all the way to $5.50/Mcf! Quite a disconnect.

This market behavior demonstrates two long-term truths, first, that natural gas prices are volatile in large part because of the inelastic nature of supply and the highly variable demand for heating. Second, continental markets, while more connected than in the past, are still significantly isolated. Indeed, although there has long been a perception that natural gas and oil prices are naturally linked, the truth is that it stems from importers’ decisions in the 1970s to link internationally traded natural gas with oil prices based on their heat content. The logic for that is not much greater than linking coffee and tea prices based on their caffeine equivalence.

And especially before the shale gas revolution in the United States, there were periods when it seemed as if oil, gas and even coal prices were moving in tandem, but this was usually more coincidental than not. Oil and gas are imperfect substitutes, especially since oil was backed out of power generation in the 1970s. But internationally, this was much less the case, as the figure below shows.

While U.S. LNG exports have made a lot of news (and earned the U.S. a lot of money), they are constrained by the need for liquefaction capacity, which is expensive and time-consuming to build. In theory, no one is going to look at a price spike and plan an investment for twenty years’ worth of equipment, although in practice that does sometimes happen (a.k.a. irrational exuberance).

And at present, the U.S. LNG export industry is not only operating near capacity, but there is only a small amount of capacity planned to come on line in the next fifteen months, roughly 1.2 Bcf/d (about 1.5% of the U.S. market). This means that despite tight international gas markets, the U.S. supply will not be able to supply much additional gas this winter. Existing LNG plants can be expanded fairly quickly compared to new plant construction, but it will still take at least 1-2 years.

This is important for the domestic market, because it means that higher exports will not support prices in the near-term. At present, the U.S. natural gas storage is about 600 Bcf below this point last year, when inventories were abundant and the price was $2/Mcf, but only about 250 Bcf below the five year average, as the figure below shows. Compared to European storage, which is roughly 1 Tcf below normal, the U.S. market is much better balanced, which largely explains the price differential.

For natural gas, the important long-term variable is location, location, location: transport costs are high, and distance to the consumer dominates prices. In the short-term, however, the primary factor is weather, weather, weather, since heating is not only a major demand component but the biggest source of variability. The figure below shows natural gas consumption in the United States for the winter season (November through March) over the recent past, and the difference between a cold winter and a warm winter can be 1,000 Bcf. In other words, if the winter is mild, natural gas inventories in the spring can be abundant and prices could easily go below $3/Mcf. A cold winter on the other hand would mean storage would be tighter by spring without either a strong reduction in exports or a significant increase in production.

The other major issue is whether shale gas producers will increase activity, especially given the much higher prices. It has only been three months since gas prices passed $3/Mcf, but drilling has yet to respond, as the figure below shows. Activity in the Marcellus, the biggest play, remains less than half what it was before gas prices dropped in 2019. Of course, that means only an additional twenty rigs active would see significant production growth.

The figure below shows the year-on-year change in production for the Marcellus and the Utica, as well as the prevailing price. In 2018, when the price was $3/Mcf, producers added roughly 4 Bcf/d which, over the course of the (five month) winter would translate into 600 Bcf. That would roughly offset a colder than normal winter and leave storage in the spring close to normal, but if the weather is warm, storage would be brimming. IF drilling picks up.

Ultimately, then, a warm winter will see U.S. gas prices retreat below $3/Mcf. A normal winter without more drilling would leave the market tight, prices (at a guess) above $4/Mcf in the spring. A cold winter without more supply could mean even higher prices, perhaps $8/Mcf at least for a few months, but if drilling returns to early 2019 levels soon, then prices will be capped at $5/Mcf. Again, weather is the dominant factor for U.S. gas prices the next six months, but drilling activity also matters, especially going into the summer season.

Bob Dylan once said that you don’t need a weatherman to know which way the wind is blowing, but I guess he never tried to forecast natural gas prices.



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