By: Michael Lynch – Forbes – An old joke about the economy goes that when your neighbor loses his/her job, it’s a recession, when you lose your job, it’s a depression. Apparently, not many writing about the global energy crisis have heard that one, since they think soaring natural gas prices in Asia and Europe mean, as New York Times NYT -1.4% columnist Thomas Friedman puts it, “Every so often the tectonic geopolitical plates that hold up the world economy suddenly shift in ways that can rattle and destabilize everything on the surface.”
The reality is that a number of regional market imbalances have caused some energy prices to surge, and those are primarily the result of transient events, such as the late winter cold earlier this year and the Chinese government’s efforts to reduce coal consumption. Russian gas exports to Western Europe are well down from last year, apparently because cold weather depleted Russian inventories and they have given priority to rebuilding them. (While a more mundane explanation than Russian pressure to achieve early certification of the Nordstream 2 pipeline, it appears more likely to be the primary cause.)
Oil—and U.S. gasoline prices—have also surged but not because of any underlying conditions, rather the success of OPEC+’s efforts to rebalance the market which have arguably overshot, leaving global oil inventories lower than normal. This was exacerbated by Hurricane Ida, which caused a loss of crude production but also refinery shutdowns that tightened product markets. But OPEC+ has 5-6 mb/d of unused capacity, so the problem appears readily solvable. Indeed, by the end of the 1st quarter of next year, the IEA forecasts that global inventories will be growing by 2 mb/d, enough to see prices moderate.
This leaves the U.S. natural gas market, where prices have surged an astonishing 150%, as the figure below shows. Of course, as the second figure shows, the price level, while elevated, is hardly exceptional. More interesting is the fact that drilling in the Marcellus has not increased noticeably: the number of rigs operating there are still less than half the pre-pandemic level. Haynesville drilling has recovered, possibly reflecting better prices received from supplying the LNG export market.
The fact that all three major gas markets—Europe, Asia and North America—are tight reflects more the correlation in their weather, at least this past year. They still remain largely independent, the only connection being some LNG supply that can be switched to the highest-priced customers. (Much LNG is traded on fixed, long-term contracts.) Sadly, benefits to U.S. gas producers from the supremely high LNG prices in Europe and Asia will be limited because export capacity is already operating at near 100%, and not much additional capacity will come online.
The table below shows the market balance for U.S. gas, and it is clear that the biggest change was the increase in net exports of 6 bcf/d in 2020 and 2021, primarily LNG, a trend the EIA forecasts to continue next year. And the subsequent figure shows U.S. gas inventories and they are approximately 100 bcf below the normal level for this year, but still well above the minimums over the past five years, although growing demand means the needed storage should grow as well. More important, recent weeks have seen inventories growing rapidly.
This brings us back to that bugaboo of the gas industry, weather. A large amount of natural gas is still normally consumed in the winter and especially for heating. The figure below shows total consumption over the course of November to March the following year, roughly corresponding to winter in the U.S. The difference between a warm and cold winter is roughly 1000 Bcf in demand, far more than the current inventory shortfall.
The EIA forecast is for roughly flat consumption next year, much higher production, and a slight increase in exports. (Only about 1.2 bcf/d of new export capacity is anticipated over the next year, and pipeline exports are unlikely to increase more than slightly.) This means that inventories should grow by 200-500 Bcf in 2022, more if the winter is mild, less if the winter is cold. But given past performance in the shale fields, raising production by 2, 3, even 5 bcf/d for the year is readily achievable—if the drilling occurs. (Figure below)
As mentioned, drilling has not recovered in the Marcellus, and that is definitely a major indicator of next year’s gas market. But if high oil prices send Permian drilling back to pre-pandemic levels, it is possible that associated gas production from that region could rise by 2-3 bcf/d, a growth level reached in 2018/2019, when oil prices were only 75% the current level as the figure showed.
A cold winter and no revival in shale drilling could see natural gas prices remain above $5, possibly $6/MMBtu or more depending on the perceptions of traders. On the other hand, a warm winter and/or a surge in drilling in either the Permian or Marcellus could easily bring prices back down to $3/MMBtu. This would certainly provide some relief to consumers, but also greater profits to LNG exports who are selling spot cargoes at currently elevated prices. I predict uncertainty and volatility! Readers are shocked, I’m sure.
