Why the Marcellus Shale is the Premier Natural Gas Play in the U.S. and Will Likely Remain So
The Appalachian region makes just less than a third of total U.S. natural gas production and closer to but still below half of U.S. shale gas production. Of the shale gas plays it is by far the most gas productive per well with the second most productive, the Haynesville Shale of Northwest Louisiana, only about two thirds as productive per well. Total Haynesville production is way less than half, closer to a third of total Appalachian production. See chart below. The Haynesville is closer to export markets in the Gulf and the Henry Hub, which gives it a price advantage over Appalachian gas. However, due to its depth, high reservoir temperature, and high reservoir pressure, it is more expensive to drill a Haynesville well than an Appalachian well. The Appalachian wells involve three distinct shale reservoirs: the Utica Shale, the Marcellus Shale, and the Upper Devonian Burkett Shale. The Marcellus is by far the most drilled, and also the most productive and economic, of the three. It has the biggest fairway, encompassing the most area. The Marcellus wells are just slightly deeper than the Burkett but much shallower than the deep Ordovician age Utica Shale wells. Utica wells may have higher initial production than Marcellus wells, but the Marcellus wells decline slower and are thus more economic. Thus, it is the Marcellus that will continue to be the driver for Appalachian gas production. While the deeper Utica dry gas in Pennsylvania and parts of West Virginia holds massive gas reserves, the cost to extract is much higher so it is really a play that requires much higher gas prices. The Appalachian plays are aided by being closer to populated Midwest and Northeast markets but getting pipelines out of the basin has been slow and is likely to remain in some sort of bottleneck state for a while. The gas-pricing in the region is very susceptible to seasonal supply and demand, and warm winters can glut supply in short order. Aside from pipeline takeaway capacity and seasonal demand there is only proposed and under construction regional natural gas power plants that can help with demand a bit.
The Permian Effect
Permian Basin shale wells are drilled predominantly for oil. Gas is now considered mostly a by-product of oil production. Quite a bit of it is pipelined to Mexico in mutually beneficial deals. A very significant but falling amount is burned off through flaring. Permian Basin flaring peaked in Dec. 2018 at 900MMCF/day, but now the whole state of Texas is down at 650MMCF/day. That is still a lot of gas and likely coming Texas regs will require high gas-to-oil ratio wells to be shut-in or choked back. Apache recently announced they were divesting the once hyped Alpine High part of the basin due to more gas relative to oil than expected. Gas-to-oil ratios in oil wells tend to increase over time so this may help keep Permian gas coming. From the Gas Production by Region graph below it can be noted that the Permian Basin as a whole makes the second highest amount of gas by formation/region but from the Well Productivity By Region graph below it can be seen that the Permian wells make about 1/10th the gas productivity of Appalachian wells. There are just so many of them that the gas amounts add up. Someone working in the Marcellus might say “hey, you guys are drilling too much!” But as long as the Permian economics continue to work, they might just shrug. However, the recent OPEC- plus situation means that the Permian is headed for a major slow-down and depending on what prices do there might be quite a few companies that can’t remain in business. Although Trump has proposed a bailout of sorts some think that they should be allowed to fail rather than be propped up in what looks like it could be a longer-term surplus. The Permian Basin also has by far the most drilled but uncompleted wells (DUCs) – see graph below. The Appalachian and Haynesville regions, the ones that make the most productive gas wells, have less than 1/6th of DUCs as the Permian and Eagle Ford combined, the two regions with the most DUCs. This bodes pretty good for a natural gas price recovery at some point in the future. However, with the economic slowdown due to the coronavirus, it is likely that demand for oil and gas will be suppressed for the time being. If the economic outlook improves by early summer then summer demand may ease back to normal but there is much uncertainty. BTU Analytics suggests that the recession impact to U.S natural gas demand could exceed 4.2BCF/day, enough to delay price recovery and stress some gas-heavy E & Ps.
To summarize, the Permian Basin is the main driver for U.S. oil production but is subject to OPEC-plus price wars that can render it uneconomic. The Appalachian region, particularly the Marcellus Shale, is the main driver for U.S. natural gas production but is subject to regional and sometimes seasonal supply and demand volatility, and to a lesser extent on global LNG demand.
References:
Drilling Productivity Report – by US Energy Information Agency, March 16, 2020
Recession Impact to Natural Gas Demand - by Andrew Bradford, BTU Analytics, March 10, 2020
