What drives U.S. natural gas production?

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Source: U.S. Energy Information Administration, Drilling Productivity Report, Natural Gas Monthly, and Short-Term Energy Outlook


Gross production of natural gas in the United States has generally been increasing for more than a decade and in recent months has been more than 10% higher compared with the same months in 2017. This growth has been driven by production in the Appalachian Basin in the Northeast, the Permian Basin in western Texas and New Mexico, and the Haynesville Shale in Texas and Louisiana. These three regions collectively accounted for less than 15% of total U.S. natural gas production as recently as in 2007, but now they account for nearly 50% of total production.

Production in these regions has increased in part because of new drilling and completion techniques, including longer well laterals that have increased well productivity. By contrast, the Gulf of Mexico's share of total production, which was 12% in 2007, has fallen to just 3% in recent months, and the share of production in the rest of the United States has declined from 60% to 28%.

Growth in natural gas production in the Northeast has come mainly from the Marcellus and Utica shale plays in the Appalachian basin, which collectively accounted for about 29% of total production in July 2018. Recent infrastructure buildout in the region has allowed natural gas to move out of the region and has reduced the prevailing discount to the national benchmark price at Henry Hub and to regional prices.

Natural gas production in the Permian Basin has also grown in recent years, largely in the form of associated gas accompanying the region’s rising crude oil production. Similar to the Appalachian Basin, natural gas in the Permian trades at lower prices relative to Henry Hub because of regional infrastructure constraints. A number of new natural gas pipelines are planned or under construction that will help move natural gas out of the region, and several of them will expand liquefied natural gas export capability. EIA projects that July 2018 production in the Permian Basin will account for about 11% of total U.S. gross production.

Production in the Haynesville region has also increased. After decreasing from its peak in 2012, increasing production in the Haynesville region since 2017 has been driven by improving initial production rates and increasing rig counts. Higher rig counts are likely a result of recovering crude oil prices, which have been generally increasing since early 2016. Together, the Haynesville and the Permian regions accounted for nearly 20% of total U.S. natural gas production in 2017.

In contrast to the Appalachian, Permian, and Haynesville regions, the Gulf of Mexico has accounted for an increasingly smaller portion of national production, which is a significant change from a decade ago. Older wells in the Gulf tend to be more natural gas-rich, and newer wells tend to be more oil-rich. These factors contributed to the overall decline in that region's natural gas production. In addition, the technology and expertise required to produce oil and natural gas from the seabed is more expensive and specialized. Drilling platforms sometimes cost a billion dollars or more and take several years to construct. Finally, offshore projects generally carry higher risk than onshore projects.

Mike Kopalek and Kiefer Mueller for US Energy Information Administration









Until a decade ago, the prices of natural gas in Europe were tightly linked to oil prices. Back then, gas delivery points and gas markets were highly segmented across Europe, natural gas competed with oil and oil-derived products for power generation, and most supplies of natural gas were indexed to oil prices.

This summer, however, European natural gas prices have not followed the typical oil price trends. Rather, they followed their own supply-demand and pricing logic, highlighting a fundamental change in Europe’s natural gas supply and market.

Today, the gas market is not about following the oil price movements, because gas sourced at one place and shipped in one way to a European hub or point of consumption has started to compete with gas sourced at another place delivered through another means to another hub. The gas market is no longer localized, and competition has increased with the growing number of interconnectors and pipelines from various gas-producing countries competing among themselves, and competing with liquefied natural gas (LNG), which also comes from a growing number of counties.

“There’s been a move toward a more globalized gas world, where gas could be moved around more readily, but the substitution link with oil has broken off, so oil and gas are not competing against each other,” Muqsit Ashraf, Managing Director and global lead for energy at Accenture Strategy, told Bloomberg.

This summer, Brent Crude prices—currently at around $76 a barrel—have faltered a couple of times since briefly hitting $80 in May. On two occasions, in mid-July and in mid-August, Brent plunged to the low $70s as fears started to emerge about the health of the global economy and oil demand growth amid concerns over the ongoing trade wars. Hedge fund and other money managers have also been liquidating bullish positions, cutting their net long position in crude oil and refined petroleum products in 13 out of the past 18 weeks, according to estimates by Reuters market analyst John Kemp. Hedge funds currently hold the lowest volume of petroleum products in contracts with long positions in nearly a year.

On the other hand, natural gas prices in the UK surged to the highest for a summer season, with Europe’s natural gas market the most bullish in years, as higher-than-expected summer demand and a tighter market drive natural gas price futures to levels last seen during this past winter’s supply crunch.

The past winter season in Europe was one of the coldest this decade, sending gas demand soaring and the level of natural gas stored in tanks across Europe dropping to below average levels.

The cold spell in Europe at the end of February and early March led to record withdrawals in the first quarter of 2018, and storage levels dropped to 18 percent of capacity—well below the five-year range, the European Commission (EC) said in its Q1 Quarterly Reporton European gas markets. By the end of the winter season, natural gas stock levels dropped below 10 percent of capacity in countries such as Belgium, France, and the Netherlands, where high gas demand from the UK contributed to strong withdrawals this winter, the report said.

In the spring and summer, demand in Europe stayed high. First, because gas storage levels were low, and second because some of Europe’s other traditional gas-supplying countries decreased supplies over issues or maintenance at facilities. In addition, utilities across Europe were seeking more gas-fired power generation because the prices of EU carbon dioxide (CO2) emissions allowances under the EU Emissions Trading System surged to a 10-year high, so utilities prefer to use more gas-fired power generation at the expense of the more emission-intensive and polluting coal.

While Brent Crude prices have been rangebound in the around $75 a barrel territory, natural gas prices in Europe followed the gas supply and demand logic and rallied this summer. Analysts and traders see more room for rises in the months ahead as winter approaches.

With the development of gas hubs, gas trading, and LNG imports and trade over the past decade, the share of gas supply indexed to oil in Europe has dropped to below 30 percent now from some 80 percent in 2005, Accenture’s Ashraf told Bloomberg.

In Europe, competition between various sources of gas rises, Ashraf says, adding that “Gas is competing with gas: piped gas from Russia is competing against piped gas from North Africa, competing against LNG from Qatar, LNG from Nigeria, and soon LNG from the U.S.” 

Tsvetana Paraskova for OilPrice.com