July 9, 2020

Does Drop in Rig Counts Really Impact Gas Production Everywhere?

By Jeff Bolyard, VP, Commodity Strategy and Procurement

This article is adapted from Edison’s Monthly Monitor Report – July 2020, a comprehensive assessment and analysis for the natural gas, electric, and crude oil markets. To download the complete report, please click here.



In commentary from last month, I wrote about COVID’s impact on natural gas demand and looked specifically at the significant drop in LNG export demand and also showed a corresponding decline in production. This month, we would like to dig a little deeper into some of the regional impacts of where supply comes from and what could impact that production in the upcoming months.

The unprecedented drop in drilling rigs has been documented over the past few months in the Baker Hughes weekly activity report as a signal to the market that future production is at risk of declining.  From January 4, 2019 until June 26, 2020, the number of rigs drilling for either gas or oil/NGL’s has dropped 810 rigs from 1,075 to 265, a growing concern for the upcoming winter. However, 85% of that total (681) were searching for oil while the remaining 15% were drilling for natural gas. So is there really any risk to natural gas since most of the drop in rigs are tied to oil?

To get an idea of what might happen to natural gas prices this winter,we need to understand which areas of the country would increase as a result of oil/NGL price increases or decreases (i.e. associated gas production) and which areas are focused on dry gas that would be more impacted by natural gas price movers like seasonal storage levels, LNG exports, domestic gas demand and extreme weather. There are eleven major commodity plays across the continental U.S. that allow us to link those rigs to a specific region and classify whether each play would be impacted by a price move in oil/NGLs or impacted by a price move in Natural Gas. Six of those regions are oil/NGL focused, four are dry gas focused, with the last being a catch-all aggregation of “other” that is a mix of both oil and gas but not defined by a particular region. Those eleven plays are shown in the graph below along with their generically assigned State/Region in which they primarily reside, the commodity focus of that play, the increase/decrease in rigs since January 2019 (data from Baker Hughes).

Now that we know which gas production regions are really driven by oil prices, we can link potential events for a particular commodity that would trigger a change in rig counts for one commodity but not the other, resulting in a change in future production of natural gas. For example, an increase in crude oil prices by $10-20/barrel in the futures market could trigger additional drilling activity in the oil focused plays of Williston, Permian, Granite Wash, Eagle Ford, Niobrara and Cana Woodford, and resulting in increased associated gas production out of these regions, while having a minimal impact to the gas focused plays. Whereas an increase in Asia and European gas demand due to a cold start to this winter would cause currently idled U.S. LNG export capacity to rebound, bringing with it the NYMEX natural gas futures contracts and increased investment in the gas plays of the Utica/Marcellus, Arkoma Woodford and the most potentially impacted gas play, the Haynesville, due to its physical proximity to the major LNG export facilities on the Gulf Coast. Of course, just because drilling increases significantly in a certain area doesn’t actually mean infrastructure exists to move that supply to market. Supply and demand locations are one thing, but whether adequate infrastructure between the two is becoming a focus of the next level of both supply and demand levers that might be pulled next. What if July and August are extremely hot, gas fired generation spikes and the current sky high storage levels come back down to normal levels. Regional storage levels would be impacted differently because natural gas supplies are no longer increasing in every region. And how does that short-term impact change to a long-term issue after the result of the next presidential election, where one of the two assumed nominees has promised to shut down access to drilling for gas and oil on federal lands his first day in office?

We can no longer monitor the traditional price drivers of natural gas pricing at the 20,000 foot level and expect the same results as we have in the past when prices went down in the summer and up in the winter. In the new natural gas market, the impact of a price increase of crude oil has much more of an impact at the regional level than it once did and should be considered in any procurement strategy. While the extent of these variables are not known today, patterns are developing in the natural gas market that allow us to envision potential outcomes as different levers get pulled over the next several months. What may have worked in the past may not work tomorrow. Be open to discuss these new risks and opportunities with Edison Energy to see what best fits the objectives of your company to manage your natural gas cost and risk.

If you have questions or concerns, please reach out to your contacts at Edison Energy for a discussion or send us an email at information@edisonenergy.com.