Last week a client called trying to get a better understanding of the relationship between natural gas production and crude oil production. Many would turn to the EIA as a resource and look at its estimates of natural gas production from crude oil wells. While this would seem like a natural place to start, it yields startlingly low results.
The EIA definition of associated gas production is very strict and relies on state reporting agencies like the Texas RRC or the Wyoming Oil and Gas Conservation Commission for its categorization of natural gas production from an oil well. Most states define an oil well as “a well in which more than 50% of the production on a barrel of oil equivalence (BOE) basis is crude oil”. The application of this definition results in less than 10% of US Lower 48 natural gas production being defined as “associated gas production”.
However, in order to understand the implications of falling crude prices on natural gas production, it is important to broaden the definition of a “crude oil well”. Drilling activity since 2011 has become increasingly focused on liquids rich wells that produce varying ratios of natural gas, natural gas liquids, condensate, and crude oil. Producers focused on liquids rich plays due to the wide value gaps associated with producing crude oil and natural gas liquids relative to the value received for natural gas.
Many of the wells in the Eagle Ford, for instance, are classified by the state as gas wells rather than oil wells. Of the approximately 6 Bcf/d of natural gas production in the Eagle Ford, more than 3.6 Bcf/d or 60% is produced from a gas well. What is critical though, is that those “gas wells” account for nearly 20% of Eagle Ford oil and condensate production. So in order to understand the full impact of low oil prices on gas production, we lowered the bar for classifying a well as an oil well to any well in the lower 48 that produced oil or condensate at the wellhead.
Widening the definition of an oil well shows that the percentage of US natural gas production associated with liquids production actually declined from 48% in 2010 to the beginning of 2012 at 41% as producers ramped up dry natural gas production in plays like the Haynesville, Fayetteville and Marcellus. By the beginning of 2012 though, producers had shifted capital budgets from dry natural gas plays towards liquids-rich plays in the Williston, Permian, South Texas and Oklahoma, boosting the supply of liquids-rich gas and simultaneously reducing the growth of dry supply from plays such as the Haynesville. As of December 2013, which is the latest complete data set for Lower 48 gas production due to state reporting lags, the percentage of natural gas production associated with liquids production(By BTU Analytics Definition) had grown to 45% or nearly 33 Bcf/d of total gas production as compared to the EIA estimate of just 10% of US natural gas production being “associated” with the production of crude oil.
We estimate that the ratio continued to grow throughout 2014, and natural gas production associated with wellhead liquids reached nearly 50% or almost 40 Bcf/d of natural gas production in October 2014. As producers cut capital spending due to weak oil and natural gas prices, expect natural gas production growth to slow on the heels of less associated gas and reductions in Marcellus & Utica activity due to weak natural gas prices . For more on BTU Analytics’ outlook for natural gas & crude oil production, see BTU Analytics’ Upstream Outlook.