It has been hard not to take note of the growing rig counts across the country. Ever since hitting the bottom in July 2016, drilling activity has slowly, but steadily climbed. Growing drilling activity begs the question, how much more activity is needed to add to natural gas production to satisfy growing US demand? Let’s approach the question by looking at where drilling activity is today and how it can affect the broader market.

For a snapshot of where gas-focused drilling activity stands today and its path over the past two years, the graphic below shows horizontal gas rig counts by region.

While oil rig counts have been dominated with growth in the Permian, horizontal gas rig counts have shown the strongest gains in Appalachia and the Midcontinent (SCOOP/STACK). Gas plays in Louisiana and Texas have recovered at slower rates, while other gas plays in the US continue to decline or have flattened out.

So how will this translate into production if we project current activity forward? Using Appalachia as an example, the following graphic shows what happens to Appalachian production if we project rig activity as of March 10, 2017 (224 Lower 48 horizontal gas rigs) forward.

A few caveats: the projection model assumes a 6-month spud-to-sales time, and the rig efficiency is calculated using the most recent six months of data then projected forward. Also, while operators have announced expected increases in drilling activity, this projection is just meant to look at where drilling activity sits today.

Appalachia is expected to add significant volumes to US supply as infrastructure projects like Rover bring much awaited takeaway capacity out of the region. However, as is obvious by the graphic above, current drilling activity in the region won’t cut it. You could say, “Of course drilling activity hasn’t increased yet in Appalachia, there are no new pipes to support incremental production!” However, in Appalachia there is a six to nine month spud-to-sales time, and with Energy Transfer calling for a July 2017 in-service date for its Rover project (3.25 Bcf/d), drilling activity at current levels spells trouble for a boom in production if the pipe comes online as planned.

While Appalachia is used here as an example, similar examples could be made from other regions in the US. Now let’s take these projections in aggregate for the entire country (including associated gas from oil plays) and look at the US supply/demand balance and its impacts on monthly storage injections/withdrawals, something we do monthly in our Henry Hub Outlook report where we also include BTU Analytics’ natural gas production forecast not just a projection of current activity.

Demand is expected to continue to grow thanks mainly to LNG and Mexican exports. However, current drilling activity restricts production growth, leading to unrealistic results in 2018 and beyond. So, what drilling activity and, maybe more importantly, prices are required to balance the market? Join me for a free webinar discussing regional supply/demand balances and impacts to Henry Hub pricing on Wednesday, March 22.