The Baker Hughes US Rig Count is now beginning to recover from its constant slide downward that started in September 2014 (rigs peaked at 1,931) bottoming at 404 rigs in late May 2016 before climbing to 424 rigs in the latest report for mid-June. Great news for the industry. In this blog, BTU Analytics wanted to look at three natural gas plays with different vintages to see how they will respond in terms of production, PDP, rigs, wells and DUCs (drilled by uncompleted wells) as we enter the latter innings of the current correction. The Piceance, Fayetteville, and Eagle Ford were selected as natural gas production peaked in 2008, 2012 and 2015, respectively, driven by the evolution of technology and drilling economics.
Each of these plays is in a different development stage as shown below when we look at current PDP as compared to the BTU Analytics Upstream Outlook production forecast. A vertical dry gas play, the Piceance grew significantly from 2005-2008 as one of the most economic developments at that time. The Fayetteville was the next big dry gas shale play following the Barnett and Haynesville, and hit its peak in 2012. Eagle Ford gas production was primarily driven by $100-plus oil economics and peaked in early 2015. Going forward we can see all are in decline (as seen by the light blue line). However, each has a different outlook with the Piceance continuing to decline through 2020 as gas prices remain low enough to challenge economics, the Fayetteville plateauing by 2020 as rigs eventually return driven by growing Southeast demand, and the Eagle Ford getting back to growth by as early as 2017 driven by crude economics. Also of note, a play with significant recent activity like the Eagle Ford has a one-year PDP decline of 28% (sans DUCs) while the Piceance is an older play with more vertical wells at a 15% decline.
If we look at each of these plays we can see how production will be driven going forward in terms of rig orientation, wells, and DUCs. Note that neither the Piceance or the Fayetteville have a DUC inventory above normal levels as economics drove production declines in these plays in advance of the current correction. The Eagle Ford, however, does have a DUC inventory to work off. Shown below are forecasts of wells by orientation (top row) and wells to sales and wells drilled (bottom row) for the three shale plays. Notice in the Piceance, BTU Analytics expects vertical rigs to keep production above PDP and since there are no DUCs, wells to sales and wells drilled are equivalent. A similar story is expected to play out in the Fayetteville. In the Eagle Ford, horizontal wells drive the forecast and you can see the lag (lower right) between wells to sales and wells drilled as we work down the inventory of DUCs in 2016-2017.
So with all eyes on rigs coming back, the question is, how quickly and where will rigs return when accounting for DUCs? Obviously, in a play like the Eagle Ford, the number of rigs needed will be tempered by DUCs as shown below, where an estimated incremental 400 MMcf/d of gas will come from DUC wells alone in 2017. However, rigs will have to return to offset the one-year PDP decline through June 2017 of 23% or 1.55 Bcf/d (including DUCs).
The main takeaway is not as many rigs will need to return to the field due to DUCs, not to mention high-grading, improved frac designs and other producer efficiencies – linear regression modelers beware. To learn more about BTU Analytics’ production analysis – request a copy of the BTU Analytics Upstream Outlook.