Read Our Latest Energy Market Insights – Go There >>

Are Permian Rig Counts high enough to drive growth?

Since reaching a trough in summer 2020, Permian operators have increased activity 86%, adding almost 100 rigs to the basin.  This is the largest gain in activity across the US. Notably, the pace of rig additions between the Delaware and Midland Basin have diverged significantly. Midland operators have returned to 70% of January 2020 pre-COVID levels. On the other hand, the Delaware Basin stands at just 50% of January 2020 levels. Today’s Energy Market Insight will explore if current Permian rig activity levels are enough to return the Permian to growth over the next 12 months.  

Using purely rig counts to forecast production has pitfalls but is a useful starting place to lay a baseline for production trajectories. When using rig counts, one key component to examine is average spud-to-sale times. Spud-to-sales times can vary for a variety of reasons including well-pad size, operator strategies, region, and infrastructure constraints. The chart below shows average spud-to-sale times for the major Permian sub locations since 2017. The trends in average monthly spud-to-sale times vary across the regions.  However, in 2018/2019 the range of average spud-to-sale times for all the regions was between 5.5 months and 6.7 months. Applying an average 6-month spud-to-sale time to rig counts helps refine the timing of the potential production impact from the rapid rise in rigs in the Permian.

The result of historical rig counts and a 6-month spud-to-sale time shows that drilling activity over the last 6 months would result in a 300 Mb/d drop from April levels before production plateaus in 3Q 2021 at 3.65 MMb/d. However, breaking the Delaware Basin and Midland Basins apart shows that recent rigs additions in the Midland are enough to return the Midland to growth.  Conversely, the slower pace of rig additions in the Delaware indicates that without further increases in activity, production would decline in perpetuity.

However, as we have highlighted in the past, rigs are only a part of the production story, particularly in the Permian. As producers attempted to grapple with crashing oil prices in 2020, many delayed completing wells and built up a backlog of DUCs.  As a result, we estimate that there are currently just under 3,000 DUCs in the Permian that producers can continue to draw down.  Drawing down DUCs can provide incremental production and a boost to cashflow with oil prices currently above $60/bbl.  Producers leveraging DUCS and current rigs would need to draw down 1,000 DUCs over the next 12 months to hold production at April levels of 3.95 MMb/d.  Current completion activity indicates pulling 1,000 DUCs from the backlog is not a stretch and additional rig count gains or higher DUC completions would return the Permian to growth.  However, not all 3,000 DUCs are immediately available or economic to complete.  Some of these DUCs were drilled in fringe areas and operators may choose to abandon them as they remain uneconomic at current oil pricing even when considering drilling a sunk cost. The chart below shows the distribution of DUCs in the Permian by breakeven price after adjusting for sunk D&C costs.

Additionally, well vintage, operator dynamics, and factoring in working inventory levels further complicates the production equation.

To help our clients understand how rigs, DUCs, breakevens, well productivity trends, capital budgets, and infrastructure constraints all influence production, BTU Analytics publishes oil and gas production forecasts for the Permian and other areas of the US in our Upstream Outlook report each month. To learn more about BTU’s in depth production methodology and analysis, request a copy of the Upstream Outlook today.

 

 

 

 

Share This Article

Share on facebook
Share on twitter
Share on linkedin
Erika Coombs is Manager of Consulting Services at BTU Analytics. She leads the team to deliver customized energy-market analysis and provides BTU Analytics’ customers with critical information for a variety of energy markets including oil, gas, and NGLs from wellhead to downstream markets. She also leads research on upstream analysis, crude oil midstream infrastructure, breakeven economics, and commodity pricing dynamics for several BTU Analytics’ reports. She holds a M.S. in Mineral and Energy Economics from the Colorado School of Mines.

Recommended for You

Log In

Energy Market Insights

Receive Free Energy Market Insights When They Are Published