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1.8 MMb/d Permian Production Potential from DUCs

As operators continue to grapple with a $40/bbl oil price environment, many are looking for ways to balance declining production with capital expenditures. In the Permian, a familiar, but perhaps currently under-emphasized story of DUCs and excess backlog has the potential to play a significant role.  As oil prices began to rapidly deteriorate in March, operators responded quickly and both completions and drilling activity fell precipitously. However, completions fell faster and further than drilling activity. As a result, the excess backlog of wells in the Permian Basin sky-rocketed from ~350 wells in February to over 2,300 wells by May. Depending on the location of these wells and timing of completions, there is ~1.8 MMb/d of production potential.

It is important to note, that BTU Analytics differentiates between excess backlog and DUCs (drilled, uncompleted wells). DUCs are wells that have been drilled, but are not completed.  To calculate excess backlog, BTU Analytics assumes a normal working inventory level of DUCs based on a spud-to-sale time and subtracts those from the total DUC figure. This results in identifying backlog that is in excess of normal working inventory levels to provide a better estimate for forecasting.

As producers continue to face pressure from investors to return money to shareholders and face limited options to tap into the equity and debt markets, this excess backlog is a capital efficient way to maintain production in the face of a ~$40/bbl oil strip. The pace of drawdown of this excess backlog is one of several key drivers between declining production through 2021 or a return to growth. From a capital efficiency perspective, DUCs in excess backlog have a much lower breakeven than drilling and completing a new well because the drilling cost is already sunk. Therefore, the go-forward economics of completing these wells is based on approximately two thirds of the total D&C cost for a new well.  The chart below shows the WTI breakeven distribution for wells drilled and completed in the Delaware and Midland Basins compared to the economics of those same wells if they were DUCs and the drilling cost was sunk.

Removing the drilling cost and only accounting for the completion cost to bring a well online increases the percentage of wells that have a breakeven at a $40 WTI from 32% in the Delaware and 37% in the Midland to 67% and 68%, respectively. With an estimated 2,300 wells in excess backlog, this means that if the same distribution can be applied, there are ~1,500 wells available for producers to tap into over the coming months and year, even in a $40 environment.  While the decision to bring these deferred wells online will vary by producer and there is no guarantee that the distribution of these wells is identical to 2019 activity, if these 1,500 wells are brought online evenly at a rate of 125 wells per month over the next 12 months they would add an average of almost 0.5 MMb/d of new production to the Permian.

BTU Analytics often highlights the disconnect between rigs, drilling activity, and production as seen most recently here. With the significant buildup of excess DUCs in 2020, this will continue to leave rig count production models wondering why they are wrong.  If you are interested in BTU Analytics’ production outlook for the Permian as well as other US shale basins that take into account key variables like DUCs, economics, infrastructure constraints, and more, request a sample of our Upstream Outlook Report.

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Erika Coombs is Senior Manager of Energy Markets at BTU Analytics. She leads the team to deliver 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 oversees BTU Analytics’ oil and gas product suite which includes research on upstream, midstream, breakeven economics, and commodity pricing dynamics. She holds an M.S. in Mineral and Energy Economics from the Colorado School of Mines.

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