Exploring the 885 DUCs in North Dakota

Exploring the 885 DUCs in North Dakota

What do you mean DUCs?

When our clients talk about DUCs, there is a discussion about what exactly constitutes a drilled but uncompleted well. Is it drilled and cased? What is the typical timeframe of a DUC? When is the well considered temporarily abandoned? If it finished drilling last week, should that be included in the DUC count? What was the typical DUC count prior to the downturn? These questions set the table for how the company views how DUCs impact their particular market.

Others look at DUCs and rig count trends together to understand what is available to complete and how the new wells impact overall production. Some use the analogy of 1 rig to multiple well relationship. Depending on the operator, that could be 2 to 12 wells based on who is talking to whom in the Bakken. You can see more drilling pad trends in Energent’s Pad Trends report at http://energentgroup.com/basin-pad-trends/.

This article explores the relationship between DUCs, rig count, oil prices with our interpretation of the key market constraints – capital, supply, and labor. Throughout this analysis, we highlight two key periods of oil price changes: (1) Q4’2014 – 1st major oil price decline annotated in gray and (2) Q3’15 – evaporation of recovery hopes highlighted as red in the charts below.

Changing Constraints: Fall-out, false hope, and capital freeze

Fear and uncertainty spread throughout the industry and capital markets. Instead of $200 oil, now analysts and pundits were citing $20 oil. By mid-2015, false hope set in as the price of oil reached $60 per barrel for a short period.

Immediately after prices hit $60, oil dropped again this time below $40 (highlighted in red). Not only did labor exit the market, now capital was sitting idle on the sidelines.

The chart below shows the story of DUCS along with the price of oil. The bottom chart illustrates the change in DUCs over the same time period.

Early in 2015 the prevalence of profitable hedges and continuation of D&C plans is seen through the decrease in DUCs as operators completed and brought wells online in core areas. However, in mid-2015 DUCs started to increase as the hope of recovery faded.


Nearly 1000 Sitting DUCs

The total DUC count reached its max towards the end of 2014. Just as rigs declined in early 2015, so did the number of frac spreads in North Dakota. The crews completed wells faster than the rig crews drilled and cased new wells.

With the false hope in 2015, DUC count declined in early 2015; however, oil prices fell again and operators reduced frac crews across the basin.


Average Days as a DUC Doubles in 2015

What was the typical timeframe for a DUC in North Dakota? In 2013 and 2014, the average days as a DUC was between 60 to 75 days. That changed dramatically in 2015.

The rolling median days spent as a DUC continues to increase, now over 160 days. This analysis capped DUCs at 365 days to remove possible outliers and reporting errors.


Rig Counts Staying Lower for Even Longer

With oil staying near $35, many are asking what happens next with the drilling rig count. A number of operators have drastically reduced the number of planned rigs for 2016. For instance, Continental Resources initially planned 8 rigs running in 2015 compared to 4 rigs planned for 2016. Marathon planned 2 rigs for 2015 compared to only 1 in 2016.

QEP Resources operated 21 rigs in 2014 and 9 in 2015. Currently, QEP has only 3 active rigs in the Bakken. Others, like Whiting Petroleum, are not completing wells in certain areas. Others have slashed the budget to a sliver of what it was in 2015. Sure, the low price of oil pushes rig count down, but drilling efficiency impacts the number of rigs required to develop these assets.

The chart below shows the percentage of wells by pad size in North Dakota.


The Bakken wells per pad shows exactly how drilling efficiencies and pad trends continue to increase the rig to well ratio over time.

The stacked chart below shows the price of oil and average rig count in North Dakota. The rig count peaked in 2012, then stayed relatively flat until the end of 2014 due to the sharp decline in oil (highlighted in gray).


Where does the North Dakota DUC count go from here?

With CAPEX being the constraint now, the oilfield equipment and service market will be slow to react to increased oil prices.

Rig counts will lag frac crew counts through 2016 and possibly 2017. The restarting of activity in the shale plays will take longer than expected due to the loss of experienced crews.

Over time, capital will return to the market to fuel the return of oilfield service labor and equipment.


Find DUCs by Operator and Basin. Contact us to get the details.

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