Earnings season is here again, and there will be an abundance of talk describing how producers have continued to improve efficiencies and reduce drilling and completion costs. Better yet, most operators will likely predict that the average cost per lateral foot will continue to decrease in 2017, aiding their economics and profitably going forward. If this is the case, as the energy market stabilizes and oil prices head north of $50 WTI, this could mean significant value added for producers. However, permanently lower Drilling and Completion costs (D&C) can only occur if productivity and technology advancements offset inflation in service costs. BTU wrote an article in June describing the correlated nature of service costs with WTI pricing, indicating a significant portion of D&C reductions are related to lowered costs from service companies such as Schlumberger (NYSE: SLB) and Halliburton (NYSE: HAL). The take home message was service costs will bounce back.
Schlumberger’s 3Q earnings call made it clear that the trend of extremely low service margins cannot continue, and the company plans to start renegotiating contracts and selectively focusing on only profitable projects. The timing for this will be sooner rather than later, as service costs should begin increasing with drilling activity levels.
The chart above shows BTU’s forecast of horizontal drilling activity over the next five years. As the backlog of drilled but uncompleted (DUC) wells is consumed, new drilling activity will need to respond. During this time, we would expect that rising demand for services will return some pricing power back to industry service providers, offsetting some of the cost reductions producers have reported over the last two years. In an energy market where economics are a driving factor of producer decisions, what does this mean for the cost of production?
BTU’s wellhead breakeven calculations based on representative wells for selected regions are shown above. Average D&C costs for each specific area were raised by 10%, 30%, and 60% to see the effect on breakeven pricing as service costs increase. Breakeven results were then allocated into $5 buckets (meaning that in the chart above a $50 breakeven actually equates to a $50-55/bbl breakeven). A 60% increase was previously calculated to be the change in D&C costs needed for service companies to realign with their historical margins.
Adding 30% to the average D&C costs results in a $5-$15 increase in breakeven economics for the selected plays. Under this scenario, $10 increase in WTI from today’s value from $50 to $60 WTI would leave the typical Bakken well seeing no net gain if service costs and WTI increased over the same time frame. Because of this, new wells in areas that barely break even under current service costs may not be profitable going forward despite higher WTI prices. In Midland, the same $10 WTI increase results in a net gain of only $5. While every bit helps, producer gains from increasing commodity prices may not be as pronounced as expected.
Breakeven calculations for wells that represent the top 10% of wells in each basin show a similar story. In the case of the Western Eagle Ford, higher service costs could push even the best wells towards marginal breakeven territory. But this isn’t necessarily a bad thing. In an industry that tends to dive all in and overproduce too quickly, higher WTI prices and permanently low well costs could cause producers to overshoot the supply and demand balance, driving price back down again. Increasing well costs may limit incremental cash flow enough to help restrain producers while still allowing for some degree of growth and recovery. For more information on BTU Analytics’ breakeven analysis, request a sample of the E&P Positioning Report.