As operators continue to press the envelope on optimizing their resources by high-grading drillable locations and leveraging vendor cost concessions, there arises the prospect of an emerging strategy shift that could underpin a further ramp-down in drilling even as the stage is set for increased oil production in the near term. That might sound grim, yet there’s a silver lining on the horizon as a result.
The RigData News & Analysis (RDNA) team came to this conclusion after reviewing comments made during some operators’ recent conference calls pointing to reduced E&P capex in 2016. We found a useful proxy for our thesis in Occidental’s (OXY) and Anadarko Petroleum’s (APC) recent conference calls highlighting drilling efficiency improvements for Wolfcamp Shale wells. These two operators also provide some contrast between what to expect from operators fully entrenched in the development/production mode (OXY) of the play vs. one maturing into this mode (APC) over the next year.
Relative to 2014, OXY reduced its average Wolfcamp well cost by 42% to $6.3 million/well, while APC lowered its average Wolfcamp cost by about 37% to $7.5 million/well and expects to shave another $1.5–$2.0 million off its future cost as its pad-drilling campaign expands field-wide. Much of the cost savings is due to reduced cycle times as well as lower day rates. Anadarko has lowered its Wolfcamp drilling cycle times by 13% when comparing its 3Q15 vs. 2Q15 averages. OXY, which started with a much lower base number, still was able to lower its drilling cycle time by 5% QtQ. It’s likely that such improvements in cycle times underpinned an 18% QtQ gain in total Wolfcamp wells drilled in Q3, one of only five major unconventional plays to post a QtQ increase during the peiod. What does this suggest? It seems that later entrants bidding to expand development in currently economic plays still have room for efficiency improvements. But the capex pullback/high-grading push amid low oil prices has blunted some of that efficiency initiative.
Consequently, the rise in the number of drilled yet uncompleted wells (DUCs) reflected a need to boost returns by waiting for vendor price cuts to kick in. We now see this phenomenon beginning to slow as operators capture the benefits of reduced costs. Now the economics favor completing these backlogged wells vs. spending capital to drill and complete new wells. So operators are more inclined to draw down or at least not build upon their DUCs inventory going forward. APC indicated as much when it noted that its incremental 4Q15 DUCs would range from -25 to +25 wells. This contrasts with the prior 3 quarters, when APC averaged an incremental 67 DUC wells added each quarter.
The RDNA team believes this slowing DUC trend is emerging as a pattern for the US industry overall and would be the logical precursor to what Dave Lesar of Halliburton described as the “Drill or Die” scenario.
Quite simply, an operator at some point will experience overall production volume declines due to a lack of investment in well development. But in an environment of depressed oil and natural gas prices, working through an inventory of DUC wells enables the operator to add production at a lower unit cost than would otherwise be the case. Thus while completion activities will be muted going forward, they will nonetheless garner a greater share of capital budgets than drilling activities. That said, once this phase plays out, it will force operators to reset their drilling campaigns and thus cause a quick surge in the rig count—we’re guessing by 3Q 2016.