The most recent guidance on 2019 capital budgets indicates that US E&P operators expect, on average, a 6% decrease in capital expenditure in 2019 versus 2018. However, capital guidance itself does not provide clear insight into capital efficiency expectations for the coming year. Given a shale industry scenario with a slightly restricted capital environment, we at Rystad Energy see two possible outcomes; more wells drilled at a lower capital cost, or fewer wells drilled but with investment toward longer laterals and higher productivity.
Cost improvement in the shale industry was an exciting topic from 2014 to 2016, when a continuous shift toward field development was accompanied by a steady decline in service prices. Drilling and completion cost per lateral length foot across major US liquid basins declined during this period, from about $1,220 in 1Q14 to $730 in 3Q16. All major basins followed a similar downward trend over the same period.
Since then, cost changes have been less material in all basins. On average, costs per foot increased by approximately 19% between 3Q16 and 2Q18, driven by a combination of increasing completion intensity and service cost inflation. Modest deflation (around 5%) was observed again over the second half of 2018, driven predominantly by an oversupply of frac services and varying proppant cost segments, such as oversupply in some areas and in-basin sand adoption in others.
However, not all cost components are proportional to the length of lateral. As some components imply a fixed cost, longer laterals will always result in efficiency gains when such gains are measured by cost per foot. As of late 2018, an average 2-mile US onshore well exhibited a D&C cost of approximately $740 per foot, while 1.5- and 1-mile wells will cost $870 and $1,120 per foot, respectively. When the wells are grouped by lateral length, cost inflation over the 3Q16 to 2Q18 period looks more material, with 2-mile laterals becoming about 25% more expensive.
The relationship between lateral length and cost per foot remains true for each basin, as well as on a national scale. To analyze this relationship further, we first see that the average D&C cost per foot for 2-mile laterals varies from $530 in Niobrara to $870 in Anadarko Basin. (It should be noted, however, that some sub-basins in the Permian will have costs per foot in excess of $1,000 to $1,100, even for 2-mile laterals.) As of 2018, more than 20% of completions in each basin had a 2-mile lateral length. Hence, this is a representative group of wells to analyze the impact of various well-level drivers on costs, allowing us to better understand cost variability among the basins.
Generally there are many drivers of well costs. Each driver may individually represent a kaleidoscope of information from other variables. In the simplest model when lateral length is fixed, such as a grouping of exclusively 2-mile laterals, about 90% of well cost variability per foot can be understood as the outcome of three variables; true vertical depth, proppant intensity and project size (or the number of wells per pad). In this simple model, proppant intensity could be substituted with frac fluid intensity, but as these two metrics typically exhibit a strong correlation, a thorough analysis need only factor in one of these costs. A more complex model could account for both of these variables by using the proppant to fluid ratio (known as proppant concentration) rather than including both variables simultaneously.
When cost drivers are compared between different basins, the variability in cost per foot across basins becomes easy to understand. For example, wells in Anadarko (primarily in SCOOP & STACK) exhibit the highest average true vertical depth (TVD), highest proppant intensity and lowest average pad size. It follows, then, that these wells are more expensive than wells in all other basins. Meanwhile, the average well in Niobrara targets shallower landing zones, exhibits lower proppant intensity and is located on a pad with more than five wells on average. The combination of these factors results in the lowest cost per foot across all shale basins.
Using a linear model, Rystad Energy has estimated the direct impact of each cost driver on cost per foot, and cost per well for 2-mile laterals in 2018. All else being equal, targeting a 1,000’ shallower zone results in a cost reduction of $59 per foot, or $560,000 per 2-mile well. Reduction of proppant intensity by 1,000 pounds per foot generates cost savings of $49 per foot and $460,000 per well. Pad size is an important driver too; switching from a two-well pad to a four-well pad results in an average $800,000 cost savings per well.
Zooming into the Permian Basin, an average 2-mile well in 2018 incurred costs of around $7.9 million (although it was notably more expensive on the Delaware side of the basin than in Midland). Based on the mix of currently outstanding permits and capital guidance, we expect activity to shift toward slightly deeper zones in 2019, while a positive tendency in proppant intensity emerges, triggered by greater availability of in-basin sand and rapid adoption. For this reason, we anticipate the direct impact of proppant on costs per foot will decline from $49 to $33.
Finally, Rystad Energy expects average pad size to increase from 2.6 wells in 2018 to 3.1 in 2019, nudged along by increased penetration of large-scale projects. Considering these factors, we foresee that the average cost per 2-mile lateral well will decline by approximately 6% in the Permian in 2019.
While capital guidance for US E&Ps (excluding majors) points to downward trending activity in 2019, “capital” itself is a misleading indicator of activity. The industry is on-track to achieve significant capital efficiency gains this year through an increasing share of long-laterals, large-scale projects and in-basin sand adoption. Ultimately, new production per dollar spent is expected to increase this year, resulting in an all-time high of new production additions – in the Permian and beyond.