US cost inflation: the comeback
After three years of sharp declines, costs are rising again on higher drilling activity in America's tight oil patch
Since late 2014, North American shale producers have witnessed a significant decrease in wellhead breakeven prices. The main shale oil plays in the US saw a 20% year-on-year decline in 2015 and a further 29% fall in 2016. While a reduction in unit prices has been the main driver in lower breakevens, efficiency improvements and acreage high grading have also played their part. Rystad Energy research indicates that unit price and lease-operating expense (LOE) trends have contributed to about 57% of the reduction in breakeven prices, while acreage high grading and efficiency gains contributed to 18% and 25%, respectively. While unit prices, LOE and acreage high grading are all cyclical components that tend to vary in line with oil and gas market volatility, well productivity and drilling and completion (D&C) efficiency gains represent more structural components, which are led by, among other things, technological improvements.
Many large service providers have guided an increase in the more cyclical components for 2017; in fact, all major proppant providers reported increased pricing starting in Q4 of 2016. Proppant, which is typically sand or miniscule ceramic materials employed during and/or following a fracturing treatment, is one of the biggest drivers behind well completion costs.
FairmountSantrol, a major proppant provider, reported higher pricing in their proppant services in Q1 2017, during which sales volumes increased by 13% to 2.1m tonnes and revenues increased by 24% to $141m. This implies a 6.6% quarter-on-quarter price increase per tonne of proppant. Other major service providers, such as Keane Group, also reported a sharp increase in revenue per active frack spread in the first quarter.
Several producers also incorporated higher cost inflation assumptions in their first-quarter presentations compared to what they laid out late last year. Noble Energy, a large operator with a diversified portfolio of operations in the Niobrara, Eagle Ford, Marcellus and Permian Delaware shale plays, now signals 10-15% higher service costs. Murphy Oil predicts a worst-case scenario of 30% increased fracking costs in its US operations, which are highly exposed to the Eagle Ford shale play, while seeing continued efficiency gains in drilling. The largest operator in Permian Midland—Pioneer Natural Resources—also assumes 10-15% cost inflation in some areas but expects net cost inflation of 5% for aggregate operations. Pioneer also expects operational efficiencies, including vertical integration and productivity gains, to partially offset 2017 cost inflation. In contrast, EOG Resources guides a cost reduction for 2017 and is reportedly on track to reach this reduction. Noteworthy, however, is that EOG reported a depletion in its drilled but uncompleted wells (DUCs) last year and plans to build additional DUC inventory in 2017, implying that operations won't be affected by the inflation now seen across well fracturing and completion activities.
Most E&P firms continue to drive down operating costs, with some minor exceptions. Chesapeake Energy, a major gas producer with a diversified portfolio of operations in oil areas like Eagle Ford, Mid-Continent Stack, Mississippian Lime and the Utica, Haynesville and Marcellus gas plays, reported its first-quarter operating expenses per barrel of oil equivalent at the high end of its guidance for 2017, although these were explained by increased general and administrative (G&A) expenses. Pioneer Natural Resources witnessed a 5% quarter-on-quarter increase in Q1 operating expenses per boe and flat development of LOE/boe. Concho Resources, another operator with a presence in Permian Delaware and Midland, also guides that operating expenses per boe will be down for 2017, although Q1 was the second consecutive quarter of increasing LOE/boe, offset by decreasing G&A/boe.
Recent market data also suggest that operators are beginning to drill on higher-breakeven acreage, which will start to offset previous breakeven reductions from acreage high grading (see Figure 1). To capture the effect of acreage high and low grading, Rystad Energy categorises acreage as either "core" or "non-core". Core acreage is defined as the 0-50th percentile of the distribution of average horizontal-well breakeven prices within a cluster of wells, while non-core acreage accounts for the remaining percentiles. Each cluster in each individual shale play consists of horizontal wells within an area of 100 square kms. Distribution is analysed at operator level for all operators with more than 150 wells in a play, while remaining wells are attributed to minor operators and analysed together.
Figure 2 shows quarterly developments (2014-17) for wells spudded in the Eagle Ford, Bakken, Permian Midland and Permian Delaware shale plays, categorised by acreage grading. Core acreage accounted for 60% of all new wells in 2014 rising to 80% by 2016, underlining a clear high-grading trend. As seen in Figure 1, breakeven prices fell by approximately 43% over the same period, with strong covariation between overall wellhead-breakeven prices and core/non-core grading trends. Such covariation is visible in Figure 3, which compares the monthly development of average wellhead breakeven prices in the main shale oil plays with the share of drilling on core acreage. Operators' preference for core acreage since 2014 coincides with lower breakeven prices.
Nevertheless, the number of spudded wells on non-core acreage began increasing relative to core acreage spuds in Q2 2016 (see Figure 2). This trend is more apparent in Figure 4, in which wells are rebased to 100 in both first quarter 2014 and second quarter 2016. While non-core spuds have increased relative to core wells since the second quarter of 2016, the opposite trend is apparent from Q1 2014 to the second quarter of 2016. Core spuds have continued to decrease during the first two months of 2017, with a concomitant increase in breakeven prices over the same period as seen in Figure 3 and 4.
The data all suggest an increase in well costs for shale producers in 2017. This increase is driven mainly by higher prices in the service segment, specifically with regards to well-completion operations. Rystad Energy NASWellCube data also indicate that operators are not continuing the high-grading trends observed over 2014-16. So far in 2017, operators have increased drilling on acreage with comparatively higher breakeven prices. Considering the increase in the service-segment unit prices and the relative decline in acreage high grading, increased breakeven prices in US shale are highly likely throughout 2017. According to Rystad Energy data, all major US oil shale plays are expected to show breakeven increases this year (Figure 5). Aggregate breakevens are estimated to see a 7% increase.
Robin Helander is oil and gas analyst at Rystad Energy