Unraveling the Oil Conundrum: Productivity Improvements and Cost Declines in the U.S. Shale Oil Industry, Accessible Data
PrintAccessible version of figures
Figure 1. Rig Counts and Wells per Rig, Bakken Region.
Source: U.S. Energy Information Administration (EIA), Drilling Productivity Report, March 2016
This figure plots the rig count (blue line) and the number of wells per rig (red line) for the Bakken region. The data come from the Drilling Productivity Report, March 2016. Movements in the rig count followed closely the path of oil prices: the number of rigs started declining in late 2014 and it is down by about 60 percent since its peak. Looking at the same period, however, the number of wells drilled per rig in a given month has risen steadily since 2011, and it accelerated further after the rig count began falling. By early 2016 each rig could drill more than 1 and 1/2 wells. This change reflects the productivity improvements in drilling, such as pad drilling technology, an appliance that allows each rig to drill multiple wells from the same location without the need for disassembly and reassembly.
Figure 2. Average Well Decline Curve by Cohort.
Source: Authors' calculation from Dept. of Mineral Resources, North Dakota
Note: Average well decline curves for Bakken.
This figure shows the lifecycle production of an average well for a given cohort in the Bakken region. For example, we show in blue the lifecycle production of an average well that has come online in 2015. The data are from the Dept. of Mineral Resources of North Dakota. Increased and more efficient use of water, sand, and other proppants in the fracking process has enhanced the productivity of oil wells, particularly early in the well lifecycle. Production during the first month of operation increased for wells of more recent cohorts; initial production in 2015 exactly doubled with respect to wells that started producing in 2007. More recent cohorts also display larger production rates at successive months of operations. While innovations in fracking technology are primarily thought to shift production forward in the well lifecycle (rather than to increase total lifetime output), well-level data suggest that output in later-producing months has actually increased in recent years.
Figure 3. Well Decline, Controlling for Well Size.
This figure plots the differential changes in output along the lifecycle of an average well from 2015 with respect to 2007 (our baseline year). Using well-level data from the Dept. of Mineral Resources of North Dakota, we regress well-level output on a series of monthly indicators that are distinct for each cohort year. The blue line shows the 2015 well-decline coefficients, and the shaded blue area represents the associated 95% confidence interval. The grey line shows similar estimates after controlling for a measure of well size in the regression, specifically, the lateral distance of well that undergoes perforations in preparation for fracking. Because of the large overlap between the confidence intervals associated with each estimate, the adjusted coefficients are not largely different from the raw coefficients without the well-size adjustment. This analysis points to innovations apart from increases in well size as the main contributing factors to the well output gains.
Figure 4. Decomposition of Production Changes.
Figure 4 decomposes the change in monthly oil production from all regions into the positive contribution of new wells (the blue line) and the negative contribution from existing wells (the red line), the latter being almost invariably negative as a result of the natural lifecycle declines in well production. Consequently, aggregate production increases whenever output from new wells (the blue line) exceeds the natural output declines among existing wells (the red line). Despite productivity improvements, output from new wells began falling in mid-2015 as the number of well completions dropped significantly. This pushed the positive contribution from new wells below the negative contribution from existing wells, resulting in aggregate production declines. The drag from existing well declines, however, peaked shortly thereafter, mitigating the fall in aggregate output. Completions of larger wells and productivity improvements among legacy wells have softened the negative pull from existing wells.
Source: Drilling Productivity Report, EIA, March 2016.
Figure 5. Rigs Needed for Flat Production.
Source: Drilling Productivity Report, EIA, March 2016.
This figure shows the number of rigs needed to maintain a constant production level, rigs needed for flat production (RNFP). The data are from the EIA’s Drilling Productivity Report, March 2016. The RNFP is constructed by calculating the number of new rigs necessary to offset observed declines from existing wells, using the prior month’s estimate of new production per rig. We compare the RNFP (in red) to the rig count (in blue). As rig efficiency has increased and legacy-well decline curves have shifted up, and as total production has gradually fallen, the RNFP has declined.
Figure 6. Cash Costs. Verbal Description.
Source: SEC filings and investor reports. 2015 results only reported through Q3. Weights based on barrels oil produced
Sum of operating costs, G&A expenses, and production taxes (excludes interest)
This figure plots cash costs reported by shale oil producers in SEC filings. Values for 2013 and 2014 correspond to annual (10-K) reports, and values for 2015 correspond to the first three quarters of 2015 (retrieved from 10-Q reports). Individual firms’ values are displayed as blue dots, and the production-weighted average is reported as a red line. A handful of extreme outliers are omitted from the scatter (but not from the average). The weighted average is flat at about $18 per barrel in 2013 and 2014 then falls to just under $14 per barrel in 2015. In 2013, values for individual producers range from about $12 per barrel to above $30 per barrel. The total range is largely unchanged in 2014, but most firms are clustered closer together. In 2015, the minimum value falls to under $9 per barrel, with a close formation of firms below $20 and a few outliers above that level.
Figure 7. Long-Cycle Breakeven Estimates. Verbal Description.
Source: Federal Reserve Bank of Kansas City firm survey, profitable price for drilling
This figure plots self-reported long-cycle breakevens from the FRB Kansas City energy surveys of 2014q3, 2015q1, and 2015q3. The red line shows the simple average across firms, which fell from almost $80 per barrel in 2014q3 to just over $60 per barrel in 2015q1 and 2015q3. The figure also shows the range of reported breakevens for each quarter (shown by blue bars indicating the space between minimum and maximum values). The breakevens range from about $55 to about $95 in 2014q3. In 2015q1, the range moves down and narrows, with breakevens ranging from about $45 to about $75. In 2015q1, the range tightens further with minimum and maximum values of $50 and $75, respectively.