Permian Basin 2017

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PERMIAN BASIN: PRODUCTION FORECAST 82 | November 2017 | in relation to other basins and fields in the U.S. is shown in Figure 16. Although there are many fields across the various basins in the U.S. that yield a 15% rate of return below $60/bbl, the Permian Basin dominates the stack. Overall Permian production is expected to grow considerably in the coming years as shown in Figure 17. Crude oil production is expected to grow 723 Mbbl/d in the Permian from December 2016 to December 2017. In five years, by December 2021, Permian Basin production will reach 4.43 MMbbl/d, which is 1.89 MMbbl/d higher than the current 2.54 MMbbl/d of production. The Delaware Basin will contribute 192 Mbbl/d of the growth from December 2016 to December 2017. By December 2021, the Delaware Basin will be produc- ing 1.68 MMbbl/d, up 960 Mbbl/d from current levels of 1.68 MMbbl/d. The Midland Basin, on the other hand, is forecasted to grow 303 Mbbl/d from December 2016 to December 2017. Midland Basin production will reach 1.68 MMbbl/d by December 2021, up 1.07 MMbbl/d from current level of 724 Mbbl/d. These forecasts could be conservative as per the efficiency gains, which are confirmed by the year-over-year growth observed in the vintage type curves (Figures 5 and 6). However, the infrastruc- ture concerns will place a lid on how much crude oil production can really grow. The rapid growth in crude oil production may outpace infrastructure additions. This could lead to periods where crude oil differentials in the Perm- ian Basin to the Cushing WTI benchmark may blow out due to the inability to deliver the crude oil to market. As shown in Figure 18, the crude oil pro- duction forecast currently requires all known take- away projects be completed on time for there to be no disturbance in getting Permian Basin crude oil supply to market in 2017. During the latter part of 2018, Figure 18 shows that should the production forecast materialize rail capacity would be necessary to evacuate all crude oil volumes to demand cen- ters. Utilizing rail, which is a more expensive form of transportation, would cause differentials to the wellhead to be deeply discounted to benchmark pricing for operators that have no other means of transport. Unless additional takeaway capacity can be added during this time period, the need to utilize other forms of transport could lead certain operators to change drilling plans due to deterio- rating wellhead economics or to defer completions until additional capacity is built (which would lead to an increase in DUC well inventory in the Perm- ian Basin for this period of time). Operators in the Delaware and Midland basins tend to target crude oil but natural gas prices do provide a boost to operator economics. Given the uptick in drilling, gross gas production will also continue to grow in the Permian as per Figure 19. Gross gas production is expected to grow 1.34 Bcf/d from December 2016 to December 2017. By 2021, Permian Basin production will reach 13.15 Bcf/d, up 5.92 Bcf/d from current levels. The Delaware Basin will make up 0.44 Bcf/d of the growth in gross gas production between December 2016 and Decem- ber 2017. Over the next five years, Delaware Basin gross gas production will grow 3.85 Bcf/d from 2.94 Bcf/d to 6.79 Bcf/d. The Midland Basin is forecasted to contribute 419 Mbbl/d of the December 2016 to December 2017 gross gas growth. By the end of 2021, production from the Midland Basin is fore- casted to grow 1.34 Bcf/d to 4.09 Bcf/d from 2.75 Bcf/d currently. Areas like the Alpine High, where development mode has yet to start, will provide fur- ther upside to these forecasts along with efficiency gains. Any slowdown in the pace of production due to infrastructure constraints for crude oil may hold back the production of gross gas as well. Gross gas will have to be processed at processing plants near the producing areas. Due to the eco- nomics of gathering and processing gross gas, the need for additional processing capacity may arise in the basin if production shifts away from currently active areas towards areas such as the Alpine High, where infrastructure is currently lacking. NGLs will evacuate the basin towards Mont Belvieu. The processed, dry gas will head to demand centers or export terminals across the Gulf Coast, Midcon- tinent and Mexico. Although capacity exists for dry gas to head in the various different directions, demand trends are going to play a large part in how the Permian Basin gas makes its way to market. n Phillip Dunning is manager, Consulting Services, and Sarp Ozkan is manager, Energy Analytics, for Drillinginfo.

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