Drillinginfo DPR. FundamentalEdge January learn more at drillinginfo.com

Transcription

1 FundamentalEdge January 218 learn more at drillinginfo.com

2 Contents What is the Drillinginfo Drilling Productivity Report? 3 Key Takeaways 4 Anadarko 5 Appalachia 8 Bakken 11 Eagle Ford 14 Haynesville 17 Niobrara 2 Permian 23 Methodology Notes 26

3 What is the Drilling Productivity Report? The purpose of the Drilling Productivity Report (DPR) is to give a short-term (three month) outlook for oil and gas production from the major shale basins in the country. The major shale basins are defined as Anadarko, Appalachia, Eagle Ford, Haynesville, Niobrara, Permian, and Williston. The counties included in the different basin definitions correspond to the same geographic extents as the. The 's DPR was initiated to provide guidance on short-term production given the lack of up-to-date production information from the state reporting agencies using several different data sources including Drillinginfo (DI). The Drillinginfo Drilling Productivity Report () uses DI's datasets and some key changes to methodology to provide an alternative short-term forecast for the market's consumption. Key differences between and DI s DPR: Historical production: both source DI s historical production. However, the determination of the completeness of the state data vs. when projections start varies between the two (e.g. the date that uses to cut off historical observed data versus the forecast is generally more recent than the DPR forecast starting date). Additionally, DI does not employ a natural gas flow data driven adjustment to historical volumes, instead taking the state reported volumes as the defacto production level. We do this because the state reported volumes are used for the purpose of calculating royalty and tax liabilities, and therefore should be the most accurate data available. Rig counts, wells drilled, and wells completed: uses Baker Hughes while DI incorporates proprietary data from GPS tracking units and publicly reported information to more accurately monitor oil and gas drilling rig movements. Incremental production: DI s calculation uses a vintage type curve (from wells drilled in the last 12 months) from reported actual well results. calculates incremental volumes per rig by diving production from new wells by the rig count from the most recent month. The use of a vintage type curve allows for the use of a completion count instead of a rig count. 3

4 Key Takeaways Williston basin production is expected to grow in line with recent increases. DI s production forecast differs from the s due to the lower production actuals reported from the states for the month of September. Anadarko basin production has been growing at a rapid rate recently due to the increased rig activity in the STACK and SCOOP due to the great economics in the area. The pace of the growth is somewhat muted in the DI forecast due to a combination of different factors: DI uses a later start date for its forecast, given that the reporting well counts in the area support a complete production data set through June; our forecast start date is more recent than. The oil production is increasing in the area given the emphasis placed on the STACK. The STACK is an oil directed play while the SCOOP is more gas heavy. In the DI forecast, the shift away from the gas producing areas is highlighted by the flatter gas production profile of the recently producing wells. The greater Niobrara area is expected to continue its growth trajectory, and that trajectory is slower than the DPR trend. Although efficiency gains have played a large role in the upward production profile in the basin, DI believes crude oil production will trend below estimates due to recent well results, but expects gas production to rebound following a temporary decline back in May 217. The Permian is the most active basin in the country. DI and both foresee a steep upward trend in production, but DI s higher gas production forecast seems to support the reasons behind the higher basis differential at Waha. There is one key factor to keep in mind about future Permian growth: The DUC count (wells drilled and not completed for more than 6 months) in the Permian has continued to grow over the last several months and this is due to the inability of available completions crews to keep up with the pace of drilling in the area. This will almost certainly lead to a lower completion/well start ratio in the short-term, meaning that the forecast may be too optimistic. DI forecasts a lower Eagle Ford production level due to the impact that Hurricane Harvey had on production in August 217. Although the DI forecast seems lower than that of the, should production recover further in revised state data, the expected production levels moving forward would follow a similar trajectory for crude oil. The natural gas production expectations are higher in the longer term in DI s forecast, since gas productivity has increased as active operators with a focus on the Eagle Ford have focused their activity more to the southwest, gassier portion of the basin. The growth trajectory of the two natural gas directed basins, Appalachia & Haynesville, both show similar upward trends in gross gas production. However, the per well oil productivity assumed in Appalachia has changed significantly since the last reported crude oil data from the states and activity has focused on the dry parts of the basin due to lower oil prices. Thus, the declining crude oil production trajectory in Appalachia is expected to continue. Additionally, the Haynesville will continue to decline crude oil production as the per well productivity is below that of the s, meaning that the declining trajectory seen in the basin since 215 will continue according to DI. The oil production forecasts from DI for these two basins run contrary to the forecasts sudden decline reversals. 4

5 Active Rigs & Well Starts Anadarko Active Rigs and Well Starts CHART 1 Active Rigs and Well Starts Active Rigs (H) Well Starts (H) Source: DI Rig Analytics 5

6 Oil (Bbl/d) Gas (Mcf/d) Anadarko Vintage Type Curves CHART 2 CHART 3 Crude Oil Vintage Curve Gross Gas Vintage Curve ,8 1,6 1,4 1, 1, Source: DI Web App 6

7 Crude Oil Production (MMBbl/d) Gross Gas Production (Bcf/d) Anadarko - Production Forecast CHART 4 CHART 5 Crude Production Gross Natural Gas Production Source: DI ProdCast 7

8 Active Rigs & Well Starts Appalachia Active Rigs and Well Starts CHART 6 Active Rigs and Well Starts Active Rigs (H) Well Starts (H) Source: DI Rig Analytics 8

9 Oil (Bbl/d) Gas (Mcf/d) Appalachia Vintage Type Curves CHART 7 CHART 8 Crude Oil Vintage Curve Gross Gas Vintage Curve 6 12, 5 1, 4 8, 3 6, 2 4, 1 2, Source: DI Web App 9

10 Crude Oil Production (MMBbl/d) Gross Gas Production (Bcf/d) Appalachia Production Forecast CHART 9 CHART 1 Crude Production Gross Natural Gas Production Source: DI ProdCast 1

11 Active Rigs & Well Starts Bakken Active Rigs and Well Starts CHART 11 Active Rigs and Well Starts Active Rigs (H) Well Starts (H) Source: DI Rig Analytics 11

12 Oil (Bbl/d) Gas (Mcf/d) Bakken Vintage Type Curves CHART 12 CHART 13 Crude Oil Vintage Curve Gross Gas Vintage Curve 1, , 1, Source: DI Web App 12

13 Crude Oil Production (MMBbl/d) Gross Gas Production (Bcf/d) Bakken Production Forecast CHART 14 CHART 15 Crude Production Gross Natural Gas Production Source: DI ProdCast 13

14 Active Rigs & Well Starts Eagle Ford Active Rigs and Well Starts CHART 16 Active Rigs and Well Starts Active Rigs (H) Well Starts (H) Source: DI Rig Analytics 14

15 Oil (Bbl/d) Gas (Mcf/d) Eagle Ford Vintage Type Curves CHART 17 CHART 18 Crude Oil Vintage Curve Gross Gas Vintage Curve 6 2,5 5 2, 4 1,5 3 1, Source: DI Web App 15

16 Crude Oil Production (MMBbl/d) Gross Gas Production (Bcf/d) Eagle Ford Production Forecast CHART 19 CHART 2 Crude Production Gross Natural Gas Production Source: DI ProdCast 16

17 Active Rigs & Well Starts Haynesville Active Rigs and Well Starts CHART 21 Active Rigs and Well Starts Active Rigs (H) Well Starts (H) Source: DI Rig Analytics 17

18 Oil (Bbl/d) Gas (Mcf/d) Haynesville Vintage Type Curves CHART 22 CHART 23 Crude Oil Vintage Curve Gross Gas Vintage Curve 25 9, 8, , 6, 5, 4, 3, 2, 1, Source: DI Web App 18

19 Crude Oil Production (MMBbl/d) Gross Gas Production (Bcf/d) Haynesville Production Forecast CHART 24 CHART 25 Crude Production Gross Natural Gas Production Source: DI ProdCast 19

20 Active Rigs & Well Starts Niobrara Active Rigs and Well Starts CHART 26 Active Rigs and Well Starts Active Rigs (H) Well Starts (H) Source: DI Rig Analytics 2

21 Oil (Bbl/d) Gas (Mcf/d) Niobrara Vintage Type Curves CHART 27 CHART 28 Crude Oil Vintage Curve Gross Gas Vintage Curve 35 1, ,4 1, 1, Source: DI Web App 21

22 Crude Oil Production (MMBbl/d) Gross Gas Production (Bcf/d) Niobrara Production Forecast CHART 29 CHART 3 Crude Production Gross Natural Gas Production Source: DI ProdCast 22

23 Active Rigs & Well Starts Permian Active Rigs and Well Starts CHART 31 Active Rigs and Well Starts Active Rigs (H) Well Starts (H) Source: DI Rig Analytics 23

24 Oil (Bbl/d) Gas (Mcf/d) Permian Vintage Type Curves CHART 32 CHART 33 Crude Oil Vintage Curve Gross Gas Vintage Curve 6 1, 5 1, Source: DI Web App 24

25 Crude Oil Production (MMBbl/d) Gross Gas Production (Bcf/d) Permian Production Forecast CHART 34 CHART 35 Crude Production Gross Natural Gas Production Source: DI ProdCast 25

26 DRILLINGINFO, INC. (DI) DRILLING PRODUCTIVITY REPORT (DPR) The purpose of the DPR is to give a short-term (three month) outlook for oil and gas production from the major shale basins in the country. The major shale basins are defined as Anadarko, Appalachia, Eagle Ford, Haynesville, Niobrara, Permian, and Williston. The counties included in the different basin definitions can be found in the data attachment to this report and correspond to the same geographic extents as the. The 's DPR was initiated to provide guidance on short-term production given the lack of up-to-date production information from the state reporting agencies using several different data sources including DI. The DI DPR uses DI's datasets and some key changes to methodology to provide an alternative short-term forecast for the market's consumption. The DI DPR uses DI Rig Analytics to obtain key inputs regarding rig counts and wells drilled. Using monthly active rig counts and well starts, a well starts/active rig/month is calculated for the shale basin for both horizontal wells and vertical/directional wells. The latest six month average for active rigs is used as the count going forward for the purposes of the forecast. The latest six month average for well starts/active rig/month is used as the rate going forward for the purposes of the forecast. Permit type Deepen Below, Deepen Within, Field Transfer, Plug Back, Reclass, Recompletion, & Reenter are not considered. Product description Carbon Dioxide, Disposal, Enhanced Recovery, Gas Storage, Injector, Monitoring Well, Permitted Carbon Dioxide, Permitted Disposal, Permitted Injection, Permitted Water Supply, Salt, Salt Water Disposal, Stratigraphic/Core Test, Water are not considered. If Drilling trajectory is listed as Unknown, the drilling trajectory is assumed to be Horizontal. A three month lag is assumed for the well start to completion lag for horizontal wells. A two month lag is assumed for the well start to completion lag for vertical wells. Active rigs data starts from June 214 and well starts data starts from March 214. Only data from months that have been completed are employed in the analysis. The key differences between the and DI DPRs regarding the rig counts, wells drilled, and wells completed is the use of DI's rig count vs. Baker Hughes', a count of well starts from DI's more detailed rig activity data set vs. an approximation through modeling, and a three month la in DI's DPR for horizontal wells between well start and completion vs. two months. DI's state well-level data is used as the source for historical production for the shale basin from both horizontal and vertical/directional wells. The historical data starts in January 7. If Drill type is listed as Unknown, the drill type is assumed to be Horizontal. DI makes a determination as to the completeness of state data using both the volumes and the count of wells reporting for the shale basin. The also uses DI as the source for historical production data. The key difference between the and DI DPRs regarding historical production will be the determination of the completeness of the state data vs. when projections start. Additionally, DI does not employ a natural gas flow data driven adjustment to historical volumes, instead taking the state reported volumes as the defacto production level. Historical production from active wells is assumed to decline at a certain rate in the shale basin for both horizontal and vertical/directional wells, constituting the PDP volumes starting from the last month of complete state data. The declines are calculated by fitting a decline curve to every well within every vintage year by drilling trajectory. The calculated decline rates for both horizontal and vertical/directional wells is applied to the last month of complete historical production data to calculate PDP volumes for the shale basin. The decline rates are calculated using DI ProdCast. The key difference between the and DI DPRs regarding the PDP volumes is that declines are calculated from a well-level up calculation of PDP volumes and the resulting decline rate over the duration of the forecast vs. a model that estimates monthly decline rate from the historical decline rate. Historical production data from Appalachia is lagged further than most other areas. Thus, natural gas flow data from Genscape is used to approximate gross gas production volumes using a ratio from the last year of complete historical production data from the state vs. the flow data from the same area. This allows for a more up to date starting point for natural gas production forecasts in Appalachia, ensuring a more accurate short-term outlook. This methodology, however, limits the availability of the data granularity for Appalachia. Incremental volumes from wells completed after the state data ends are calculated using a vintage type curve for both horizontal and vertical/directional wells that have started production in the basin in the last 12 months. Should there be a sample size issue or a lack of state data, DI exercises discretion in terms of extending the time period or set of wells that are considered. The key differences between the and DI DPRs from an incremental production calculation perspective is the use of a vintage type curve from wells actual well results vs. the use of an estimation of incremental volumes per rig given the most recent month of production. The use of a vintage type curve allows for the use of a completion count vs. a rig count and the aggregation of volumes given the combination of well completions through time and vintage type curve declines. The DI DPR data deliverable provides the active rig count, well starts, well starts/active rig, historical production, PDP, and incremental production by month and trajectory where data is available for both commodities.

27 Contact Market Intelligence Team Direct ext 3 Drillinginfo, Inc W Mineral Ave Suite 11 Littleton, CO 812 Additional Publications