Drillinginfo DPR - EnverusDrillinginfo Drilling Productivity Report (Drillinginfo DPR) uses DI's datasets and some key changes to methodology to provide an alternative short-term forecast

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Drillinginfo DPR

FundamentalEdge | January 2018


Contents

What is the Drillinginfo Drilling Productivity Report? 3

Drillinginfo DPR – Key Takeaways 4

Anadarko 5

Appalachia 8

Bakken 11

Eagle Ford 14

Haynesville 17

Niobrara 20

Permian 23

Methodology Notes 26

Drillinginfo DPR © 2018 Drillinginfo, Inc. All rights reserved. All brand names and trademarks are the properties of their respective companies. 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 EIA.

➢ The EIA'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 (Drillinginfo DPR) 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 EIA 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 DrillingInfo uses to cut off historical observed data versus the forecast is generally more recent than the EIA 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: EIA 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. EIA 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.


Key Takeaways

➢ Williston basin production is expected to grow in line with recent increases. DI’s production forecast differs from the EIA’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 EIA.

▪ 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 EIA 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 EIA estimates due to recent well results, but expects gas production to rebound following a temporary decline back in May 2017.

➢ The Permian is the most active basin in the country. DI and EIA 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 2017. Although the DI forecast seems lower than that of the EIA, 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 EIA’s, meaning that the declining trajectory seen in the basin since 2015 will continue according to DI. The oil production forecasts from DI for these two basins run contrary to the EIA forecasts’ sudden decline reversals.


0

50

100

150

200

250

Active R

igs &

Well

Sta

rts

Active Rigs (H) Well Starts (H)

Anadarko – Active Rigs and Well Starts

CHART 1

Active Rigs and Well Starts

Source: DI Rig Analytics


Anadarko – Vintage Type Curves

0

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300

350

Oil (

Bb

l/d

)

Months on Production

2012 2013 2014 2015 2016 2017

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800

1,000

1,200

1,400

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1,800

Ga

s (M

cf/d

)


2012 2013 2014 2015 2016 2017

Gross Gas Vintage CurveCrude Oil Vintage Curve

CHART 2 CHART 3

Source: DI Web App


Anadarko - Production Forecast

Source: DI ProdCast

0.30

0.35

0.40

0.45

0.50

0.55

Cru

de O

il P

roduction (

MM

Bbl/d)

EIA DrillingInfo

4.0

4.5

5.0

5.5

6.0

6.5

Gro

ss G

as P

roduction (

Bcf/

d)

EIA DrillingInfo

Gross Natural Gas ProductionCrude Production

CHART 4 CHART 5


Appalachia – Active Rigs and Well Starts

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250

Active R

igs &

Well

Sta

rts


CHART 6




Appalachia – Vintage Type Curves

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30

40

50

60

Oil

(Bbl/d)


2012 2013 2014 2015 2016 2017

0

2,000

4,000

6,000

8,000

10,000

12,000

Gas (

Mcf/

d)


2012 2013 2014 2015 2016 2017


CHART 7 CHART 8

Source: DI Web App


Appalachia – Production Forecast

Source: DI ProdCast

0.00

0.02

0.04

0.06

0.08

0.10

0.12

0.14

Cru

de O

il P

roduction (

MM

Bbl/d)

EIA DrillingInfo

9

11

13

15

17

19

21

23

25

27

29

Gro

ss G

as P

roduction (

Bcf/

d)

EIA DrillingInfo


CHART 9 CHART 10


0

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300

Active R

igs &

Well

Sta

rts


Bakken – Active Rigs and Well Starts

CHART 11




Bakken – Vintage Type Curves

0

100

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500

600

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800

900

1,000

Oil

(Bbl/d)


2012 2013 2014 2015 2016 2017

0

200

400

600

800

1,000

1,200

Gas (

Mcf/

d)


2012 2013 2014 2015 2016 2017


CHART 12 CHART 13

Source: DI Web App


Bakken – Production Forecast

Source: DI ProdCast

0.80

0.85

0.90

0.95

1.00

1.05

1.10

1.15

1.20

1.25

1.30

Cru

de O

il P

roduction (

MM

Bbl/d)

EIA DrillingInfo


0.50

0.70

0.90

1.10

1.30

1.50

1.70

1.90

2.10

2.30

Gro

ss G

as P

roduction (

Bcf/

d)

EIA DrillingInfo

CHART 14 CHART 15


Eagle Ford – Active Rigs and Well Starts

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350

Active R

igs &

Well

Sta

rts


CHART 16




Eagle Ford – Vintage Type Curves

0

100

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500

600

Oil

(Bbl/d)


2012 2013 2014 2015 2016 2017

0

500

1,000

1,500

2,000

2,500

Gas (

Mcf/

d)


2012 2013 2014 2015 2016 2017


CHART 17 CHART 18

Source: DI Web App


Eagle Ford – Production Forecast

Source: DI ProdCast

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

1.8

2.0

Cru

de O

il P

roduction (

MM

Bbl/d)

EIA DrillingInfo

4.0

4.5

5.0

5.5

6.0

6.5

7.0

7.5

8.0

Gro

ss G

as P

roduction (

Bcf/

d)

EIA DrillingInfo


CHART 19 CHART 20


Haynesville – Active Rigs and Well Starts

0

10

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70

Active R

igs &

Well

Sta

rts


CHART 21




Haynesville – Vintage Type Curves

0

5

10

15

20

25

Oil

(Bbl/d)


2012 2013 2014 2015 2016 2017

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

Gas (

Mcf/

d)


2012 2013 2014 2015 2016 2017


CHART 22 CHART 23

Source: DI Web App


Haynesville – Production Forecast

Source: DI ProdCast

0.00

0.01

0.02

0.03

0.04

0.05

0.06

0.07

Cru

de O

il P

roduction (

MM

Bbl/d)

EIA DrillingInfo

5.0

5.5

6.0

6.5

7.0

7.5

8.0

8.5

Gro

ss G

as P

roduction (

Bcf/

d)

EIA DrillingInfo


CHART 24 CHART 25


Niobrara – Active Rigs and Well Starts

0

20

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80

100

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140

160

180

Active R

igs &

Well

Sta

rts


CHART 26




Niobrara – Vintage Type Curves

0

50

100

150

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250

300

350

Oil

(Bbl/d)


2012 2013 2014 2015 2016 2017

0

200

400

600

800

1,000

1,200

1,400

1,600

Gas (

Mcf/

d)


2012 2013 2014 2015 2016 2017


CHART 27 CHART 28

Source: DI Web App


Niobrara – Production Forecast

Source: DI ProdCast

0.20

0.25

0.30

0.35

0.40

0.45

0.50

0.55

0.60

Cru

de O

il P

roduction (

MM

Bbl/d)

EIA DrillingInfo

3.8

4.0

4.2

4.4

4.6

4.8

5.0

Gro

ss G

as P

roduction (

Bcf/

d)

EIA DrillingInfo


CHART 29 CHART 30


Permian – Active Rigs and Well Starts

0

50

100

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250

300

350

400

450

500

Active R

igs &

Well

Sta

rts


CHART 31




Permian – Vintage Type Curves

0

100

200

300

400

500

600

Oil

(Bbl/d)


2012 2013 2014 2015 2016 2017

0

200

400

600

800

1,000

1,200

Gas (

Mcf/

d)


2012 2013 2014 2015 2016 2017


CHART 32 CHART 33

Source: DI Web App


Permian – Production Forecast

Source: DI ProdCast

1.0

1.5

2.0

2.5

3.0

3.5

Cru

de O

il P

roduction (

MM

Bbl/d)

EIA DrillingInfo

4

5

6

7

8

9

10

11

Gro

ss G

as P

roduction (

Bcf/

d)

EIA DrillingInfo


CHART 34 CHART 35


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 EIA. The EIA'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 2014 and well starts data starts from March 2014. Only data from months that have been completed are employed in the analysis. The key differences between the EIA 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 2007. 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 EIA also uses DI as the source for historical production data. The key difference between the EIA 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 EIA 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 Genscapeis 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 EIA 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.


Contact

Drillinginfo, Inc.1221 W Mineral Ave Suite 101Littleton, CO 80120

Market Intelligence Team Direct [email protected] ext 3

Additional Publications

Documents

Drillinginfo DPR - EnverusDrillinginfo Drilling Productivity Report (Drillinginfo DPR) uses DI's datasets and some key changes to methodology to provide an alternative short-term forecast