the “shale revolution” - legacy.firstenergy.comlegacy.firstenergy.com/userfiles/hughes first...

The “Shale Revolution”

Myths and Realities

Energy Growth Conference

First Energy Capital

Toronto, Ontario

November 19, 2013

J. David Hughes

Global Sustainability Research Inc.

Post Carbon Institute

- The Shale Revolution and Conventional Wisdom

Points to be covered:

- SHALE (TIGHT) OIL – A look at the fundamentals with

examples from the Permian Basin, Bakken and Eagle

Ford

- Bakken and Eagle Ford production forecast

- SHALE GAS – A look at the fundamentals with

examples from the Haynesville and Marcellus (with a

quick look at LNG exports from Western Canada)

- IMPLICATIONS for long term energy sustainability

The Shale Revolution

• Began with the application of high-volume, multi-stage, hydraulic-

fracturing of shale for gas in the Barnett Field of eastern Texas.

• Now accounts for 40% of U.S. gas production.

• The technology was first applied to oil extraction in the Bakken

Field of Montana and North Dakota.

• Allowed a 50% increase in U.S. oil production reversing the long

standing decline from peak U.S. production in 1970.

• Nearly 35% of upstream investment in lower 48 exploration and

development will be applied to the Bakken and Eagle Ford tight oil

plays in 2013.

© Hughes GSR Inc, 2013

Conventional Wisdom

• The United States is on the verge of Energy Independence thanks

to the “SHALE REVOLUTION”.

• Shale Gas production will continue to grow for the foreseeable

future (2040 at least) and prices will remain below $4.50/mcf for

the next 10 years and below $6.00/mcf for the next 20 years.

• Shale Gas can replace very substantial amounts of oil for

transport and coal for electricity generation.

• The way is clear for U.S. LNG exports to monetize the shale

bounty. Large scale LNG exports of shale gas from Canada will

provide a bonanza.

• Tight Oil will allow U.S. production to exceed that of Saudi Arabia

and U.S. imports will shrink to zero.


0

5

10

15

20

25

30

1998 2000 2002 2004 2006 2008 2010 2012

Tri

llio

n C

ub

ic F

eet

per

Year

Year

Net LNG Imports Net Canadian Imports Dry Gas Production

U.S. Gas Production and Imports, 1998-2012

Dry Gas Production

Net Canadian Imports

Net LNG Imports

© Hughes GSR Inc, 2013 (data from EIA current to August, 2012)

0

10

20

30

40

50

60

70

80

2010 2011 2012 2013

Billi

on

Cu

bic

Feet

per

Day

Year

U.S. Dry Gas Production, 2010-2013

U.S. production plateau September 2012 - July 2013

(data from EIA Natural Gas Monthly, October, 2013, 3 month trailing moving average) © Hughes GSR Inc, 2013

0

5

10

15

20

25

30

35

2010 2015 2020 2025 2030 2035 2040

Tri

llio

n C

ub

ic F

eet

per

Year

Year

LNG Imports Canada Imports Shale Gas

Alaska Coalbed Methane Tight Gas

Associated Conventional Offshore

U.S. Natural Gas Supply Projection by Source, 2010-2040,

EIA Reference Case 2013

Shale Gas

50

% o

f 20

40

Pro

du

ctio

n

55% increase in

production by 2040

Tight Gas

Conventional

Offshore

Associated

Alaska

U.S. domestic consumption

(data from EIA Annual Energy Outlook 2013, Tables 13 and 14, http://www.eia.gov/forecasts/aeo/er/excel/yearbyyear.xlsx) © Hughes GSR Inc, 2013

http://www.eia.gov/forecasts/aeo/er/excel/yearbyyear.xlsx

0

5

10

15

20

25

30

35

0

3

6

9

12

15

18

21

1995 1999 2003 2007 2011 2015 2019 2023 2027 2031 2035 2039

An

nu

al G

as P

rod

uc

tion

(Trillio

n c

ub

ic fe

et)

Gas P

rice (

$U

S/m

cf)

Year

Russian Gas Price Indonesia LNG Gas Price in Japan U.S. Henry Hub Gas Price EIA Forecast U.S. Gas Price ($2011) Actual U.S. Gas Production EIA Forecast U.S. Gas Production

EIA Projections of Gas Price and U.S. Production

Compared to History, 1995-2040

© Hughes GSR Inc, 2012 (data from EIA Annual Energy Outlook 2013, EIA, 2012; International Monetary Fund)

0

500

1,000

1,500

2,000

2,500

2000 2002 2004 2006 2008 2010 2012

Oil

Gas

Gas

Oil

(data from Baker-Hughes, November, 2013) © Hughes GSR Inc, 2013

U.S. Rig Count, 2000-2013

0

5

10

15

20

25

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Billi

on

Cu

bic

Feet

per

Day

Year

Other

Austin Chalk

Bone Spring

Bossier

Antrim

Niobrara

Bakken

Woodford

Eagle Ford

Fayetteville

Marcellus

Barnett

Haynesville

U.S. Shale Gas Production by Play, 2000-2012

(data from Drillinginfo, September, 2012, fitted with 3 month centered moving average including data up to June, 2012)

Barnett Haynesville

40% of U.S. production


0

1

2

3

4

5

6

7

Billi

on

Cu

bic

Feet

per

Day

Shale Play

U.S. Shale Gas Production by Play – mid 2012

(data from DI Desktop, September, 2012, for production in most cases through May-June, 2012)

Top 3 Plays = 66% of Total



The Shale Play Life Cycle

• Discovery followed by leasing frenzy.

• Drilling boom follows to meet “held-by-production” lease

requirements.

• Sweet spots identified, targeted and drilled off.

• Gas production rises rapidly and is maintained for cash-flow

despite potentially uneconomic full-cycle costs.

• Sweet spots become saturated and well quality and field

production decline.

• Plays like the Haynesville become middle aged after just five

years.


0

500

1000

1500

2000

2500

3000

3500

4000

0

1

2

3

4

5

6

7

8

9

2006 2007 2008 2009 2010 2011 2012 2013

Nu

mb

er o

f Op

era

ting

Wells

G

as P

rod

uc

tio

n (

Bil

lio

n c

ub

ic f

eet

per

day)

Year

Gas Production

Number of Wells

Haynesville Gas Production and Number of

Operating Wells, 2006-2013

© Hughes GSR Inc, 2013 (data from DrillingInfo/HPDI, July, 2013, three month trailing moving average)

Peak January 2012

0

1000

2000

3000

4000

5000

6000

7000

8000

1 6 11 16 21 26 31 36 41 46

Gas P

rod

ucti

on

(T

ho

usan

d c

ub

ic f

eet

per

Day)

Months on Production

Haynesville Type Gas Well Decline Curve

(data from DrillingInfo/HPDI, March, 2013)

Yearly Declines

First year = 66%

Second year = 49%

Third year = 41%

Fourth year = 49%


0

500

1000

1500

2000

2500

3000

3500

4000

0

1

2

3

4

5

6

7

8

2007 2008 2009 2010 2011 2012

Nu

mb

er o

f Op

era

ting

pre

-2012 W

ells

G

as P

rod

ucti

on

(B

illi

on

cu

bic

feet

per

Day)

Year

Production from pre-2012 Wells

Number of pre-2012 Wells

Overall Field Decline for Haynesville Gas Production

based on Production Decline from pre-2012 Wells

Overall Field Decline = 47%

© Hughes GSR Inc, 2013 (data from DrillingInfo/HPDI, March, 2013)

0

500

1000

1500

2000

2500

3000

3500

0

500

1000

1500

2000

2500

3000

3500

4000

2008 2009 2010 2011 2012

Nu

mb

er o

f Wells

A

vera

ge

Pro

du

cti

on

per

Well

(T

ho

usan

d c

ub

ic f

eet

per

day)

Year

Average Production per Well

Number of Wells

Haynesville Average Production per Well


0

200

400

600

800

1000

1200

-4000

-3000

-2000

-1000

0

1000

2000

3000

4000

5000

2009 2010 2011 2012

An

nu

al N

um

ber o

f Wells

Ad

ded

A

nn

ual

Pro

du

cti

on

Ad

ded

per

Well

(T

ho

usan

d c

ub

ic f

eet

per

day)

Year

Yearly Production Added per Well

Yearly Wells Added

Haynesville Annual Production Added per New Well


Need 680 wells per year

to keep production flat

Haynesville Sweet Spot Well Footprint

1 mile


0

0.2

0.4

0.6

0.8

1

1.2

1.4

1.6

1.8

Pro

du

cti

on

(b

illi

on

cu

bic

feet

per

day)

County

Pennsylvania Marcellus Production By County


Top 2 counties = 46% of production



0

1000

2000

3000

4000

5000

6000

1 6 11 16 21 26 31 36

Gas P

rod

ucti

on

(M

cf

per

Day)


Bradford (24%)

Susquehanna (22%)

Lycoming (12%)

Greene (10%)

Tioga (10%)

Washington (9%)

Remaining 27 Counties (15%)

Type Decline Curves for Marcellus Horizontal Wells by County


0

0.5

1

1.5

2

2.5

3

3.5

4

4.5

5

Pro

du

cti

on

(b

illi

on

cu

bic

feet

per

day)

County

Remaining Well Life

First 3 years

Estimated Ultimate Recovery for Pennsylvania Marcellus

Horizontal Wells By County

62%-77% produced in first 3 years.

EIA EUR estimate of 1.56 bcf

underestimates best counties.


Well Footprint – Dimock, Susquehanna County, PA


1 Mile

0

1000

2000

3000

4000

5000

6000

7000

8000

1 6 11 16 21 26 31 36 41 46

Gas P

rod

ucti

on

(T

ho

usan

d c

ub

ic f

eet

per

Day)


Haynesville

Marcellus

Barnett

Fayetteville

Woodford

Type Gas Well Decline Curves for Top Five Shale Gas Plays

Constituting 80% of Shale Gas Production

(data from Drillinginfo, March, 2013)

3-Year Decline

Haynesville = 89%

Marcellus = 79%

Barnett = 79%

Fayetteville= 80%

Woodford = 77%


Average 3-Year

Decline = 84%

0

1

2

3

4

5

6

7

8

2008 2009 2010 2011 2012

Gas P

rod

ucti

on

(B

illi

on

cu

bic

feet

per

Day)

Year

Haynesville

Marcellus

Barnett

Fayetteville

Woodford

Overall Field Decline for Top Five Shale Gas Plays

based on Production Decline from pre-2012 Wells

Field Decline (per year)

Haynesville = 47%

Marcellus = 29%

Barnett = 28%

Fayetteville = 35%

Woodford = 44%

© Hughes GSR Inc, 2013 (data from Drillinginfo, March, 2013)

Average Field

Decline = 37%

0

1

2

3

4

5

6

7

8

9

2006 2007 2008 2009 2010 2011 2012 2013

Ga

s P

rod

uc

tio

n (

Bil

lio

n c

ub

ic f

eet

per

day)

Year

Barnett

Fayetteville

Woodford

Haynesville

PA Marcellus

WV Marcellus

Shale Gas Production from Top Five Plays Comprising 80%

of U.S. shale gas production, 2006 - 2013

© Hughes GSR Inc, 2013 (data from Drillinginfo, July, 2013, three month trailing moving average)

0

100

200

300

400

500

600

700

800

900

1,000

Feb, 11 Jun, 11 Oct, 11 Feb, 12 Jun, 12 Oct, 12 Feb, 13 Jun, 13 Oct, 13

Other

Marcellus

Barnett

Haynesville

Haynesville

Other


U.S. Gas Rig Count by Basin, 2011-2013

Barnett

Marcellus 61%

24%

15%

0

5

10

15

20

25

30

2006 2007 2008 2009 2010 2011 2012 2013

Ga

s P

rod

uc

tio

n (

Bil

lio

n c

ub

ic f

eet

per

day)

Year

PA Marcellus

WV Marcellus

Woodford

Fayetteville

Haynesville

Barnett

Peak Excluding

PA Marcellus

August 2012

Now Down 12%

Shale Gas Production from Top Five Shale Gas Plays,

2006-June, 2013

© Hughes GSR Inc, 2013 (data from DrillingInfo, October, 2013, three month trailing moving average)

0

0.2

0.4

0.6

0.8

1

1.2

2008 2009 2010 2011 2012

Avera

ge I

nti

al P

rod

ucti

vit

y

per

Well

In

dexed

to

2010

Year

Marcellus

Haynesville

Barnett

Fayetteville

Woodford

Marcellus – Youth

Horizontal Well Quality Trends – Top Five Shale Gas Plays

© Hughes GSR Inc, 2013 (data from Drillinginfo, March, 2013)

Fayetteville – Early Middle Age

Barnett – Middle Age

Haynesville – Late Middle Age

Woodford – Early Old Age

0

50000

100000

150000

200000

250000

0

5

10

15

20

25

1970 1975 1980 1985 1990 1995 2000 2005 2010

Nu

mb

er o

f Op

era

ting

Wells

G

as P

rod

ucti

on

(B

illi

on

cu

bic

feet

per

Day)

Year

Gas Production

Number of producing wells

Western Canadian Gas Production vs Number of Wells

(data from DrillingInfo/HPDI, June, 2013) © Hughes GSR Inc, 2013

British Columbia Shale Plays (EIA/ARI, June, 2013)

0

0.5

1

1.5

2

2.5

3

3.5

4

4.5

2000 2002 2004 2006 2008 2010 2012

Gas P

rod

ucti

on

(B

illi

on

cu

bic

feet

per

Day)

Year

Horn River Montney Remainder

B.C. Gas Production from Horn River, Montney and

Remaining Fields


0

2

4

6

8

10

12

14

2000 2002 2004 2006 2008 2010 2012

Gas P

rod

ucti

on

(B

illi

on

cu

bic

feet

per

Day)

Year

Existing BC Gas Production

British Columbia Gas Production vs LNG Export Applications


Existing NEB Approval

28 million tonnes/year

Exxon Application

30 million tonnes/year

BG Group Application

21.6 million tonnes/year

0

2

4

6

8

10

12

14

16

2000 2002 2004 2006 2008 2010 2012 2014 2016 2018 2020 2022 2024

Gas P

rod

ucti

on

(B

illi

on

cu

bic

feet

per

Day)

Year

Ramp up required to meet exports Production required to offset depletion of non-shale/tight plays Horn River Montney Remainder


B.C. Gas Production Required to meet 3.82 tcf/year

of LNG exports by 2025

Citigroup 2012 Projection of U.S. Shale Oil, 2010-2022 T

housa

nd B

arr

els

per

Day

0

1

2

3

4

5

6

7

8

9

2010 2015 2020 2025 2030 2035 2040

Mil

lio

n B

arr

els

per

Day

Year

Alaska

Onshore EOR

Onshore Shale/Tight Oil

Lower-48 Onshore Conventional

Lower-48 Offshore

Shale/Tight Oil

Lower-48 Offshore

Alaska

Lower-48 Onshore Conventional Production

Onshore EOR

32%

of 2

040 S

up

ply

U.S. Crude Oil Production Projection by Source and

Region 2010-2040 (EIA 2013 Reference Case)

Peak Production 2019


0

5

10

15

20

25

2010 2015 2020 2025 2030 2035 2040

Mil

lio

n B

arr

els

per

Day

Year

Net Imports Biofuels

Natural Gas Liquids Refinery Processing Gain

Coal and Gas to Liquids Other Liquids and SPR

Crude Oil Production

Net Imports

Domestic Crude Oil Production

Biofuels

Natural Gas Liquids

Refinery Gains

Net Im

ports 3

6%

O

il 32%

U.S. Petroleum Liquids Supply by Source

2010-2040 (EIA 2013 Reference Case)


0

100

200

300

400

500

600

Th

ou

san

d B

arr

els

per

Day

Shale Play

Crude Oil and Other Liquids Production by Shale Play –

mid 2012

(data from HPDI, September, 2012, for production in most cases through May-June, 2012)




0

200

400

600

800

1,000

1,200

1,400

1,600

Feb, 11 Jun, 11 Oct, 11 Feb, 12 Jun, 12 Oct, 12 Feb, 13 Jun, 13 Oct, 13

Other

Permian

Eagle Ford

Williston (Bakken)

Williston (Bakken)

Other


U.S. Oil Rig Count by Basin, 2011-2013

Permian Basin

Eagle Ford

40%

33%

14%

13%

80000

90000

100000

110000

120000

130000

140000

150000

600

700

800

900

1000

1100

1200

1300

1400

2000 2002 2004 2006 2008 2010 2012

Nu

mb

er o

f Pro

du

cin

g W

ells

O

il P

rod

ucti

on

(T

ho

usan

d B

arr

els

/day)

Year

Oil Production

Number of Wells

Permian Basin Total Oil plus NGL Production and Number

of Operating Wells, 2000-2013

© Hughes GSR Inc, 2013 (data from Drillinginfo, October, 2013, three month trailing moving average)

Total Wells Drilled = 388,533

Currently Producing Wells = 138,624

Oil Produced = 29.8 billion barrels

Gas Produced = 106.4 tcf

0

200

400

600

800

1000

1200

1400

1600

2000 2002 2004 2006 2008 2010 2012

Oil

Pro

du

cti

on

(T

ho

usan

d B

arr

els

per

Day)

Year

Permian Basin Oil plus NGL Production by Well Type -

Comparing Horizontal to Vertical Wells, 2000-2013

(data from Drillinginfo, November, 2013) © Hughes GSR Inc, 2013

Horizontal/Directional Wells

(33,421)

Vertical Wells

(105,775)

Total Horizontal Oil Production = 13.1 billion barrels

Total Horizontal Gas Production = 23 tcf

Total Vertical Oil Production = 16.7 billion barrels

Total Vertical Gas Production = 83.4 tcf

Avalon Shale

Bone Springs Sand

Cline Shale

Leonard Shale

Spraberry

Wolfberry

Wolfbone

Wolfcamp

Permian Basin Select Plays

Avalon Shale

Bone Springs Sand

Cline Shale

Leonard Shale

Spraberry

Wolfberry

Wolfbone

Wolfcamp

Permian Basin Select Plays (TX) – post 1990 wells

Avalon Shale

Bone Springs Sand

Cline Shale

Leonard Shale

Spraberry

Wolfberry

Wolfbone

Wolfcamp

Permian Basin Select Plays (NM & TX) – post 1990 wells

0

1000

2000

3000

4000

5000

6000

7000

0

50

100

150

200

250

2000 2002 2004 2006 2008 2010 2012

Nu

mb

er o

f Pro

du

cin

g W

ells

O

il P

rod

ucti

on

(T

ho

usan

d B

arr

els

/day)

Year

Oil Production

Number of Wells

Permian Basin (Subset) Unconventional Oil plus NGL

Production and Number of Operating Wells, 2000-2013


0

50

100

150

200

250

1 6 11 16 21 26 31 36 41 46

Oil

Pro

du

cti

on

(B

arr

els

per

Day)


Oil Production

BOE Production

Permian Basin (Subset) Type Oil and Barrels of Oil

Equivalent Well Decline Curves

(data from Drillinginfo, October, 2013) © Hughes GSR Inc, 2013

Oil Decline

First Year = 66%

Second Year = 37%

Third Year = 29%

Fourth Year = 29%

3-Year Decline = 83%

0

50

100

150

200

250

1 6 11 16 21 26 31 36 41 46

Oil

Pro

du

cti

on

(B

arr

els

per

Day)


Horizontal Production

Vertical Production

Permian Basin (Subset) Type Oil Well Decline Curves

Comparing Horizontal to Vertical Wells


3-Year Oil Decline

Horizontal = 84%

Vertical = 46%

0

50

100

150

200

250

2000 2002 2004 2006 2008 2010 2012

Oil

Pro

du

cti

on

(T

ho

usan

d B

arr

els

per

Day)

Year

Horizontal Production

Vertical Production

Permian Basin (Subset) Oil Production by Well Type -

Comparing Horizontal to Vertical Wells

(data from Drillinginfo, November, 2013) © Hughes GSR Inc, 2013

Horizontal Wells

Vertical Wells

0

1000

2000

3000

4000

5000

6000

7000

0

100

200

300

400

500

600

700

800

900

2005 2006 2007 2008 2009 2010 2011 2012 2013

Nu

mb

er o

f Pro

du

cin

g W

ells

O

il P

rod

ucti

on

(T

ho

usan

d B

arr

els

/day)

Year

Oil Production

Number of Wells

Bakken/Three Forks Oil Production and Number of



0

100

200

300

400

500

600

1 6 11 16 21 26 31 36 41 46

Oil

Pro

du

cti

on

(B

arr

els

per

Day)


Oil Production

BOE Production

Bakken/Three Forks Type Oil and Barrels of Oil Equivalent

Well Decline Curves Including Montana and North Dakota


Oil Decline

First Year = 70%

Second Year = 34%

Third Year = 23%

Fourth Year = 21%


0

500

1000

1500

2000

2500

3000

3500

4000

4500

5000

0

100

200

300

400

500

600

700

2007 2008 2009 2010 2011 2012 2013

Nu

mb

er o

f Pro

du

cin

g W

ells

O

il P

rod

ucti

on

(T

ho

usan

d B

arr

els

/day)

Year

Total Oil Production


First Year Field Decline = 44%

Bakken Field Production Decline – Oil Production from all

Wells Drilled Prior to 2012

© Hughes GSR Inc, 2013 (data from Drillinginfo, October, 2013)

Bakken/Three Forks Stratigraphy

© Hughes GSR Inc, 2013 (Image from Samson Oil and Gas)

0

100

200

300

400

500

600

1 6 11 16 21 26 31 36 41 46

Oil

Pro

du

cti

on

(B

arr

els

per

Day)


Bakken

Three Forks

Bakken and Three Forks

Type Oil Well Decline Curves in North Dakota


Three Forks

First Year = 70%

Second Year = 39%

Third Year = 25%

Fourth Year = 23%

3-Year Decline

Bakken = 86%

Three Forks = 85%

Bakken

First Year = 71%

Second Year = 34%

Third Year = 22%

Fourth Year = 19%

0

50

100

150

200

250

Mountrail (ND)

McKenzie (ND)

Williams (ND)

Dunn (ND) Divide (ND) Remaining ND

counties

Richland (MT)

Remaining MT

counties

Pro

du

cti

on

(T

ho

usan

d B

arr

els

p

er

day)

County

Bakken/Three Forks Production By County,

North Dakota and Montana, June, 2013

Total Production = 787 Kbbls/day




0

100

200

300

400

500

600

700

1 6 11 16 21 26 31 36 41 46

Oil

Pro

du

cti

on

(B

arr

els

per

Day)


Divide (ND)

Dunn (ND)

McKenzie (ND)

Mountrail (ND)

Williams (ND)

Other ND Counties

Richland (MT)

Other MT Counties

Bakken/Three Forks Type Oil Well Decline Curves

by County and Region


0

100

200

300

400

500

600

700

Mountrail (ND)

McKenzie (ND)

Williams (ND)

Dunn (ND) Divide (ND) Remaining ND

counties

Richland (MT)

Remaining MT

counties

Cu

mu

lati

ve P

rod

ucti

on

(T

ho

usan

d B

arr

els

)

County

Cumulative for remaining 26 years with 10% annual decline

Cumulative first four years

Bakken/Three Forks Estimated Ultimate Recovery per Well

By County, North Dakota and Montana (over 30-year life)

All wells hit stripper

status within 11-24 years

(10 barrels per day)


47% to 61% of oil is

recovered in first four

years

(data from Drillinginfo, October, 2013)

0

50

100

150

200

250

300

350

400

450

2008 2009 2010 2011 2012

Av

era

ge F

irst

Year

per

Well P

rod

ucti

on

(B

arr

els

/day)

Year

Mountrail (ND) McKenzie (ND) Williams (ND) Dunn (ND) Divide (ND) Other ND Counties Richland (MT) Other MT Counties MT Average ND Average Bakken Average

Bakken Average First Year Well Production by County and

Region, 2008-2012


0

5000

10000

15000

20000

25000

30000

0

200

400

600

800

1000

1200

2005 2010 2015 2020 2025 2030 2035

Nu

mb

er o

f Pro

du

cin

g W

ells

O

il P

rod

ucti

on

(T

ho

usan

d B

arr

els

/day)

Year


Number of Wells

Peak 2015 - 2016

Bakken Oil Production - Declining Drilling Rate Scenario,

(2000 wells/year declining to 1000 wells/year), 2005-2035


Max Number of Wells = 25974

Total production = 5 billion bbls

Peak Year = 2015 - 2016

Max Drilling rate = 2000 wells/y

Final Drilling rate = 1000 wells/y

Last Well

Drilled 2026

0

5000

10000

15000

20000

25000

30000

0

200

400

600

800

1000

1200

2005 2010 2015 2020 2025 2030 2035

Nu

mb

er o

f Pro

du

cin

g W

ells

O

il P

rod

ucti

on

(T

ho

usan

d B

arr

els

/day)

Year


Number of Wells

Peak 2017

Bakken Oil Production - Constant Drilling Rate Scenario,

(2000 wells/year), 2005-2035



Total production = 5.2 billion bbls

Peak Year = 2017

Drilling rate = 2000 wells/y

Last Well

Drilled 2023

0

5000

10000

15000

20000

25000

30000

0

200

400

600

800

1000

1200

2005 2010 2015 2020 2025 2030 2035

Nu

mb

er o

f Pro

du

cin

g W

ells

O

il P

rod

ucti

on

(T

ho

usan

d B

arr

els

/day)

Year

Risked Total Oil Production Unrisked Total Oil Production Risked Number of Wells Unrisked Number of Wells

Peak 2015

Bakken Oil Production - Declining Drilling Rate Scenario,

Risked at 80% for locations versus Unrisked, 2005-2035


Risked Wells = 21474

Unrisked Wells = 25974

Risked total production = 4.5 billion bbls

Unrisked total production = 5.0 billion bbls.



Eagle Ford Gas and Oil Well Distribution through mid-2013

© Hughes GSR Inc, 2013 (data from Drillinginfo, October 2013

Gas Wells

Oil Wells

0

1000

2000

3000

4000

5000

6000

7000

0

200

400

600

800

1000

1200

2008 2009 2010 2011 2012 2013

Nu

mb

er o

f Pro

du

cin

g W

ells

O

il P

rod

ucti

on

(T

ho

usan

d B

arr

els

/day)

Year

Oil Production

Number of Wells

Eagle Ford Oil plus NGL Production and Number of



0

100

200

300

400

500

600

1 6 11 16 21 26 31 36 41 46

Oil

Pro

du

cti

on

(B

arr

els

per

Day)


Oil Production

BOE Production

Eagle Ford Type Oil and Barrels of Oil Equivalent Well

Decline Curves


Oil Decline

First Year = 59%

Second Year = 29%

Third Year = 76%

Fourth Year = 58%


0

500

1000

1500

2000

2500

3000

3500

4000

4500

5000

0

50

100

150

200

250

300

350

400

2008 2009 2010 2011 2012 2013

Nu

mb

er o

f Pro

du

cin

g W

ells

O

il P

rod

ucti

on

(T

ho

usan

d B

arr

els

/day)

Year



First Year Field Decline = 34%

Eagle Ford Field Production Decline – Oil Production from

all Wells Drilled Prior to 2012


0

50

100

150

200

250

Karnes Lasalle Dewitt Dimmit Gonzales Other counties

Pro

du

cti

on

(T

ho

usan

d B

arr

els

p

er

day)

County

Eagle Ford Oil Production By County,

June, 2013

Total Production = 749 Kbbls/day



© Hughes GSR Inc, 2013 (note that this is 79% of total liquids production, the balance being NGLs; data from Drillinginfo, October, 2013)

0

50

100

150

200

250

300

350

400

450

500

1 6 11 16 21 26 31 36 41 46

Oil

Pro

du

cti

on

(B

arr

els

per

Day)


Dewitt

Karnes

Gonzales

Dimmit

Lasalle

Other Counties

Eagle Ford Type Oil Well Decline Curves

by County and Region


0

50

100

150

200

250

300

350

400

450

2009 2010 2011 2012

Av

era

ge F

irst

Year

per

Well P

rod

ucti

on

(B

arr

els

/day)

Year

Eagle Ford Average Dewitt Dimmit Gonzales Karnes Lasalle Other Counties

Eagle Ford Average First Year Well Production by County

and Region, 2008-2012


Dewitt

0

5000

10000

15000

20000

25000

30000

35000

40000

45000

50000

0

200

400

600

800

1000

1200

1400

1600

2008 2013 2018 2023 2028 2033

Nu

mb

er o

f Pro

du

cin

g W

ells

O

il P

rod

ucti

on

(T

ho

usan

d B

arr

els

/day)

Year


Number of Wells

Peak 2017

Eagle Ford Oil Production - Declining Drilling Rate Scenario,

(3500 wells/year declining to 2000 wells/year), 2008-2035



Total production = 7.3 billion bbls

Peak Year = 2017



Last Well

Drilled 2027

0

5000

10000

15000

20000

25000

30000

35000

40000

45000

50000

0

200

400

600

800

1000

1200

1400

1600

1800

2008 2013 2018 2023 2028 2033

Nu

mb

er o

f Pro

du

cin

g W

ells

O

il P

rod

ucti

on

(T

ho

usan

d B

arr

els

/day)

Year

Risked Total Oil Production Unrisked Total Oil Production Risked Number of Wells Unrisked Number of Wells

Peak 2017

Eagle Ford Oil Production - Declining Drilling Rate Scenario,

Risked at 80% for locations versus Unrisked, 2008-2035


Risked Wells = 37052

Unrisked Wells = 45302

Risked total production = 6.3 billion bbls

Unrisked total production = 7.5 billion bbls.



0

500

1000

1500

2000

2500

2005 2010 2015 2020 2025 2030 2035

Oil

Pro

du

cti

on

(T

ho

usan

d B

arr

els

/day)

Year

Eagle Ford Risked Production

Bakken Risked Production

Peak 2016

Bakken and Eagle Ford Oil Production – Declining Drilling

Rate Risked at 80% for locations, 2005-2035


Bakken Risked Wells = 21474

Eagle Ford Risked Wells = 37052

Bakken risked total production = 4.5 billion bbls

Eagle Ford risked total production = 6.5 billion bbls.



Eagle Ford

Bakken

There is no such thing

as a FREE LUNCH

There has been a great deal of pushback by

many in the general public – and in State and

National governments – to environmental issues

surrounding hydraulic fracturing.

(eg. Global Frackdown held October 19, 2013,

involving 250 protests in 26 countries)


A Reality Check?


"We are all losing our shirts today.

We're making no money. It's all in the red.” (Rex Tillerson, CEO of Exxon Mobil, Wall Street Journal, June 2012)

The United States oil and gas industry has “over

fracked and over drilled” (Mattihus Bichsel, projects and technology director, Royal Dutch Shell Plc.,

October 17, 2013)

Shell writes down $2.2 billion in shale assets and

puts Eagle Ford properties up for sale (Reuters September 30, 2013)

A Reality Check?


In a recent analysis, [Bernstein Research] estimates

that non-Opec marginal cost of production rose last

year to $104.5 a barrel, up more than 13 per cent

from $92.3 a barrel in 2011. (Bernstein Research, New York, May 2013)

• Tight oil production from the top two plays is likely to peak in 2016-2017

timeframe.

• High field decline rates mandate sustained high levels of drilling to

maintain production.

• Increasing drilling rates over current levels in the Bakken and Eagle Ford,

which account for one third of U.S. E&P investment, would only increase

peak production slightly and move it forward by perhaps a few months.

• Increases in the number of available drilling locations will increase

ultimate recovery but will not change the timing of peak production at

current drilling rates.

• High quality shale plays are not ubiquitous:

• 88% of shale gas production comes from 6 of 30 plays.

• 70% of tight oil production comes from 2 of 21 plays.

Tight Oil Takeaways


• US “Energy Independence” with the forecast energy trajectory is highly unlikely, barring a radical reduction in consumption.

• Almost all eggs are in the shale basket as a hope in meeting U.S. energy supply growth projections from oil and gas – and in meeting B.C. LNG export requirements.

Implications

• The “Shale Revolution” has provided a temporary respite from declining oil and gas production but should not be viewed as a panacea for increasing energy consumption – and exporting the bounty - rather it should be used as an opportunity to create the infrastructure needed for a lower energy throughput to maximize long term energy security.

• The Shale Revolution has been a “game-changer” in that it has temporarily reversed a terminal decline in supplies from conventional sources. Long term sustainability is questionable and environmental impacts are a major concern.

the “shale revolution” - legacy.firstenergy.comlegacy.firstenergy.com/userfiles/hughes first...

Documents