Forecast for US Oil and Gas Production (Laherrère & Hall 2018)

Jean Laherrere

19 March 2018

This paper was written in association with Charlie Hall in view of a presentation in New Orleans on 21 March at ACS conference “M. King Hubbert: Is He Relevant?” Forecasts for US oil and gas production

My assumptions for forecasting US oil and natural gas production are several: 1-Reserves estimates of LTO and shale gas, like conventional ones, are based on multiplying estimates of the volume in place (or the volume generated by the source rock) and a recovery factor. Such assessments are completely unreliable because the volume of the accumulation is fuzzy (no water plane) and the recovery factor unknown by lack of historical checks with LTO or shale gas fields produced until abandoned 2-Future production estimated by many (in particular EIA) by assuming a large number (tens of thousands) of future wells multiplied by the optimistic estimated EUR of past wells (in sweet spots) without bothering to check if there is enough room for drilling economical wells is for me very unreliable. EIA does not bother reporting the cumulative future production of their forecasts up to 2050 EIA publishes the LTO reserves at end 2016 ranked by proved reserves: Bakken is number one but in their AEO forecasts up to 2050 Permian basin is number one This EIA approach relying on number of wells and well ultimate reminds of the USGS estimate in 1962 of 590 Gb for the US oil ultimate by V.McKelvey (based on Zapp’s work https://pubs.usgs.gov/bul/1142h/report.pdf) by multiplying a large number of feet drilled (5 10E9 foot) by the recovery per foot op to 1961 (118 b/ft = 130 Gb discovered for 1.1 Gft drilled = G.Bowden 1982): Hubbert was strongly against such approach, saying that the oil recovery per foot was showing a roughly exponential decline (D.Strahan 2007) and would be lower in the future. Present estimate of the US ultimate is far below Zapp’s estimate (590 Gb), but higher than Hubbert’s estimate (150-200 Gb for conventional USL48). It is the same with LTO. The present ultimate recovery per well (EUR) will be lower in the future and the location of future wells will be limited, in particular with lateral length increase. 3-I believe it is better to estimate the ultimate production of LTO and shale gas with HL (Hubbert linearization) of past production. But many plots display several declines and the last data with rise Hubbert Linearization is the plot of the ratio of annual production to cumulative production in percentage (Y axis) versus the cumulative production (Hubbert 1980). Empirically once the field is moderately well developed, this gives one or several relatively straight lines and the last one can be extrapolated to the Y axis, giving the EUR when production will fall to zero (assumed to be the end of the production) 4-Past oil and gas data for the USLower48 displays cycles and most of the cycles display approximately symmetrical rises and declines, so the future cycle is assumed to be also symmetrical. This symmetry is explained by the fact that, in the USL48, there are thousands of producers acting in random (law of large numbers). Random behavior is described as “Brownian motion”, displaying Gaussian symmetrical curve.

"

The past crude oil production 1859-2017 of the USL48, Texas, California and Gulf of Mexico displays several cycles and each decline has the same slope as the last increase. USL48 crude oil + condensate annual production

Texas crude oil +condensate annual production

3,5 1,5 USL48

3,0

b G n o i t c u d o r p l a u n n a d n o c + e d u r c

2,5

b G n 2,0 o i t c u d o 1,5 r p l a u n 1,0 n a

aP Gb

1,2

0,9

0,6

0,3

0,5

0,0 1860

0,0 1890 1890 1880

1900

1920

1940

1960

1980

2000

year

Jean Laherrere Feb 2018

1900 1900

1910 1910

1920 1920

1930 1930

1940 1940

1950 1950

2020 Jean Laherrere February 2018

California annual crude oil production

1960 1960

1970 1970

1980 1980

1990 1990

2000 2000

2010 2010

2020 2020

year

BOEM/MMS Gulf of Mexico annual production 1947-2017

450

1000

crude oil prod DOGGR 900

400

total gas Gcf/5.6

350

b M n o300 i t c u d o r250 p l i o e200 d u r c l 150 a u n n a100

700

6 . 5 600 / f c G e 500 o b M 400

300

200

50

0 1875 1900 Jean Laherrere Feb 2018

100 000 90 000

oil +condensate Mb

800

!""#$%%&&&'()")'*+,-'.+/%!+-,#.%#0*1 23+%4,#5)"%#4+(05"%6,.1+2')7#

100

1925

1950

1975

2000

2025

2050

0 1940

2075

year

120

all wells

108

oil

80 000

s l l 70 000 e w f o60 000 r e b m 50 000 u n l a u40 000 n n a30 000

dry

1960

1970

1980

1990

2000

2010

2020

year

North Dakota: Bakken oil monthly production per well

US annual number of wells drilled

gas

1950


96 84

oil price $2016/b gas price $2016/MBtu

b 72 / 6 1 0 2 60 $ e c i 48 r p 36

200

12000

180

10800

160

9600

140

l 8400 l e

s

w / d / 120 b n o i t c100 u d o r 80 p l i o

w g

n 7200 i

Antelope field

c u d 6000 o r p f o 4800 r e b m 3600 u n

60

20 000

24

40

2400

10 000

12

20

1200


1900

1920

1940

year

1960

1980

2000

0 2 0 20

0 1950

1960

Jean Laherrere March 2018

1970

1980

1990

2000

2010

0 2020

year

Our main forecasts are based on EIA monthly production data (unfortunately there are several different reports as weekly, monthly).

#

The following plots show for different plays: -left: annual & cumulative production as forecast for ultimate from HL -right: HL (Hubbert linearization) of past production extrapolated to ultimate (U) CP = cumulative production, RR = remaining reserves, CP+RR = initial reserves (discoveries) -Natural gas production -Shale gas: Bakken Bakken HL of dry shale gas production from EIA (FQ)

Bakken dry shale gas monthly production from EIA (FQ) 50 45

Bakken FAQ U = 6 Tcf

40

f c G 35 n o i t c 30 u d o r 25 p y l h 20 t n o m 15

4

6

aP/CP%

5

U = 6 Tcf

jan2015-feb2017

3

CP FQ

4

3

2

10

1

f c T n o % i t c P 2 u C / d P o a r p e v i t a l u 1 m u c

5 0 2000 2005 Jean Laherrere Feb 2018

2010

2015

2020

2025

2030


0 2035

year

2

3

4

5

6

cumulative production Tcf

Mason Inman requested the EIA to get more details on the AEO and received the forecasts for each shale play for AEO 2013 to 2018 Bakken cumulative shale gas production from AEO & U=6 Tcf

Bakken shale gas production from AEO & U = 6 Tcf

25

0,7

AEO2018

AEO2018 0,6 f c T0,5 n o i t c u0,4 d o r

AEO2017

AEO2017

AEO2016

AEO2016

20

AEO2015

AEO2015 AEO2014

AEO2014

AEO2013

AEO2013 15

U=6 Tcf EIA FAQ

f c T

p l a0,3 u n n a

U=6 Tcf hist FAQ

10

0,2 5

0,1

0,0 2 0 00 2 0 05 2 0 10 Jean Laherrere March

2 0 15

2020

202 5

2030

year

2 0 35

204 0

2045

2 050

0 2000

2005

2010

Jean Laherrere March

2015

2020

2025

2030

2035

2040

2045

2050

year

AEO annual production forecasts are chaotic with time! -Shale gas: Barnett

$

Barnett HL of dry shale gas production from EIA

Barnett dry shale gas monthly production from EIA 4 170

50 Barnett Gcf/m

153

U = 25 Tcf

45

aP/CP%

CP+RR 136

CP Tcf

f c G n 119 o i t c u d 102 o r p y 85 l h t n o m 68

jan2010-dec2017

40

3

U = 25 Tcf 35

30

25

20

51

15

34

10

17

5

f c T n o i t c % u P 2 d o C r / p P a e v i t a l u m u c 1

0 20 00

20 05

2 01 0

20 15


20 20

0

0 2030

20 2 5

CP+RR 2016 = 33.8 Tcf 2015 = 32.8 Tcf 2014 = 38.8 Tcf

0 3 Jean Laherrere Feb 2018

year

6

9

12

15

18

21

24

27

30


From TxRRC annual data Barnett gas & liquids production from RRC

Barnett HL gas production RRC 1993-2017

6

Barnett gas decline 2000-2017 from RRC

36 U =25 Tcf HL

6

gas aP/CP %

33

5

2014-2017

30

gas Gcf/d RRC

gas Gcf/d RRC

2008-2010 RRC

5

2010-2017 RRC

d / f 4 c G n o i t 3 c u d o r p s2 a g

27 4 d / f c G n o i t c3 u d o r p G N 2

24 21

% P18 C / P a15 12 9 6

1

1

3 0 0 1990

1995

2000

2005

2010

2015

2020

2025

0

2030

year

5



10

15

20

25

0

30

0


5

10


15

20

25

30

35


Mason Inman data AEO 2013 to 2018 and also from University of Texas UT Barnett cumulative gas production from AEO & U= 25 Tcf

21/3.44 5617. 815 -/9:;*4<93 60

%"#

AEO2018 55

AEO2017 AEO2016

50

AEO2015

%"!

=>?%!$'

45

AEO2014

=>?%!$( =>?%!$# =>?%!$@

$"#

/ 1 . 0 / . + * )

AEO2013 40

TxRRC

f c T 35

U=25 Tcf hist AEO

=>?%!$A =>?%!$B C) %!$(" =>?%!$( D

$"!

30 25

C) %!$@" =>?%!$( D C) %!$A" D'EF*+ 6<54 G>H=I

!"#

20 15 10 5

!"! $&&!

0 1 99 0

%!!!

%!$!

%!%!

%!'!

%!(!

%!#!

1 99 5

2 00 0


2 00 5

2 01 0

2 01 5

2 02 0

2 02 5

2 03 0

2 03 03 5

2 04 04 0

2 04 04 5

2 05 05 0

year

AEO2013 was much higher than AEO2018, missing the decline after the peak of 2012, , UT 2017 (University of Texas) is close to our forecast

-Shale gas: Eagle Ford

%

Eagle Ford HL of dry shale gas production from EIA

Eagle Ford dry shale gas monthly production from EIA 160

5

32 Eagle Ford Gcf/m

140

28

U = 15 Tcf

aP/CP%

f 120 c G n o i t c 100 u d o r p y 80 l h t n o m 60

dec2013-feb2017

4

CP+RR

mar2017-dec2017

24

CP Tcf U = 15 Tcf

f c

20 T

3 n o i t c % u P 16 d / o C r p P a e v 2 i t 12 a l u m u c

40

CP+RR 2016 = 30.1 Tcf 2015 = 25.4 TCF 2014 = 27.8 Tcf

8

1

20

4

0 2 0 00

2005

2 01 0

2015

2 02 0

0 2 0 30

2 0 25

0 0

year


2

4

6

8


10

12

14

16

18

20


From TxRRC annual data Eagle Ford HL natural gas production from RRC

Eagle Ford NG production & forecast for U = 15 Tcf 2,5

100

90

gas Tcf U = 15 Tcf 2,0

80

f c T n o1,5 i t c u d o r p l a u1,0 n n a

70

aP/CP% 2013-2017

60

% P 50 C / P a 40

30

20

0,5

10

0

0,0 2005

2010


2015

2020

http://www.rrc.state.tx.us/eagleford/index.php

year

0

2025

2

4

6

8

10

12

14

16



Mason Inman data AEO 2013 to 2018 Eagle Ford shale gas annual production from AEO & U=15 Tcf

Eagle Ford shale gas cumulative production from AEO & U=15 Tcf 60

3,0 AEO2018

55

2,5

50

AEO2016 AEO2015

45

AEO2014 f 2,0 c T n o i t c u1,5 d o r p

AEO2018 AEO2017

AEO2017

f 40 c T n 35 o i t c u 30 d o r p 25 e v i t 20 a l u m15 u c

AEO2013 hist U = 15 Tcf

1,0

AEO2016 AEO2015 AEO2014 AEO2013 hist U = 15 Tcf

10

0,5

5

0,0 2000

2005

2010


2015

2020

2025

2030

2035

year

2040

2045

2050

source: Mason Inman EIA

0 2000

2005

2010


2015

2020

2025

year

2030

2035

2040

2045

2050

source: Mason Inman EIA

-Shale gas: Fayetteville

&

Fayetteville HL of dry shale gas production from EIA

Fayetteville dry shale gas monthly production from EIA 100

4

20 U = 10 Tcf

90 80

f c G n o i t c u d o r p y l h t n o m

18

Fayetteville CP+RR EIA

aP/CP%

16 3

U = 10 Tcf 70

CP

20

f c T 12 n o i t % c u P 10 d C 2 / o P r a p e 8 v i t a l 6 u m 1 u c 4

10

2

60 50 40 30


feb2013-dec2017

14

0

0 2010

2015

2020

2025

2030

2035

CP+RR EIA end 2016 = 13.5 Tcf end 2015= 2015= 13.6Tcf end 2014 = 17.3 Tcf

0

2040

1

2

3

4


year

5

6

7

8

9

10

11

12


Mason Inman data AEO 2013 to 2018 and UT 2017 Fayetteville shale gas cumulative production from AEO & U = 10 Tcf Tcf

10/-22-345545

%"!

AEO2018

678%!$&

AEO2017

40

AEO2016

678%!$' 678%!$#

$"#

678%!$9 . 0 / . , * ) (

678%!$:

$"!

678%!$; <( %!$'" 678%!$' = <( %!$9" 678%!$' =

!"#

AEO2015

35

f c T n o 30 i t c u d o r 25 p e v i t a 20 l u m u c 15

AEO2014 AEO2013 UT 2017 $3/Mcf U = 10 Tcf hist (EIA)

10

<( %!$:" =&>?)*

5

@4A2 B7C6D

!"! %!!!

%!$!

%!%!

%!&!

%!'!

0 2000 2005 2010 Jean Laherrere March 2018

%!#!

2015

2020

2025

2030

2035

2040

2045

2050

year

AEO2014 was completely unconnected with reality, when University of Texas UT2017 cumulative production up to 2050 is 18 Tcf against 42 Tcf for AEO2018 or 10 Tcf for my forecast: UT is closer to my estimate than to AEO2018! -Shale gas: Haynesville Haynesville HL of dry shale gas production from EIA

Haynesville dry shale gas monthly production from EIA 250

40

2,0 aP/CP%

U = 27 Tcf 225 200

f c G 175 n o i t c u 150 d o r p 125 y l h t n 100 o m

oct2014-nov2016

36

Haynesville

dec2016-dec2017

CP+RR EIA

32 1,5

U = 27 Tcf CP Tcf

28

50

f c T 24 n o i t c % u P 1,0 20 d C o / r P p a 16 e v i t a l 12 u m 0,5 u c 8

25

4

75


2010

2015

2020

year

2025

2030

0 2035

CP+RR EIA end 2016 = 26.5 Tcf end 2015= 24.8Tcf end 2014 = 27.2 Tcf

0,0 0

3

Jean Laherrere Feb2018

6

9

12

15

18

21

24

27

30


'

Mason Inman data AEO 2013 to 2018 and UT 2017 0/.1,23455,

Haynesville shale gas cumulative production from AEO 2013-2018 & UT2017 130

&

AEO2018 678#!"$ 678#!"%

%

678#!"& 678#!"9

$

/ , . , + ) ( '

678#!": 678#!";

#

<' #!"%= 678#!"% > <' #!"9= 678#!"% >

120

AEO2016 AEO2015

f 100 c T n 90 o i t c 80 u d o r 70 p e v 60 i t a l u 50 m u c 40

AEO2014 AEO2013 UT 2017 $3/Mcf U = 27 Tcf hist (EIA)

30

<' #!":= >$?@()

"

AEO2017

110

20

A42B C7D6E

10

! #!!!

#!"!

#!#!

#!$!

#!%!

0 2000 2005 2010 Jean Laherrere March March 2018

#!&!

2015

2020

2025

2030

2035

2040 2045 2050 source: Mason Inman EIA

year

-Shale gas: Marcellus My estimate for Marcellus gas is within the range 80-100 Tcf, when the cumulative production up to 2050 is forecasted by AEO 2018 to be over 360 Tcf Marcellus HL of dry shale gas production from EIA

Marcellus dry shale gas monthly production from EIA

5

650 600 550

f 500 c G n 450 o i t c 400 u d o r 350 p y l h t 300 n o m 250

110 Marcellus Gcf/m

100

U = 80 Tcf

aP/CP%

prod (res)

Jun2015-Dec2017

U = 100 Tcf U = 80 Tcf

80

CP+RR

f c 70 T n o i t 60 c u d o r 50 p e v i t a 40 l u m u 30 c

CP Tcf U = 100 Tcf

200 150

3 CP+RR EIA end 2016 = 109.1 Tcf end 2015 = 91.4 Tcf end 2014 = 97.4 Tcf

% P C / P a 2

1

20

100

10

50 0 2000

4

90

2005


2010

2015

2020

year

2025

2030

2035

0 2040

0 0

10

20


30

40

50

60

70

80

90

100


Marcellus basin is huge, but the sweet spots are concentrated in two areas and no drilling in between: its potential is likely to be poor! MCOR David Hughes 2018

(

Mason Inman data AEO 2013 to 2018 & UT 2017 Marcellus cumul ative gas production from AEO & U= 80 & 100 Tcf Tcf

21/*.3345 400

&#

AEO2018 AEO2017 350

&"

AEO2015 300

678"!&#

AEO2014 AEO2013

&!

678"!&(

%

U = 100 Tcf

f 250 c T

678"!&$ / 1 . 0 / . + * )

AEO2016

678"!&'

U = 80 Tcf hist AEO

678"!&9

200

678"!&%

$

150

:) "!&#; 678"!&# < :) "!&$; 678"!&# <

#

100

:) "!&9; <'=2*+ >?5@ A7B6C

"

50

0

! "!!!

"!&!

"!"!

"!'!

"!#!

2000

"!(!

2005

2010

2015

2020

2025

2030

2035

2040

2045

2050

year


The AEO2018 forecast for Marcellus in 2045 is more than 5 times the UT2017 forecast -Shale gas: Utica Utica dry shale gas monthly production from EIA

Utica HL of dry shale gas production from EIA

160

20 U = 10 Tcf

140

14 13

18

Utica

12

CP+RR EIA 16

f 120 c G n o i t c 100 u d o r p y 80 l h t n o

aP/CP%

11

U = 12 Tcf 14

CP

12

10

8

m 60

6 40 4

10

f c 9 T n o 8 i t c % u 7 d P o C / r P p a 6 e v i t 5 a l u m 4 u c 3

jan2017-dec2017 CP+RR EIA end 2016 = 18 Tcf end 2015 2015 = 13.9Tcf end 2014 = 7.0 Tcf

2

20 2

1 0 2000

2005


2010

2015

2020

2025

year

2030

2035

0 2040


6

8

10

12

14

16

18

20


-Shale gas: Woodford

)

Woodford HL of dry shale gas production from EIA

Woodford dry shale gas monthly production from EIA 100

4

30 U = 18 Tcf

90

CP+RR EIA

80

f c G n o i t c u d o r p y l h t n o m

27

Woodforfd

aP/CP%

24

U = 18 Tcf 70

3

CP

21

60

18

50

15

40

12

30

9

20

6

10

3

0 2000

2005

2 010

2015

2020


2 025

2030

CP+RR EIA end 2016 = 25.7Tcf end 2015 2015 = 23Tcf end 2014 = 20 Tcf

0

0 2 040

2035

sept2011-dec2017

f c T n o i t c % u P 2 d C o / r P p a e v i t a l u m 1 u c

0 Jean Laherrere Feb 2018

year

5

10

15

20


-Shale gas: all US US dry shale gas monthly production from EIA

US HL of dry shale gas production from EIA jan2000-dec2017

3 50 U = 250 Tcf 45

310

https://www.eia.gov/naturalgas/week ly/archivenew_ngwu/2017/12_1/

https://www.eia.gov/naturalgas/weekly/archivenew_ngwu/2017/06_29 /

279

US shale gas Gcf/d CP+RR

40

d / f c G n o i t c u d o r p s a g e l a h s y r d

35

cumulative Tcf

217

30 EIA does not report any reserves for Permian and for Bakken

20 15 10

62

5

31

0 2000

0 2005

jan2013-feb2017

2 f c T n 186 o i t c % u P 155 d o C r / p P e a v 124 t i a l u 1 93 m u c

EIA wet reserves

25

aP/CP%

248

U = 250 Tcf

2010

2015

2020

2025

2030

2035

year



50

75

100

125

150


175

200

225

250

-Natural gas: US HL of US marketed natural gas production 1900-2017

US natural gas production & forecasts 45

40

2400

f 30 c T n o i t 25 c u d o r p20 l a u n n15 a

1983-2006 2000

dry

f c 1800 T s e v 1600 r e s e r 1400 & n 1200 i o t c u 1000 d o r p 800 e v i t a 600 l u m u 400 c

AEO2018 AEO2017 AEO2016 AEO2013 AEO2010 U = 2400 Tcf cum prod mark EIA reserves

10

5

0 1900

mark aP/CP%

2200

U = 2400 Tcf marketed

35

6

5

4

% P3 C / P a 2 AEO 2018 extrapolated towards 2100 = 4000 Tcf 1

200

1920

1940

Jean Laherrere 20 Feb 2018

1960

1980

2000

2020

2040

year

2060

2080

0 2100

0 0

400

800

Jean Laherrere 16 %arch2018

1200

1600

2000

2400

2800

3200

3600

4000


Summary for US shale gas plays

*

gas play Tcf ultimate Barnett 25 Eagle Ford 15 F ayetteville 10 Haynes ville 27 Marcellus 80 Utica 10 Woodford 18 s hale gas 250 natural gas 2400

cum prod 2017 18 9 8 15 31 4,5 6 110 1400

remaining 2017 7 6 2 12 49 5,5 12 140 1000

-Other forecasts EIA/AEO forecasts from 1979 to 2018 display a huge range of uncertainty or poor practice (often change of the person doing the estimate): it means that the last forecast is likely to be poor too! US natural gas dry production forecasts from EIA/AEO 1979-2018 45 40 35

f30 c T n o25 i t c u d o r20 p y r d15

10

5 0 1960

1970

1980


50

1990

2000

2010

2020

2030

2040

2050

year

US natural gas dry production forecasts from USDOE/EIA/AEO

AEO 1979 AEO 1982 AEO 1983 AEO1985 AEO1990 AEO1995 AEO1996 AEO1997 AEO1998 AEO1999 AEO2000 AEO2001 AEO2002 AEO2003 AEO2004 AEO2005 AEO2006 AEO2007 AEO2008 AEO2009 AEO2010 AEO2011 AEO2012 AEO2013 AEO2014 AEO2015 AEO2016 AEO2017 AEO2018 actual dry

AEO1990

40

for 2040 for 2030 for 2020

35

for 2010

f30 c T n o25 i t c u d o r20 p y r d15

10

5

0 19 9 0

AEO1993

1 99 5

200 0

20 05

20 10

2 015

US cumulative dry gas production production forecasts from USDOE/EIA/AEO

AEO 1979

4000

AEO 1982 AEO 1983

3750

AEO1985 AEO1990

3500

?

AEO1994 AEO1995

2 02 0

year of forecast


AEO 1982 AEO 1983

?

for 2050

40

AEO 1979

AEO1985

45

US natural gas dry production forecasts from EIA/AEO 45

AEO1993 AEO1994

3250

AEO1995

AEO1996 f 35 c T n o i t 30 c u d o r p 25 s a g y r 20 d

15

AEO1997 AEO1998 AEO1999 AEO2000 AEO2001 AEO2002 AEO2003 AEO2004 AEO2005 AEO2006 AEO2007 AEO2008 AEO2009 AEO2010

10

AEO2011 AEO2012

3000

AEO1996

f c2750 T n o2500 i t c u d2250 o r p2000 s a g1750 y r d1500 e v i t a1250 l u 1000 m u c

AEO1997 AEO1998 AEO1999 AEO2000 AEO2001 AEO2002 AEO2003 AEO2004 AEO2005 AEO2006 AEO2007 AEO2008 AEO2009 AEO2010 AEO2011 AEO2012

750

AEO2013

AEO2013

5 0 1960 1960 1970 1970 1980 1980 1990 1990 2000 2000 2010 2010 2020 2020 2030 2030 2040 2040 2050 2050 2060 2060 2070 2070 2080 2080 2090 2090 2100 2100 Jean Laherrere March 2018 year

AEO2014 AEO2015 AEO2016 AEO2017 AEO2018 actual dry

AEO2014

500

AEO2015 AEO2016

250

AEO2017

0 1960

AEO2018

1970

1980

1990


2000

2010

2020

2030

year

2040

2050

2060

2070

2080

2090

2100

cum actual cum + 1P

"+

US cumulative dry gas production forecasts from USDOE/EIA/AEO 3000

4000

for 2010 2700

f c T 2400 n o i t c 2100 u d o r 1800 p s a g y 1500 r d e v 1200 i t a l u m 900 u c

for 2020

3750

for 2030

3500

for 2040

3250

for 2050

US cumulative dry gas production forecasts from AEO 2008 & 2018 and JL ultimates AEO2018

?

AEO2008 JL ultimate 2018

3000

f c T2750 n o i t 2500 c u2250 d o r2000 p s a1750 g y r1500 d e1250 v i t a1000 l u m750 u c 500

ultimates JL mark

600

JL ultimate 2008 cum actual

300 250

0 1 990 19 95 Jean Laherrere March 2018

2 0 00

200 5

2 010

2015

20 20

year of forecast

0 1960 1960 1970 1970 1980 1990 1990 2000 2000 2010 2020 2020 2030 2030 2040 2050 2050 2060 2060 2070 2080 2080 2090 2090 2100 Jean Laherrere March 2018

year

My own estimates for the ultimates of total US NG marketed has increased from 1600 Tcf in 2008 to 2400 Tcf in 2018 In contrast, the official EIA/AEO forecast is for dry gas production, which is about 7% less than marketed gas. Our forecast U=2400 Tcf is for marketed gas. The difference of forecasts between AEO 2108 dry gas and U=2400 Tcf/1,07 is 13 Tcf for 2030, 20 Tcf in 2040 and 30 Tcf in 2050; But AEO2018 NG consumption is well below AEO production by about 7 Tcf, but exceeds my forecast after 2023 and in 2050 20 Tcf is missing. The plot of AEO 2018 US NG consumption shows that US in 2050, instead of exporting 8 Tcf, will be forced to import 20 Tcf: quite a change compared to the official statements US natural gas production, consumption & forecasts AEO2018 & U=2400 Tcf 45

40

U = 2400 Tcf marketed

35 f 30 c T n o i t 25 c u d o r p20 l a u n n15 a

AEO2018 dry consumption AEO 2018 AEO2018-U=2400 AEO2018-U=2400 Tcf/1,07

10

5

0 1980

1990


2000

2010

2020

2030

2040

2050

2060

year

Europe counts on the US shale gas to import LNG, but for that to occur the US must be able to produce more than they consume, which is unlikely All other analysts beside the US EIA give results that disagree with the EIA estimates, specifically: David Hughes 2018 displays US NG production 2012-2050 from EIA/AEO 2017 (but not his own forecast) and Art Berman displays US NG monthly production 2000-2017 (production starts at 20 Gcf/d)

""

DNV GL (Det Norske Veritas Germanischer Lloyd in Norway is assumed to tell the truth!) report “Oil and gas forecast to 2050- Energy Transition outlook 2017” displays a peak of unconventional onshore gas production in 2016 for North America at 880 G.m3 = 31 Tcf

DNV forecasts that North America unconventional onshore gas in 2050 will be 70% of 2016 value (going down), against 160 % (going up) for AEO2018 forecasts for the US unconventional gas (only onshore) as shown in the above graph. It means that DNV disagrees with the EIA forecasts for US unconventional gas. However DNV adds: unconventional gas will be the primary source for North American LNG exports. ExxonMobil 2018 outlook forecasts that the North America unconventional gas should be in 2040 150% of its 2016 value, in agreement with AEO 2018 -Gas price, oil/gas price and flaring Gas price has sharply peaked in 2005 and 2008 and today back to pre2000 price despite that the heat content has increased.

"#

US natural gas price: wellhead, citygate & Henry Hub from EIA & heat content 10

1,16

7

US oil over gas price MBtu ratio from EIA and flared over marketed percentage

56

annual oil/gas ratio

9

1,14

u 7 t B M / $ 6 & f c k 5 / $ e c 4 i r p G N 3

oil/gas ratio AEO2018

6

% d e 1,12 f t c e 5 k k r / u a t m 1,1 B / d M e r 4 s a a l g f y & 1,08 r d i o t t 3 n e a r t s 1,06 n o a g c / l t i a e o 2 h 1,04

8

wellhead $/MBtu citygate $/kcf Henry Hub spot $/Mbtu heat content mark MBtu/kcf heat content dry MBtu/kcf

48

oil/gas ratio AEO2016 40 t a

flared/marketed % US

o k a D 32 h t r o N % d 24 l o s / d e r a 16 l f

flared/sold % ND

2 1,02

1 0 1950 1960 1970 Jean Laherrere March 2018

1980

1990

year

2000

2010

2020

1 2030

1

0 1950

8

1960

1970


1980

1990

2000

2010

2020

2030

2040

0 2050

year

If in Europe some gas contracts are indexed to oil price. The US ratio of oil to gas price per Joule (MBtu) varies largely being over 6 in 1950 decreasing slowly to 1 in 2004, increasing to 6 in 2013 and is presently around 3. EIA forecast that it will increase but stay below 4 in 2050. The problem is that the cost of transporting gas internationally is much higher than transporting oil and when gas is cheap and in excess associated to oil it is flared. The oil over gas price correlates with flared over marketed percentage in the US and since 2004 in North Dakota. I am surprised that the 1950-2005 trend for equality between oil and gas price is not the goal of EIA. I doubt that the future increase of this ratio will occur.

"$

Oil production -Tight oil: Bakken North Dakota & Montana US Bakken monthly production from EIA play & forecast U= 4.5 Gb 1,3

US HL of Bakken LTO monthly production from EIA play 1953-Sept2017 9 000

4

120

Bakken (ND & MT)

1,2

2000-2017

8 000

U = 4.5 Gb 1,1

Jan2014-Feb2017

CP+RR 7 000

EIA 1P

1,0

U = 4,5 Gb

0,9

100

WTI

6 000

cum prod Mb

0,8 5 000

d0,7 / b 0,6 M

4 000

0,5 3 000

0,4 0,3

b M n o i t c u d o r p e v i t a l u m u c

2 000

3 80

% P2 C / P a

60

b / $ I T W

40 1 20

0,2 1 000

0,1

CP 1953-1999 = 42 Mb

0,0 2000

2005

2010


2015

2020

2025

2030

0 2035

year

0

0 0

500

1000

1500

2000

2500

3000

3500

4000

4500

5000

cumulative production Mb


Bakken ND from ND.gov https://www.dmr.nd.go https://www.dmr.nd.gov/oilgas/stats/hist v/oilgas/stats/historicalbakkenoil oricalbakkenoilstats.pdf stats.pdf Ultimate 4 Gb North Dakota: Bakken oil monthly production

Bakken North Dakota monthly oil production Hubbert linearization 5

1200 1100

125

U = 4 Gb 1955-2008

1000

kb/d

Nov2008-Dec2012

4

900 d / b k n o i t c u d o r p l i o

100

Jan 2012-Feb 2017 Feb2017-Dec2017 WTI $/b

800 3

700

75

% P C / P a

600 500

b / $ I T W

2

50

1

25

400 300 200 100 0 2004 2004 2006 2006 2008 2008 2010 2010 2012 2012 2014 2014 2016 2016 2018 2018 2020 2020 2022 2022 2024 2024 2026 2026 2028 2028 2030 2030


year

0 0

500


1000

1500

2000

2500

3000

3500

0 4000


From Mason Inman: AEO 2013 to 2018, and UT2017 forecast

"%

-.//01 345 673,89:431

US Bakken annual cumulative production from EIA AEO & U= 4.5 Gb 26

&"!

24

AEO2018 AEO2017

%"#

%"!

22

AEO2016

20

AEO2015

18 , + *$"# )

16 14

AEO2014 AEO2013 U=4.5 Gb past EIA/FAQ

b G

$"!

12 10

!"#

8 !"! $ '' !

6 % !! !

% !$ !

% !% !

% !& !

;< =% =%! $& -.//0 1

;< =% =%! $( -.//0 1

;< =% =%! $# -.//0 1

;< =% =%! $> -.//0 1

;< =% =%! $? -.//0 1

;< =% =%! $@ -.//0 1

% !( !

% !# !

4 2

AB%!$?CD(! $?CD(!+**5 +**5 9.E0F -./ -.//01 /01

AB%!$?CD## $?CD##+**5 +**59.E0F -./ -.//01 /01

AB%!$?C;<=%!$? AB%!$?C;<=% !$? 67490 9.E0F -.//01

G4E:3749.5 G4E:37 49.5 C
0 2000 2005 2010 Jean Laherrere March 2018

2015

2020

2025

2030

2035

2040

2045

2050

year

-Tight oil: Eagle Ford US Eagle Ford monthly production & forecast U = 3 Gb 1,8

7 000

US HL of Eagle Ford LTO monthly production from EIA play 8

120

Eagle Ford play 1,6

aP/CP%

U = 3 Gb

6 000

CP+RR 1,4

EIA 1P CP Mb

1,0

d / b M 0,8 0,6 0,4

100

WTI 80

60

b / $ I T W

40

1 000

0,2 0,0 2005

Oct2013-Nov2016

b 6 5 000 M n o i t 5 c 4 000 u d % o P r p / C4 e 3 000 v P i t a a l 3 u m 2 000 u c 2

U = 3 Gb 1,2

7

20 1

2010

2015

2020

year


2025

0 2030

https://www.eia.gov/petrole https://www.eia.gov/petroleum/data.php#c um/data.php#crude rude

0 0

500

1000


1500

2000

2500

3000

3500

0 4000


From TxRRC annual production Eagle Ford RRC oil & condensate production & forecast for U = 3 Gb 550

Eagle Ford HL RRC crude oil +condensate production

1,5 90

500

100 aP/CP%

1,4 U = 3 Gb

450

oil

400

e o b350 M n o i 300 t c u d o r250 p l a u200 n n a

1,1

90

2010-2013

80 1,2

oil + cond Mb

2013-2017 70

80

WTI $/b

condensate 1,0

60

0,8

50 % P C / P40 a

d / b 0,7 M 0,5

70 60 50 40

30 30

150

0,4 20

100

0,3

50

0,1

20

10

10

0 0 2005 Jean Laherrere March 2018

b / $ I T W

2010

2015

year

2020

0,0 2025

http://www.rrc.state.tx.us/eagleford http://www.rrc.state.tx.us/eagleford/index.php /index.php

0

500

Jean Laherrere Jan 2018

1000

1500

2000

2500

300 0

0 3 500


From Mason Inman data: AEO2013 to 2018

"&

US Eagle Ford cumulative production fromAEO & forecast U = 3 Gb

/0123 567. 682 976.:;<86=

20

'"&

AEO2018 18

AEO2017

'"%

AEO2016

16

AEO2015

'"$

AEO2014

14

AEO2013

'"#

U = 3 Gb

12 '"! . , + !"&

past

b10 G

8 !"%

6 !"$

4 !"#

2 !"! ' (( !

# !! !

# !' !

# !# !

# !) !

# !$ !

>/?#!') >/?# !') /0123567.

>/?#!'$ /0123567.

>/?#!'* /0123567.

>/?#!'% >/?# !'% /0123567.

>/?#!'@ /0123567.

>/?#!'& /0123567.

# !* !

0 2005

2010

2015

2020

2025

2030

2035

year

Jean Laherrere March2018

2040

2045

2050

source Mason Inman

-Tight oil: Permian Basin HL of Permian LTO monthly oil production production 2000- sept 2017

US LTO Permian monthly oil production for U = 10 Gb 2,0

10 000

3

120 aP/CP%

1,8

9 000

March2015-Feb2017

8 000

WTI

Permian play real LTO ?

1,6

U = 10 Gb 1,4 1,2

6 000

U = 10 Gb CP Mb

5 000

0,8

4 000

0,6

96

b 7 000 M

CP+RR EIA 1P

d / b1,0 M

108

3 000

source: EIA/FAQ

n o i t c u d o r p e v i t a l u m u c

84 2 72

d / b k

60 source: EIA/FAQ 48

1 36

0,4

2 000

24

0,2

1 000

12

0,0 2000

2005

2010

2015

2020

2025

2030

2035

2040

2045

0

0 2050

0

year


b / $ I T W

2 000

4 000


6 000

8 000

0 12 000

10 000


All Permian basin annual production displays a decline since the peak of 1974 which is constant at 3%/a until 2005 before the burst of LTO, this 3% decline is extrapolated down to 2017 and the difference with all oil production is assumed to be the LTO, in agreement with EIA values, except for the period 2005-2010 where the EIA confuses LTO and horizontal wells Permian Basin LTO oil production Hubbert linearization 2004-2017

Permian Basin oil production & forecasts from ultimates 900

decline3% + U=10 Gb

35

2,5

U = 50 Gb 800

Tx+NM = conv

2,2

aP/CP% 30

decline 3% 700

2012-2016

U LTO = 10 Gb

1,9

LTO =all-decline3%

b 600 M n o i t c 500 u d o r p l 400 a u n n 300 a

25

LTO EIA/FAQ 1,6

all PB EIA

1,4

1,1

d / b M

20

% P C / P a15

0,8 10

200

0,5

100

0,3

0 1920

5

0,0 1930

1940


1950

1960

1970

1980

1990

year

2000

2010

2020

2030

2040

2050

2060

sourceTxRRC & NMemnrd

0 0

1

2


3

4

5

6

7

8

9

10

11 11

12 12

13 13

14 14

cumulative oil production Gb

"'

From Mason Inman data: AEO 2013 to 2018 Permian cumulative oil production from AEO & U = 10 Gb

-./0123 516 7/5,89:153 '"#

50

'"!

45

AEO2018 AEO2017 AEO2016

&"#

40

AEO2015

&"!

AEO2014

35

%"#

AEO2013

, + *

%"!

30

$"#

b25 G

)

$"!

U = 10 Gb past

20

!"#

15 !"! $ (( !

% !! !

%!$ !

% !%!

% !& !

% !' !

% !# !

10

;<=%!$& -./0123>2?13 ;<=%!$' -./0123@ A;8?:13 BC26D E ;F2653+>53. G7/13H? E G7/2*.//I E J56K9207L

5

;<=%!$# -./0123@ A;8?:13 BC26D E ;F2653+>53. G7/13H? E G7/2*.//I E J56K9207L ;<=%!$M -./0123@ A;8?:13 BC26D E ;F2653+>53. G7/13H? E G7/2*.//I E J56K9207L

0 2 00 00 0

;<=%!$N -./0123@ A;8?:13 BC26D E ;F2653+>53. G7/13H? E G7/2*.//I E J56K9207L ;<=%!$O -./0123@ A;8?:13 BC26D E ;F2653+>53. G7/13H? E G7/2*.//I E J56K9207L

2 00 00 5

2 01 01 0

2 01 01 5

2 02 02 0

2 02 02 5

2 03 03 0

2 03 03 5

2 04 04 0

2 04 04 5

2 05 05 0

year


-Tight oil: all less Permian, Bakken & Eagle Ford all LTO-Permian-Bakken-Eagle Ford monthly production 0,7

US HL of all LTO-Permian-Bakken-Eagle Ford monthly production

2

3 500 LTO-Permian-Bakken-Eagle U = 3 Gb

0,6

Aug2015-Jul2017

3 000

real LTO? CP+RR

0,5

120

aP/CP% 100

WTI

b

EIA 1P

2 500 M

0,2

n o i t c u 2 000 d o r p e v 1 500 i t a l u m 1 000 u c

0,1

500

U = 3 Gb CP Mb

d 0,4 / b M 0,3

80

% P1 C / P a

60

40

20

0,0 2000 2005 Jean Laherrere Feb 2018

-

2010

2015

2020

2025

0

0 2030

0

500

1000


year

1500

2000

2500

3000

3500

0 40 00


Tight oil: all US US LTO monthly production from EIA play & forecast U= 20 Gb 5

US HL of LTO production from EIA play 1953-Dec2017 25 000

4

120

all plays

2000-Sept2017

U = 20 Gb 4

Dec2012-Feb2017

CP Mb EIA 1P

3 b M n o i 15 000 t c u d % o P r 2 p C / e P v a i 10 000 t a l u m u c

CP+RR U = 20 Gb 3

d / b M 2

80

b / $ T W

60 I

ultimate in Gb Permian = 10 Bakken = 4.5 Eagle Ford = 3 r es es t = 3 total = 20.5

1

1

100

WTI

20 000

5 000

40

20

CP 1953-1999 = 42 Mb 0 2000

2005


2010

2015

2020

year

2025

2030

0 2035

0

0 0 2 000 4 000 6 000 8 000 10 000 000 12 000 000 14 000 000 16 000 000 18 000 000 20 000 000 22 000 000 24 000 Jean Laherrere Feb 2018 cumulative production Mb

"(

From Mason Inman data: AEO 2013 to 2018 ,-./0 2,3 45-678.9-:

US LTO cumulative production from AEO & U=20 Gb

+"!

110

*"!

100

AEO2018 AEO2017

90

)"!

AEO2016 80

AEO2015

("!

AEO2014

70

AEO2013

'"!

b G

&"!

U = 20 Gb

60

past

50

%"!

40

$"!

30 20

#"!

10 !"! # ++ !

$ !! !

$ !# !

$ !$ !

$ !% !

$ !& !

;<3$!# ;<3 $!#% ,-. ,-./0 /0

;<3$!# ;<3 $!#& ,-. ,-./0 /0

;<3$!# ;<3 $!#' ,-. ,-./0 /0

;<3$!# ;<3 $!#( ,-. ,-./0 /0

;<3$!# ;<3 $!#) ,-. ,-./0 /0

;<3$!# ;<3 $!#* ,-. ,-./0 /0

$ !' !

0 1 99 99 0

1 99 99 5

2 00 00 0

2 00 00 5

2 01 01 0

2 01 01 5

2 02 02 0

2 02 02 5

2 03 03 0

2 03 03 5

2 04 04 0

2 04 04 5

2 05 05 0

year


-Crude oil: USL48 without Alaska USL48 crude oil (incl condensate) oil production 3,5

US Lower 48 HL of oil production 1859-2017

280

9

USL48 3,0

8

240

USL48 less LTO U = 235 Gb

200 b G n o i t c 160 u d o r p e 120 i v t a l u m 80 u c

U = 215 Gb

2,5

U = 235 Gb

b G n 2,0 o i t c u d o 1,5 r p l a u n 1,0 n a

U less LTO = 215 Gb cum prod + reserves cum prod cum USL48 less LTO

1859-2017 1978-2008 before LTO

7

1930-1972 at Hubbert's 1980 paper time

% 6 e v i t a5 l u m u c4 / l a u n3 n a 2

0,5

40

0,0 1860 1880 1900 Jean Laherrere Laherrere Feb 2018

1920

1940

1960

1980

2000

2020

2040

2060

1 0

0 2080


year

80

100

120

140

160

180

200

220

240

260

cumulative production Gb

-Crude oil: US US HL of crude oil production 1859-2017

US crude oil + condensate production from EIA & forecasts from U=280 Gb & AEO 5,0

300

9

270

8

AEO2018 4,5

AEO2017

aP/CP%

AEO2016

b4,0 G e t a s 3,5 n e d n o c +3,0 e d u r 2,5 c n o i t c 2,0 u d o r p l 1,5 a u n n a 1,0

AEO2015

240

b G s e 210 v r e s e r 180 & n o i 150 t c u d o r 120 p e v i t a l 90 u m u c 60

AEO2014 U=280 Gb past cum + 1P U = 280 Gb cum prod

1931-2007 7

% e6 v i t a5 l u m u c4 / l a u n3 n a

AEO2018 extrapolated towards 2100 = 500 Gb

2 1

0,5

30

0 0,0 186 0

18 80


1 900

19 20

1 940

196 0

19 80

year

2 000

202 0

20 40

0 2 06 0

0

50

100


150

200

250

300

350

400

450

500

cumulative production Gb

")

The difference between AEO 2018 and my forecast for U = 280 Gb is over 2 Gb in 2030 and 3.8 Gb in 2050. AEO 2018 crude oil consumption is forecasted flat around 6.2 Gb/a from 2016 to 2050; But in percentage of AEO 2018 my forecast is 50% in 2030 but only 6.5 % in 2050 US crude oil production & consumption AEO2018 & U=280 Gb 6,5

100

6,0

90

5,5

AEO2018 cons

b G5,0 e t a s n4,5 e d n o c 4,0 + e d3,5 u r c n3,0 o i t c u d2,5 o r p l 2,0 a u n n1,5 a

AEO2018 prod

80

U=280 Gb AEO2018-U280Gb

70

past

8 1 2 O E / 50 A b

% U280Gb/AEO2018

60 0

G 0 8 2 40 U % 30

20

1,0 10

0,5 0,0 20 05

20 10

20 15

2 020

2 025

2 030

2 035

2 040

2 045

0 2 050

year


Summary for the oil plays oil play play Gb Bakken Eagle F ord P ermian LTO U SL48 US

ultima ultimate te 4,5 3 10 20 235 280

cum prod 2017 2,5 2,5 3,5 10,4 204 222

remain remaining ing 2017 2, 0 0, 5 6, 5 9, 6 31 58

-EIA/AEO forecasts evolution EIA/AEO forecasts from 1979 to 2018 display a huge and chaotic range of uncertainty: it means that the last forecast is likely to be poor too! For example AEO 2011 forecasted 6 Mb/d for the US in 2020 when over 9 Mb/d was reached in 2015! AEO 1979

US crude oil production forecasts from USDOE/EIA/AEO

12

US crude oil production forecasts from USDOE/EIA/AEO

AEO 1982 AEO 1983

12

AEO 1985

11

AEO 1990

11

AEO 1994

10

AEO 1995

for 2050

10

AEO 1996

9

AEO 1997

d / b8 M n o7 i t c u d6 o r p l i5 o e d u r c4

AEO 1998 AEO 1999 AEO 2000 AEO 2001 AEO 2002

?

AEO 2003 AEO 2004 AEO 2005 AEO 2006 AEO 2007 AEO 2008

for 2040 9

for 2030

d / b M 8 n o i t c 7 u d o r p 6 l i o e d 5 u r c

for 2020 for 2010

4

AEO 2009 AEO 2010

3

3

AEO 2011 AEO 2012

2

AEO 2013

2

AEO 2014

1

AEO 2015

1

AEO 2016

0 1960

AEO 2017

1970

1980

1990


2000

2010

2020

2030

year

2040

2050

2060

2070

2080

2090

2100

AEO 2018 actual

0 1990

1995

Jean Laherrere Feb2018

2000

2005

2010

2015

2020

year of forecast

"*

US cumulative crude oil production forecasts from USDOE/EIA/AEO

US cumulative crude oil production forecasts from USDOE/EIA/AEO

AEO 1979

500

AEO 1982 AEO 1983

400

AEO 1985

450

AEO 1990

?

AEO 1994 AEO 1995

400

AEO 1996 AEO 1997

b350 G n o i t c 300 u d o r p l i 250 o e d u r 200 c e v i t a l u150 m u c

AEO 1998 AEO 1999 AEO 2000 AEO 2001 AEO 2002 AEO 2003 AEO 2004 AEO 2005 AEO 2006 AEO 2007 AEO 2008 AEO 2009 AEO 2010 AEO 2011 AEO 2012

100

350

b G n o300 i t c u d o250 r p l i o e200 d u r c e v150 i t a l u m u100 c

AEO 2013 AEO 2014

for 2020 for 2030 for 2040

50 for 2050

AEO 2015

50

for 2010

AEO 2016 AEO 2017

0 19 6 0

AEO 2018

19 70

1 980

1990


2000

201 0

2 0 20

2 030

year

2 040

2050

206 0

20 70

2080

2090

2100

cum actual cum +1P

0 1990 1995 Jean Laherrere Feb

2000

2005

2010

2015

2020

year of forecast

Rystad (a Norwegian data seller) has published a paper on world reserves in 2016. Laherrere J.H. 2016 « World, US, Saudi Arabia, Russia & UK oil production & reserves -Comments on Rystad 2016 world reserves » August http://aspofrance.org/files/reservesUS_SA_%20Ru_UK-JL2016.pdf https://aspofrance.org/2016/08/11/world-us-saudi-arabia-russia-uk-oil-production-reserves-august-2016-jeanlaherrere/

Bowden reported reported in 1982 1982 the US crude crude oil resources resources (ultimate?) (ultimate?) showing showing an evolution evolution with with time: ultimates less than 200 Gb from 1940 to 1956 (Hubbert in 1956 was using 150 & 200 Gb for USL48), between 150 and 600 Gb (with Zapp’s estimate in 1962 = 590 Gb from unrealistic recovery per feet drilled) from 1956 to 1974 and between 200 and 280 Gb from 1974 to 1980: the range was wild and it is still!

The future US crude oil (+condensate) production is modeled with the likely ultimate of 300 Gb and the unlikely Rystad 480 Gb and the EIA/AEO forecasts from 2013 to 2016. It appears that Rystad ultimate ultimate of 480 Gb Gb is related related to AEO 2016 2016 forecast forecast of more more than 11 Mb/d in 2040. There There is a wild change in LTO forecasts between AEO 2015 and AEO 2016

#+

-Other forecasts David Hughes 2018 displays US crude oil production from AEO2018 peaking in 2042, because of steady tight oil but not his own forecast.

As for unconventional gas, DNV forecasts unconventional onshore oil production for North America, but if for gas Canada production is small compared with the US, it is not the same for oil. CAPP forecasts the oilsands to increase by 1 Mb/d from 2015 to 2030 for Canada, when AEO2018 forecasts an increase of 2 Mb/d for the US, when DNV forecasts an increase of 4 Mb/d for North America: it means that DNV is more optimistic than EIA

ExxonMobil Outlook 2018 forecasts that tight oil in 2040 will be 3 times the value of 2016

#"

-My forecasts If the performance of the EIA is not good in forecasting US crude oil production, what about my forecasting? My modeling of the future is based on the estimate of the ultimates My estimate of the US crude oil ultimate has changed from 220 to 300 Gb between 2002 and 2018, when the extrapolation of AEO 2002 cumulative production to 2100 (assumed close to ultimate) is 350 Gb and AEO2018 500 Gb. My change is less than EIA US all sit site year year fore foreccast ult ultimat mate Gb Uppsala 2002 220 Enc Energy 2003 230 Lisbon 2005 230 Beijing 2006 230 Luxembourg 2006 250 comRys tad 2016 300 2018 280

U SL48 sit site yea year fore foreccast ast ult ultimate Gb Enc Energy 2003 200 EN SM P 2004 200 M IT 2014 225 2018 235

US cumulative crude oil production forecasts from USDOE/EIA/AEO 500

400

US cumulative crude oil production forecasts from USDOE/EIA/AEO 2018 & 2002 and JL ultimate

450 AEO 2018

350

b G n o300 i t c u d o250 r p l i o e200 d u r c e v i 150 t a l u m 100 u c

?

AEO 2002

400 JL ultimate2018

b350 G n o i t c 300 u d o r p l i 250 o e d u r 200 c e v i t a150 l u m u c

for 2010 for 2020 for 2030 for 2040

JL ultimate2002 cum actual

100

for 2050

50

ultimates JL

0 19 90 1 9 95 Jean Laherrere Laherrere Feb 2018

50

2 00 0

2 00 5

2 010

20 15

0 1960

2 0 20

year of forecast

1970

1980

1990

Jean Laherrere March2018

2000

2010

2020

2030

2040

2050

2060

2070

2080

2090

2100

year

-Oil price and dollar value Oil price influences the US oil production, it is then important to know how the oil price changes. The best correlation for the WTI is the dollar value as I presented in many papers US WTI crude oil daily price and dollar value * -1 shifted 30 days

US WTI crude oil daily price and dollar value * -1 150 135

70

-55

WTI $/b Dollar Index (major currencies)*-1

http://www.federalreserve.g http://www.federalreserve.gov/releases/h1 ov/releases/h10/sum 0/sum mary/indexn96_b.htm http://www.eia.gov/dnav/pe http://www.eia.gov/dnav/pet/hist/LeafHan t/hist/LeafHandler.as dler.as hx?n=PET&s=rwtc&f=D

-60

120

-65

105

-70

b / 90 $ e c i r p 75 l i o I T 60 W

-75 -80 -85

45

-90

30

-95

15

-100

1 * x e d n i r a l l o d s e i c n e r r u c r o j a m l a n i m o n

-85

http://www.federalreserve.gov/releases/ h10/summary/indexn96_b.htm https://research.stlouisfed.org/fred2/seri es/DCOILWTICO/downloaddata

-86 -87

60 -88 -89

b / 50 $ e c i r p l i o I T40 W

-90 -91 -92 -93 -94

30 -95 WTI $/b -96

dollar shift 30 days

0 1/1/ 00 Jean Laherrere March 2018

12/31/ 04

1/1/ 10

date

1/1/ 15

-105 1/2/ 20

20 Jan-15 Jan-16 Jean Laherrere March 2018

Jan -17

Jan-18

s y a d 0 3 d e t f i h s 1 * x e d n i r a l l o d s e i c n e r r u c r o j a m l a n i m o n

-97 Jan-1 9

date

-US private crude oil stocks and WTI 3 months before

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Some believe that the oil price follows the private stocks of crude oil, but since 2014 it appears that the stocks follows the WTI 13 weeks before, except few months in 2017 after the OPEC Russia deal for reducing production US weekly private stocks crude oil & WTI *-1 shifted 13 weeks

US weekly private stocks crude oil & WTI *-1 shifted 13 weeks

540

-15

520

-25

500

-35

b 480 M460 l i o e d 440 u r c 420 s k c 400 o t s e 380 t a v i r 360 p S U 340

-45 -55 -65 -75 -85 Weekly U.S. Ending Stocks excluding SPR of Crude Oil "excluding lease stock" Mb

2016

2017

year

-95

0

510

-20

b M l 460 i o e d u r c410 s k c o t s 360 e t a v i r310 p S U

e r o f e -60 b s k e e -80 w 3 1 1 -100 * I T -120 W -40

Weekly U.S. Ending Stocks e xcluding SPR of Crude Oil "excluding lease stock stock"" Mb WTI *-1 13 weeks before

260

WTI *-1 13 weeks before

-140

-105

320 300 2014 2015 Jean Laherrere 14 March 2018

e r o f e b s k e e w 3 1 1 * I T W

560

2018

-115 2019

210 1980

1985

1990


1995

2000

2005

2010

2015

-160 2020

year

Conclusions The USDOE/EIA believes that the US oil and gas production will be higher in 2050 (and in every year in between) than in 2017, based on the growth of shale plays coming from the drilling of a huge number of wells. They do so without bothering to check if there is enough room in the sweet spots to do so or if the yield in the non sweet spots is enough to generate that much oil ; we believe the contrary, based on the estimate of the ultimate of shale plays from the Hubbert linearization of past production and on the assumption that in the USL48 many cycles of past production and drilling were symmetrical that the shale plays will also display symmetrical future production curves. AEO2018 forecasts US production in 2040 for oil at 12 Mb/d, my forecast is 4 times less at 3 Mb/d, for gas at 40 Tcf, my forecast is half at 20 Tcf. It is not a small difference, but a huge one. I can be wrong, but EIA has to prove that their future drilling is possible economically and geologically, but up to now I cannot find any view from EIA on this problem. The EIA has also to estimate the ultimate of each play, but, in order to do so, they have to reject the stupid rule of the SEC (to please the bankers) forbidding the reporting of 2P (proved + probable) reserves. The EIA has to recognize the fact reported by the SPE/PRMS that the aggregation of proved (1P) reserves is incorrect, only the addition of 2P is correct. (Laherrère J.H. 2008 «Advice from an old geologist-geophysicist on how to understand Nature» presentation Statoil Oslo 14 August http://aspofrance.viabloga.com/files/JL_Statoil08_long.pdf ) USDOE/EIA should report the 2P US reserves like the USDOI/BOEM for the reserves of the Gulf of Mexico. Reporting 2P and backdating discovery allows to estimate ultimate using creaming curve. EIA once reported as an open file backdated established reserves with USDOE/EIA-0534 1990 "US oil and gas reserves by year of field discovery» Aug: it was supposed to be the first of a series, but in fact later it was censured and never updated. It is time to restart such good practice. Exxon and Total 10 years ago were reporting proved and non-proved reserves (2P), but today they report only 1P to follow the SEC rule. Today only Gazprom is reporting 1P and 2P, as also their queer ABC1.

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All scouting agencies report the confidential 2P reserves used internally by the operators to decide the development of their fields.

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Forecast for US Oil and Gas Production (Laherrère & Hall 2018)

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