will the vaca muerta be a game changer?

© 2016 IHS

Presentation

ihs.com

IHS

Argentina SymposiumWill the Vaca Muerta be a game changer?

Latin America Upstream

Ricardo Bedregal , Senior Director, +55 21 3299 9936, [email protected]

26 July 2016

ENERGY

mailto:[email protected]

© 2016 IHS. ALL RIGHTS RESERVED.

Key Takeaways

Argentina Symposium – Vaca Muerta Potential

• Vaca Muerta production could add 560 Mb/d of liquids and 6 Bcf/d of

gas, recovering totaling 2800 MMbbl of liquids and 33 Tcf of gas by

2040.

• At peak drilling activity, Vaca Muerta would require annual investments

of approximately $8 billion per year.

• Gas prone areas are more attractive than oil prone areas.

• The pace and scale of development, and foreign investment, will be

dictated by aboveground conditions.

• Production growth will not occur overnight.


The Vaca Muerta Formation: Widespread and offering

high potential

• Location map

3

• Vaca Muerta Formation covers

115,000 sq km of the Neuquen Basin

• Late Jurassic to early Cretaceous in

age

• Ranges in thickness from 100 m to

200 m over the most prospective

areas

• It is the source rock for over 13 billion

boe of conventional oil and gas

• Just over 600 wells drilled to date—

mostly in the YPF-operated Loma

Campana block

• Extent and quality of unconventional

sweet spots not clear at present

Area of most

licensing

Most drilling

activity

CHILE

Neuquén City



Modeling aboveground uncertainties, a scenario

approach


• Base Case: Macri administration successfully implements key macroeconomic

reforms and those policies endure beyond his first term. As a result, YPF,

majors, foreign IOCs and independent E&Ps all gradually increase their

investment.

• High case: A game changer emerges. The main difference between the base

case and the high case, is that in the high case we assume that Vaca Muerta

production proves to be a globally competitive and thus the speed of investment

is accelerated resulting in faster ramp-up.

• Low Case: In this scenario, there are prominent boom bust cycles, which

impede investment decisions and increase risk aversion.


From the Low to the High Case scenarios, improving aboveground

conditions is reflected in the pace of development


Source: IHS © 2016 IHS


Methodology—Vaca Muerta below ground potential

constrained by aboveground dynamics

Block

selection /

prioritization


Type well

analysis

Development

concept

Economic

competitiveness

Market

demand

Bottom-up

approach

Top-down

constraints

Price

forecast

Vaca Muerta

oil and gas

production

outlooks

(low/base/high)Government

policy

Source: IHS© 2016 IHS


Type curves reflect ongoing activity and results from

Vaca Muerta


• Horizontal liquids type well based on 45

horizontal producing wells in Loma Campana

from Vaca Muerta Formation with historical

production greater than six months.

• Initial results from Aguada Pichana and El

Orejano horizontal wells suggest that well

productivity could be even higher than the Eagle

Ford West average type well.

Potential EUR:~500 mboe


Potential EUR:~400 mboe0

200

400

600

800

1,000

1,200

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21

Ave Eagle Ford Type Well Ave Loma Campana Fitted Type Well

SOil-178(h) Fitted Type Well Ave Loma Campana Historical

SOil-178(h) Historical

Light Oil Horizontal Type Wells

Notes: Potential EUR based on 35 years of production.


Bo

e/d

Month



Potential EUR:

~2000 mboe

0

200

400

600

800

1,000

1,200

1,400

1,600

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21

Ave Eagle Ford West Type Well Ave El Orejano Fitted Type Well

Ave Aguada Pichana Fitted Type Well Ave El Orejano Historical

Ave Aguada Pichana Historical

Dry Gas Horizontal Type Wells

Notes: El Orejano and Aguada Pichana average based on 4 horizotal wells each.

Potential EUR based on 35 years of production.

Source: IHS © 2016 IHSB

oe

/d

Month


Project selection based on current development activity, capital

commitments, exploration activity, and proximity to infrastructure


• Pilot duration (1–5 years, varies depending on block size)

• Drilling/completion

• Rig allocation varies depending on block size and accessibility

• Considers Vaca Muerta Formation depth & thickness

• Wellpad drilling

• Applies learning curve of 10%

• Modular production processing facilities



Basic development assumptions:


0

1

2

3

4

5

6

7

8

2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

Dry Gas (EFW mean) 13MM Well Dry Gas (AP mean) 18MM Well

Vaca Muerta dry gas breakeven price range

Notes: Costs are in real 2016 US$; fiscount at 10%; Opex range $0.50–1.50/Mcfe;

average well cost reductions continue at 8% per year.


$/M

cf

Year

0

20

40

60

80

100

2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

Light Oil (LC Mean) 13MM Well Light Oil (LC Highest) 18MM Well

Vaca Muerta light oil breakeven price range

© 2016 IHS

$/b

bl

Year

Preliminary breakeven analysis suggests dry gas–prone

areas are currently more attractive than oil-prone areas


• Based on current average Loma Campana well

productivity, oil breakeven prices are higher than

government-regulated price of US$67.50/bbl.

• Highest producing well in Loma Campana,

however, shows that there is the potential of

being economic.

• Based on current publicly available cost data

(ex., US$13MM, horizontal well 1000 meters

lateral length), and using EFW horizontal type

well, breakeven prices fall below the

government-regulated price of $7.50/MMBtu.

• Initial results from Aguada Pichana and El

Orejano horizontal wells indicate economics

could be even more attractive.

Most productive well

Loma CampanaAguada Pichana average

well productivity

Notes: Costs are in real 2016 US$; discount at 10%; Opex $10/boe; average well

cost reductions continue at 8% per year.

Source: IHS


Vaca Muerta liquids production could add 560 Mb/d of oil

by 2040, recovering 2800 MMbbl


0

200

400

600

800

1,000

1,200

1,400

2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040

Low Base High

Vaca Muerta Liquids Production by Scenario

Notes: Boxes reflect the number of active operators


Mb

/d

Year


We do not expect the Vaca Muerta ramp-up to be a repeat

of Eagle Ford even in the most optimistic scenario


2

16

18

59

73

77

78

75

0

200

400

600

800

1,000

1,200

1,400

2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040

Low Base High Eagle Ford

Vaca Muerta Liquids Production by Scenario

Notes: Boxes reflect the number of active operators


Mb

/d

Year


In the Base Case, Vaca Muerta liquids production more

than offsets conventional declines by 2020


0

100

200

300

400

500

600

700

800

900

1,000

2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040

Base Production Low Base High

Argentina Liquids Production by Scenario

Source: IHS, Ministerio de Energía y Minería © 2016 IHS

Year

Mb

/d


Vaca Muerta gas production could add 150 MMcm/d of

gas by 2040, recovering 33 Tcf


0

50

100

150

200

250

2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040

Low Base High

Vaca Muerta Gas Production by Scenario

Notes: Gas production is net to market


MM

cm

/d

Year


In the base case, Vaca Muerta enables the country to

reduce its dependence on LNG imports in the 2020s


0

50

100

150

200

250

300

0

50

100

150

200

250

300

2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040

Base Production (+ Tight Gas) Low Base High Reference Demand

Argentina Gas Production by Scenario

Notes: Gas production is net to market


MM

cm

/d

Year


At peak drilling activity, Vaca Muerta could require

annual investments of ~$8Bn/y


0

500

1,000

1,500

2,000

2,500

0

2,000

4,000

6,000

8,000

10,000

12,000

2016 2018 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040

To

tal E

qu

ivale

nt

Pro

du

cti

on

(m

bo

e/d

)

Low (left) Base (left) High (left) Low (right) Base (right) High (right)

Vaca Muerta Drilling Capex and Production

Notes: Real 2016 USD


To

tal D

rill

ing

Cap

ex

(U

SD

in

mil

lio

ns

)

Year


At peak drilling activity, Vaca Muerta dry gas & wet gas

blocks could require annual investments of ~$5Bn/yr.


0

200

400

600

800

1,000

1,200

1,400

1,600

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

2016 2018 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040

To

tal E

qu

iva

len

t P

rod

uc

tio

n (

mb

oe/d

)

Gas Prone Areas (left) Liquid Prone Areas (left) Base (right)

Vaca Muerta Drilling Capex and Production (Base Case)

Notes: Real 2016 USD


To

tal D

rillin

g C

ap

ex

(U

SD

in

millio

ns

)

Year


Pace and scale of Vaca Muerta production growth has

important implications for the upstream service sector


47

130

182

0

50

100

150

200

250

2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040

Low Base High

Average Rig Count by Scenario

Notes: Historical rig counts have been estimated


Nu

mb

er

of

Rig

s

Year


Base Case would require operators drill over 1000 wells

per year by 2023, rising to 1500 per year by 2040


0

500

1,000

1,500

2,000

2,500

2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040

Low Base High

Well Count by Scenario

Source: IHS, Ministry of Energy © 2016 IHS

Nu

mb

er

of

Wells

Year


YPF, Exxon, Chevron, Total, and Shell together hold

about 60% of developed acreage in 2010–40


0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

YP

F S

A

ExxonM

obil

Explo

ratio

n A

rgentin

a S

RL

Chevro

n A

rgentin

a S

RL

To

tal A

ustr

al S

A

Sh

ell

(O&

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evelo

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ents

Ltd

)

Win

ters

hall

Energ

ia S

A

G&

P N

euquen S

AP

EM

Pa

n A

merican E

nerg

y L

LC

Plu

spetr

ol S

A

Pe

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ra E

ntr

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om

as S

A (

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L)

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ol S

A

Sa

n J

org

e P

etr

ole

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SA

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es I

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Pe

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A

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Energ

ia A

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Pe

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&P

Arg

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a S

A

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trole

ra P

am

pa S

A

Ma

dale

na A

ustr

al S

A

AE

AQ

Me

danito S

A

Inte

rnatio

nal F

inance C

orp

Roch S

A

An

des E

nerg

ia A

rgentin

a S

A

Ke

tsa

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A &

Kilw

er

SA

Dow

Quim

ica A

rgentin

a S

A

En

erg

ia A

rgentin

a S

A (

EN

AR

SA

)

Operator (left axis) Partner (left axis) Cumulative % (right axis)

Base case - Developed acreage by player 2010–40

© 2016 IHS

Acre

ag

e s

q k

m

Notes: Cumulative area reflects 6.830 sq km drained in 2010–40 in Base case.

Source: IHS


Where are we today?


0

2

4

6

8

10

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14

16

18

20

Nov-1

0

Fe

b-1

1

Ma

y-1

1

Au

g-1

1

Nov-1

1

Fe

b-1

2

Ma

y-1

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Au

g-1

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Nov-1

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g-1

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Nov-1

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b-1

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y-1

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Au

g-1

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Nov-1

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Fe

b-1

5

Ma

y-1

5

Au

g-1

5

Nov-1

5

Fe

b-1

6

Ma

y-1

6

Vertical/Directional Horizontal

Historical Well Count by Type at Loma Campana


Nu

mb

er

of

Well

s

Month

02468

101214161820

Nov-1

0

Fe

b-1

1

Ma

y-1

1

Au

g-1

1

Nov-1

1

Fe

b-1

2

Ma

y-1

2

Au

g-1

2

Nov-1

2

Fe

b-1

3

Ma

y-1

3

Au

g-1

3

Nov-1

3

Fe

b-1

4

Ma

y-1

4

Au

g-1

4

Nov-1

4

Fe

b-1

5

Ma

y-1

5

Au

g-1

5

Nov-1

5

Fe

b-1

6

Ma

y-1

6


Historical Well Count by Type at El Orejano and Aguada Pichana


Nu

mb

er

of

Well

s

Month

Lig

ht

Oil

Dry

Gas


Recent trend shows higher IP’s for horizontal wells


0

2

4

6

8

10

12

14

16

18

20

Nov-1

0

Fe

b-1

1

Ma

y-1

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Au

g-1

1

Nov-1

1

Fe

b-1

2

Ma

y-1

2

Au

g-1

2

Nov-1

2

Fe

b-1

3

Ma

y-1

3

Au

g-1

3

Nov-1

3

Fe

b-1

4

Ma

y-1

4

Au

g-1

4

Nov-1

4

Fe

b-1

5

Ma

y-1

5

Au

g-1

5

Nov-1

5

Fe

b-1

6

Ma

y-1

6


Historical Well Count by Type at Loma Campana


Nu

mb

er

of

Well

s

Month

02468

101214161820

Nov-1

0

Fe

b-1

1

Ma

y-1

1

Au

g-1

1

Nov-1

1

Fe

b-1

2

Ma

y-1

2

Au

g-1

2

Nov-1

2

Fe

b-1

3

Ma

y-1

3

Au

g-1

3

Nov-1

3

Fe

b-1

4

Ma

y-1

4

Au

g-1

4

Nov-1

4

Fe

b-1

5

Ma

y-1

5

Au

g-1

5

Nov-1

5

Fe

b-1

6

Ma

y-1

6


Historical Well Count by Type at El Orejano and Aguada Pichana


Nu

mb

er

of

Well

s

Month

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

Nov-1

0

Ma

r-1

1

Jul-

11

Nov-1

1

Ma

r-1

2

Jul-

12

Nov-1

2

Ma

r-1

3

Jul-

13

Nov-1

3

Ma

r-1

4

Jul-

14

Nov-1

4

Ma

r-1

5

Jul-

15

Nov-1

5

Ma

r-1

6

Ave IP Horizontal Well Ave IP Directional/Vertical

Historical Trend in IP by Well Type at Loma Campana


bo

e/d

Month

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

Nov-1

0

Ma

r-1

1

Jul-

11

Nov-1

1

Ma

r-1

2

Jul-

12

Nov-1

2

Ma

r-1

3

Jul-

13

Nov-1

3

Ma

r-1

4

Jul-

14

Nov-1

4

Ma

r-1

5

Jul-

15

Nov-1

5

Ma

r-1

6

Ave IP Horizontal Well Ave IP Directional/Vertical

Historical Trend in IP by Well Type at El Orejano and Aguada Pichana


bo

e/d

Month

Lig

ht

Oil

Dry

Gas


Taking a closer look at horizontal well breakeven prices


0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000N

ov-1

0

Ma

r-1

1

Jul-

11

Nov-1

1

Ma

r-1

2

Jul-

12

Nov-1

2

Ma

r-1

3

Jul-

13

Nov-1

3

Ma

r-1

4

Jul-

14

Nov-1

4

Ma

r-1

5

Jul-

15

Nov-1

5

Ma

r-1

6

Ave IP Horizontal Well



bo

e/d

Month

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

Nov-1

0

Ma

r-1

1

Jul-

11

Nov-1

1

Ma

r-1

2

Jul-

12

Nov-1

2

Ma

r-1

3

Jul-

13

Nov-1

3

Ma

r-1

4

Jul-

14

Nov-1

4

Ma

r-1

5

Jul-

15

Nov-1

5

Ma

r-1

6




bo

e/d

Month

Lig

ht

Oil

Dry

Gas

IP - 660 boe/dDecline Rate - 80%EUR - 390 mboe

0

20

40

60

80

100

120

5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20

LC. Mean_EUR_390mboe Domestic Price

Light Oil Horizontal Well Breakeven Range


Oil

Pri

ce $

/bb

l

Well Cost $MM

IP - 1332 boe/dDecline rate – 62%EUR – 1540 mboe

0

2

4

6

8

10

12

5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20

EOAP._Mean_EUR_1540mboe Domestic Price

Dry Gas Horizontal Well Breakeven Range


Gas P

rice $

/mm

btu

Well Cost $MM


Assuming horizontal well costs between US$ 11-18 MM


0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000N

ov-1

0

Ma

r-1

1

Jul-

11

Nov-1

1

Ma

r-1

2

Jul-

12

Nov-1

2

Ma

r-1

3

Jul-

13

Nov-1

3

Ma

r-1

4

Jul-

14

Nov-1

4

Ma

r-1

5

Jul-

15

Nov-1

5

Ma

r-1

6




bo

e/d

Month

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

Nov-1

0

Ma

r-1

1

Jul-

11

Nov-1

1

Ma

r-1

2

Jul-

12

Nov-1

2

Ma

r-1

3

Jul-

13

Nov-1

3

Ma

r-1

4

Jul-

14

Nov-1

4

Ma

r-1

5

Jul-

15

Nov-1

5

Ma

r-1

6




bo

e/d

Month

Lig

ht

Oil

Dry

Gas


0

20

40

60

80

100

120

5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20




Oil

Pri

ce $

/bb

l

Well Cost $MM

IP - 1332 boe/dDecline rate – 62%EUR – 1540 mboe

0

2

4

6

8

10

12

5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20




Gas P

rice $

/mm

btu

Well Cost $MM


What IP/Decline-Rate/EUR is needed to breakeven?


0

200

400

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800

1,000

1,200

1,400

1,600

1,800

2,000N

ov-1

0

Ma

r-1

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Jul-

11

Nov-1

1

Ma

r-1

2

Jul-

12

Nov-1

2

Ma

r-1

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Jul-

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Nov-1

3

Ma

r-1

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Jul-

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Nov-1

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r-1

5

Jul-

15

Nov-1

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Ma

r-1

6




bo

e/d

Month

0

200

400

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800

1,000

1,200

1,400

1,600

1,800

2,000

Nov-1

0

Ma

r-1

1

Jul-

11

Nov-1

1

Ma

r-1

2

Jul-

12

Nov-1

2

Ma

r-1

3

Jul-

13

Nov-1

3

Ma

r-1

4

Jul-

14

Nov-1

4

Ma

r-1

5

Jul-

15

Nov-1

5

Ma

r-1

6




bo

e/d

Month

Lig

ht

Oil

Dry

Gas

IP - 660 boe/dDecline Rate - 80%EUR - mboe

0

20

40

60

80

100

120

5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20




Oil

Pri

ce $

/bb

l

Well Cost $MM

IP - 1332 boe/dDecline rate – 62%

0

2

4

6

8

10

12

5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20




Gas P

rice $

/mm

btu

Well Cost $MM




0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000N

ov-1

0

Ma

r-1

1

Jul-

11

Nov-1

1

Ma

r-1

2

Jul-

12

Nov-1

2

Ma

r-1

3

Jul-

13

Nov-1

3

Ma

r-1

4

Jul-

14

Nov-1

4

Ma

r-1

5

Jul-

15

Nov-1

5

Ma

r-1

6




bo

e/d

Month

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

Nov-1

0

Ma

r-1

1

Jul-

11

Nov-1

1

Ma

r-1

2

Jul-

12

Nov-1

2

Ma

r-1

3

Jul-

13

Nov-1

3

Ma

r-1

4

Jul-

14

Nov-1

4

Ma

r-1

5

Jul-

15

Nov-1

5

Ma

r-1

6




bo

e/d

Month

Lig

ht

Oil

Dry

Gas

IP - 660 boe/dDecline Rate - 80%EUR - 390 mboe IP - 1050 boe/d

Decline Rate - 80%EUR - 600 mboe

0

20

40

60

80

100

120

5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20

LC. Mean_EUR_390mboe EUR_600mboe

Domestic Price



Oil

Pri

ce $

/bb

l

Well Cost $MM


0

2

4

6

8

10

12

5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20




Gas P

rice $

/mm

btu

Well Cost $MM




0

200

400

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800

1,000

1,200

1,400

1,600

1,800

2,000N

ov-1

0

Ma

r-1

1

Jul-

11

Nov-1

1

Ma

r-1

2

Jul-

12

Nov-1

2

Ma

r-1

3

Jul-

13

Nov-1

3

Ma

r-1

4

Jul-

14

Nov-1

4

Ma

r-1

5

Jul-

15

Nov-1

5

Ma

r-1

6




bo

e/d

Month

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

Nov-1

0

Ma

r-1

1

Jul-

11

Nov-1

1

Ma

r-1

2

Jul-

12

Nov-1

2

Ma

r-1

3

Jul-

13

Nov-1

3

Ma

r-1

4

Jul-

14

Nov-1

4

Ma

r-1

5

Jul-

15

Nov-1

5

Ma

r-1

6




bo

e/d

Month

Lig

ht

Oil

Dry

Gas




0

20

40

60

80

100

120

5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20


EUR_600mboe Domestic Price



Oil

Pri

ce $

/bb

l

Well Cost $MM


0

2

4

6

8

10

12

5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20




Gas P

rice $

/mm

btu

Well Cost $MM




0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000N

ov-1

0

Ma

r-1

1

Jul-

11

Nov-1

1

Ma

r-1

2

Jul-

12

Nov-1

2

Ma

r-1

3

Jul-

13

Nov-1

3

Ma

r-1

4

Jul-

14

Nov-1

4

Ma

r-1

5

Jul-

15

Nov-1

5

Ma

r-1

6




bo

e/d

Month

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

Nov-1

0

Ma

r-1

1

Jul-

11

Nov-1

1

Ma

r-1

2

Jul-

12

Nov-1

2

Ma

r-1

3

Jul-

13

Nov-1

3

Ma

r-1

4

Jul-

14

Nov-1

4

Ma

r-1

5

Jul-

15

Nov-1

5

Ma

r-1

6




bo

e/d

Month

Lig

ht

Oil

Dry

Gas

IP - 660 boe/dDecline Rate - 80%



0

20

40

60

80

100

120

5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20





Oil

Pri

ce $

/bb

l

Well Cost $MM

IP - 1332 boe/dDecline rate – 62%EUR - 1540 mboe

0

2

4

6

8

10

12

5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20




Gas P

rice $

/mm

btu

Well Cost $MM




0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000N

ov-1

0

Ma

r-1

1

Jul-

11

Nov-1

1

Ma

r-1

2

Jul-

12

Nov-1

2

Ma

r-1

3

Jul-

13

Nov-1

3

Ma

r-1

4

Jul-

14

Nov-1

4

Ma

r-1

5

Jul-

15

Nov-1

5

Ma

r-1

6




bo

e/d

Month

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

Nov-1

0

Ma

r-1

1

Jul-

11

Nov-1

1

Ma

r-1

2

Jul-

12

Nov-1

2

Ma

r-1

3

Jul-

13

Nov-1

3

Ma

r-1

4

Jul-

14

Nov-1

4

Ma

r-1

5

Jul-

15

Nov-1

5

Ma

r-1

6




bo

e/d

Month

Lig

ht

Oil

Dry

Gas




0

20

40

60

80

100

120

5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20





Oil

Pri

ce $

/bb

l

Well Cost $MM

IP - 1332 boe/dDecline rate – 62%EUR - 1540 mboe

IP - 856 boe/dDecline rate - 68%EUR - 830 mboe

0

2

4

6

8

10

12

5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20

EOAP._Mean_EUR_1540mboe DryGas_830mboe

Domestic Price



Gas P

rice $

/mm

btu

Well Cost $MM


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