wood mackenzie global upstream forums november 2013

Global Upstream Forums

Houston - November 13, 2013

London November 26, 2013

Trusted commercial intelligence www.woodmac.com

Trusted commercial intelligence Wood Mackenzie

2

Transforming Wood Mackenzies North American offering.

Granular

Timely

Access to the Data


3

Granular where it matters

Su

b-P

lay

Pla

y A

na

lysis

We

ll A

na

lysis

Co

mp

an

y A

na

lysis

150 Companies Modelled

200+ Plays Modelled

100+ sub-play areas in 15 Key Plays

Well data (1000s)


4

Spotlights - quick reaction and insight into key events

Timely analysis when you need it


5

Data intelligently cleaned by our experts and linked to our analysis

Access to the data behind the analysis


6

Houston Upstream Forum presentations

Slides 89-109 Upstream Capital Allocation - Value versus Volume

Tom Ellacott

Slides 104-125 Creating value through conventional and unconventional exploration: a global analysis

Julie Wilson

Slides 9-18 What is the outlook for North America and what are the key uncertainties that will impact future value

creation?

John Dunn

Slides 19-26 Ever improving technology and efficiency game Implications for North America upstream players Phani Gadde

Slides 27-34 Panel Session What are challenges realizing the value of well head liquids: infrastructure and quality? How will gas and NGL prices evolve?

NAGs, NGLs, Oils

Slides 35-45 The Appalachian Shale Gale Sub-plots behind the Marcellus headlines Jesse Jones

Slides 46-62

A Dive into the Permian Should you believe the hype? Benjamin Shattuck

Slides 63-77 The Eagle Ford Karnes Trough in post ramp-up phase A data driven case study on incremental value Callan McMahon

Slides 78-87 Panel session What defines a winning strategy for ultra-competitive onshore plays? Rob Clarke, Matt Snyder, Phani Gadde

Slides 88-177

London Forum Slides

Upstream Capital Allocation Value versus Volume

Tom Ellacott

(Please go to slide 89 for full presentation)


Creating Value

Through Conventional &

Unconventional Exploration

A Global Analysis

Julie Wilson

(Please go to slide 104 for full presentation)


What is the Outlook for North

America and what are the Key

Uncertainties that will Impact

Future Value Creation

John Dunn



10

US dominates global upstream spend

0

20

40

60

80

100

120

140

160

US Australia China Canada Russia Brazil Norway UK Mexico Iraq

US

$ b

illi

on

2013 2014 2015

Source: Wood Mackenzie

Top 10 countries for upstream development spending 2013 to 2015


11

The big two plays continue to drive Lower 48 capex

Eagle Ford Shale,

US$23bn

Bakken, US$21bn

Wolfcamp / Cline,

US$5bn Bone

Spring, US$7bn

Marcellus, US$12bn

Utica, US$7bn

Other Lower 48, US$38bn


Total = US$113 bn

0

20

40

60

80

2008 2009 2010 2011 2012 2013 2014 2015 2016

US

$ b

illi

on

Conventional

CBM

Heavy Oil

Shale Gas

Tight Gas

Tight Oil


US Lower 48 development spend by theme US oil production by type US Lower 48 development spend by play


12

Production accelerating in line with our expectations

US liquids production by play US gas production by type

0

10

20

30

40

50

60

70

80

90

2000 2004 2008 2012 2016 2020

bc

fd

Conventional Associated

CBM Tight

Shale


0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

2000 2004 2008 2012 2016 2020

Oil

an

d c

on

de

ns

ate

pro

du

cti

on

'0

00

b/d

Other emerging & established

Utica

Niobrara

Bone Spring/Wolfcamp

Eagle Ford

Bakken

Conventional

Source Wood Mackenzie


13

Wide range in performance between sub-plays

12 sub-plays

10 sub-plays

9 sub-plays

4 sub-plays

5 sub-plays

Range of sub-play type well NPV10 by key play

-4 -2 0 2 4 6 8

Bakken

Eagle Ford

Marcellus

Utica

Bone Spring

Wolfcamp

Sub-play type well NPV10 post tax



14

And there is still a lot of work to be done

0

10,000

20,000

30,000

40,000

50,000

60,000

Ca

pe

x (

US

$ m

illi

on

s)

Wolfcamp Utica

Niobrara Monterey

Marcellus Haynesville

Eagle Ford Bone Spring

Bakken / Three Forks


Remaining Lower 48 company capex by play


15

Lease and exploration spend critical factors

US unconventional lease costs, exploration spend and development value

-10,000

-5,000

0

5,000

10,000

15,000

20,000

25,000

An

ad

ark

o

Co

no

coP

hill

ips

No

ble

Murp

hy

Mara

thon

Exxo

nM

ob

il

Ch

evro

n

Ap

ach

e

Hess

Talis

ma

n

BG

Occid

enta

l

Sh

ell

Sta

toil

BH

P B

illito

n

Tota

l

BP

Va

lue

an

d c

osts

- n

o ta

x e

ffe

ct (U

S$

millio

n) Development value - High Case Lease acquisition spend Exploration spend


-10,000

-5,000

0

5,000

10,000

15,000

20,000

25,000

An

ad

ark

o

Co

no

coP

hill

ips

No

ble

Murp

hy

Mara

thon

Exxo

nM

ob

il

Che

vro

n

Ap

ach

e

He

ss

Talis

ma

n

BG

Occid

enta

l

Sh

ell

Sta

toil

BH

P B

illito

n

Tota

l

BP

Va

lue

an

d c

osts

- n

o ta

x e

ffe

ct (U

S$

millio

n)

Development value - Base Case Lease acquisition spend Exploration spend


-10,000

-5,000

0

5,000

10,000

15,000

20,000

25,000

An

ad

ark

o

Co

no

coP

hill

ips

No

ble

Murp

hy

Mara

thon

Exxo

nM

ob

il

Che

vro

n

Ap

ach

e

He

ss

Talis

ma

n

BG

Occid

enta

l

Sh

ell

Sta

toil

BH

P B

illito

n

Tota

l

BP

Va

lue

an

d c

os

ts -

no

ta

x i

mp

ac

t (U

S$

mil

lio

n)

Development value - Base Case



16

US unconventionals move the dial for companies

US unconventional organic liquid and gas reserves creation relative to global discoveries

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

0

1,000

2,000

3,000

4,000

5,000A

na

da

rko

Sh

ell

Co

no

coP

hill

ips

Exxo

nM

ob

il

Sta

toil

Nob

le

Mara

thon

Talis

ma

n

He

ss

BG

Ap

ach

e

Occid

enta

l

Murp

hy

BP

Ch

evro

n

BH

P B

illito

n

Tota

l

Res

erv

es

cre

ate

d 2

00

8-2

01

2 fro

m U

S u

nc

on

s

Co

mm

erc

ial

res

erv

es

dis

co

ve

red

(m

mb

oe

)

Liquid reserves created

Gas reserves created

% of global discoveredreserves from 2008-2012



17

Reserves commercialised, but value creation elusive

US unconventional value and reserves creation through exploration

Anadarko

ConocoPhillips

Noble

Murphy

Marathon BG

Chevron Hess

Apache Statoil

BHP Total

Talisman ExxonMobil

Occidental

BP

Shell

Average

Major

Large-cap

Mid-cap

-5,000

-3,000

-1,000

1,000

3,000

5,000

7,000

9,000

11,000

1,0

00

2,0

00

3,0

00

4,0

00

5,0

00

Fu

ll c

yc

le

va

lue

cre

ati

on

(U

S$

mil

lio

n)

Reserves commercialised (mmboe) Source: Wood Mackenzie


18 Wood Mackenzie 18

Future

Value

Creation

Development

strategy

Well

performance

Location,

location,

location

Markets,

infrastructure,

and quality

Technology

and

efficiencies

Stacked

formations and

downspacing

Future value creation hinges on many variables, including

Ever Improving Technology

and Efficiency Game

Implications for North American

upstream players

Phani Gadde



20

Shale gas and tight oil story: A saga of continuous innovation

Wood Mackenzie 20

Pad drilling supports efficiencies Improvements still underway in legacy shale plays

2,500

3,500

4,500

5,500

0

10

20

30

40

2010 2011 2012 2013

La

tera

l le

ng

th (

ft)

Da

ys

to

dri

ll a

we

ll

Barnett Drilling Days Fayetteville Drilling Days

Eagle Fd (KT) Drlng Days Barnett Lat. Length

Fayetteville Lat. Length Eagle Fd (KT) Lat. Length

Source: Wood Mackenzie Upstream Service

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

2008 H1 2009 H1 2010 H1 2011 H1 2012 H1 2013 H1

% o

f w

ell

s o

n p

ad

s

Haynesville

Bakken

Eagle Ford



21

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

0

2

4

6

8

10

12

14

16

18

20

2006 2007 2008 2009 2010 2011 2012 2013

Well C

ost

(US

$ M

illio

ns)

Dri

llin

g D

ays

Drilling days

Well Cost

50-80% increase in

rig day rates

40-100% increase in frac costs

Guar

2012-2013 marks a significant shift in the cost-efficiency game - overcapacity in services

markets

Drilling days vs costs for Southwestern in Fayetteville Completion cost per stage for Anadarko Petroleum

Well Costs balancing act between efficiencies and service costs

0

50

100

150

200

250

300

Haynesville Marcellus Avalon Bone SpringC

os

t/S

tag

e (

US

$ ,

00

0)

2011

2012

Source: Wood Mackenzie Upstream Service, Company Presentations Source: Wood Mackenzie Upstream Service, Company Presentations


22

New technology likely to further improve economics

Frac

placement

What

else?

Dual

laterals

Automated

drilling


Operational practices are an important

element in the efficiency game

Multiple technologies and practices,

each making a marginal contribution,

together drive the continued

improvement

Costs: Pad drilling, rig fleet upgrades,

spudder rigs, mud motors, high build RSS,

drill bits , mud pulse drilling/steering, plug

and perf vs sliding/cemented sleeves,

smaller holes, longer laterals, vertical

integration frac crews/rigs/sand mines, infrastructure, water transportation and

logistics, computerized systems to improve

drilling / completion designs, LNG/Natural

gas rigs

Well performance: Lateral length, frac

spacing, cluster spacing, proppant and fluid

placement, artificial lift, well density, well

placement/field development plans, choke

size reduction, marinating


23 23

Cost and Performance Improvements Improve Value

IRR Increases for a Well in Eagle Ford Edwards Condensate

Current % IRR

10% Drill. Cost Red. -

Efficiencies

10% Drill. Cost Red. - New Technology

10% Comp. Cost Red. - New Technology

10% Perf. Imp

Breakeven US$63.98/boe

Breakeven US$57.54/boe

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

50%%

IR

R



24 24

Reduction in breakevens likely to improve returns for tight oil


0

1

2

3

4

5

6

7

0

20

40

60

80

100

120

140

160

Bakke

n-P

ars

ha

ll an

d S

anis

h

Eagle

Fo

rd-K

arn

es T

rough

Utica-S

W C

ore

Bone

Sp

ring

-Pecos R

ive

r

Bakke

n-N

esson A

nticlin

e S

ou

th

Utica-C

ond

ensate

Eagle

Fo

rd-E

dw

ard

s C

on

d.

Wolfca

mp-O

zona

Eagle

Fo

rd-H

aw

kvill

e C

ond

.

Bakke

n-N

ort

hw

est D

un

n

Bakke

n-W

este

rn W

illia

ms

Bone

Sp

ring

-Nort

hw

est

Sh

elf

Bakke

n-N

ort

he

rn M

ountr

ail

Wolfca

mp-G

lasscock N

ose

Wolfca

mp-D

el. B

asin

Bakke

n-W

est

Nesson

Eagle

Fo

rd-B

lack O

il

Bakke

n-N

esson A

nticlin

e N

ort

h

Eagle

Fo

rd-M

averick C

on

d.

Bone

Sp

ring

-Centr

al B

asin

Bakke

n-E

lm C

oule

e

Wolfca

mp-D

eep B

asin

Bakke

n-D

ivid

e C

oun

ty

Bakke

n-S

outh

ern

Pin

cho

ut

Bone

Sp

ring

-Edd

y C

oun

ty

Wolfca

mp-C

arb

. P

lat.

Utica-W

este

rn O

il

Eagle

Fo

rd-M

averick O

il

Eagle

Fo

rd-N

ort

hea

st

Oil

Ris

ke

d U

nd

rill

ed

Reserv

es (

bn

bo

e)

Bre

akev

en

(U

S$/b

oe)

Breakeven Reserves


25 25

Reduction in breakevens can push the floor on gas prices


0

20

40

60

80

100

120

140

0

1

2

3

4

5

6

7

8

Ma

rce

llus-S

usqu

eha

nna

Core

Fayett

evill

e

Ma

rce

llus-B

radfo

rd A

rea

Ma

rce

llus-S

ou

thw

est

PA

Ma

rce

llus-S

ou

thw

est

Core

Ma

rce

llus-W

V R

ich G

as

Utica-W

et G

as

Barn

ett

Eagle

Fo

rd-S

ou

thw

est

Ga

s

Ha

yn

esvill

e-T

ier

1

Ma

rce

llus-N

ort

hea

st

PA

Ma

rce

llus-A

lleg

hen

y M

oun

tain

s

Barn

ett

-Sou

thw

est

Utica-L

ea

n G

as

Ha

yn

esvill

e-T

ier

2

Ma

rce

llus-W

V D

ry G

as

Ma

rce

llus-C

entr

al P

A

Un

dri

lled

Reserv

es (

tcfe

)

Bre

akev

en

(U

S$/m

cfe

)

Breakeven Reserves


26 26

Corporate effect is pronounced but portfolio scale dictates impact

0%

2%

4%

6%

8%

10%

12%

North American Mid-Cap

Asian NOC North AmericanLarge-Cap

International Large-Cap

Major

Incre

ase in

NP

V,1

0 f

or

10%

cap

ex c

ost

defl

ati

on

(o

nsh

ore

No

rth

Am

eri

ca)

Onshore North America NPV,10 impact Global portfolio NPV,10 impact


What are Challenges Realizing

the Value of Well Head Liquids:

Infrastructure and Quality?

How will Gas and NGL Prices Evolve?

Gabriel Harris, Anne Keller, Skip York



28

$3.5

$4.0

$4.5

$5.0

$5.5

$6.0

2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

$/m

mb

tu

Henry Hub Midcontinent Dominion South Point Opal

Cheyenne Permian AECO San Juan

Henry Hub strength reflects new Gulf Coast markets; risks around

power demand and supply drivers

Source: Wood Mackenzie North America Gas Service

Price outlook

Power load growth

Carbon and policy initiatives

+6 bcfd LNG Exports 2016-2020

Production growth continues


29

Beyond next summer, the Southeast (and later New England) will

increasingly be the target market for Marcellus supplies

Marcellus destinations and key projects

0

2

4

6

8

10

12

14

16

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

bc

fd

Pennsylvania New York New Jersey New England Nearby south

Nearby west Canada Far south Other

Nearby south: Delaware, Maryland, West

Virginia, Virginia Nearby west: Ohio, Kentucky,

Indiana

Empire to Chippawa

Leidy southeast

AIM

Transco backhauls

AIM

exp.?

Spectra NY-

NJ


30

Short-term infrastructure constraints mean that Marcellus production

upside may not have a significant impact on prices elsewhere

Pennsylvania gas-fired generation Utilization at major Penn. CCs & South Point prices

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

1.8

2 3 4 5

bc

fd

Dominion South Point ($/mmbtu)

2014 2015

2012

2011

2010

2009

2013

Expected range

Marcellus

upside

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Jan. 1,2008

Jan. 1,2009

Jan. 1,2010

Jan. 1,2011

Jan. 1,2012

Jan. 1,2013

$5+/mmbtu $4-5/mmbtu $3-4/mmbtu $2-3/mmbtu


31

Pipelines - Buying Ethane Optionality:

Buildout 1.0 investment provides capacity to move must recover ethane to markets to continue drilling rich gas and oil leases

More optionality on future volumes, especially in the

NE; future barrels will be more market sensitive

NGL Infrastructure Catching Up With The Drillers Providing Optionality for Ethane

Processing Working to Keep Up With Growth

More gathering and processing needed to bring

production from edge leases to market, reduce flaring

Ethane economics may influence timing of cryogenic

capacity additions increase use of ethane in field operations

0

10

20

30

40

50

60

70

80

90

2012 2013 2014 2015 2016 2017 2018 2019 2020

bcf

/d

Gas Processing Capacity Wet Gas Production


0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

2012 2013 2014 2015 2016 2017 2018 2019 2020

k b

pd

NE Rejection Case NE Recovery Case

Y-Grade Pipelines NE Ethane Take awaySource: Wood Mackenzie

Gas Processing Capacity Utilization

(ex Louisiana)

NGL & Ethane Pipelines

Field to Market Centers


32

NGL Price Trends

Per Barrel Pricing Reflects Declines in Ethane Values/Pentane Volumes

January 2012 was the highest ethane volume recovery month in history

Future ethane content will rise with pull from ethylene demand

C5+ is competing with the lighter part of the condensate barrel for market share

36%

32%

10%

8%

14%

C2 C3 NC4 IC4 C5+

Ethane Rejection August 2013

39% WTI - $.98/Bbl

39%

26%

9%

5%

11%

C2 C3 NC4 IC4 C5+

Ethane Recovery January 2012

48% WTI - $1.13/Bbl


33

Expanding logistics offer destination markets optionality

Gulf Coast

$86.50/bbl

East Coast

$90.50/bbl

PNW

$91.00/bbl

California

$93.75/bbl

Chicago

$90.00/bbl


34

API: 58.0 41.7 39.9 38.5 36.4

Assay comparison reveals value drivers and further opportunities

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Eagle Ford Bakken WTI Brent LLS

Yie

ld C

ut,

Wt

%

LPG

Gasoline

Kero

Distillate

VGO

Resid

The Appalachian Shale Gale

Sub-plots behind the Marcellus headlines

Jesse Jones



36

Marcellus Key Play Report 12 sub-play areas

Atlantic Ocean

Pennsylvania

VirginiaWest

Virginia

Ohio

New York

App

alac

hian

Bas

in

1

47

12

5

3

11

2

10

6

9

8

75W

75W

78W

78W

81W

81W

84W

84W

42

N

42

N

39

N

39

N

0 40 8020km Source: Wood Mackenzie

U.S.A.

Canada

Marcellus

1 - Big Sandy Field Area

2 - SW PA

3 - Allegheny Mountain

4 - Central PA

5 - High Plateau

6 - Bradford Area

7 - Northeast PA

8 - Susquehanna Core

9 - SW Core

10 - WV Rich Gas

11 - WV Dry Gas

12 - New York


37

How the Marcellus stacks up

Country Field Commercial Remaining

Gas Reserves (bcf)

Qatar North Field 261,994

Russia Bovanenkovskoye 105,828

Saudi Arabia Ghawar 71,842

Russia Gazprom dobycha Urengoi 65,573

Russia Zapolyarnoye Fields 64,715

US - Marcellus Northeast Pennsylvania 61,059

Turkmenistan South Iolotan 59,945

Russia Yamburgskoye 53,380

US - Marcellus Bradford Area 51,857

US - Marcellus Southwest Pennsylvania 44,740

Turkmenistan Dauletabad-Donmez 39,199

Australia Gorgon Project 36,687

Russia Kharasaveiskoye 36,612

Norway Troll 33,683

US - Marcellus West Virginia Rich Gas 30,162

Source: Wood Mackenzie Pathfinder0

1

2

3

4

5

6

0 20 40 60 80 100 120 140 160 180 200 220 240

Avera

ge b

reakeven p

rice (

US

$/m

cfe

)

Commercial reserves (tcfe) Source: Wood Mackenzie

Wood Mackenzie Long-term

Planning Price (US$4.64/mcf)

Marcellus commercial reserves by company Top 15 Fields Remaining commercial gas reserves


38

Atlantic Ocean

Pennsylvania

Virginia

WestVirginia

Ohio

New York

App

alac

hian

Bas

in

1

47

12

5

11

2

10

3

6

9

8

75W

75W

78W

78W

81W

81W

84W

84W

42N

42N

39N

39N


U.S.A.

Canada

Marcellus

Initial Production(mmcfd)

High (47)

Low (0)

Mid (10)


2 - SW PA


4 - Central PA

5 - High Plateau

6 - Bradford Area

7 - Northeast PA


9 - SW Core

10 - WV Rich Gas

11 - WV Dry Gas

12 - New York

Marcellus Heat Map Implied IPs


39

Well choking demonstrates infrastructure constraints

Pennsylvania

WestVirginia

Ohio

New York

App

alac

hian

Bas

in

4

7

12

5

2

10

3

6

9

8

Ohio OilGathering

Dom

inion

Lancer Gas

Company

Tenn. Gas Pipe

G

TI

Cen

tra

l H

ud

so

n G

as a

nd

Ele

ctr

ic C

orp

.

Iro

quois

Pipe

line

Oper

ating

Com

pany

Transcontinental

Cen

tral

NY

Colum

bia G

as

TX

E

Transcontinental

WV Oil

Enterprise

Tenn. G

as Pip

e

Millennium

75W

75W

78W

78W

81W

81W

42N

42N


U.S.A.

Canada

Marcellus


2 - SW PA


4 - Central PA

5 - High Plateau

6 - Bradford Area

7 - Northeast PA


9 - SW Core

10 - WV Rich Gas

11 - WV Dry Gas

12 - New York

Low

Moderate

Degree of ChokeSevere


40

Infrastructure projects gradually ease transportation constraints

-

100

200

300

400

500

600

700

800

900

-

2

4

6

8

10

12

14

Nu

um

be

r o

f w

ell

s

bc

fd

Marcellus production Potential production

Take-away capacity Marcellus well backlog



41

Condensate and rich gas production

Atlantic Ocean

Pennsylvania

Virginia

West

Virginia

Ohio

New York

App

alac

hian

Bas

in

1400

BTU

1250

BTU

1050

BTU

950 B

TU

800

BTU

1

47

12

5

11

2

10

3

6

9

8

75W

75W

78W

78W

81W

81W

84W

84W

42N

42N

39N

39N


U.S.A.

Canada

Marcellus

Producing Wells

Wells with condensate production

Wells with gas production


2 - SW PA


4 - Central PA

5 - High Plateau

6 - Bradford Area

7 - Northeast PA


9 - SW Core

10 - WV Rich Gas

11 - WV Dry Gas

12 - New York

*Contours reference calorific value of gas (BTU Content)


42

0

1

2

3

4

5

6

0 20 40 60 80 100 120 140 160 180 200 220 240

Ave

rag

e b

rea

ke

ve

n p

rice

(U

S$

/mcf)

Commercial reserves (tcfe) Source: Wood Mackenzie

Wood Mackenzie Long-term Planning Price (US$4.64/mcf)

EQ

T

Ran

ge

Ch

esap

eake

Ch

evro

n

Exxo

nM

ob

il

Corporate positioning in the Marcellus

Cab

ot


43

Corporate positioning by sub-play

Cab

ot

0

1

2

3

4

5

6

0 20 40 60 80 100 120 140 160 180 200 220 240

Su

b-p

lay b

rea

ke

ve

n p

rice

(U

S$

/mcf)

2P reserves (tcfe) Source: Wood Mackenzie

Wood Mackenzie Long-term Planning Price

(US$4.64/mcf)

ExxonMobil Marcellus sub-plays


44

Marcellus formation thickness

Atlantic Ocean

Pennsylvania

Virginia

West

Virginia

Ohio

New York

AppalachianBasin

50 -

100 f

t

100 - 1

50

ft

150

- 200

ft

100 - 1

50 ft

200

- 250

ft

0 - 50 ft

0 - 50 ft

0 - 50

ft

150 - 200 ft

250 - 3

00 ft

300 - 3

50 ft

350+ ft

1

4 7

12

5

11

2

10

3

6

9

8

75W

75W

78W

78W

81W

81W

84W

84W

42N

42N

39N

39N


U.S.A.

Canada

Marcellus


2 - SW PA


4 - Central PA

5 - High Plateau

6 - Bradford Area

7 - Northeast PA


9 - SW Core

10 - WV Rich Gas

11 - WV Dry Gas

12 - New York


45

Utica formation thickness

A Dive into the Permian

Should you believe the hype?

Benjamin Shattuck



47

Agenda

1 What are they saying? Why are they saying it?

2 A snapshot of the Wolfcamp Shale

3 Can we believe the hype?

4 Conclusions


48

1.0 Permian hype is at an all-time high

If early estimates prove to be even close to true, the vast amounts of recoverable oil and natural gas

will make the Cline Shale go down in history as the largest shale play ever.

including one West Texas shale formation that could dwarf both the Eagle Ford Shale in South

Texas and North Dakotas famous Bakken Shale.

Compare that to the Eagle Ford shale formation, which is about 300 ft thick and the

Spraberry/Wolfcamp shale, with its 50 billion boe, begins to dwarf the Eagle Ford and the Bakken

with 27 billion boe and 13 billion boe, respectively

Based on recoverable reserves, the Wolfcamp is second only to the Ghawar field in Saudi Arabia

Wolfcamp shale graduates to world class play


49

1.1 The Wolfcamp is driving the hype

Tex

as Permian Basin

1

New

Mex

ico

2

4

35Otero

Lea

Eddy

Pecos

Chaves

Hudspeth

Lincoln

Culberson

Reeves

Crockett

Terrell

PresidioBrewster

Irion

Jeff Davis

Sutton

Gaines

Upton

KentLynn

Kimble

Terry

Coke

Andrews

Ector

Jones

Nolan

Ward

Taylor

Reagan

Garza

Martin

FisherScurry

Tom Green

Runnels

Crane

Concho

Borden

Haskell

Schleicher

Sterling

MitchellHoward

Menard

MidlandWinkler

Dawson

Loving

Yoakum Stonewall

Glasscock

100W

100W

102W

102W

104W

104W

32N

32N


1 - Ozona

2 - Glasscock Nose

3 - Deep Basin

4 - Carbonate Platform

5 - Delaware Wolfcamp

Wolfcamp Wells

Bench

Bench Unknown

A

B

C

Cline

01/06/2011 and before

Completion Date


50


Tex

as Permian Basin

1

New

Mex

ico

2

4

35Otero

Lea

Eddy

Pecos

Chaves

Hudspeth

Lincoln

Culberson

Reeves

Crockett

Terrell

PresidioBrewster

Irion

Jeff Davis

Sutton

Gaines

Upton

KentLynn

Kimble

Terry

Coke

Andrews

Ector

Jones

Nolan

Ward

Taylor

Val Verde

Reagan

Garza

Martin

FisherScurry

Tom Green

Edwards

Runnels

Crane

Concho

Borden

Haskell

Schleicher

Sterling

MitchellHoward

Menard

MidlandWinkler

Dawson

Loving

Yoakum Stonewall

Glasscock

100W

100W

102W

102W

104W

104W

32N

32N


1 - Ozona

2 - Glasscock Nose

3 - Deep Basin



Wolfcamp Wells

Bench

Bench Unknown

A

B

C

Cline


01/06/2011 to 31/12/2011

Completion Date


51


Tex

as Permian Basin

1

New

Mex

ico

2

4

35Otero

Lea

Eddy

Pecos

Chaves

Hudspeth

Lincoln

Culberson

Reeves

Crockett

Terrell

PresidioBrewster

Irion

Jeff Davis

Sutton

Gaines

Upton

KentLynn

Kimble

Terry

Coke

Andrews

Ector

Jones

Nolan

Ward

Taylor

Val Verde

Reagan

Garza

Martin

FisherScurry

Tom Green

Edwards

Runnels

Crane

Concho

Borden

Haskell

Schleicher

Sterling

MitchellHoward

Menard

MidlandWinkler

Dawson

Loving

Yoakum Stonewall

Glasscock

100W

100W

102W

102W

104W

104W

32N

32N


1 - Ozona

2 - Glasscock Nose

3 - Deep Basin



Wolfcamp Wells

Bench

Bench Unknown

A

B

C

Cline


01/06/2011 to 31/12/2011

01/01/2012 to 30/06/2012

Completion Date


52


Post 01/06/2012

Tex

as Permian Basin

1

New

Mex

ico

2

4

35Otero

Lea

Eddy

Pecos

Chaves

Hudspeth

Lincoln

Culberson

Reeves

Crockett

Terrell

PresidioBrewster

Irion

Jeff Davis

Sutton

Gaines

Upton

KentLynn

Kimble

Terry

Coke

Andrews

Ector

Jones

Nolan

Ward

Taylor

Val Verde

Reagan

Garza

Martin

FisherScurry

Tom Green

Edwards

Runnels

Crane

Concho

Borden

Haskell

Schleicher

Sterling

MitchellHoward

Menard

MidlandWinkler

Dawson

Loving

Yoakum Stonewall

Glasscock

100W

100W

102W

102W

104W

104W

32N

32N


1 - Ozona

2 - Glasscock Nose

3 - Deep Basin



Wolfcamp Wells

Bench

Bench Unknown

A

B

C

Cline


01/06/2011 to 31/12/2011

01/01/2012 to 30/06/2012

Completion Date

01/06/2012 to 31/12/2012


53

1.2 Wolfcamp annual capex spend

Tracking data vintages shows dramatic increase in future spend

Source: Wood Mackenzie Play Company Tool


54

2.0 A tale of two sub-plays

Delineation into the Deep Basin sub-play

Tex

as

PermianBasin

1

New

Mex

ico

3

PecosCrockett

Terrell

Irion

Gaines

Upton

Coke

Andrews

Ector

Ward Reagan

Martin

FisherScurry

Tom GreenCrane

Borden

Schleicher

Sterling

Mitchell

Howard

MidlandWinkler

Dawson

Loving Glasscock

TX

OK

NM

DiamondBack

Devon

Laredo Pioneer Rsp Permian

Company

B

C

Unknown

A

Cline

Bench


55

2.1 How does the Deep Basin stack up?

Comparing Wood Mackenzies type wells

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1.0

0

50

100

150

200

250

0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32G

as p

rod

uctio

n (m

mcfd

) Liq

uid

s p

rod

uctio

n (b

/d)

Year

i = initial 12 months


Oil IP30: 275 b/d

Gas IP30: 0.52 mmcfd

Well cost: US$6.6 million

Oil Gas 1

Di=67% Di=68%

bi=1.46 bi=1.68

bt=1.45 bt=1.72

Oil EUR: 0.22 mmbbl

NGL EUR: 0.05 mmbbl

Gas EUR: 0.47 bcf

EUR boe: 352 mboe

IRR: 17%

Breakeven price (WTI): US$66/boe

Ozona sub-play Deep Basin sub-play

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1.0

0

50

100

150

200

250

0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32

Ga

s p

rod

uctio

n (m

mcfd

)

Liq

uid

s p

rod

uctio

n (b

/d)

Year i = initial 12 months

Oil IP30: 282 b/d

Gas IP30: 0.61 mmcfd

Well cost: US$7.6 million

Oil Gas 1

Di=67% Di=69%

bi=1.23 bi=1.65

bt=1.23 bt=1.65

Oil EUR: 0.18 mmbbl

NGL EUR: 0.06 mmbbl

Gas EUR: 0.53 bcf

EUR boe: 333 mboe

IRR: 9.7%

Breakeven price (WTI): US$84/bbl


56

3.0 Can we buy into the hype?

Yes and no:

Yes, proficient operators in core areas of the play can realize world-class returns

Yes, stacked pays allow operators to leverage infrastructure and multiply drilling

inventories

But keep in mind:

Play-wide multi-bench development is still under testing

Drainage from 90 years of production increases risk factors


57

100

150

200

250

300

350

400

450

500

Q3

20

11

Q4

20

11

Q1

20

12

Q2

20

12

Q3

20

12

Q4

20

12

Ma

x m

on b

oe

/d

Average max month and wells online

A-bench B-bench C-bench

Ozona sub-play region


0

10

20

30

40

50

60

70

0

100

200

300

400

500

600

700

Lare

do

EO

G

Apa

ch

e

Pio

nee

r

App

roa

ch

De

von

End

uri

ng

Ep E

nerg

y

BH

P

Mo

lop

o

Hig

hm

oun

t

Co

no

co

Pro

du

cin

g w

ells

30

-da

y IP

bo

e/d

30-day average max rate 2H 2012

Producing wells


Midland Basin Wolfcamp

3.1 Stacked pays means multiple learning curves

IP rate variability within the industry


58

3.2 Outperforming our type curve a statistical play

Max month rates trending up

0

100

200

300

400

500

600

700

800

900

1,000

1,100

1,200

1,300

1,400

1,500

Ma

x m

on

th b

oe

/d

January 2011

Type well Series21


Ozona and Deep Basin

Breakeven

June 2013

Max month by well


59

3.3 Key to success

Operational competency leads to efficiency

0

10

20

30

40

50

60

70

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

Apa

ch

e

Pio

nee

r

EO

G

De

von

App

roa

ch

Ep E

nerg

y

End

uri

ng

Co

no

co

Hig

hm

oun

t

BH

P

Mo

lop

o

Fo

rest

Oil

IP b

oe

/1,0

00

ft

Ave

rag

e la

tera

l (f

t)

Average Lateral (ft) IP boe/1,000ft


3,000

4,000

5,000

6,000

7,000

8,000

9,000

2011 2012 2013

Ave

rag

e la

tera

l le

ng

th (

ft)

Ozona

Carbonate Platform

Deep Basin

Glasscock Nose

Delaware



60

3.4 Keys to success

Driving down costs through efficiencies

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

EP

En

erg

y

Apa

ch

e

App

roa

ch

EO

G

De

von

Oth

er

Bhp

Bill

ito

n

% w

ells

on

pa

ds

2011 2012 2013


0

2

4

6

8

10

12

14

Base -10% -20% -30%S

ection v

alu

e (U

S$ m

illio

ns)

B-bench Conventional A-bench C-bench


Section equals 640 acres or one square mile

Assumes derisked section; spacing assumptions by bench

Assumes 30% D&C reduction for B-bench


61

Lower 48 Play Company Tool


62

4.0 Conclusions

The Wolfcamp is a world-class play for the best operators in the best areas

The Ozona is currently the most economic sub-play of the Wolfcamp

The Deep Basin starts ahead of the curve and has the most upside

The play must significantly outperform our base case to live up to initial estimates

The Eagle Ford Karnes Trough

in post ramp-up phase

A data driven case study

on incremental value

Callan McMahon



64

Eagle Ford Shale Update

10,000 permits and counting Now producing over 1,000,000 b/d

The worlds most productive tight oil formation

- 10.0 20.0 30.0

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

0

50

100

150

200

250

300

350

400

No

rth

ea

st O

il (1

)

Bla

ck O

il (2

)

Ka

rne

s C

ond

. (3

)

Ed

wa

rds C

ond

. (4

)

So

uth

ea

st

Ga

s (

5)

So

uth

we

st G

as (

6)

Ma

verick C

ond

. (7

)

Ma

ve

rick O

il (8

)

Ha

wkvill

e C

on

d. (9

)

We

llhea

d liq

uid

s p

erc

en

t

Pro

du

ctio

n (

mb

oe

/d)

Mar-2012 prod. Sept-2012 prod. Mar-2013 prod.

Mar-2012 % oil Sept-2012 % oil Mar-2013 % oil

Source: Wood Mackenzie and Lasser

Operator (1)

NE

Oil

(2)

Black

Oil

(3)

Karnes

Cond.

(4)

Edwards

Cond.

(5)

SE

Gas

(6)

SW

Gas

(7)

Mav.

Cond.

(8)

Mav.

Oil

(9)

Hawkville

Cond.

Total

Chesapeake 620 5 3 422 104 330 1,484

EOG Resources 294 802 1 118 1,215

Anadarko 12 1 753 197 963

BHP Billiton 3 153 246 35 231 3 112 783

Marathon 36 350 244 17 647

ConocoPhillips 177 420 597

Lewis 2 305 200 67 574

Pioneer 12 418 17 14 461

Murphy Oil 67 133 7 19 11 5 172 414

SM Energy 260 47 307

EP Energy 137 4 158 299

Talisman 4 91 52 145 292

Freeport (PXP) 32 183 69 284

Shell 155 5 90 250

Rosetta 6 27 1 5 197 11 247

Carrizo 129 23 53 205

Swift Energy 14 53 4 110 181

Geosouthern 16 81 57 154

Comstock 47 93 140

Hunt Oil 115 1 10 126

Forest Oil 4 100 1 105

Penn Virginia 8 33 61 102

Cabot 85 85

Newfield 37 46 83

Laredo Energy 65 65

Cheyenne 65 65

Goodrich 62 62

Escondido 11 48 59

Sum 236 1,638 2,018 1,558 105 718 2,002 117 1,857 10,249


65

Agenda: A six well project in the Eagle Ford Shale

Karnes Trough Condensate sub-play area Base Case cash flow and post-tax PV10

The average operator would run this project and generate returns of US$5.7 million per well

Caldwell

Guadalupe

San Antonio

Bee

Lavaca

Atascosa

Goliad

Live Oak

Wilson

McMullen

Gon

zale

s

DeWitt

Karnes3

0 20 4010km


Wells PermittedOperator

Others

ConocoPhillips

Carrizo

EOG

Marathon

Murphy

Penn Virginia

BHP

Plains

Base C

ase (

5.7

)

-2.0

-1.0

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

-40

-20

0

20

40

60

80

100

120

140

160

2014 2019 2024 2029 2034 2039

PV

10 o

f a s

ing

le w

ell -

pro

ject P

V10/6

(US

$ m

illion)

Six

well

pro

ject cash f

low

(U

S$ m

illio

n)

Source: Wood MackenzieSource: Wood Mackenzie


66

Adding US$800,000 in post-tax PV10 value per well

Karnes Trough Condensate sub-play area Adding US$800,000 in value per well

The leading operators would run this project and generate returns of US$6.5 million per well

Shifted drilling speed, pad drilling and choke size to the current level of the leading operators

Caldwell

Guadalupe

San Antonio

Bee

Lavaca

Atascosa

Goliad

Live Oak

Wilson

McMullen

Gon

zale

s

DeWitt

Karnes3

0 20 4010km


Wells PermittedOperator

Others

ConocoPhillips

Carrizo

EOG

Marathon

Murphy

Penn Virginia

BHP

Plains

Base C

ase (

5.7

)

Co

mb

ined

(6.5

)

+0.8

-2.0

-1.0

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

-40

-20

0

20

40

60

80

100

120

140

160

2014 2019 2024 2029 2034 2039

PV

10 o

f a s

ing

le w

ell -

pro

ject P

V10/6

(US

$ m

illion)

Six

well

pro

ject cash f

low

(U

S$ m

illio

n)



67

Base Case Karnes Trough type well assumptions

Karnes Trough IP30 rates by operator

Sub-play area assumptions Data from Wood Mackenzie's Key Plays

Average well cost (capex in US$M) 7.45

Total number of wells drilled (through 2013) 1,719

Risked remaining undrilled locations (2014 onward) 4,017

Total sub-play area (000 acres) 510

Average acre spacing (acres/well) 80

Remaining capex required to develop area (US$bn) 24.6

Remaining post-tax PV10 (US$bn) 30.6

0

500

1,000

1,500

2,000

2,500

3,000

3,500

Ge

oso

uth

ern

Pa

lom

a

Ro

setta

EO

G R

eso

urc

es

Co

no

coP

hill

ips

BH

P B

illito

n

Mu

rphy O

il

Ma

rath

on

Fre

epo

rt (

PX

P)

Pe

nn

Virg

ina

Ma

x m

onth

ra

te (

mb

oe

d)

IP Average IP


0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1.0

0

50

100

150

200

250

300

350

400

0 2 4 6 8 10 12 14 16 18 20 22 24 26 28

Gas p

roductio

n (m

mcfd

)Liq

uid

s p

roduction (

b/d

)

YearSource: Wood Mackenzie

Oil/condensate IP30: 566 b/dGas IP30: 1.00 mmcfd

Oil/condensate EUR: 0.49 mmbblNGLs EUR: 0.07 mmbblGas EUR: 0.83 bcf

Well Cost: US$7.45 millionIRR (post tax): 43%Breakeven price (LLS): US$52/bblPost-tax PV10: US$5.8 million

Oil Di = 19%Oil bi = 1.92Oil bt = 1.50

Gas Di = 23%Gas bi = 1.77Gas bt = 1.44


68

Base Case Drilling six wells on one pad in the Karnes Trough

Project timeline Base Case cash flow and post-tax PV10

Drilling six wells on the same pad is less expensive, but increases time to production

1 2 3 4 5 6 7 8 9 10 11 12

Pad1Well6

Pad1Well5

Pad1Well4

Pad1Well3

Pad1Well2

Pad1Well1

Month

Production


Development

Ba

se C

as

e (

5.7

)

-2.0

-1.0

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

-40

-20

0

20

40

60

80

100

120

140

160

2014 2019 2024 2029 2034 2039

PV

10 o

f a s

ing

le w

ell -

pro

ject P

V1

0/6

(US

$ m

illion)

Six

we

ll p

roje

ct ca

sh f

low

(U

S$

mill

ion)



69

Decreasing the number of wells drilled on a pad from six to two

New project timeline Adding US$200,000 in value per well

This brings production forward but increases well cost from US$7.45 to US$7.94 million

1 2 3 4 5 6 7 8 9 10 11 12

Pad3Well2

Pad3Well1

Pad2Well2

Pad2Well1

Pad1Well2

Pad1Well1

Month

Production


Development

Ba

se C

as

e (

5.7

)

2 W

ell P

ad

s (

5.9

)

+0.2

-2.0

-1.0

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

-40

-20

0

20

40

60

80

100

120

140

160

2014 2019 2024 2029 2034 2039

PV

10 o

f a s

ing

le w

ell -

pro

ject P

V1

0/6

(US

$ m

illion)

Six

we

ll p

roje

ct ca

sh f

low

(U

S$

mill

ion)



70

Simply drilling faster can have substantial cost savings

Operator ROP in the Eagle Ford by year Adding US$700,000 in value per well

Drilling costs US$2.1 million for 31 days (2011-2012 average) (US$68,000/day)

Drilling 7 days faster (2013 Karnes average) saves nearly half a million dollars per well

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

Fre

eport

(P

XP

)

Com

sto

ck

Mara

thon

EO

G R

esourc

es

New

field

Lare

do E

nerg

y

Murp

hy O

il

Rosetta

Penn V

irgin

ia

Hess

ConocoP

hill

ips

Lew

is

SM

Energ

y

Talis

man

Pio

neer

EP

Energ

y

Chesapeake

Fore

st O

il

ExxonM

obil

Cabot

BH

P B

illiton

Sanchez E

nerg

y

Anadark

o

Avera

ge f

eet drille

d p

er

day

2010 2011 2012 2013

Source: Wood Mackenzie and Texas RRCB

as

e C

as

e (

5.7

)

Inc

rease R

OP

(6.4

)

+0.7

-2.0

-1.0

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

-40

-20

0

20

40

60

80

100

120

140

160

2014 2019 2024 2029 2034 2039

PV

10 o

f a s

ing

le w

ell -

pro

ject P

V1

0/6

(US

$ m

illion)

Six

we

ll p

roje

ct ca

sh f

low

(U

S$

mill

ion)



71

Completions through production

Top 10 EOG IP30 rates (boe/d) in the Eagle Ford

Completions techniques and choke settings

during production impact the type curve

0

200

400

600

800

1,000

1,200

1,400

0 6 12 18 24 30 36

Pro

duction (

boe/d

)

Month

EOG top 10 Offset to EOG


Offset EOG Karnes New (15-yr) Oil/cond IP30 (b/d): 548 979 566 1,011Gas IP30 (mmcfd): 0.8 1.2 1.0 1.4

Liquids EUR (mmbbl): 0.54 0.48 0.55 0.51Gas EUR (bcf): 0.93 0.56 0.83 0.68


72


New Karnes Trough type well curve (15-yr) Adding US$500,000 in value per well

Shifting the Karnes Trough type well curve by the same factor as the offset to EOG wells

0

200

400

600

800

1,000

1,200

1,400

0 6 12 18 24 30 36

Pro

du

ction

(b

oe

/d)

Month


Karnes Type Well New Karnes type well







Base C

ase (

5.7

)

Co

mp

-pro

d 1

5-y

r (6

.2)

+0.5

-2.0

-1.0

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

-40

-20

0

20

40

60

80

100

120

140

160

2014 2019 2024 2029 2034 2039

PV

10 o

f a s

ing

le w

ell -

pro

ject P

V1

0/6

(US

$ m

illion)

Six

we

ll p

roje

ct ca

sh f

low

(U

S$

mill

ion)



73


New Karnes Trough type well curve (20-yr)

Adding US$1,300,000 in value per well

We assume the increased drawdown would decrease the wells life to 15 years, but if it produced for 20 years

0

200

400

600

800

1,000

1,200

1,400

0 6 12 18 24 30 36

Pro

duction (

boe/d

)

Month






Source: Wood MackenzieB

ase C

ase (

5.7

)

Co

mp

-pro

d 1

5-y

r (6

.2)

Co

mp

-pro

d 2

0-y

r (7

.0)

+0.5

+1.3

-2.0

-1.0

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

-40

-20

0

20

40

60

80

100

120

140

160

2014 2019 2024 2029 2034 2039

PV

10 o

f a s

ing

le w

ell -

pro

ject P

V1

0/6

(US

$ m

illion)

Six

we

ll p

roje

ct ca

sh f

low

(U

S$

mill

ion)



74


New Karnes Trough type well curve (25-yr) Adding US$1,800,000 in value per well

We assume the increased drawdown would decrease the wells life to 15 years, but if it produced for 25 years

0

200

400

600

800

1,000

1,200

1,400

0 6 12 18 24 30 36

Pro

duction (

boe/d

)

Month






Source: Wood MackenzieB

ase C

ase (

5.7

)

Co

mp

-pro

d 1

5-y

r (6

.2)

Co

mp

-pro

d 2

0-y

r (7

.0)

Co

mp

-pro

d 2

5-y

r (7

.5)

+0.5

+1.3

+1.8

-2.0

-1.0

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

-40

-20

0

20

40

60

80

100

120

140

160

2014 2019 2024 2029 2034 2039

PV

10 o

f a s

ing

le w

ell -

pro

ject P

V1

0/6

(US

$ m

illion)

Six

we

ll p

roje

ct ca

sh f

low

(U

S$

mill

ion)



75

Base C

ase (

5.7

)

2 W

ell P

ad

s (

5.9

)

Incre

ase R

OP

(6.4

)

Co

mp

-pro

d 1

5-y

r (6

.2)

Co

mp

-pro

d 2

0-y

r (7

.0)

Co

mp

-pro

d 2

5-y

r (7

.5)

Co

mb

ined

(6.5

)

+0.2

+0.7 +0.5

+1.3

+1.8

+0.8

-2.0

-1.0

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

-40

-20

0

20

40

60

80

100

120

140

160

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

PV

10 o

f a s

ing

le w

ell -

pro

ject P

V10/6

(US

$ m

illion)

Six

well

pro

ject cash f

low

(U

S$ m

illio

n)


Adding US$800,000 in value by destroying 66,000 boe of reserves

Well cost Project PV10 Well PV10 Increse over base Oil / cond. (b/d) NGL's (b/d) Gas (mmcfd) Liquids (mmbbl) Gas (bcf)

Karnes Type Well 7.45 - 5.8 - 566 72 0.91 0.55 0.83

Base Karnes Trough 7.45 43.4 5.7 - 566 72 0.91 0.55 0.83

Small pads 7.94 47.1 5.9 0.2 566 72 0.91 0.55 0.83

Drill fast 6.96 40.9 6.4 0.7 566 72 0.91 0.55 0.83

Open choke 15-yr 7.45 43.4 6.2 0.5 1,011 100 1.27 0.51 0.68

Open choke 20-yr 7.45 43.4 7.0 1.3 1,011 100 1.27 0.61 0.84

Open choke 25-yr 7.45 43.4 7.5 1.8 1,011 100 1.27 0.72 0.93

Combined 7.45 44.2 6.5 0.8 1,011 100 1.27 0.51 0.68

Costs (US$M) Economics (US$M)Case

IP Rates EUR's


76

7%

Dis

c R

ate

(7.6

)

7%

Dis

c R

ate

(7.8

)

7%

Dis

c R

ate

(8.4

)

7%

Dis

c R

ate

(7.7

)

7%

Dis

c R

ate

(9.1

)

7%

Dis

c R

ate

(10.1

)

7%

Dis

c R

ate

(8.2

)

Base C

ase (

5.7

)

2 W

ell P

ad

s (

5.9

)

Incre

ase R

OP

(6.4

)

Co

mp

-pro

d 1

5-y

r (6

.2)

Co

mp

-pro

d 2

0-y

r (7

.0)

Co

mp

-pro

d 2

5-y

r (7

.5)

Co

mb

ined

(6.5

)13%

Dis

c R

ate

(4.3

)

13%

Dis

c R

ate

(4.4

)

13%

Dis

c R

ate

(5.0

)

13%

Dis

c R

ate

(4.9

)

13%

Dis

c R

ate

(5.4

)

13%

Dis

c R

ate

(5.7

)

13%

Dis

c R

ate

(4.6

)

-3.0

-1.0

1.0

3.0

5.0

7.0

9.0

11.0

13.0

-30

-20

-10

0

10

20

30

40

50

60

70

80

90

100

110

120

130

140

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

PV

10 o

f a s

ing

le w

ell -

pro

ject P

V10/6

(US

$ m

illion)

Six

well

pro

ject cash f

low

(U

S$ m

illio

n)


Adding US$800,000 in value by destroying 66,000 boe of reserves

Well cost Project PV10 Well PV10 Increse over base Oil / cond. (b/d) NGL's (b/d) Gas (mmcfd) Liquids (mmbbl) Gas (bcf)

Karnes Type Well 7.45 - 5.8 - 566 72 0.91 0.55 0.83

Base Karnes Trough 7.45 43.4 5.7 - 566 72 0.91 0.55 0.83

Small pads 7.94 47.1 5.9 0.2 566 72 0.91 0.55 0.83

Drill fast 6.96 40.9 6.4 0.7 566 72 0.91 0.55 0.83

Open choke 15-yr 7.45 43.4 6.2 0.5 1,011 100 1.27 0.51 0.68

Open choke 20-yr 7.45 43.4 7.0 1.3 1,011 100 1.27 0.61 0.84

Open choke 25-yr 7.45 43.4 7.5 1.8 1,011 100 1.27 0.72 0.93

Combined 7.45 44.2 6.5 0.8 1,011 100 1.27 0.51 0.68

Costs (US$M) Economics (US$M)Case

IP Rates EUR's


77

BHP Billiton, $12.0

Carrizo, $2.0

ConocoPhillips, $12.9

EOG Resources, $18.3

Marathon, $9.8

Murphy Oil, $4.7

Penn Virginia, $1.4

Pioneer, $5.7Rosetta, $3.4

Freeport (PXP), $2.30

1,000

2,000

3,000

4,000

5,000

2.0 3.0 4.0 5.0 6.0 7.0 8.0

Re

ma

inin

g E

ag

le F

ord

Loca

tion

s

Type Well PV10 (US$ million)Source: Wood Mackenzie

Bubble size represents Eagle Ford Rem. PV10Company name, PV10 (US$ billion)

The company lifecycle in a play

1. Increase well performance

2. Downspace (increase locations but cannibalize wells)

3. Dispose non-developable locations

1. Improve well performance

Northeast Oil (1)

Karnes Cond. (3)

Edwards Cond. (4)

Southeast Gas (5)

Southwest Gas (6)

Mav. Cond. (7)

Maverick Oil (8)

Hawkville Cond. (9)

3,000

3,500

4,000

4,500

5,000

5,500

6,000

2010 2011 2012 2013

Avera

ge late

ral le

ng

th (

feet)

Source: Wood Mackenzie and Texas RRC

Black Oil (2)

What Defines a Winning

Strategy for Ultra-Competitive

Onshore Plays?

Robert Clarke, Matt Snyder, Phani Gadde



79

Three powerful questions clients have asked our analysts

recently are:

What do independents do differently than larger operators in unconventional plays?

Why is there so much value differentiation

across similar portfolios?

Early entrants in the big shale plays appear to be the winners, so which

up-and-coming assets have commercial

potential and low entry costs?

Should I strive for an average position in the best shale play, or can I settle for the

best position in an average play?

Companies

Text

Operations Geography

&

Where Next?


80

Between the rock and the operator Which does well performance depend on more?

5.50

6.00

6.50

7.00

7.50

8.00

0

10

20

30

40

50

60

70

80

Small-cap Mid-cap LargeIndependent

Other LargeIndependent

Major

We

ll C

os

t (U

S$

Mil

lio

ns

)

EU

R p

er

1,0

00

ft

(mb

oe

/10

00

ft)

EUR Well Cost

Eagle Ford Maverick Condensate

All things being equal, well performance in areas with

similar rock characteristics is relatively similar for all

operators. However, cost structure defines valuation.


81

The perception of operator importance may be slightly different

though, according to the Unconventional Play Service 2013

User Survey

Word Cloud Responses - Which unconventional operator do you most admire?

EOG Resources Chesapeake

Shell Marathon

Petrochina

Pioneer Statoil

XTO

EQT

Devon

Conoco

CNOOC

Canadian Natural Resources


82

Average position in a good play vs. good position in an

average play (1)

Tole

do B

end

Rese

rvoir

Red

Riv

er

Lake o'the Pines

Wright Patman Lake

Caddo Lake

Sam Rayburn Reservoir

Lufkin

Longview

Alexandria

Jacksonville

Shreveport

El Dorado

Louisiana

TylerJasper

Trinity

Angelina

SanAugustine

Newton

Nacogdoches

Rusk

Gregg

Cherokee

Shelby

Panola

Upshur

Sabine

Camp

Harrison

Cass

Marion

Houston

Vernon

Rapides

Natchitoches

Grant

Caddo

Red River

Winn

Bossier

Sabine

Jackson

LincolnBienville

Webster

Claiborne

De Soto

ArkLaTex

Basin Arkansas

Texas

4 BCF6

BCF

6 BCF

8 BCF

10 BCF

Tier 2

Tier 1

En

d o

f s

tud

y a

rea

End of study area

93W

93W

94W

94W

95W

95W

33N

33N

32N

32N

31N

31N

0 20 4010km

U.S.A.

MEXICO

CANADA

Source: Wood Mackenzie, Company Reports and Lasser Inc.

Haynesville IDW - 6 point

Peak Month (mmcfd)

>=8 to =11 to =16 to =19

Brand name plays are generally viewed favorably by Equity

Analysts and many institutional

investors

Negative news about average plays can affect the valuations for all the

operators

Companies generally have better upside through bolt-ons when the

existing acreage position is

average

Infrastructure and services development typically faster in the

top-tier plays


83

Average position in a good play vs. good position in an average

play (2)

0

5

10

15

20

25

0%

10%

20%

30%

40%

50%

60%

Marc

ellu

s-S

usq

ue

ha

nna

Co

re

Ea

gle

Fo

rd-K

arn

es T

roug

h C

on

d.

Ba

kke

n-P

ars

ha

ll a

nd S

an

ish

Ba

kke

n-N

esso

n A

nticlin

e S

ou

th

Ba

kke

n-W

est

Ne

sso

n

Utica-S

W C

ore

Marc

ellu

s-B

rad

ford

Are

a

Ea

gle

Fo

rd-E

dw

ard

s C

ond

.

Ba

kke

n-N

ort

he

rn M

ou

ntr

ail

Ea

gle

Fo

rd-H

aw

kvill

e C

on

d.

Bo

ne

Sp

ring

-Pe

co

s R

iver

Re

gio

n

Marc

ellu

s-S

ou

thw

est

PA

Ba

kke

n-D

ivid

e C

ou

nty

Wo

lfca

mp

-Ozo

na

Utica

-Con

de

nsa

te

Ba

kke

n-N

ort

hw

est D

un

n

Ea

gle

Fo

rd-B

lack O

il

Bo

ne

Sp

ring

-Nort

hw

est

Sh

elf

Ba

kke

n-W

este

rn W

illia

ms

Wo

lfca

mp

-Gla

ssco

ck N

ose

Wo

lfca

mp

-Del. B

asin

Ea

gle

Fo

rd-M

ave

rick C

on

d.

Marc

ellu

s-S

ou

thw

est

Co

re

Ba

kke

n-N

esso

n A

nticlin

e N

ort

h

Ba

kke

n-E

lm C

ou

lee

Utica-W

et G

as

Ea

gle

Fo

rd-S

ou

thw

est

Gas

Wo

lfca

mp

-Dee

p B

asin

Bo

ne

Sp

ring

-Cen

tra

l B

asin

Slo

pe

Ris

ked

Un

dri

lled

Reserv

es

Po

st

Tax I

RR

IRR

Reserves


84

Non name-brand plays that could generate value (1) - The eastern

portion of the Canol appears to be a preferential place to drill thus far

Source: Wood Mackenzie's Unconventional Play Service

Early well placement could be related to infrastructure proximity.

Average porosity is 14% and a modal quartz range of 82 90% makes the Canol brittle. It is highly fractured in some regions.

Oil seeps, presumably from the Canol, were first noted along the Mackenzie River in 1920. Preliminary tests from MGM Energy Corp., show that oil is light, sweet crude.

Operators can hold exploration licences for 9 years. The Northwest Territories employs a work-commitment system. Bidders expenditures are refunded on a prorated basis.

The only well-test result has come from the MGM-operated East MacKay I-78 well drilled in winter 2012 on EL 466B. Over a four-day test period, the well recovered 140 barrels of liquids.

The National Energy Board just approved ConocoPhillips application to drill two wells on Exploration Licence area EL470


85

Non name-brand plays that could generate value (2) - Shallow

declines from inexpensive oil wells define the niche, Eastern

Plains Colorado play


In particular, Nighthawks Steamboat Hansen 8-10 first started producing in November 2012 at roughly 200 b/d. It steadily rose to 300 b/d in June 2013 before rising again to 400 b/d in July 2013. Additional wells have produced between 700 and 1,200 b/d close to their completion dates.

The most prospective areas of the Eastern Plains lie in Kit Carson, Cheyenne, Kiowa, and Prowers counties where Mississippian and Pennsylvanian strata could provide stacked pay potential.

A horizontal well drilled by Chama Oil and Minerals of Midland TX (the Pronghorn State #16-15-48-1H) reportedly tested up to 2,000 b/d.

In the last four months of 2012, Nighthawk Energy drilled five vertical test wells. One of the first fields in the Eastern Plains play, the Arikaree, was discovered by Nighthawk with the Steamboat Hansen 8-10 well.


86

Unconventional portfolio value Are the majors positioning themselves for larger sector influence in the future?

2013 Majors Account for 14% of PV (US$ million) 2018 Majors Account for 29% of PV (US$ million)

0 10,000 20,000 30,000 40,000

Cenovus

Denbury

Eni

Freeport-McMoRan

CNRL

Total

Newfield

Pioneer

BP

Chevron

Range

Statoil

Southwestern

Continental

Shell

Encana

Devon

ExxonMobil

Anadarko

Chesapeake

EOG

CBM Shale Gas

Tight Gas Tight Oil

Source: Wood Mackenzie's Corporate Benchmarking Tool

0 10,000 20,000 30,000 40,000

Denbury

Eni

Freeport-McMoRan

CNRL

Newfield

Total

BP

Pioneer

Southwestern

Range

Statoil

Chevron

Shell

Encana

Continental

Devon

ExxonMobil

EOG

Anadarko

Chesapeake

CBM Shale Gas

Tight Gas Tight Oil


87

What will define the majors contribution to the sector? Balance sheet strength is essential to move international

unconventional plays forward

Neuqun Basin Vaca Muerta Shale in Argentina

Bazhenov Tight Oil -

Russia

Cooper Basin Shale

Gas - Australia



88

London Upstream Forum presentations

Upstream Capital Allocation Value versus Volume?

Slides 89-103

Upstream Capital Allocation - Value versus Volume

Tom Ellacott

Slides 104-125 Creating value through conventional and unconventional exploration: a

global analysis

Andrew Latham

Slides 126-141 Sub-Sahara a wealth of investment opportunities Obo Idornigie

Slides 142-156 North Sea a safer place to invest? Lindsay Wexelstein

Slides 157-177 Prospects for investment in the Middle East

Richard Quin

Upstream Capital Allocation -

Value versus Volume

Upstream Forum

26th November 2013

Tom Ellacott



90

15

16

17

18

19

20

21

22

23

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Pro

du

cti

on

(m

mb

oe

/d)

Volumes: a decade of under delivery will it be different this time?

The outlook for production through this decade

looks very strong. But if the past is a guide to

the future how confident should we be?

Majors aggregate production (entitlement) expected to grow by 4 million boe/d by end decade

Source: Wood Mackenzie Corporate Benchmarking Tool


91

Investors chasing economic recovery have lost interest in energy

-50%

-40%

-30%

-20%

-10%

0%

10%

20%

30%

40%

2007 2008 2009 2010 2011 2012 2013 YTD

MSCI World Energy MSCI World

To

tal R

etu

rns

Total returns from the energy sector have lagged the market by 20% since January 2012

Source: ThomsonReuters Datastream


92

Value: equity market pressures are forcing strategic change

90

100

110

120

130

140

150

160

12/1

0/1

2

12/1

2/1

2

12/0

2/1

3

12/0

4/1

3

12/0

6/1

3

12/0

8/1

3

12/1

0/1

3

Hess MSCI WORLD ENERGY

Management change

Capital allocation under the microscope

Value over volume - the new mantra

Upstream is king

Demerge/ sell downstream, other

business

Marathon, COP splits created value

Focus on core strengths visible to investors

Independents retreat to US plays

Sell-off non-core, international assets

Selective higher risk exploration

Scrutiny of risk/reward profile, well by well

Active financial management

Return surplus cash to investors

Hess: change has sparked equity recovery

Source: ThomsonReuters Datastream, Wood Mackenzie


93

Upstream cash flow set to be materially higher than past forecasts

0

50

100

150

200

250

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

Fre

e c

as

hfl

ow

(p

re-e

xp

lora

tio

n)

$b

n

2007F 2013F BASE PRICE 2013F LOW PRICE

2007 2014

2013

2022

2018

Years from start of period

Up

str

ea

m F

CF

(p

re-e

xp

lora

tio

n)

Majors: 15 year cash flow (pre exploration and finance) forecasts from 2013 vs 2007



94

Organic investment: no cyclical peak, capex shifting from LNG

0

20

40

60

80

100

120

140

160

180

2008 2013 2018

Ca

pe

x (

US

$ B

illi

on

)

Technicals

Others

Probable

Under develpmt

Onstream

0

20

40

60

80

100

120

140

160

180

2008 2013 2018

Ca

pe

x (

$m

n)

Other

Shale/tight

Oil Sands

LNG

Heavy Oil

Deepwater

Conventional

Capex by project status: spend can be sustained Majors project capex by theme

0

20

40

60

80

100

120

140

160

180

2008 2013 2018

Cap

ex

(U

S$

Bil

lio

n)

Technicals

Others

Probable

Under develpmt

Onstream

Cap

ex

(U

S$

Billi

on

)



95

*Capital Spend is the net investment in new projects (nominal terms). It does not include investment in fields which are already onstream and newfield developments that fall under tax

ring fences which are already onstream. Therefore the capital spend is less than total corporate capital spend and the average IRR may not fully reflect the full economic picture.

Resource themes: clear differences emerging in returns

Conventional

Deepwater

LNG Oil sands

Shale gas

Tight oil

0

5

10

15

20

25

30

0 100 200 300 400 500

Weig

hte

d A

vera

ge I

RR

(%)

CAPEX Investment in Greenfield projects 2006-2020 (US$Billion)

Greenfield project IRRs by theme

Increasing spend

Declining spend

Unconventionals: play economics

Marcellus SW

Marcellus NE

Haynesville

Fayetteville

Barnett

Utica gas/cond

Anadarko

Woodford

Granite Wash

Bakken

Three Forks

Wolfcamp

Niobrara

Bone Spring

Eagle Ford

0%

5%

10%

15%

20%

25%

30%

35%

0 50 100 150 200 250IR

R (

%)

Remaining capex (US$ billion)

Gas plays Liquids plays

Develo

pm

en

t w

ell

IR

R



96

Probable developments

5

7

9

11

13

15

17

19

21

23

25

0 20,000 40,000 60,000 80,000

IRR

(%)

CAPEX 2006-2020 (US$Million)

BP

Total

Chevron

ENI

Shell ExxonMobil Statoil

BP ex. Oman gas

New field returns: uncommitted projects provide optionality

The Majors: Probable Development and unconventional IRRs and associated capital investment

*Capital Spend is the net investment in new projects (nominal terms). It does not include investment in unsanctioned developments that fall under tax ring fences which are already

onstream. Therefore the capital spend is less than total corporate capital spend and the average IRR may not fully reflect the full economic picture.

Uncons & Probables

5

7

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wood mackenzie global upstream forums november 2013

Documents