Natural GasIn the Production Growth Vortex

Energy Finance Discussion Group

Denver

November 11, 2008

David Pursell

*Important Disclosures on page 33 of this document.*

22

Natural Gas 12 Month Strip

$6

$7

$8

$9

$10

$11

$12

$13

$14Aug

-05

Oct

-05

Dec

-05

Feb-

06

Apr

-06

Jun-

06

Aug

-06

Oct

-06

Dec

-06

Feb-

07

Apr

-07

Jun-

07

Aug

-07

Oct

-07

Dec

-07

Feb-

08

Apr

-08

Jun-

08

Aug

-08

Oct

-08

$/m

cf

3

Futures – Are They Accurate?

-60%

-30%

0%

30%

60%

Jan

-99

Jan

-01

Jan

-03

Jan

-05

Jan

-07

Jan

-09

% D

iffe

rne

ce N

YM

EX

12

mo

Str

ip a

nd

Act

ua

l StripToo High

(Strip Too Low)

4

Thoughts On Price

Price range

□ 2001 : Marginal Cost Supply ~$3.50/mcf Marginal Consumption ~$8 to $10/mcf

□ 2008 Marginal Cost Supply ~$8/mcf Marginal Consumption ~$10 to 12/mcf (assuming economy

OK)

□ LNG

□ 2001 – N/A

□ 2008 - $12/mcf (moving target with oil)

4

5

Thoughts On Price – Long Term

US Can grow demand…we have supply growth.

□ Economic expansion required

Power demand is THE driver of natural gas demand growth

□ Need gas-fired backup (large capacity margin) to back stop alternatives (wind, solar, and hydro).

□ Transportation fuels…I cant make the math work

Carbon Legislation – should greatly benefit power generation demand

□ Gas >> Oil >> Coal

□ Concerns: Overall tax/cost of retail electricity may hinder economic

growth Demand side management (incentive to consume less) will

be integral part of plan.

5

66

GOM Production

6

8

10

12

14

16

1996 1998 2000 2002 2004 2006 2008

bcf

/day

“I can hardly remember how I built my bankroll, but I can't stop thinking about the way I lost it."

Mike….Rounders

77

Onshore Supply Growth!

“Ohhhh, man I wish I could go back in time. I'd take state.”

Uncle Rico – Napoleon Dynamite

40

45

50

55

60

0

400

800

1200

1600

2000

Jan-97

Jan-98

Jan-99

Jan-00

Jan-01

Jan-02

Jan-03

Jan-04

Jan-05

Jan-06

Jan-07

Jan-08

Jan-09

Jan-10

Onshore G

ross Gas P

roduction, bcf/day

Rig

Cou

ntOnshore Gas Rig Count

Onshore Gas Production

8

Gas Storage – Back to Normal

8

0

1,000

2,000

3,000

4,000

J A J S D

Wo

rkin

g G

as,

bcf

Normal

Max

2007

Min

Projected Storage Level on Nov 1st

9

Shale Plays Improving Mix

9

0

200

400

600

800

1000

1200

- 5,000 10,000 15,000 20,000 25,000 30,000 35,000

Ave

rag

e F

irs

t Y

ea

r P

rod

uc

tio

n,

mc

f/d

ay

Onshore Gas Wells Drilled, Annually

2003

2000

20042001

1995

19981999

1996

1997

2002

20052006

2007

10

Implications for Rig Count

10

(14)

(12)

(10)

(8)

(6)

(4)

(2)

0

2

4

0 200 400 600 800 1000 1200 1400 1600

On

sho

re S

up

ply

Gro

wth

(D

ecl

ine

), b

cf/d

ay

Onshore Gas Directed Rig Count

Capital Market Issues

E&P companies can’t / won’t outspend cash flow

□ Raise Equity….nope

□ Debt…good luck

□ Sell assets…not so much

□ Cut spending/rig count…most likely

Pipeline companies

□ How to fund new pipes?

□ Basis issues harder to solve via more pipes

□ Need to solve via lower production in near term

11

12

Rigcount By Operator Type

1Refer to page 74 in the Appendix for a listing of the publicly-traded E&P operators in each category.

Large-Cap E&P

470 468 481 510 490 508 534 562 569 584 550 549

0100200300400500600700

Q4'

06

Q2'

07

Q4'

07

Q2'

08

Q4'

08

4 W

eeks

Ago

10/3

1/08

Mid-Cap E&P

195 213 229 241 236 243270

302 302 315283 283

050

100150200250300350

Q4'

06

Q1'

07

Q2'

07

Q3'

07

Q4'

07

Q1'

08

Q2'

08

Q3'

08

Q4'

08

4 W

eeks

Ago

Prio

r W

eek

10/3

1/08

Small-Cap E&P

119 114 116 124 121 122138 143 144 145 140 134

0

50

100

150

200

Q4'

06

Q1'

07

Q2'

07

Q3'

07

Q4'

07

Q1'

08

Q2'

08

Q3'

08

Q4'

08

4 W

eeks

Ago

Prio

r W

eek

10/3

1/08

Integrated Oil

141143

137142

154 154

145

155153 153

148

155

125130135140145150155160

Q4'

06

Q2'

07

Q4'

07

Q2'

08

Q4'

08

4 W

eeks

Ago

10/3

1/08

Stealth E&P

2821

29 29 31 3237

45 42 44 41 41

0

10

20

30

40

50

Q4'

06

Q1'

07

Q2'

07

Q3'

07

Q4'

07

Q1'

08

Q2'

08

Q3'

08

Q4'

08

4 W

eeks

Ago

Prio

r W

eek

10/3

1/08

Hybrid Utilities

54 57 59 60 59 59 59 6472 74 75 73

0

20

40

60

80

Q4'

06

Q1'

07

Q2'

07

Q3'

07

Q4'

07

Q1'

08

Q2'

08

Q3'

08

Q4'

08

4 W

eeks

Ago

Prio

r W

eek

10/3

1/08

MLP Public E&P

17 18 1821

2832 31 32

2630

19 20

05

101520253035

Q4'

06

Q2'

07

Q4'

07

Q2'

08

Q4'

08

4 W

eeks

Ago

10/3

1/08

Private E&P/Other

969863 849 862 900 825

925 1,0021,028 1,0291,0311,009

0200400600800

1,0001,200

Q4'

06

Q1'

07

Q2'

07

Q3'

07

Q4'

07

Q1'

08

Q2'

08

Q3'

08

Q4'

08

4 W

eeks

Ago

Prio

r W

eek

10/3

1/08

Total U.S. Land

1,9921,896 1,917

1,988 2,020 1,976

2,138

2,306 2,335 2,3742,287 2,264

1,500

1,700

1,900

2,100

2,300

2,500

Q4'

06

Q1'

07

Q2'

07

Q3'

07

Q4'

07

Q1'

08

Q2'

08

Q3'

08

Q4'

08

4 W

eeks

Ago

Prio

r W

eek

10/3

1/08

13

Shale Comparison

13

0

2

4

6

8

10

12

IP's, mmcfd EUR, bcf NYMEX, $/mcf Well Cost, $mm

Barnett

Woodford

Haynesville

Marcellus

Source: CHK

1414

Basin Breakeven Analysis

$13.45

$11.61

$11.40

$10.45

$9.75

$9.65

$9.15

$8.45

$7.94

$7.30

$7.14

$7.01

$6.86

$6.85

$6.44

$6.37

$5.87

$5.48

$8.07

$6.80

$6.97

$6.39

$5.83

$5.72

$5.59

$5.13

$4.76

$4.42

$4.32

$4.38

$4.44

$4.16

$4.10

$4.48

$3.65

$3.31

$- $2 $4 $6 $8 $10 $12 $14

Gulf of Mexico Shelf

NE BC Shale

Gulf Coast LA

Piceance

Woodford Fringe

Wolfcamp (Permian)

Carthage Field

Woodford Core

Barnett Tier 2

Barnett Tier 1

Core Barnett

Marcellus Horizontal

J ames Lime

Haynesville Well 7.5mmpd IP

Fayetteville

Appalachia CBM

East Texas Freestone

Pinedale

Breakeven Gas Price, $/mcf

Average Well

Marginal Well

Basis Differentials

15

Henry Hub Rockies Appalachia California Mid-Con AECO Rockies Appalachia California Mid-Con AECO

2005

Q1 $6.29 $5.62 $6.55 $5.86 $5.98 $5.53 ($0.66) $0.26 ($0.43) ($0.31) ($0.76)

Q2 $6.95 $6.03 $7.27 $6.24 $6.34 $5.90 ($0.92) $0.32 ($0.71) ($0.61) ($1.05)

Q3 $9.57 $7.66 $9.95 $7.96 $8.34 $7.40 ($1.91) $0.38 ($1.61) ($1.23) ($2.17)

Q4 $12.12 $9.48 $12.64 $9.95 $9.80 $9.24 ($2.64) $0.52 ($2.18) ($2.33) ($2.88)

Year $8.77 $7.27 $9.21 $7.57 $7.69 $7.09 ($1.51) $0.44 ($1.20) ($1.09) ($1.69)

2006

Q1 $7.77 $6.54 $8.12 $6.82 $6.63 $6.02 ($1.22) $0.36 ($0.95) ($1.14) ($1.75)

Q2 $6.56 $5.33 $6.79 $5.69 $5.58 $4.81 ($1.22) $0.23 ($0.87) ($0.97) ($1.75)

Q3 $6.13 $4.99 $6.28 $5.82 $5.57 $4.56 ($1.14) $0.15 ($0.31) ($0.56) ($1.57)

Q4 $6.61 $4.68 $6.78 $6.13 $5.92 $5.55 ($1.92) $0.18 ($0.47) ($0.69) ($1.06)

Year $6.77 $5.39 $6.99 $6.11 $5.92 $5.23 ($1.38) $0.23 ($0.65) ($0.84) ($1.53)

2007

Q1 $7.08 $5.67 $7.27 $6.54 $6.39 $5.90 ($1.42) $0.18 ($0.54) ($0.70) ($1.18)

Q2 $7.55 $3.73 $7.98 $6.92 $6.69 $5.67 ($3.81) $0.44 ($0.63) ($0.86) ($1.88)

Q3 $6.16 $2.80 $6.36 $5.78 $5.58 $4.16 ($3.37) $0.20 ($0.38) ($0.58) ($2.00)

Q4 $6.92 $3.99 $7.19 $6.41 $6.05 $4.92 ($2.93) $0.27 ($0.51) ($0.87) ($2.00)

YTD $6.93 $4.01 $7.20 $6.40 $6.17 $5.17 ($2.92) $0.27 ($0.52) ($0.76) ($1.76)

2008

Q1 $8.47 $7.62 $8.88 $8.09 $7.83 $6.28 ($0.85) $0.41 ($0.38) ($0.64) ($2.19)

Q2 $11.21 $8.50 $11.64 $10.15 $9.65 $8.15 ($2.71) $0.43 ($1.06) ($1.56) ($3.06)

Q3 $9.34 $6.17 $9.60 $8.32 $7.29 $6.39 ($3.17) $0.27 ($1.02) ($2.04) ($2.95)

Q4 td $6.78 $3.11 $6.97 $4.34 $3.17 $5.30 ($3.66) $0.20 ($2.44) ($3.61) ($1.47)

YTD $9.29 $6.86 $9.63 $8.25 $7.58 $6.72 ($2.43) $0.35 ($1.04) ($1.71) ($2.56)

Henry

Week of Hub Rockies Appalachia California Mid-Con AECO Rockies Appalachia California Mid-Con AECO

11/ 7/ 2007 $6.93 $2.31 $7.22 $6.24 $5.67 $4.58 ($4.62) $0.29 ($0.69) ($1.26) ($2.35)

11/7/2008 $6.57 $3.19 $6.83 $4.00 $3.11 $5.17 ($3.38) $0.26 ($2.57) ($3.46) ($1.40)

Basis Differential

Regional Gas Prices and Basis Differential to Henry Hub ($/mmbtu)Weekly Weighted Average Prices ($/MMBtu) Basis Differential

16

Demand – Can Improve Long Term

16

30

40

50

60

70

80

90

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

De

ma

nd

, bcf

/da

y

Actual Natural Gas Demand

NPC Long Term Projection

17

Demand and Basis Risk

Northeast US

□ Natural Gas Demand ~8.5bcf/day over past eight years.

□ Growth Prospects?

□ Rockies Express = more gas

□ Shale Development in West Virginia and Kentucky = more gas

Does the region need the Marcellus?

Risk to basis?

17

1818

Natural Gas – Power Generation

2,000,000

2,500,000

3,000,000

3,500,000

4,000,000

4,500,000

5,000 6,000 7,000 8,000 9,000 10,000 11,000 12,000

US GDP, $billions (2000 dollars)

US

gen

erat

ion

, th

ou

san

d m

egaw

atth

ou

rs

US GDP and Total Power Generation Load

US Natural Gas Demand driven by

electricity sector expansion and

growth

19

Got Shale?

Rationale – Transition in Public Company E&P Mindset

□ 10 years ago - hard to find, but easy to produce Exploration focus Seismic / Geology driven

□ Now - easy to find, but hard to produce Shale plays – going to the source rock/formations Presence of gas not a big risk Engineering risk increase

19

20

Resource Triangle

Source: Holditch

21

Marcellus Shale ResourceCompany Net Acres Risk % Risked Acres Total Wells Reserves (bcfe)CHK 1,200,000 20% 240,000 3,000 6,612 REXX 57,000 30% 17,100 201 442 RRC 800,000 30% 240,000 2,987 6,583 SWN 98,000 30% 29,400 355 781 XCO 276,403 30% 82,921 954 2,003 XTO 152,000 30% 45,600 570 1,256 UPL 145,000 30% 43,500 544 1,198 EQT 400,000 20% 80,000 987 2,113 TOTAL 3,128,403 778,521 10,447 22,861

0

500

1,000

1,500

2,000

2,500

3,000

2008 2013 2018 2023 2028 2033 2038 2043 2048 2053

Dai

ly P

rod

uct

ion

(m

mcf

/d)

CHK REXX

RRC SWN

XCO XTO

UPL EQT

0

10

20

30

40

50

60

2008 2010 2012 2014 2016 2018 2020 2022 2024

Rig

Co

un

t

CHK REXX

RRC SWN

XCO XTO

UPL EQT

2222

Marcellus Shale

“According to the map we've only gone 4 inches.”

Harry…Dumb and Dumber

23

Haynesville Shale

The Good

□ Takes “froth” out of the Marcellus Shale

The Bad

□ Pulls some of the necessary capital resources away from the region

The Ugly

□ Creates a large amount of supply-side/production growth focus

23

24

Haynesville Shale Activity Overview

24

Source: Company Filings, Investor Presentations.

24

GDP – Vertical wellsHall 5 No. 1 (50% WI non-op)Caddo Parish; Central Pine Island FieldCompletion Phase

Taylor Sealey No. 1 (100% WI)Panola/Rusk Counties; Minden FieldIP ~ 2.6 MMcfe/d (22/64 choke)

Lutheran Church No. 4 (100% WI)Panola/Rusk Counties; Beckville FieldIP ~ 1.6 MMcfe/d

ECA (50% Shell)Sabine Parish: IP ~ 8 MMcf/dRed River Parish*: IP ~ 15 MMcf/d*T-R: 13N-9W

Current Players

Berry (4,500 Net)

Cabot (135,000 Gross)

Chesapeake (440,000 Net) & Plains E&P (110,000 Net)

Comstock (53,000 Net)

Devon (483,000 Net)

Ellora (70,600 Net)

El Paso (42,500 Net)

EnCana/Shell (370,000 Net)

Encore (21,200 Net)

EXCO (107,000 Net)

Forest (91,000 Net)

GMX Resources (38,500 Net)

Goodrich (60,500 Net)

J-W Operating (Acreage n/a)

Penn Virginia (60,000 Net)

Petrohawk (300,000 Net)

Questar (28,000 Net)

XTO (100,000 Net)CHK (20% Plains E&P)Caddo Parish; T-R: 15N-15W1) Feist 28-#01 (section 28)

IP ~ 2.6 MMcf/d (9/64 choke)11,596 ft. TVD

2) Milton Crow 27-1H (section 27)IP ~ 14 MMcf/d (24/64 choke)11,744 ft. TVD

PVA – 5/30/08 AnnouncementFogle #5-H (100% WI)Harrison County; South sectionIP ~ 8 MMcf/d11,378 ft. TVD, 3,861 ft. lateral

HK – 1H 08 AnnouncementsElm Grove Plantation #63 (100% WI)Bossier Parish; T-R: 16N-11W, sec 9IP ~ 16.8 MMcf/d (26/64 choke)11,005 ft. TVD, 3,880 ft. lateral

Hutchinson 9-6 (91% WI)Caddo Parish; T-R: 15N-12W, sec 9IP ~ 16.7 MMcf/d (22/64 choke)11,222 ft. TVD

COG – 11 Vertical wellsRusk County; Minden FieldIP ~ 650-2,300 Mcf/d11,596 ft. TVDTrawick: 3.3 MMcf/d testCounty Line test - 4Q 08

2525

Haynesville Shale Resource Summary

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

2008 2013 2018 2023 2028 2033 2038

Dai

ly P

rodu

ctio

n (m

mcf

/d)

XTO

PXP

APC

GMXR

GDP

XCO

HK

DVN

CHK

0

20

40

60

80

100

120

140

160

180

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Rig

Cou

nt

XTO

APC

GMXR

GDP

XCO

HK

PXP

DVN

CHK

Company Net Acres Risk % Risked Acres Total Wells Reserves (bcfe)DVN 483,000 50% 241,500 2,421 9,931 CHK 440,000 50% 220,000 2,558 10,905 HK 300,000 50% 150,000 1,875 8,526 XCO 125,000 50% 62,500 781 3,035 PXP 110,000 50% 55,000 496 2,112 APC 100,000 50% 50,000 433 1,846 XTO 100,000 50% 50,000 576 2,046 GDP 56,000 50% 28,000 350 1,466 GMXR 38,400 50% 19,228 240 1,025 TOTAL 1,752,455 876,228 9,730 40,892

26

Shale Development Issues

Macro Environment/Credit Markets Matter

Pipeline Infrastructure – Who builds the pipelines?

Onshore Production Growth:

□ Implications to overall gas price

□ Implications to basis differential

Growth Companies (i.e., deficit spenders) looking for partners/sell assets

Location Matters – Shale plays have lots of good and bad acreage

26

27

Emerging Shales

Canada

□ Utica (Eastern Canada)

□ Montney-Doig – NE BC

□ Horn River Basin – NE BC

United States

□ Haynesville

□ Marcellus Lots of other shales in Appalachia

□ Utica (NY)

□ Pearsall – S. TX

□ Some shales in Rockies…but basis differential an issue

27

28

Not All Shales Work

Palo Duro Canyon

□ Texas Panhandle

New Albany Shale – Indiana

□ Antrim look-alike…except no natural fractures

West Texas Barnett

□ Too early to stick a fork in….but results les than impressive

Mississippi / Alabama Shales – still early but…

□ Lots of wells with no positive well news

28

2929

2009 Free Cash Flow at Different Commodity Prices

($11,000)

($9,000)

($7,000)

($5,000)

($3,000)

($1,000)

$1,000

$3,000

$5,000

Large-Caps Mid-Caps Small-Caps

Fre

e C

ash

Flo

w (

$mm

)

$7 gas, $70 oil

$6 gas, $60 oil

$5 gas, $50 oil

3030

Gating Items - People - Revenge Of the Nerds! Horizontal Drilling□ Proper Azimuth□ Optimum Length

Completion – Hydraulic Fracture…can’t boilerplate□ Multiple Stages, Simultaneous Fracturing□ Slickwater vs. Gelled Fracs□ Regionally Specific□ Surfactant, 100 mesh, proppant transport etc.

Well Spacing - will drive ultimate recovery□ Depends on Completions and Reservoir□ Fracture Mapping with Micro-seismic helps

Reservoir Modeling difficult□ Natural fracture spacing/orientation□ Isotherm, gas-in-place, free gas porosity

“No one will really be free until nerd persecution ends.”

Gilbert – Revenge of the Nerds

Change! Gas Market Implications

Carbon Tax (er….Legislation) is Coming

□ Natural Gas should benefit Lower carbon than oil and coal

□ Drilling Wait and see

□ Magnitude of Tax? Skeptic says taxing fossil fuels last great gov’t

revenue source

□ Demand side management Expect legislation to encourage lower consumption

31

"Oh, uh, there won't be any money, but when you die, on your

deathbed, you will receive total consciousness." So I got that

goin' for me, which is nice Caddyshack - Carl

Spackler

32

Conclusion

Formula for success:

“Rise early, work hard, strike oil.”

J. Paul Getty

Formula for success - 2008:

“Rise early, work hard, buy acreage.”

Formula for success - 2009:

“Rise early, work hard, survive.”

32

3333

Disclaimer

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3434

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