EX-99.1 2 dex991.htm PRESENTATION BY PETROHAWK ENERGY CORPORATION Presentation by Petrohawk Energy Corporation
ANALYST DAY 2008
Exhibit 99.1

2
This communication
contains
“forward-looking
statements”
within
the
meaning
of
the
U.S.
Private
Securities
Litigation
Reform
Act
of
1995,
including
statements
regarding
planned
capital
expenditures
(including
the
amount
and
nature
thereof),
estimates
of
future
production,
the
number
of
wells
we
anticipate
drilling
in
2008 and beyond, availability and costs of drilling rigs and other oil field services, the number and nature of potential drilling locations, our growth strategies,
anticipated trends in our business, our future results of operations, estimates regarding future net revenues from oil and natural gas reserves and the present
value thereof, estimates, plans and projections relating to acquired properties, quality and nature of our asset base, our ability to successfully and economically
explore
for
and
develop
oil
and
gas
resources,
market
conditions
in
the
oil
and
gas
industry,
the
assumptions
upon
which
estimates
are
based
and
other
expectations, beliefs, plans, objectives, models, strategies, assumptions or statements about future events or performance often, but not always, using such
words
as
“expects,”
“anticipates,”
“plans,”
“estimates,”
“seeks,”
“believes,”
“hopes,”
“predicts,”
“envisions,”
“intends,”
“potential,”
“possible,”
“probable,”
“opportunities,”
“confident,”
or
stating
that
certain
actions
“may,”
“will,”
“should,”
or
“could,”
be
taken,
occur
or
be
achieved
("forward
looking
qualifiers"). 
Statements
concerning
oil
and
gas
reserves
also
may
be
deemed
to
be
forward-looking
statements
in
that
they
reflect
estimates
based
on
certain
assumptions
that the resources involved can be economically exploited and other assumptions.
All forward-looking statements contained in this communication (whether or not accompanied by a forward looking qualifier) are based on current expectations,
plans, estimates and projections that involve a number of risks and certainties, which could cause actual results to differ materially from those reflected in the
statements.  These risks include, but are not limited to, the risks of the oil and gas industry (for example, operational risks in exploring for, developing and
producing crude oil and natural gas; risks and uncertainties involving geology of oil and gas deposits; the uncertainty of reserve estimates; the uncertainty of
estimates and projections relating to future production, costs and expenses; potential delays or changes in plans with respect to exploration, development
projects or capital expenditures; and health, safety and environmental risks); uncertainties as to the availability and cost of financing; fluctuations in oil and gas
prices;
risks
related
to
our
hedging
program;
inability
to
realize
expected
value
from
acquisitions;
inability
of
our
management
team
to
execute
its
plans
to
meet
its
goals;
loss
of
services
of
our
management
team;
inability
to
replace
oil
and
gas
reserves;
shortage
of
drilling
equipment,
oil
field
personnel
and
services;
and
unavailability of gathering systems, pipelines and processing facilities.  All forward-looking statements contained in this communication (whether or not
accompanied by a forward looking qualifier) are based on the estimates, opinions and beliefs of our management at the time the statements are made and
should be considered approximations unless specifically indicated otherwise.  We assume no obligation to update forward-looking statements should
circumstances
or
our
management’s
estimates
or
opinions
change.
Unless
the
context
otherwise
indicates,
when
we
refer
to
“Petrohawk,”
the
“Company,”
“us,”
“we,”
“our,”
or “ours”
in this presentation, we are describing Petrohawk Energy Corporation, together with its subsidiaries.
The SEC permits oil and gas companies to disclose in their filings with the SEC only proved reserves, which are reserve estimates that geological and
engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating
conditions.  In
this
presentation,
Petrohawk
uses
the
term
“resource
potential”
which
could
be
equated
with
“probable”
and
“possible”
reserves.
SEC
guidelines
prohibit probable and possible reserves from being included in filings with the SEC.  Probable reserves are unproved reserves which are more likely than not to
be recoverable.  Possible reserves are unproved reserves which are less likely to be recoverable than probable reserves.  Resource potential includes both
types
of
reserves.
Estimates
of
probable
and
possible
reserves
which
may
potentially
be
recoverable
through
additional
drilling
or
recovery
techniques
are
by
their nature much more uncertain than estimates of proved reserves and accordingly are subject to substantially greater risk of not actually being realized by the
Company.
In
addition,
our
production
forecasts
and
expectations
for
future
periods
are
dependant
upon
many
assumptions,
including
estimates
of
production
decline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or
drilling costs increases.
Forward Looking Statements

3
Core Resource Areas
Elm Grove /  Terryville /  Fayetteville Shale
72% of Current Production
69% of Proved Reserves
87% of 2008 Capital Budget
90% of Future Drilling Locations
96% of Total Resource Potential
Petrohawk Today
Resource-style
tight
gas
focus:
conventional
and
unconventional
–
1.1 Tcfe
of Proved Reserves, 90% Natural Gas, 57% Proved Developed
–
4.7 Tcfe
Total Resource Potential
–
Multi-year drilling inventory and significant upside in low-risk exploration and
development
–
100% drilling success rate in Core Areas
Sawyer
Fayetteville Shale
Woodford Shale
WEHLU
James Lime
Terryville
Elm Grove
TXL North
Waddell Ranch
Jalmat

4
High Potential Core Assets
(1)
Based on Petrohawk estimates of risked potential including proved and non-proved locations and reserves. 
(1)
Concentrated upside in
three core resource areas
Stable proved reserve base
in Western Region
Total upside significantly
above current valuation
Approx. Net Acres
Proved
Reserves (Bcfe)
Future
Risked
Drilling
Locations
Estimated
Risked Resource
Potential (Tcfe)
Fayetteville
155,000
54
6,600
2.0
Elm Grove
34,000
542
1,500
1.5
Terryville
42,000
129
900
1.0
Total Core
231,000
725
9,000
4.5
Western / Other
292,000
337
1,000
0.2
Total Company
523,000
1,062
10,000
4.7

5
Undervalued Resource Company
7.5x
11.6x
12.3x
14.0x
14.3x
15.1x
15.7x
0.0x
3.0x
6.0x
9.0x
12.0x
15.0x
18.0x
HK
RRC
SWN
KWK
DPTR
UPL
SD
EV/EBITDA
EV / 2008E EBITDA
(1)
6.3x
7.3x
11.1x
12.4x
12.9x
16.4x
16.8x
0.0x
3.0x
6.0x
9.0x
12.0x
15.0x
18.0x
HK
KWK
RRC
DPTR
SWN
UPL
SD
Price/CFPS
Price / 2008E CFPS
(1)
$18,610
$28,841
$28,984
$39,490
$32,468
$30,994
$34,824
0
10,000
20,000
30,000
40,000
HK
KWK
RRC
SWN
UPL
SD
DPTR
$/Mcfe/d
EV / Latest Daily Production ($/Mcfe/d)
(2)
$4.03
$4.06
$4.08
$4.09
$5.15
$5.75
$8.20
$0.00
$3.00
$6.00
$9.00
RRC
UPL
HK
KWK
SD
DPTR
SWN
$/Mcfe
EV / Proved Reserves ($/Mcfe)
(2)
Source: Lehman Brothers
(1)
Prices as of 3/10/08.  EBITDA and CFPS estimates based on Wall Street research analyst estimates, adjusted to normalize price decks.
(2)
Prices as of 3/10/08.  Production and proved reserves based on most recent publicly released data.

6
Natural
Gas
Companies
are
On
the
Move

7
High Price Realizations
(1)
Gas: 103% NYMEX / Oil: 97% NYMEX
Low-Cost Operator
(1) Based on Q4 realized prices. Gas prices include NGLs.
$0.00
$1.00
$2.00
$3.00
UPL
SWN
HK
RRC
SD
DPTR
KWK
$0.00
$1.00
$2.00
$3.00
HK
FST
XTO
CRK
SFY
SM
XEC
COG
EAC
WLL
PXP
$0.92
Q4 2007 Operating Cost Comparison
Resource Companies
Non–Resource Companies
LOE, Workover, Gathering, and Transportation
$0.92
Our lease operating costs are among the lowest in the sector
–
FY 2007 LOE = $0.56 per Mcfe vs. $0.73 per Mcfe in 2006
$/Mcfe
$/Mcfe

8
Focus on Margins
@$8.00
Petrohawk has continually posted improved cash margins
In 2008, HK can achieve over 50% cash margins at under $6.50 gas
1
Excludes one-time severance cost associated with the Gulf Coast divestiture.
(1)
@$7.00
LOE + Workover
Taxes -
other
Gathering / Trans
G&A
Interest
Cash Margin
$-
$1.00
$2.00
$3.00
$4.00
$5.00
$6.00
$7.00
$8.00
$9.00
2006
2007
2008E
2008E
2008E
2008E
@$7.41A
@$7.50
@$6.50
@$6.75A

9
2007 Proved Reserves
Other
337 / 32%
Core
725 / 68%
Proved Reserves (Bcfe), SEC Pricing
PV-10 Value ($ millions), SEC Pricing
PUD Reserves
Other
99 / 21%
Core
356 / 79%
SEC
Pricing
(as
of
12/31/07):
Oil
-
$95.98/bbl
($92.50
Posted);
Gas
-
$6.80/MMbtu
Note: Reserves per NSAI as of 12/31/07; PV10 is pre-tax
•
Reserve growth >30%, after adjusting for sales
•
90% Gas
•
57% Proved Developed
•
77% Operated
•
11.5 Year RPI
•
SEC PV10 $2.56 billion
•
Organic F&D Cost $2.38/Mcfe
•
Organic Reserve Replacement 281%
•
All Sources F&D Cost $3.51/Mcfe
•
All Sources Reserve Replacement 318%
Other
$890 / 34%
Core
$1,688 / 66%

10
1076
30
437
1062
0
200
400
600
800
1,000
1,200
2004
2005
2006
Production
Divestments
Adds +
Revisions
2007
Proved
Reserves:
Growth
and
Improved
Quality
375
116
273

11
2008 Capital Budget
$800 million
Core Expansion
–
90% operated
–
~650 total gross wells
–
87% allocated to Core Resource
Areas
Core Areas
87%
$692 MM
Non-Core Areas
13%
$108 MM
Drill & Complete
87%
Seismic
1%
Land
2%
Facilities
4%
Recompletions
6%
PUD
35%
Non-PUD
65%

12
7
8
4
1
1
21 Operated Rigs
–
Fayetteville ramping up to 7 rigs
Improvement based on drilling
efficiencies
–
Twelve-rig program planned for
Elm Grove and Terryville
Horizontal program
Downspacing + expansion
Additional zone exploration
Fayetteville
34%
Terryville
15%
Other
13%
Elm Grove
38%
2008 Capital Budget

13
$293 million
~140 operated wells
~50 non-operated wells
20 acre downspacing
20 operated horizontal wells
–
Build on recent Taylor Sand success
•
10 horizontal wells in Taylor
•
10 Davis Sand wells
Developing
Haynesville
Shale
play
Elm Grove Field Overview
90%
% Operated
2008 Budget:
1,500 on 20 acre spacing
Potential
Locations:
$0.30 /  Mcfe
LOE:
Drilling: $1.8 –
4.5 MM / Well
Recompletion: $0.6 MM / Well
Est. Well Cost:
1.5 Tcfe
Est. Resource
Potential:
Drilling: 1.2 –
5.0
Bcfe / Well
Recompletion: 0.5
Bcfe / Well
Est. EUR:
Approx. 34,000
Net Acreage:
(1)
Elm Grove
Monroe
Shreveport
2008 Drilling Plan
(1) Petrohawk estimates of risked potential.

14
Elm Grove: Reserve and Production Summary
Reserves YE 2006 to YE 2007:
–
Increased
from
454
Bcfe
to
549
Bcfe
for
21%
YOY
Growth
Daily Production Full Year 2006 to Full Year 2007:
–
Increased
from
78
MMcfe/d
to
95
MMcfe/d
for
22%
YOY
Growth
0
100
200
300
400
500
600
2003
2004
2005
2006
2007
2008E
0
20
40
60
80
100
120
140
Proved Reserves
Net Production
Reserves
(Bcfe)
Production
(Mmcfe/d)

15
Elm Grove: Cotton Valley Structure
with 2007 & 2008 Drilling Program
2007 Drilling Program
2008 Drilling Program
2007 Drilling Program
2007 Drilling Program
2008 Drilling Program
2008 Drilling Program

16
Elm Grove: Type Log and Play Type
Coil Tubing fracture stimulation avoids salt
water and allows co-mingling with Cotton
Valley production
Approximately $400,000 to recomplete
53 Hosston recompletions planned in 2008
Stratigraphic
field pay
Possible horizontal target
Most prevalent sand across field area
Developed vertically on 20 acre spacing
Ongoing 10 well horizontal program
Better porosity and permeability, and higher
pressure, than Cotton Valley Davis
Ongoing 10 well horizontal program
UPPER COTTON VALLEY (8,500’
-
9,000’)
HOSSTON (7500’
-
8500’)
COTTON VALLEY DAVIS (9,300’
-
9 500’)
LOWER  COTTON VALLEY TAYLOR (9,800’
-
10,000’)

17
Elm Grove: Horizontal Targets
Thickness
30 ft
HORIZONTAL
TARGET
LCV Taylor Sand
Type Log
Gross
Thickness
250 ft
Cotton Valley Davis
Type Log
HORIZONTAL
TARGET

18
Elm Grove: Isopach
Lower Cotton Valley
Taylor Sand
Knighton
#14-5
Drilling
Roos
#8
Completing
Killen #13-3
IP: 16.5 MMcfe/d
Killen #13-4
Completing
JW Leiber
4.0 MMcfe/d
Planned 1
st
half
new drill
Currently drilling
Producing well

19
JW Operating Moore #2H
IP: 2.0 MMcfe/d
Petrohawk Snyder #26-5H
IP: 4.5 MMcfe/d
Petrohawk Charles Horton #30-1H
IP: 3.1 MMcfe/d
Planned 1
st
half
new drill
Currently drilling
Producing well
Elm Grove: Isopach
Cotton Valley
Davis Sand

20
Haynesville Shale:
New North Louisiana Resource Play
Rich organic Shale between Bossier and Smackover
Ranges in depth between 10,500’-13,000’
Highly overpressured
in southern area of play
Elm Grove area only marginally overpressured
Over 200’
thick underlying Elm Grove
Encana
J.W. Adcock core indicates favorable geochemical
and petrophysical
characteristics

21
JW Operating:
Attempted to Frac
Screened out
Petrohawk:
Drilled deep vertical test
Section comparable to CHK
and Encana
Horizontal well scheduled Q2
Chesapeake:
Completed one low volume vertical well
Completed horizontal well in October
2007 for 2.8 MMcfe/d
Planned
1
half
new drill
Currently drilling
Producing well
Camterra, Questar
and JW:
Permitted or AFE’d
vertical wells
Haynesville Shale
A
A’
Encana:
Completed 5 low volume
vertical wells
Released whole core data with
favorable rock properties
Recently frac’d
first horizontal well
Awaiting results
st

22
Haynesville Shale: Cross Section
A
A’
Chesapeake
#1-29H SLRT
2007 Horizontal Test
Encana
J.W. Adcock
Vertical Completion
Petrohawk
EGP 9-15
Elm Grove Deep Test
Test 4.0 MMcfe/d
IP: 2.7 MMcfe/d
>200’
Net Shale

23
Resource Potential
Terryville
Fayetteville
Total Company
Elm Grove
Undeveloped acres: 20,000
Spacing: 20 Acres
Risked Potential: 65%
Avg
Gross Reserves: 1.3 Bcfe
Net Revenue Interest: 80%
Estimated Resource Potential: 1.5 Tcfe
Undeveloped acres: 30,000
Spacing: 60 Acres
Risked Potential: 65%
Avg
Gross Reserves: 3.0 Bcfe
Net Revenue Interest: 80%
CV / Hosston
Haynesville
+ Proved Reserves =
2.0 Tcfe

24
Terryville Field Overview
90%
% Operated
2008 Budget:
Over 900 on 20-acre
spacing
Potential
Locations:
$0.15 / Mcfe
LOE:
$1.8 –
3.2 MM / Well
Est. Well Cost:
1.0 Tcfe
Est. Resource
Potential:
1.2 –
3.0
Bcfe / Well
Est. EUR:
Approx. 42,000
Net Acreage:
$121 Million
~60 operated wells
~15 non-operated wells
50 sq. mile 3D survey completed
Additional seismic planned
Horizontal exploitation
Gray Sand exploration
Bossier exploration
(1) Petrohawk estimates of risked potential.
(1)
Terryville
Monroe
Shreveport
2008 Drilling Plan

25
Terryville: Production and Reserves
Reserves YE 2006 to YE 2007:
–
Increased from 84 BCFE to 122 BCFE for 45% YOY Growth
Daily Production Full Year 2006 to Full Year 2007:
–
Increased from 17 MM/d to 40 MM/d for 135% YOY Growth
-
20
40
60
80
100
120
140
2003
2004
2005
2006
2007
2008E
0
10
20
30
40
50
60
Proved Reserves
Net Production
Reserves
(Bcfe)
Production
(Mmcfe/d)

26
Terryville: Cotton Valley / Bossier Type Log
Base Bossier
Lower CV
Bodcaw
CV Vaughn
CV “D”
Bossier
9500 -
10,600’
10,600-
11,700’

Terryville:
Lower
Cotton
Valley
Structure
Terryville Extension Acquisition
•
Minimal Lower Cotton Valley,
Bossier & Gray penetrations
Existing Terryville 3D
Area of Possible Eastern 3D
Existing Terryville Productive Area
Area of Ongoing Western 3D
27

28
Terryville: Bossier Wedge Cross Section
T. Bossier
B. Bossier
T. Bossier
B. Bossier
~ 600’
~ 1300’

31
Terryville Extension: Cotton Valley Structure
Terryville Field
Terryville Extension Acquisition
8000 acres controlled
Hosston, UCV approx. 25% WI
LCV, Bossier, Gray Sand minimum 75% WI
Two Gray Sand locations scheduled Q2
Terryville Extension 3D
60 square miles
Currently permitting
Anticipate late Q3/ early Q4
delivery
Planned 1
st
half
new drill
Currently drilling
Producing well

32
Resource Potential
Terryville
Fayetteville
Total Company
Elm Grove
Undeveloped acres: 20,000
Spacing: 20 Acres
Risked Potential: 65%
Avg
Gross Reserves: 1.3 Bcfe
Net Revenue Interest: 80%
Estimated Resource Potential: 1.5 Tcfe
Undeveloped acres: 30,000
Spacing: 60 Acres
Risked Potential: 65%
Avg
Gross Reserves: 3.0 Bcfe
Net Revenue Interest: 80%
CV / Hosston
Haynesville
Undeveloped acres: 37,000
Spacing: 20 Acres
Risked Potential: 50%
Avg
Gross Reserves: 1.4 Bcfe
Net Revenue Interest: 80%
Estimated Resource Potential: 1.0 Tcfe
+ Proved Reserves =
2.0 Tcfe
+ Proved Reserves =
1.2 Tcfe

33
Fayetteville Shale Overview
$0.35
/ Mcfe
LOE:
90%
% Operated
2008 Budget:
Over 6,600 on 60 acre
spacing
(1)
Potential
Locations:
$1.75 –
2.75 MM / Well
Est. Well Cost:
2.0 Tcfe
(2)
Est. Resource
Potential:
1 –
4 Bcfe / Well
Est. EUR:
Approx. 155,000
Net Acreage:
2008 Drilling Plan
$278 million
Maximum 7 rig program
–
~150 operated wells
–
~120 non-operated wells
Capitalize on tight-gas
completion expertise
Invest heavily in infrastructure
A R K A N S A S
Little Rock
Fayetteville Shale
Arkoma Basin
(1) Based on internal risked estimate.
(2) Petrohawk estimates of risked potential.

34
Production / Reserve Summary
0
10
20
30
40
50
60
2006
2007
2008E
0
10
20
30
40
50
60
Proved Reserves
Net Production
Reserves
(Bcfe)
Net Production
(Mmcfe/d)
Reserves YE 2006 to YE 2007:
–
Increase from 0.5 to 54.4 Bcfe
–
Included 250 total wells
•
150 Proved Developed with
average EUR of 1.8 Bcfe
•
98 Proved Undeveloped locations
with average EUR of 1.7 Bcfe
Production YE 2006 to YE 2007:
–
Increased Gross Operated Production
from 0 to ~42 MMcfe/d
–
Current Gross Operated ~ 70 MMcfe/d

35
Fayetteville: Production Growth
0
5
10
15
20
25
30
35
40
45
50
55
60
65
70
75
2/1/2007
3/1/2007
4/1/2007
5/1/2007
6/1/2007
7/1/2007
8/1/2007
9/1/2007
10/1/2007
11/1/2007
12/1/2007
1/1/2008
2/1/2008
3/1/2008
Gross Operated Production

36
Time Zero Production Plot
Petrohawk Operated Fayetteville Shale
Average Daily Production Per Well
0
500
1,000
1,500
2,000
2,500
3,000
3,500
Petrohawk Operated Daily Average
3.0 Bcf Type Curve
2.0 Bcf Type Curve
1.0 Bcf Type Curve
Month of Production
1st
2nd
3rd
4th
5th
6th
7th
8th
9th
10th
11th
12th
13th
Sample Set
# Wells
28
22
16
13
10
9
8
7
5
4
3
2
1

37
Fayetteville:  Core Area with Net Isopach
> 1 MMcfe/d
1 -
2 MMcfe/d
2 -
3 MMcfe/d
> 3 MMcfe/d
Currently Drilling
Scheduled 1H 2008
50’
100’
125’
150’
200’
75’

38
Fayetteville –
Northern Area
PETROHAWK
HIPP
PETROHAWK
BURGESS
PETROHAWK
GREEN BAY

39
Fayetteville: Northern Cross Section
PETROHAWK
GREEN BAY
PETROHAWK
BURGESS
PETROHAWK
HIPP
PETROHAWK
03141102100000
1-16H
GREEN BAY
PETROHAWK
03141102260000
1-11H
BURGESS
PETROHAWK
03023100630000
1-30
HIPP
<14.02MI>
<13.51MI>
0
150
GR [GAPI]
0.1
20000.45
AF10 [OHMM]
0.1
20000.45
AF20 [OHMM]
0.1
2000
AF30 [OHMM]
0.1
2000
AF60 [OHMM]
0.1
2000
AF90 [OHMM]
0
NPHI [CFCF]
0
DPHZ [CFCF]
0
150
GR [GAPI]
0.1
20000.45
AF10 [OHMM]
0.1
20000.45
AF20 [OHMM]
0.1
2000
AF30 [OHMM]
0.1
2000
AF60 [OHMM]
0.1
2000
AF90 [OHMM]
0
NPHI [CFCF]
0
DPHZ [CFCF]
0
150
GR [GAPI]
0.1
20000.45
AF10 [OHMM]
0.1
20000.45
AF20 [OHMM]
0.1
2000
AF30 [OHMM]
0.1
2000
AF60 [OHMM]
0.1
2000
AF90 [OHMM]
0
NPHI [CFCF]
0
DPHZ [CFCF]
660
690
720
750
780
810
840
870
900
930
960
990
1020
1050
1080
1110
1140
1170
1200
1230
1260
1290
1320
1350
1380
1410
1440
1470
1500
1530
1560
1590
1620
1650
1680
1710
1740
1770
1800
990
1020
1050
1080
1110
1140
1170
1200
1230
1260
1290
1320
1350
1380
1410
1440
1470
1500
1530
1560
1590
1620
1650
1680
1710
1740
1770
1800
1830
1860
1890
1920
1950
1980
2010
2040
2070
2100
2130
2160
840
870
900
930
960
990
1020
1050
1080
1110
1140
1170
1200
1230
1260
1290
1320
1350
1380
1410
1440
1470
1500
1530
1560
1590
1620
1650
1680
1710
1740
1770
1800
1830
1860
1890
1920
1950
1980
2010
Fayetteville
Shale
Morrow Shale
Basal Hale
L. Fayetteville
Shale

40
Fayetteville –
Northern Area
Section 11-T11N-13W:
2 Brown wells
producing 3.1 MMcfe/d
1 Burgess well
producing 1.4 MMcfe/d
Section 14-T12N-12W:
May well producing
1.2 MMcfe/d
Section 31-T12N-10W:
Hipp
vertical well
test 1.0 MMcfe/d;
WOPL
Section 30-11N-13W:
Lewis well tested
3.3 MMcfe/d; WOPL
Section 7-11N-15W:
Lemings
well
waiting on frac
Section 4 & 5-10N-12W:
7 Whisenhunt
wells
producing 10.0 MMcfe/d
19 HK Operated Wells Producing 27 MMcfe/d
Expected EUR 1.5 –
2.0 Bcfe
per well
Section 19-11N-14W:
Gunn well cleaning up
after workover
Anticipate 0.4-0.6 MMcfe/d
1
st
Northern well drilled
Fault complications
Frac
only 50% of other fracs
Section 16-11N-15W:
Green Bay well
producing 400 Mcfe/d
2
nd
Northern well drilled
Frac
only 40% of other fracs
Section 16 & 17-11N-13W:
5 Brown wells producing
8.0 MMcfe/d
2 Bentzinger
wells producing
3.0 MMcfe/d

41
Fayetteville –
Southern Area
PETROHAWK
WHISENHUNT
TEXAS OIL & GAS
LILES
PETROHAWK
BOLAND

42
Fayetteville: Southern Cross Section
PETROHAWK
WHISENHUNT
TEXAS OIL & GAS
LILES
PETROHAWK
BOLAND
PETROHAWK
03115107080000
1-5H
CIRCLE V RANCH
PETROHAWK
03141100440000
1-36H
WHISENHUNT
TEXAS O&G
03023100030000
1
LILES
<27.78MI>
<21.91MI>
0
150
GR [GAPI]
0.1
20000.45
AF10 [OHMM]
0.1
20000.45
AF20 [OHMM]
0.1
2000
AF30 [OHMM]
0.1
2000
AF60 [OHMM]
0.1
2000
AF90 [OHMM]
0
NPHI [CFCF]
0
DPHZ [CFCF]
0
150
GR [GAPI]
0.1
20000.45
AF10 [OHMM]
0.1
20000.45
AF20 [OHMM]
0.1
2000
AF30 [OHMM]
0.1
2000
AF60 [OHMM]
0.1
2000
AF90 [OHMM]
0
NPHI [CFCF]
0
DPHZ [CFCF]
0
150
GRR [GAPI]
0.1
20000.45
ILM [OHMM]
0.1
2000
ILD [OHMM]
0
NPHI [CFCF]
2320
2360
2400
2440
2480
2520
2560
2600
2640
2680
2720
2760
2800
2840
2880
2920
2960
3000
3040
3080
3120
3160
3200
3240
3280
3320
3360
3400
3440
3480
3520
3560
3600
3640
3680
3720
3760
2480
2520
2560
2600
2640
2680
2720
2760
2800
2840
2880
2920
2960
3000
3040
3080
3120
3160
3200
3240
3280
3320
3360
3400
3440
3480
3520
3560
3600
3640
3680
3720
3760
3800
3840
3880
3920
3600
3640
3680
3720
3760
3800
3840
3880
3920
3960
4000
4040
4080
4120
4160
4200
4240
4280
4320
4360
4400
4440
4480
4520
4560
4600
4640
4680
4720
4760
4800
4840
4880
4920
4960
5000
5040
Fayetteville
Shale
L. Fayetteville
Shale

43
Fayetteville –
Southern Area
Section 29-10N-15W:
Chwalinski, Huff &
Jones wells
5 wells producing
6.1 MMcfe/d
SWN Cove Creek Field:
8N-14W
35 wells with average
State Test of
1.5 MMcfe/d
Section 20-9N-12W:
Sequoyah well
State Test  3.8 MMcfe/d
Producing 1.8 MMcfe/d
Whisenhunt
Development:
19 wells producing 30 MMcfe/d
1.6 MMcfe/d
per well
8N-15W & 16W:
Underdeveloped
townships
Comparable net
iospach
to Cove
Creek Field
26 HK Operated Wells Producing 40 MMcfe/d
EUR 2.0 Bcfe
per well
Section 9-9N-12W:
Rothwell
well
State Test 4.6 MMcfe/d
Producing 3.2 MMcfe/d

44
Fayetteville Seismic: 2D and 3D
Seismic
Data
Summary:
1,027 miles of existing 2D seismic
120 miles of new 2D to be shot in 2008
40 square miles of existing 3D seismic
43 square miles of new 3D to be shot or acquired in 2008 over
operated sections
268 non-operated sections with existing or in-progress 3D surveys
Primary
Benefit:
Identify macro structural features, specifically faults in excess of 50’
2D data can be effective in accomplishing this

45
Regional Fayetteville Depth Map
1000’
2000’
3000’
4000’
6000’
5000’
•
We operate in the entire depth   
range of the play
•
Reserves and costs have a
relative relationship to depth
•
Drilling and completion
efficiencies are occurring at all
depths

46
Comparative Well Cost and Reserves by Depth
1,500' TVD / 4,000' MD
3,500' TVD / 6,500' MD
5,500' TVD / 8,500' MD
RIG
$213M
$267M
$365M
TUBULARS
$85M
$123M
$142M
MUD
$45M
$55M
$65M
FRAC COST / STAGES
$450M / 6
$530M / 8
$650M / 9
COMPLETION PACKERS
$130M
$160M
$248M
FIXED COSTS
$745M
$1,105M
$1,255M
EST. TOTAL WELL COST
$1,688M
$2,240M
$2,725M
EST. RESERVE RANGE (BCF)
1.0 - 2.0
1.0 - 3.0
1.0 - 4.0
DEV. COST PER MCFE @ 80% NRI
$2.09 - $1.05
$2.80 - $0.93
$3.41 - $0.85
Note: Assumes no intermediate casing. Major fixed costs include roads, location, directional tools and completion rig.

47
Fayetteville: Simul-Frac
Summary
Total of 8 have been pumped (7 Simul-Fracs
and
1 Tri-Frac)
All have been drilled 560’
apart, simulating 40 acre
drainage
Most have resulted in production comparable to, or in
excess of, nearby single well completions
Most recent wells were frac’d
on February 29
th
We will monitor results to support 40 acre development 

48
Fayetteville: Northern Area Simul-Frac
Results
HK Burgess #1-11H
Frac’d
December 19
th
Producing 1.4 MMcfe/d
HK Lewis #1-30H: 
Frac’d
January 3
rd
Tested 3.3 MMcfe/d; WOPL 
1
st
Sales Est. March 15th
HK Bentzinger
#1 & 2-17H: 
Frac’d
February 21
st
Producing 1.5 & 1.5 MMcfe/d
HK Brown #1 & #2-11H
Frac’d
February 29
th
Producing 1.6 & 1.5 MMcfe/d
Single Fracs
Simul-Fracs
HK Brown #2 & #3-16H:
Frac’d
February 5
th
Producing 1.8 & 1.8 MMcfe/d
HK Brown #1 & 2-17H: 
Frac’d
January 18
th
Producing 1.8 & 1.6 MMcfe/d
HK Brown #1-16H:
Frac’d
December 14
th
Producing 1.4 MMcfe/d

49
Cemented Liner Completion System
Pros for Cemented Liner System
Ability to specifically place perforations
Ability to control the number of perforations
Ability to eliminate sand production
Eliminate the mechanical risk of the packer system
Not limited to a maximum number of stages

50
Open Hole Packer Completion System
Pros for Open Hole Packer System
Frac
pumped 1 day, accelerating production
Frac
accesses entire formation face in the stage
Formation is not exposed to damaging cement
Surface logistics and down hole time with tools
minimized

51
Fayetteville Drilling Efficiencies (<5,000 ft MD)
$450,000 per well savings
–
Spud-to-spud reduced by 45%
BHA optimization
Drilling parameters
0
5
10
15
20
25
30
$0
$1,000,000
$2,000,000
Spud to Spud
Avg Est Cost
Casing size reduction
Spudder
rig
Continuous improvement
Feb 2007
Jan 2008

52
Fayetteville Drilling Efficiencies (>5,000 ft MD)
$200,000 per well savings
–
Spud-to-spud reduced by 35%
No intermediate casing
Spudder
rig
0
5
10
15
20
25
30
$0
$1,000,000
$2,000,000
Spud to Spud
Avg Est Cost
Optimized casing
Upgraded rig fleet
Continuous improvement
Feb 2007
Jan 2008

53
Fayetteville: Drilling Performance
Rig efficiency up 50%
Spud-to-spud down 40%
3
5
6
6
9
1
1.50
1.67
1.50
1.50
2.25
0
3
6
9
J-A '07
Sep
Oct
Nov
Dec
Jan08
12
14
16
18
20
22
24
26
Wells per Month
Rig Count
Spud to Spud
Drill more wells with fewer rigs
–
Budgeted 155 wells with 5 rigs
–
Drill 2.5 wells per rig per month

54
Fayetteville Pipeline Plan
Petrohawk
Gathering
Expected to be stand-alone profit center
~100 miles of gathering lines built or planned
Goal is better control and cost efficiencies
Aggressively seek to transport third party gas
Firm Transport on Boardwalk
Contracted for 100 MMbtu/d
transportation
Total pipeline capacity –
850 MMbtu/d
Expected service in late 2008
Access to Eastern markets –
expect ~$0.45/MMbtu price upgrade

55
Resource Potential
Total Company
Elm Grove
Undeveloped acres: 20,000
Spacing: 20 Acres
Risked Potential: 65%
Avg
Gross Reserves: 1.3 Bcfe
Net Revenue Interest: 80%
Estimated Resource Potential: 1.5 Tcfe
Undeveloped acres: 30,000
Spacing: 60 Acres
Risked Potential: 65%
Avg
Gross Reserves: 3.0 Bcfe
Net Revenue Interest: 80%
CV / Hosston
Haynesville
Terryville
Undeveloped acres: 37,000
Spacing: 20 Acres
Risked Potential: 50%
Avg
Gross Reserves: 1.4 Bcfe
Net Revenue Interest: 80%
Estimated Resource Potential: 1.0 Tcfe
Fayetteville
Undeveloped acres: 155,000
Spacing: 60 Acres
Risked Potential: 65%
Avg
Gross Reserves: 1.6 Bcfe
Net Revenue Interest: 78%
Estimated Resource Potential: 2.0 Tcfe
+ Proved Reserves =
2.0 Tcfe
+ Proved Reserves =
1.2 Tcfe
+ Proved Reserves =
2.1 Tcfe

56
Western Region: Locator Map
Jalmat
TXL North
Waddell Ranch
Sawyer
James Lime
Tyler Waterflood
Talihina NW
WEHLU
Lipscomb
74%  
% Gas:
$1.15
/ Mcfe
LOE:
51%
% Operated
2008 Budget:
$87MM
2008 Budget:
72
MMcfe/d
Daily
Production:
0.2 Tcfe
Est. Resource
Potential:
325 Bcfe
Proved
Reserves:

57
Production / Reserve Summary
Steady state assets with low maintenance capital requirements
Low decline, high cash generation
Growth opportunities derived from special projects
0
50
100
150
200
250
300
350
400
2003
2004
2005
2006
2007
2008E
0
10
20
30
40
50
60
70
80
Proved Reserves
Net Production
Reserves
(Bcfe)
Production
(Mmcfe/d)
Note: 2003 –
2005  proved reserves internally estimated

58
Western Region: WEHLU
West Edmond Hunton
Lime Unit
Hunton
production @ ~ 8,000’
Oklahoma & Logan Counties, Oklahoma
33,000 net acres
~8.0 MMcfe/d
current net production w/
~2.0 MMcfe/d
shut-in
$18 million 2008 budget
Combination of vertical and horizontal
development
AMI with Chesapeake on west side
17
20
29
28
27
32
33
34
5
4
8
18
17
24
25
LOGAN
OKLAHOMA
I DRAKE
CALVERT
STORM
STORM
LIBECAYT
TRINDLE
STATE 34
STEWART
CRISWELL
LENHART
BOONE PEARL M
BOONE 1 (PEARL M)
MESSENBAUGH
CHRISTNER
LENHART "B"
FENTON
WILLY #1-7
396
DAMOGRAM #1-7
190
MABEL T #1-18
178
O`BRIEN 1-9
101
WHISLER
WHISLER
WHISLER
GILMORE
ODLE
ODLE
WISHER
VIDA
MCKINNIS
WHISLER
WHISLER
CODER 'A'
C. B. O'BRIEN
O' BRIEN "B"
YOUNG
CARGILL
CARGILL B
MC CUNE
BLUFF D
BLUFF E
BLUFF D
STATE 16 B
LYONS
S DAVIS
CASEY
PAULEY
PATTEN B
PAULEY
KIRCHNER
COURT RECEPTION #1-18
158
UNBRIDLEDS BOY
11
MAJESTRY'S CROWN 1-12
300
SPUNKY GAL 1-17
74
CARACOL
29
BODKIN
55
STATE OF OKLAHOMA 2
STATE OF OK 1-16
6
STYLES, D.G.   # 1-13
131
LUCKY HORSE #1-1
148
DERR 1-36
16
LUCKY HORSE #2-1
284
MAJESTY'S CROWN #2-12
71
STYLE, D.G.  #2-13
167
SULTAN 1-6H
64
SPUNKY GAL 2-17H
181
STATE OF OKLAHOMA
63
VELVET ELVIS
128
WILBUR
34
MR ED
100
GRACELAND
KING LION
193
BA 1-30H
215
MABEL T 2-18H
310
ZIEBELL 1-31H
138
Deer Lakes 1-H
128
BA 2-30H
221
BA 3-30H
156
BA 3-30H L1
BA 3-30H L2
CHADDUCK 1-6H
0
CHADDUCK1-6H LW
CHADDUCK 1-6H LE
ELLA 1-20H
ELLA 2-20H
ELLA 1-20H LS
ELLA 2-20H LS
SENTERS 1-7H
SENTERS 1-7H LE
SENTERS 2-7H
SENTERS 2-7H  LW
SENTERS 2-7H LE
SENTERS 1-7H LW
ELLA 1-20H LN
ELLA 2-20H LN
RATLIFF 1-6H
RATLIFF 2-6H
FEET
0
4,000
PETRA 3/7/2008 7:07:40 AM
Well Locations 1/2008
Old Active Oil Well –
Petrohawk
Old Active Gas Well –
Petrohawk
Old Shut-IN Well –
Petrohawk
New 2001 –
2007 Oil Wells
2008 –
2009 Proposed Horizontal
2008 Proposed Vertical
4
5
9
1
8
5
11
6
10
2
2
7
1
3
3
4
6
7

59
Western Region: Sawyer Field
Petrohawk operated
Sutton County, Texas
Canyon Sand production @ ~ 5,000’
91-100% W. I.
10 MMcfe/d
current net production
$18.6 million 2008 budget
30 Bcf
PUD reserve add in 2007
Expected proved reserve adds in 2008

60
Western Region: Additional 2008 Activity
Other significant areas of development:
Waddell Ranch/Crane County, Texas
–
Ongoing development
of
shallow
oil
fields
(3,000
-
5,000’)
within
76,000 acre ranch
–
Several deeper
(8,000
-
10,000’)
exploratory
wells
budgeted
in
2008
Jalmat/Lea County, New Mexico
–
2008 budget primarily lower-risk Seven Rivers and Yates re-completions
–
Initiation of Queen Sand Waterflood
East Texas
–
Continued development of James Lime horizontal and Travis Peak
vertical program in Nacogdoches County
–
Initiation of Tyler (Paluxy) Waterflood
in Smith County

61
2008 Guidance
-
50
100
150
200
250
300
350
Fayetteville
Elm Grove
Terryville
Permian / Other
2007
Pro Forma
(2)
2008
Guidance
(1)
Includes non-cash stock based compensation charges of $0.12 -
$0.16 / Mcfe.
(2)
Pro forma production for Gulf Coast divestment and acquisitions.
25% organic production growth from core areas
Avg. daily production expected to range between 250 and 260 MMcfe/d
240
295 –
315
Production
($ per Mcfe of production unless otherwise noted)
Production (Mmcfe/d)
295
-
315
Lease Operating Expense
$0.50
-
$0.60
Workover Expense and Other
$0.04
-
$0.08
Production Taxes (Ad Val and Severance, % of Rev)
6.00%
-
7.00%
Gathering, Transportation and Other
$0.30
-
$0.40
General and Administrative
(1)
$0.45
-
$0.55
Effective Income Tax Rate (90% deferred)
37%
-
38%
Realized Prices (% of NYMEX, before effect of hedges)
Natural Gas
97%
-
99%
Oil
92%
-
96%

62
($ in millions)
12/31/2007
Debt:
Revolver
545
           
9.125% Senior Notes
775
           
7.125% Senior Notes
275
           
Total Debt
1,595
         
Total Shareholder's Equity
2,009
         
   Total Capitalization
3,604
         
   Revolver Borrowing Base
1,000
         
   Revolver Availability
455
           
Total Liquidity
455
           
Debt / Total Capitalization
44%
EBITDA / Interest Expense
4.8x
Debt and Liquidity Review

63
Derivative Summary
Collars
50,290
         
7.05
$          
10.85
$ 
62,030
7.30
$   
10.68
$        
Swaps
12,800
         
7.96
$          
3,650
8.46
$   
3,650
$8.25
Puts
5,480
           
7.00
$          
Total Volume and Avg Price
68,570
         
7.21
$          
10.85
$ 
65,680
7.37
$   
10.68
$        
3,650
$8.25
-
$     
Collars
792
              
64.96
$        
80.26
$ 
-
              
-
       
-
             
Swaps
419
              
66.35
$        
274
             
77.00
$ 
274
                 
$75.28
Total Volume and Avg Price
1,211
           
65.44
$        
80.26
$ 
274
             
77.00
$ 
-
$           
274
                 
$75.28
-
$     
Total (Mmcfe)
75,833
       
67,323
      
5,293
           
Total (Mmcfe/d)
207.2
         
184.0
       
14.5
             
GAS
2008
Floor
Ceiling
OIL
Volume
(Bbtu)
Volume
(Mbbls)
Floor
Ceiling
2009
GAS
Volume
(Bbtu)
Floor
Ceiling
OIL
Volume
(Mbbls)
Floor
Ceiling
2010
GAS
Volume (Bbtu)
Floor
Ceiling
OIL
Volume
(Mbbls)
Floor
Ceiling
Collars
12,720
$7.50
$12.32
6,350
$6.72
$8.61
11,000
$6.84
$9.30
20,220
$6.97
$11.16
16,200
$7.85
$11.68
15,470
$7.00
$9.85
16,560
$7.00
$10.31
13,800
$7.37
$10.90
Swaps
910
$8.25
6,370
$7.85
4,600
$8.00
920
$8.25
900
$8.46
910
$8.46
920
$8.46
920
$8.46
Puts
3,640
$7.00
1,840
$7.00
Total Volume and Avg Price
13,630
$7.55
$12.32
16,360
$7.22
$8.61
17,440
$7.16
$9.30
21,140
$7.03
$11.16
17,100
$7.88
$11.68
16,380
$7.08
$9.85
17,480
$7.08
$10.31
14,720
$7.43
$10.90
Collars
197
         
$64.95
$80.24
197
         
$64.95
$80.24
199
         
$64.97
$80.27
199
         
$64.97
$80.27
-
          
-
       
-
       
-
          
-
       
-
       
-
          
-
       
-
       
-
          
-
       
-
       
Swaps
104
         
$66.29
104
         
$66.29
105
         
$66.40
105
         
$66.40
68
           
$77.00
68
           
$77.00
69
           
$77.00
69
           
$77.00
Total Volume and Avg Price
301
         
$65.41
$80.24
301
         
$65.41
$80.24
304
         
$65.47
$80.27
304
         
$65.47
$80.27
68
           
$77.00
68
           
$77.00
69
           
$77.00
69
           
$77.00
Total (Mmcfe)
15,438
  
18,168
  
19,264
  
22,964
  
17,505
  
16,790
  
17,894
  
15,134
  
Total (Mmcfe/d)
171.5
    
199.6
    
209.4
    
249.6
    
194.5
    
184.5
    
194.5
    
164.5
    
Floor
Ceiling
Volume
(Mbbls)
Floor
Ceiling
Volume
(Mbbls)
Ceiling
Volume
(Mbbls)
Floor
Ceiling
Volume
(Mbbls)
Floor
Floor
Ceiling
OIL
OIL
OIL
OIL
Volume
(Bbtu)
Floor
Ceiling
Volume
(Bbtu)
Ceiling
Volume
(Bbtu)
Floor
Ceiling
Volume
(Bbtu)
Floor
Q3 2009
Q4 2009
GAS
GAS
GAS
GAS
Q1 2009
Q2 2009
OIL
Volume
(Mbbls)
Floor
Ceiling
Q4 2008
GAS
Volume
(Bbtu)
Floor
Ceiling
OIL
Volume
(Mbbls)
Floor
Ceiling
Q3 2008
GAS
Volume
(Bbtu)
Floor
Ceiling
OIL
Volume
(Mbbls)
Floor
Ceiling
Q2 2008
GAS
Volume
(Bbtu)
Floor
Ceiling
Q1 2008
GAS
Volume
(Bbtu)
Floor
Ceiling
OIL
Volume
(Mbbls)
Floor
Ceiling

64
Production Growth in Core Areas
0
50
100
150
200
250
2003
2004
2005
2006
2007
2008E
Elm Grove
Terryville
Fayetteville
81%
73%
107%
50%
57%

65
Resource Potential
Total Company
Elm Grove
Undeveloped acres: 20,000
Spacing: 20 Acres
Risked Potential: 65%
Avg
Gross Reserves: 1.3 Bcfe
Net Revenue Interest: 80%
Estimated Resource Potential: 1.5 Tcfe
Undeveloped acres: 30,000
Spacing: 60 Acres
Risked Potential: 65%
Avg
Gross Reserves: 3.0 Bcfe
Net Revenue Interest: 80%
CV / Hosston
Haynesville
Terryville
Undeveloped acres: 37,000
Spacing: 20 Acres
Risked Potential: 50%
Avg
Gross Reserves: 1.4 Bcfe
Net Revenue Interest: 80%
Estimated Resource Potential: 1.0 Tcfe
Fayetteville
Undeveloped acres: 155,000
Spacing: 60 Acres
Risked Potential: 65%
Avg
Gross Reserves: 1.6 Bcfe
Net Revenue Interest: 78%
Estimated Resource Potential: 2.0 Tcfe
+ Proved Reserves =
2.0 Tcfe
+ Proved Reserves =
1.2 Tcfe
+ Proved Reserves =
2.1 Tcfe
Estimated Resource Potential:
4.7 Tcfe
+ Proved Reserves =
5.8 Tcfe

66
Unlocking Value
Note:
Net
Asset
Value
calculated
by
allocating
$3.00
per
Mcfe
to
estimated
year
end
2007
proved
reserves
and
$1.00
per
Mcfe
to
non-proved
reserves.
Petrohawk
has a rich inventory of development and
exploration opportunities
We will continue to pursue the right strategies for
growth, and will be active in the exploration and
expansion of our current resource potential
Petrohawk’s
implied NAV is over $32 per share
We have only begun to realize the value of our 5.8 Tcfe
of reserves and risked upside potential

ANALYST DAY 2008