EX-99.2 3 dex992.htm PRESENTATION Presentation
1099 18  
Street, Suite 2300    Denver, Colorado 80202
303.312.8155, fax 303.291.0420     www.billbarrettcorp.com   
NYSE: BBG
Investor Relations contact:   Jennifer Martin    jmartin@billbarrettcorp.com
A Premier Rocky Mountain E&P Company
Piceance Basin, Colorado
August 11, 2008
Fred Barrett
Chairman & CEO
Fred Barrett
Chairman & CEO
Exhibit 99. 2
th

Forward –
Looking and Other Cautionary Statements
FORWARD LOOKING STATEMENTS -
Except for the historical information contained herein, the matters discussed in this presentation are forward-looking
statements.  These forward-looking statements reflect our current views with respect to future events, based on what we believe are reasonable assumptions.
These statements, however, are subject to risks and uncertainties that could cause actual results to differ materially including, among other things, exploration
results, market conditions, oil and gas price levels and volatility, the availability and cost of services, drilling rigs, transportation and processing, the ability to
obtain industry partners to jointly explore certain prospects, uncertainties inherent in oil and gas production operations and estimating reserves, unexpected
future capital expenditures, competition, the success of our risk management activities, governmental regulations, the ability to obtain necessary permits,
delays or prohibitions due to litigation or other disputes, and other factors discussed in our filings with the Securities and Exchange Commission (“SEC”).  We
refer
you
to
the
“Cautionary
Note
Regarding
Forward-Looking
Statements”
and
“Risk
Factors”
sections
of
these
filings.
In
addition,
historical
information
may not be indicative of future results.
Certain
information
in
this
presentation
references
“current”
or
“currently”,
which
means
on
or
about
June
30,
2008
or
as
indicated.
Bill
Barrett
Corporation assumes no obligation to revise or update the contents of this presentation.
RESERVE & RESOURCE DISCLOSURE -
The SEC permits oil and gas companies, in their filings with the SEC, to disclose only  proved reserves that a
company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and
operation conditions. Bill Barrett Corporation may use certain terms in this presentation and other communications relating to reserves and production that the
SEC’s
guidelines
strictly
prohibit  the
Company
from
including
in
filings
with
the
SEC.
It
is
recommended
that
U.S.
investors
closely
consider
the
Company’s disclosures
in
Bill
Barrett
Corporation’s Form
10-K
for
the
year
ended
December
31,
2007
filed
with
the
SEC.
This
document 
is
available
through
the
SEC
by calling 1-800-SEC-0330 (U.S.) and on the SEC and Bill Barrett
Corporation
websites
at
www.sec.gov
and
www.billbarrettcorp.com,
respectively.
DISCRETIONARY CASH FLOW -
is computed as net income plus depreciation, depletion, amortization and impairment expenses, deferred income taxes,
exploration expenses, non-cash stock based compensation, losses (gains) on sale of properties, and certain other non-cash charges. The non-GAAP
measure of discretionary cash flow is presented because management believes that it provides useful additional information to investors for analysis of the
Company's ability to internally generate funds for exploration, development and acquisitions. In addition, discretionary cash flow is widely used by
professional
research
analysts
and
others
in
the
valuation,
comparison
and
investment
recommendations
of
companies
in
the
oil
and gas exploration and
production
industry,
and
many
investors
use
the
published
research
of
industry research
analysts
in
making
investment
decisions.
Discretionary cash
flow
should  not
be
considered
in
isolation
or
as
a
substitute
for
net
income,
income
from
operations,
net
cash
provided
by
operating
activities
or
other
income, profitability, cash flow or liquidity measures prepared in accordance with accounting principles generally accepted in the United States of
America ("GAAP"). Because discretionary cash
flow excludes some, but
not all, items that affect net income and net cash provided by operating activities
and may vary among companies,
the
discretionary
cash
flow
amounts
presented
may
not
be
comparable
to
similarly
titled
measures 
of
other
companies.
FINDING & DEVELOPMENT COST –
is a non-GAAP metric commonly used in the exploration and production industry. Calculations presented by the
Company
are
based
on
costs
incurred,
as
adjusted
by
the
Company,
divided
by
reserve
additions.
Reconciliation
of
adjustments
to
costs
incurred
is
provided in the Company’s earnings release and Form 8-K issued February 26, 2008.

3
Reasons to Invest in BBG
Reasons to Invest in BBG
•
Track Record of Growth:
Double-digit proved reserve and production growth
•
Visible Development Growth:
Multi-year, low risk development inventory managed with operational excellence
•
World Class Exploration Portfolio:
•
Track record of discoveries with 4-5 delineation programs
•
Testing multiple, new, high potential prospects in 2008
•
Technology:
Leader in utilization of technology
•
Financial Strength:
Strong balance sheet and hedge position that provides flexibility to grow
•
$172.5 million Convertible Note and $467 million borrowing base on bank line

4
Management’s Track Record of Growth
Management’s Track Record of Growth
Net Production
18.3
31.7
52.1
39.4
61.2
2005
2004
2003
2006
2007
2008E
(Bcfe)
80
77
77
Dec
2002
Dec
2003
Dec
2004
292
119
204
Net Proved Reserves
341
Dec
2005
Dec
2006
428
Reserve replacement ratio
386%
226%
280%
558
Dec
2007
(Bcfe)
382%
(adjusted for property sales)
Discretionary Cash Flow*
$5
$102
$195
$38
$239
*
Non-GAAP measure (see slide 2)
($mm)
$249
2002
2004
2005
2003
2006
2007
Net Income
($mm)
$24
-
$5
-
$4
$62
2004
2005
2003
2006
2007
$27
2006 includes $31 million (pre-tax) in gains on sale of properties
$222
2008
YTD
$65
2008
YTD

5
Visible Double-digit Production Growth
Development –
Piceance, West Tavaputs, CBM
Visible Double-digit Production Growth
Development –
Piceance, West Tavaputs, CBM
224
Wells
Drilled
(Gross)
Development
107
Delineation
7
Exploration
11
CBM
99
314 Wells Drilled
(Gross)
Development
125
Delineation
10
Exploration
4
CBM
175
323 Wells Drilled
(Gross)
Development
122
Delineation
5
Exploration
14
CBM
182
0
20
40
60
80
2005
2006
2007
2008 E
39.4
39.4
52.1
52.1
61.2
61.2
77
77
80
~447 Wells Planned
(Gross)
Development
193
Delineation
14
Exploration
10
CBM
230
•
Seek 20%+ continued compound production growth
•
400-500 wells/year with existing inventory going forward

6
Strong Resource Base
to Generate Reserve Growth
Strong Resource Base
to Generate Reserve Growth
*
as of June 2008
558 Bcfe
Proved
558 Bcfe
Proved
2.8 Tcfe*
3P Resources
2.8 Tcfe*
3P Resources
1.6 Tcfe
Increased
Density
1.6 Tcfe
Increased
Density
0.6 Tcfe
Other
Probable
& Possible
0.6 Tcfe
Other
Probable
& Possible
2.8 Tcfe*
3P Resources
2.8 Tcfe*
3P Resources
8-10 Tcfe
Unrisked
Potential
8-10 Tcfe
Unrisked
Potential

7
Capital Expenditures
Capital Expenditures
Exploration
10%  +/-
Exploration
10%  +/-
Development
80%
Development
80%
Delineation
10%  +/-
Delineation
10%  +/-
Piceance
40%
Piceance
40%
Uinta
33%
Uinta
33%
WRB 5%
Exploration
& Other 15%
PRB 7%
2005
2006
2007
2008E
$347
$347
$385
$385
$49
$444
$444
$625-
650
$625-
650
F&D
($/Mcfe)
$3.67
$3.67
$2.80
$2.80
$1.83
$1.83
2005
2006
2007
CH4 acquisition (PRB), net of subsequent divestiture and non-cash deferred tax liability
Base Capex
Capex
(Millions)
2008 CAPEX
$625 –
$650 million est.

8
Natural Gas Hedges Protect Cash Flow
Natural Gas Hedges Protect Cash Flow
•
Hedge 50% -
70% of
production on a forward
12-month basis
•
Hedge natural gas
through basis
•
Approximately 70% of
2H08 production hedged
–
51% swaps
–
19% collars
•
60 Bcfe hedged 2009
•
44 Bcfe hedged 2010
As of July 31, 2008
Daily Natural Gas Production Hedged with Associated Pricing
$5.00
$6.00
$7.00
$8.00
$9.00
$10.00
$11.00
$12.00
Jan-08
Apr-08
Jul-08
Oct-08
Jan-09
Apr-09
Jul-09
Oct-09
Jan-10
Apr-10
Jul-10
Oct-10
Jan-11
Apr-11
Jul-11
Oct-11
0
20
40
60
80
100
120
140
160
180
200
220
Swapped Volume
(MMBtu/d)
Collared Volume
(MMBtu/d)
Collar Floor
($/MMBtu)
Collar Ceiling
($/MMBtu)
Swap Price
($/MMBtu)

9
Visible Development Growth
Visible Development Growth
Powder River
Basin
Piceance
Basin
Wind River Basin
West Tavaputs
Gas Prone Area
Oil Prone Area
Development Project
CBM
Big George
Gibson Gulch
Lower Risk, Repeatable,
High Quality ROR Inventory
•
95%+ natural gas
•
97% operated –
increases
control
•
94% average working interest –
concentrates staff resources
•
Visibility for 20+% CAGR in
production going forward
Uinta Basin
558
Bcfe
Proved
558
Bcfe
Proved
2.8 Tcfe*
3P Resources
2.8 Tcfe*
3P Resources
2.0 Tcfe
Development
Projects
2.0 Tcfe
Development
Projects
*as of June 2008
0.2
Tcfe
0.2
Tcfe

10
Prickly
Pear
Structure
Dry Canyon
Compressor site
Peters
Point
Structure
•
Proved reserves: 238 Bcfe (shallow and deep) (12/07)
•
Net production 63 MMcfe/d (shallow and deep) (07/08)
•
39,700 net acres; 27,300 net undeveloped acres (03/08)
•
97% working interest
•
3 Rigs -
post winter stips
(shallow)
•
EIS in process, record of decision expected 4Q08
•
3P resources 1.4 Tcfe, low risk (shallow &
deep)
•
750 –
800 drilling locations
•
Deep: 6 producing wells
•
Upside: Expansion of deep & Mancos shale
Uinta Basin –
West Tavaputs
Shallow
–
Wasatch,
Mesaverde;
Deep
–
Navajo,
Entrada,
Dakota
–
Utah
Uinta Basin –
West Tavaputs
Shallow
–
Wasatch,
Mesaverde;
Deep
–
Navajo,
Entrada,
Dakota
–
Utah
UT
Uinta
Basin
Scale:
640ac
=
1
Mile
Questar interconnect
CURRENT STATUS
PROGRAM POTENTIAL
Interplanetary
compressor site
Questar interconnect
BBC Acreage
Gas Well
Existing Pipeline
Proposed Pipeline

11
2
1
As of Aug. 1, 2008, Rockies 3-year strip price averaged $6.75/MMBtu.
2
For illustrative purposes only, does not represent formal guidance
(See “Forward-Looking
and Other Cautionary Statements”
on slide
2)
EUR (gross)
NRI
EUR (net)
Drilling
Completion
Total
Incremental D&C costs (per Mcfe)
Gas Price 
MMBtu/ sales adjustment
Realized Price (per Mcfe)
Production taxes
Gross margin (cash flow)
ROR
CIG Gas Price Required 10% ROR
Bcfe
2.5
83%
2.1
$1.0
2.2
$3.2
$1.55
$ 6.75
0.38
$ 7.13
(0.85)
(0.39)
$ 5.89
46%
$ 3.90
$mm
Uinta Basin -
West Tavaputs
Shallow
–
Wasatch, Mesaverde
-
Utah
Uinta Basin -
West Tavaputs
Shallow
–
Wasatch, Mesaverde
-
Utah
ILLUSTRATIVE DRILLING &
COMPLETION COSTS
ILLUSTRATIVE
ECONOMICS
0%
20%
40%
60%
80%
100%
120%
$3.90
$4.90
$5.90
$6.90
$7.90
$8.90
CIG Price - $/Mmbtu
Typical Well Price Sensitivity
Peters Point 6-7D production site
2
LOE,
Gathering
&
Transportation
1

12
0
25
50
75
100
125
150
175
200
Uinta Basin –
West Tavaputs
Uinta Basin –
West Tavaputs
PRODUCTION
Note:  Wells drilled include both shallow and deep
2005
2006
2007
2008
2010
2009
Wells Drilled
16 Wells
30 Wells
36 Wells
~60 Wells
~75 Wells
~75 Wells
Estimated
record of
decision on
EIS 4Q08
2008 exit rate
estimated at
92 MMcfe/d net

13
Piceance Basin –
Gibson Gulch
Williams
Fork
–
Colorado
Piceance Basin –
Gibson Gulch
Williams
Fork
–
Colorado
Silt
3-Component
3-D Seismic
CO
Piceance
Basin
CURRENT STATUS
PROGRAM POTENTIAL
•
3P resources 869 Bcfe
•
900-960 drilling locations (10-acre density)
•
Developing on 10-acre density
•
Plan to drill 100+ wells/year
•
Proved reserves:  212 Bcfe (12/07)
•
Net production:  86 MMcfe/d   (07/08)
•
16,400 net acres; 12,200 net undeveloped
acres (03/08)
•
93% working interest
•
Four rigs operating; adding fifth Aug. ‘08
BBC acreage
BBC operated gas well
BBC
non-operated
gas
well
Non-operated gas well
10 acre pilots

14
Historical Drilling Days, Well Reserves and D&C Costs
Piceance Basin
–
Gibson Gulch
Historical Drilling Days, Well Reserves and D&C Costs
Piceance Basin
–
Gibson Gulch
726
1300
1250
2005
2006
2007
Estimated Ultimate Recovery, Gross
(MMcfe)
$1.36
$2.56
$1.58
2005
2006
2007
Incremental D&C Costs,  Gross
($ per Mcfe)
10.8
11.2
12.4
13.9
2005
2006
2007
2008
YTD
Days Drilling
(per well)
1440
$1.51

15
1
As of Aug. 1, 2008, Rockies 3-year strip price averaged $6.75/MMBtu.
2
For illustrative purposes only, does not represent formal guidance
(See
“Forward-Looking
and
Other
Cautionary
Statements”
on
slide
2)
$  6.75
0.90
$  7.65
(0.97)
(0.43)
$
6.25  
EUR (gross) 
NRI
EUR (net)
Drilling
Completion
Total
Incremental D&C costs (per Mcfe)
Gas Price
MMBtu/ sales adjustment
Realized Price (per Mcfe)
LOE, Gathering & Transportation
Production taxes
Gross margin (cash flow)
ROR
CIG Price Required 10% ROR
Bcfe
1.3
81%
1.0+
$ 0.7
1.4
$ 2.1   
$ 2.09
$mm
Piceance Basin -
Gibson Gulch
Williams
Fork
-
Colorado
Piceance Basin -
Gibson Gulch
Williams
Fork
-
Colorado
ILLUSTRATIVE DRILLING
AND COMPLETION COSTS
32%
$  4.95
ILLUSTRATIVE ECONOMICS
0%
20%
40%
60%
80%
100%
120%
$4.95
$5.95
$6.95
$7.95
$8.95
$9.95
CIG Price - $/Mmbtu
Typical Well Price Sensitivity
Production wells on Specialty site
2
1

16
0
25
50
75
100
125
150
175
PRODUCTION
80 Wells
68 Wells
100 Wells
~130 Wells
~110 Wells
Wells Drilled
~110 Wells
2005
2006
2007
2008
2009
2010
Piceance Basin –
Gibson Gulch
Piceance Basin –
Gibson Gulch
Production
shut in due to
low Rockies
prices
2008 exit rate
estimate at 100
MMcfe/d net

17
•
3P Resources 180 Bcfe
•
800-850 gross drilling locations
•
Further infrastructure improvements
in 2H ‘08
•
Proved reserves: 48 Bcfe (12/07)
•
Net production: 20 MMcfe/d (07/08),
constrained by compression capacity
•
129,800 net acres, 82,200 net
undeveloped acres (03/08)
•
Low-risk, high return
drilling, Big George coals
Powder River Basin –
CBM
Big
George
Coal
–
Wyoming
Powder River Basin –
CBM
Big
George
Coal
–
Wyoming
CURRENT STATUS
PROGRAM POTENTIAL
Deadhorse
Willow
Creek
Palmtree
BIG
GEORGE
PLAY
Gillette, WY
Gillette, WY
Tuit
Tuit
Pumpkin
Creek
Hartzog
Draw
Pine Tree
Cat
Creek
Porcupine
Porcupine
SCALE
1 Township
= 36 sq mi
SCALE
1 Township
= 36 sq mi
BBC Acreage
Gas Producing Area
Dewatering
MT
WY
Powder River
Basin

18
EUR
(gross)
–
operated
EUR (net), 81% NRI
Drilling
Completion
Total
Incremental D&C costs/Mcfe
Bcfe
0.34
0.28
$    85
200
$  285
$ 1.02
(ranges
from
0.15
–
0.8)
$1000s
Powder River Basin –
CBM
Big George Coal -
Wyoming
Powder River Basin –
CBM
Big George Coal -
Wyoming
ILLUSTRATIVE DRILLING AND
COMPLETION COSTS
Gas Price 
MMBtu/ sales adjustment
Realized Price (per Mcfe)
LOE, Gathering & Transportation
Production taxes
Gross margin (cash flow)
ROR
CIG Price Required 10% ROR
$
6.75 
(0.11)
$
6.64
(2.70)
(0.84)
$
3.10
31%
$
4.25
ILLUSTRATIVE
ECONOMICS  
Production equipment on Pine Tree site
0%
10%
20%
30%
40%
50%
60%
70%
$4.25
$6.25
$8.25
$10.25
$12.25
CIG Price - $/Mmbtu
Typical Well Price Sensitivity
1
As of Aug. 1, 2008, Rockies 3-year strip price averaged $6.75/MMBtu.
2
For illustrative purposes only, does not represent formal guidance
(See
“Forward-Looking
and
Other
Cautionary
Statements”
on
slide
2)
2
1

19
-
10
20
30
40
50
60
70
PRODUCTION
Powder River Basin –
CBM
Powder River Basin –
CBM
2005
2006
2007
2008
2009
2010
182 Wells
99 Wells
195 Wells
230 Wells
~230 Wells
Wells Drilled
Production
constrained
due
to
3 
party
gathering
system
~230 Wells
2008 exit rate
estimate at
24 MMcfe/d net
rd

20
Cooper
Reservoir
Field
Wind River Basin –
Cave Gulch / Bullfrog Fields
Frontier,
Muddy,
Lakota
–
Wyoming
Wind River Basin –
Cave Gulch / Bullfrog Fields
Frontier,
Muddy,
Lakota
–
Wyoming
Potential Future Deep Loc.
Historical Deep Producers
Deep Gas Show Well
Deep Structural Axes
•
Proved reserves: 54 Bcfe (12/07)
(Wind River total)
•
Net production: 24 MMcfe/d (07/08)
•
WI: 50-100%
•
22,000 net undeveloped acres (03/08)
•
Bullfrog 14-18; 23 MMcfe/d (68% NRI),
successful Frontier recompletion (05/08)
•
Earlier BBC discoveries: Muddy
& Lakota IPs 4-20 MMcfe/d
•
Up to 3 wells in 2008, partially promoted
•
Up to 30 deep locations
•
IP: 5-20 MMcf/d per well
•
EUR: 6-8+ Bcfe gross per well
•
High impact, high volume deep
wells
CURRENT STATUS
PROGRAM POTENTIAL
Waltman
Field
SCALE
640 ac =
1 Sq Mile
Drilling 31-32
Targeting Frontier,
Muddy, Lakota
TD to ~19,000’
Cave Gulch
Field
Bullfrog 33-19
Recompletion in progress
Bullfrog 14-18
Frontier recompletion (2/08)
Current
rate:
23
MMcf/d
gross
WYOMING
Wind River Basin
Cave Gulch Field looking northwest

Denver, CO
Big Horn
Basin
Powder River
Basin
Green
River
Basin
Piceance
Basin
Paradox
Basin
Williston Basin
DJ Basin
Wind River
Basin
Uinta
Basin
World Class Exploration Portfolio
World Class Exploration Portfolio
Discovery / 2008 delineation
W. Tavaputs
deep
Lake Canyon/
Blacktail Ridge
Yellow Jacket 
Planned exploration drilling
within 12 months
Pine Ridge
Red Point
MT Overthrust-
Circus
Hook
Green Jacket
Exposure
•
1.1 million net undeveloped acres
•
Established track record discoveries
(red stars) in delineation phase
•
Multiple, large scale, resource plays testing
in 2008 (black circles)
Current Activity:
•
Yellow Jacket: Testing Horizontal
Gothic Shale
•
Lake
Canyon/BTR:
Drilling
13
well
•
Circus: Drilling 4th Cody shale gas test
•
Hook:
Drilling
Manning
Canyon
Shale
Gas
test
Upcoming
Activity:
•
Pine Ridge: drill Salt Flank Q3
•
Green Jacket: Hovenweep shale gas
test Q3
•
Big Horn Red Point: Basin Centered
test Q4
•
Hook:
possible
Ferron
shale
gas
test
Q4
th
Waltman Arch
Cave Gulch deep
Cooper deep
Wallace Creek CBM

22
10 –
25 Miles
Yellow Jacket Shale Gas Prospect
Gothic
Shale
–
Colorado
Yellow Jacket Shale Gas Prospect
Gothic
Shale
–
Colorado
UT
CO
Paradox
Basin
•
Expansive project area
•
Shallow
depths:
5,500’
–
7,500’
TDs
•
Estimated
Gothic
shale
thickness:
80’
–
150’
•
Encouraging gas contents and shale composition
•
Additional shale gas potential in Green Jacket
(Hovenweep)
PROGRAM POTENTIAL
•
55 -
100% working interest (operated)
•
216,000 net undeveloped acres (03/08)
•
Potential pay zones: Hovenweep and Gothic Shale
•
3 exploratory science wells drilled in late 2006/2007:
regional placement, varying frac technologies
•
Successfully completed first horizontal well,
2,900’
lateral, 6 stages currently testing
CURRENT STATUS
Core sample
To quantify presence of gas
Well #1
250
-
600
Mcfd
Well #3
50 -
100 Mcfd
Well #2
To be plugged
(casing design/stimulation)
UT
CO
Gothic shale
1,850 sq mi
Hovenweep
shale
1,300 sq mi
Regional Play Concept Map
Horizontal
Koskie
TD 9,125
Testing

23
Blacktail Ridge / Lake Canyon
Wasatch –
Utah
Blacktail Ridge / Lake Canyon
Wasatch –
Utah
•
Multi-pay fractured oil project with significant gas
component
•
Assessing step-out drilling, shallower pays, deeper pays
and infill drilling
•
Applying modern evaluation tools to a late 1970s aged
field
•
TDs 4,000’
to 11,000’
PROGRAM POTENTIAL
•
Net acres: control a minimum of 167,000
depending on 3rd party elections
•
10 producing wells, more than 950 Bopd
•
2008 activity –
up to 11 wells in Blacktail,
5 wells in Lake Canyon. 1 rig currently 
•
50 sq miles of 3-D seismic
CURRENT STATUS
Monument Butte
Brundage Canyon
47 MMBOE CUM
UT
Uinta
Basin
EXTENSION
STRATEGY
Lake Canyon
SCALE
1 Township
= 36 sq mi
Blacktail  Ridge
Duchesne
Altamont/Bluebell
379 MMBOE CUM
High gas area
INFILL
STRATEGY
BBC acreage
BBC oil well
BBC upcoming drilling locations
Testing or WOCT
Drainage ellipses on existing wells
Known field areas
Blacktail Ridge acreage position not shown for competitive reasons
1-5-
45 BTR
WOCT
14-7-
46 BTR
WOCT
Recent infill well
5-21-36 BTR
Testing
7-20-
46 DLB
Exploratory well
Producing 120 Bopd
after 135 days
Recent infill well
5-23-36 BTR
Testing

24
Montana
Overthrust –Circus & Toston-Six Mile Areas
Structural and Cody Shale Gas Play
Montana
Overthrust –Circus & Toston-Six Mile Areas
Structural and Cody Shale Gas Play
•
50% working interest (operated)
•
164,000 net  undeveloped acres (03/08)
•
Upper
Cretaceous
Cody
Shale
~3,000’
–
7,000’
•
Cody
Thickness:
900’
-
2,000’
•
Drilled 3 of 4 planned wells in 2008 to test Cody
shale. Coring 2 wells extensively.
•
Toston
3-D being interpreted
•
Wide-spread shale gas potential in Cody Shale
•
Continue to assess future deep structural potential
Scale in Miles
0
6
Toston-Six Mile
Circus
Wolverine
Discovery
Covenant Field
Denver, CO
Powder
River
Basin
Green
River
Basin
Uinta
Basin
Piceance
Basin
Paradox
Basin
Williston Basin
DJ Basin
Wind River
Basin
San Juan
Basin
Big Horn
Basin
Circus
164,000 Net
Undeveloped
Acres
Wyoming
Overthrust
EUR: 10+ Tcfe
Canadian Overthrust
EUR: 20+ Tcfe
74 sq. mi. 3-D
150+ sq. mi. 3-D
CURRENT STATUS
PROGRAM POTENTIAL
Leviathan
TD 11,005’; dry gas
production from Cody
Shale, continue testing
Draco 10–15
TD 12,441’; dry gas
production from Cody
Shale 250+ Mcf/d
BBC Acreage
Upcoming BBC Cody shale location
Dry with Oil Show
Dry with Gas Show
Thrust Fault
Structural Axes
Robinson Ranch
8-3;
WOC
Swandal
Ranch
14-26
To
spud
late
Aug.
Bodine-Williams
7–28; WOC
Pulis
7–15
WOC

25
Key Catalysts Going Forward
Key Catalysts Going Forward
•
Next several years is about execution, efficiency and exposure
•
Development growth visibility: low risk, multi-year
–
Proven increased density: W. Tavaputs, Piceance
–
West Tavaputs EIS: 4Q2008
–
Potential to more than double size of company next several years
•
Exploration exposure to multi-TCF upside
–
Multiple discoveries: ongoing delineation programs
–
Multiple new exploration programs on tap 2008
–
One of largest net undeveloped Rockies positions
•
Rockies Express takeaway capacity
–
Future takeaway capacity planned
•
Excellent financial position to execute

Circus, Montana Overthrust, Montana

APPENDIX

28
Visible Development Growth
Visible Development Growth
~437-
464
225 -
235
130 -135
58 -
63
2008
Wells
Planned
Powder
River
Piceance
Uinta
Basin
Rapid growth post-dewatering
phase in deep Big George and
with increased takeaway
capacity
800-850
48
CBM
Planning basis is 10-acre
density; technology leader with
“super fracs”
900-960
212
Gibson Gulch
2,450+
485
Subtotal -
Development
Planning basis is on 40-acre
and 20-acre density
750-800
225
West Tavaputs shallow –
(Peters Point and Prickly
Pear)
Comment
Drilling
Inventory
(gross
wells)
Proved
Reserves
(Bcfe)
Area
•
Large resource base –
multiple gas
manufacturing plays
•
Multi-year drilling inventory
•
Low-risk reserve and production
growth
•
Further upside and efficiencies
THREE KEY AREAS

29
Upside from Active Delineation
Upside from Active Delineation
Successfully recompleted Frontier in Bullfrog
14-18; signed up partners; drilling deep 31-32, 
current production net 23 MMcfe/d; exploration
–
deep only
Drill up to 2 horizontal and up to 2 vertical wells
in 2008; includes sister shale play at Green
Jacket
Delineation project; increased potential in
deep, Mancos, west structure
Delineation project, multi-pay oil w/ gas; in 2008
will drill up to 11 wells in Blacktail, 5 wells
in Lake Canyon; includes 119,000 acres
subject to drill-to-earn agreements
Comment
Net
undeveloped
acreage
Wells
planned ‘08
(gross wells)
Area
Basin
22,000
2
Cave Gulch / Bullfrog / 
Cooper (structural)
Wind River
216,000
2-4
Yellow Jacket
(shale gas play)
Paradox
27,000
0
West Tavaputs deep
(structural play)
Uinta
167,000
12-16
Blacktail Ridge / Lake
Canyon
(fractured oil play)
Uinta
DELINEATION
PLAYS
–
PROVING
PREVIOUS
DISCOVERIES

30
New Exploration –
High Risk, High Return Potential
New Exploration –
High Risk, High Return Potential
Completed 3-D shoot; to spud Ft. Union well
3Q08
To spud first well targeting Cutler and Honaker
Trail formations 3Q08
Sold 50% in Deep Hook shale gas play; to drill
2 wells in Manning Canyon, 1 well Shallow
Hook shale gas play; spud first well 07/08
Testing Cretaceous Cody Shale with 4 vertical
wells
Comment
Net
undeveloped
acreage
Wells
planned ‘08
(gross wells)
Area
Basin
78,000
1
Red Point and other
Big
Horn projects
(basin-centered
play)
Big Horn
30,000
1
Pine Ridge and other
projects (structural salt
flank plays)
Paradox
72,000
2-3
Hook
(shale gas play)
Uinta
164,000
4
Circus / Toston
6-mile
(structural and shale
gas play)
Montana Overthrust
NEW PROSPECTS

Export Capacity and Proposed Pipeline Expansions
Export Capacity and Proposed Pipeline Expansions
Source for expansions: Bentek Energy, May 2008
MONTANA
ARIZONA
NEW MEXICO
KANSAS
SOUTH 
DAKOTA
NEBRASKA
IDAHO
COLORADO
UTAH
WYOMING
Ruby
REX 1.5 Bcfd
+0.1 Bcfd
Jan. ‘09
+0.2 Bcfd
July ‘09
Cheyenne
Cheyenne
Meeker/
Greasewood
DJ
DJ
Uinta
Uinta
Green
River
Green
River
Big
Horn
Big
Horn
Piceance
Piceance
Williston
Williston
WRB
WRB
PRB
PRB
Paradox
Paradox
Wamsutter
Wamsutter
•
Total Current Export Capacity
including REX: 8.1 Bcfd
•
Total Proposed Additional
Capacity: 6.8 to 7.9 Bcfd
Current capacity
Proposed pipelines
or expansions to
existing pipelines
Existing pipelines
1st Quarter 2011
1200
New pipeline from Opal, WY to Malin, OR
El Paso
Ruby
Completion Timing
Capacity MMcf/d
Point to Point
Owner
Name
October 2011
1200
Wamsutter, WY to NGPL st. 109 to Chicago, IL
KMIT
Chicago Express
4th Quarter 2010
1200 -
2000
Wamsutter
to Northern Border
TransCanada
Pathfinder
4th Quarter 2010
400 -
600
Ft. Union & Big Horn gathering in Powder River to
NBPL
NBPL
Bison
3rd Quarter 2011
1200
New pipeline from Wamsutter, WY to Ventura, IA
Questar Alliance
Rockies Alliance Pipeline
4th Quarter 2010
145  
Add’l
compression added to current system
Kern River
Kern River Expansion
August 2009
June 2011
40
1200
Expand capacity from NE WY to western ND
Additional pipeline from Opal, WY to Stanfield, OR
Williston Basin Interstate
GTN NWPL
Grasslands
Sunstone
Opal
Opal
31

32
Natural Gas Hedges
Natural Gas Hedges
Natural Gas
Oil
Period
Volume
(MMBtu/d)
Price (CIG or
PEPL/MMBtu)
Volume
(Bbls/d)
Price (WTI/Bbl)
CAL 2008
35
$ 6.50/$10.00
525
$ 70.48/$ 81.62
Nov-Dec 2008
30
7.83/12.08
Jun-Dec 2008
100
90.00/160.00
CAL 2009
25
6.45/10.22
550
86.82/143.51
Jan-Mar 2009
20
8.75/12.53
Nov-Dec 2009
10
6.00/9.63
CAL 2010
300
90.00/163.00
Jan-Oct 2010
20
6.00/10.41
Apr-Oct 2010
10
7.00/11.00
Natural Gas
Oil
Period
Volume
(MMBtu/d)
Weighted
Average Swap
Price (CIG
,TCO
or PEPL/MMBtu)
Volume
(Bbls/d)
Weighted
Average Swap
Price (WTI/Bbl)
3Q08
123
$ 6.64
575
$ 73.84
4Q08
116
7.10
575
73.84
1Q09
159
7.96
375
74.41
2Q09
159
6.89
375
74.41
3Q09
159
6.89
375
74.41
4Q09
99
7.32
375
74.41
1Q10
89
7.69
--
--
2Q10
142
6.94
--
--
3Q10
142
6.94
--
--
4Q10
61
7.02
--
--

33
Price, UT
SCALE
1 Township
= 36 sq mi
Greater
Drunkards
Wash
CUM
741 Bcfe
Hook Prospect
Hook Prospect
Uinta Basin, Utah
Gas fields
Manning Canyon
show well
BBC Development Program
West Tavaputs
CUM 33 Bcfe
UT
Uinta
Basin
Shallow Hook
41,000 net undeveloped acres
Fractured “Ferron”
shale prospect
TD 1,000’
–
4,000’
CURRENT STATUS
PROGRAM POTENTIAL
•
Net undeveloped acres: 72,000 (03/08)
•
Two project types:
•
Deep
shale
gas
–
Deep
Hook
(WI
50%)
•
Shallow
shale
gas
–
Shallow
Hook
(WI
100%)
•
Multiple show wells present
•
TD’s
range from 1,000’
to 11,000’
•
Spud first well July ’08 targeting Manning Canyon
shale to 8,000’
•
Sold
50%
WI
in
“Deep
Hook”
to
ConocoPhillips
•
Drill
2
Manning
Canyon
wells
in
2008;
spud
1
well July ’08
•
Shell currently testing offset well to BBC acreage
•
Shallow
Hook
–
seeking
industry
partner
Deep Hook
2008 drilling:
50% WI in 62,000 net
undeveloped acres
1-2 wells Manning Canyon 
TD 8,000’
–
11,000’
Shell currently testing
offset to BBC lands
15-32 State
TD 8,000’
st

34
•
Net undeveloped acres: 30,000 (03/08)
Well defined acreage targets
•
Pine Ridge 21 sq. mi. 3-D acquired;
encouraged by 3-D interpretation
•
Pine Ridge exploratory test in August 2008
•
Sold WI to industry partner
Pine Ridge #1
Spud mid August, TD 10,000’
Salt Flank Prospect
Paradox Basin, Utah
Salt Flank Prospect
Paradox Basin, Utah
½
mile Fairway
•
Key show wells present
•
5 prospects assembled, building others
•
Multi-pay zones
•
8,000’
–
10,000’
TDs
•
Similar to Andy’s Mesa (~100+ Bcf)
and Double Eagle (~60+ Bcf) fields
PROGRAM POTENTIAL
CURRENT STATUS
UT
CO
Paradox
Basin

35
Denver, CO
Powder
River
Basin
Green
River
Basin
Uinta
Basin
Piceance
Basin
Paradox
Basin
DJ Basin
Wind River
Basin
San Juan
Basin
Basin Centered Gas
Gas Prone Area
Oil Prone Area
Big Horn
Basin
Rocky Mountain Basin Centered Gas
SCALE
1 Township
= 36 sq mi
Area of
Basin-Centered
Gas Play
Potential
•
Large untested region
•
50% working interest (operated)
•
78,000 net undeveloped acres
(03/08)
•
1 well in 2008
•
Potential pay zones: 
Ft.
Union
6,000’
–
11,000’
Lance
8,000’
–
14,500’,
Meeteetse
9,500’
–
16,000’,
Mesaverde
10,000’
–
17,500’
Muddy
16,000’
–
20,000’
Big Horn Basin –
Basin-Centered Gas Prospect
Wyoming
Big Horn Basin –
Basin-Centered Gas Prospect
Wyoming
BBC Acreage
Gas Field
Oil Field
Outcrop
Structural Axes
Sellers Draw #1
(1976), TD 23,081
Muddy EUR: 3.4 Bcfe
Recompleted Mesaverde;
waiting on facilities
Red Point 2007
3-D seismic
44 sq. miles
Currently interpreting
CURRENT STATUS

36
0.00
0.05
0.10
0.15
0.20
0.25
0
10
20
30
40
50
60
Months
Typical Well Production Profiles
Typical Well Production Profiles
0.0
0.5
1.0
1.5
2.0
2.5
3.0
0
10
20
30
40
50
60
Months
Typical
Shallow
Well
–
Production
Profile
West Tavaputs, Uinta Basin, Utah
0.0
0.5
1.0
1.5
2.0
2.5
0
10
20
30
40
50
60
Months
Typical Well –
Production Profile
Piceance Basin, Colorado
Powder River Basin, CBM, Wyoming
Typical
Well
–
Production
Profile
•
IP-Instantaneous,
Peak: 180 Mcf/d
•
IP-30 day Peak: 162 Mcf/d
•
EUR: 0.3 Bcfe
•
Well Life: 11 years
•
Spacing: 80 acres
•
Well Depth avg: 750’
•
IP-Instantaneous: 2300 Mcf/d
•
IP-30 day: 1800 Mcf/d
•
EUR: 1.3 Bcfe
•
Well Life: 44 years
•
Spacing: 10-acre & 20-acre
•
Well Depth avg:7,400’
•
IP-Instantaneous: 2840 Mcf/d
•
IP-30 day: 2460 Mcf/d
•
EUR: 2.5 Bcfe
•
Well Life: 34 years
•
Spacing: 40-acre
•
Well Depth avg:7,650’

1099 18    Street, Suite 2300    Denver, Colorado 80202
303.312.8155, fax 303.291.0420   
www.billbarrettcorp.com
NYSE: BBG
Investor Relations contact: Jennifer Martin   
jmartin@billbarrettcorp.com
Thank you for your interest in
th