CORPORATE
PRESENTATION
AUGUST 2015
Forward-Looking & Other Cautionary Statements
Please reference the last two pages of this presentation for important disclosures on:
 Forward-looking statements
 Non-GAAP measures
 Reserves
 Well Performance
2
Key Highlights
 Gaining operational momentum as results from extended reach lateral “XRL” program
are improving
 Latest completion design yielding improved well economics compared to previous techniques
 Have realized a 25% drop in drilling and completion costs over the fourth quarter 2014
 2015 well performance and drilling efficiency improving
 Recent well performance delivering improved results and builds confidence in future performance
expectations
 2015 production guidance was recently increased for the third time
 XRL drilling days reduced by 40% compared to earlier wells
 NE Wattenberg generating solid well economics in current environment
 Generating +25% rate-of-return at commodity price strip
 Builds a stronger production growth and cash flow outlook which strengthens financial position
 Financially well-positioned
 Excellent liquidity of $450 million, consisting of $101 million of cash and short term investments and zero
drawn on revolving credit facility
 Hedges on ~80% of 2015 oil volumes at ~$90 per bbl with favorable 2016 hedges at ~$80 per bbl
3
COMPANY
OVERVIEW
Bill Barrett Corporation Overview
 Well positioned with highly concentrated
acreage
Concentrated Asset Portfolio
 YE2014 proved reserves – 122 MMBoe
 3P reserves – 477 MMBoe
 DJ Basin provides flagship asset
 Attractive economics in current oil price environment
Uinta Oil
Future Optionality
 Projected +60% production growth in 2015; +25%
in 2016
 ~2,000 drilling locations
 Positioned to deliver strong multi-year
production growth
 Targeting 2014-2016 CAGR of ~20%
 Solid financial position
 Current liquidity of ~$450 million
BBG headquarters
 Earliest debt maturity is in 2019
5
DJ Basin
Top-Tier Economics
Delivering Strong Growth
 Bill Barrett Corp. has consistently generated strong production and reserve
growth from its core assets
 Trend expected to continue in 2015 with 90% of drilling capital dedicated to the DJ Basin
 DJ Basin is the primary component of asset portfolio
Production (MMBoe)1
Proved Reserves (MMBoe)1
6.1-6.5
6
140
27%
122
120
100
4
45%
45%
40%
55%
60%
2013
2014
80
60
2
55%
40
73%
20
0
0
2010
2011
2012
DJ
1
2013
2014
2015E
2010
2011
2012
DJ
UOP
UOP
Pro forma for previously completed asset sales and reflects recent production guidance increase for 2015; DJ Basin and Uinta Basin 2015 production is an approximate estimate based on company guidance
6
DJ Basin Provides Foundation for Growth
 NE Wattenberg proving to be a strong asset in current oil environment
 Early XRL well results have validated our conviction of the play
 Preferred completion design yielding improved well results
 Generating +25% rate-of-return at commodity price strip
 Drilling plan strengthens production growth outlook to build stronger cash
flows heading into 2016
 Annual corporate targeted production growth rate of ~20% CAGR for 2014-2016; DJ Basin oil
volumes expected to significantly grow over next several years
 2015 budget of $320 million to $350 million, includes ~35-40 XRL operated wells in NE
Wattenberg
 Excluding carryover capital, the annualized capital expenditure run-rate is expected to be
$225-$275 million, based on a 40-well XRL program in NE Wattenberg for 2016
 Capital budget for 2015 and 2016 is fully-funded
 Sources include internal cash flow, cash on hand, borrowings under revolving credit facility,
non-core asset sales
7
Capital Disciplined Approach
Production (MMBoe)1
Capital Expenditures ($mm)1
$600
8
$500
6
$400
$300
4
$200
2
$100
$0
0
2014
2015E
DJ
2016E
2014
UOP
2015E
DJ
2016E
UOP
 Prudently managed capital expenditures to adapt to a lower commodity
price environment while building a foundation for multi-year growth
 Operationally flexible to quickly adapt to changing macro-economic environment
 ~20% company production growth CAGR; ~43% DJ Basin production growth CAGR
1
Estimated capital expenditures and production volumes for 2015 and 2016 represent approximate mid-point of internal estimates incorporating ~35-40 operated XRL operated wells in 2015 and ~40 XRL
operated wells in 2016, XRL completed well cost of $6.25 mm
8
DJ BASIN
DJ Basin: Operating in our Backyard
 Large, contiguous acreage position provides
substantial running room
 98,188 total net acres in the DJ Basin
 49,359 net acres in core NE Wattenberg area
 Confidence in XRL program increasing
 Preferred completion yielding improved initial well
performance compared to early design
 NE Wattenberg provides growth driver
 2Q15 DJ Basin production up 76% YOY
 90% of 2015 capital budget targeting NE Wattenberg
 ~35-40 operated XRL wells in 2015 and ~40
operated XRL wells in 2016
 Maintain focus on total operational efficiency
to enhance economic returns
 Significantly reduced XRL well drilling days
 Targeting further cost improvements
10
Operating In the Right Basin at the Right Time
XRL program ranks fourth among all plays
BBG NE Wattenberg wells
generate 15% ROR at ~$43/bbl1
(1) Calculated for an XRL well completed with a ~9,500’ lateral, 55-stage plug-and-perf design, $6.25 mm well cost and incorporates $9/bbl long-term WTI differential
Source: Credit Suisse Equity Research Oil and Gas Primer: E&Ps, May 2015
11
DJ Basin Rate-of-Return Assumptions
700 Mboe (2-Stream) EUR with $6.25 million well cost economics
Description
Assumptions
Flat WTI
Oil Price
$/bbl
Flat HH
Gas Price
$/mmbtu
IRR
Pre-Tax
PV10
Payout
(Years)
(millions)
WTI Oil Price ($/Bbl)
$55.00
$50
$2.75
22%
$2.6
3.4
Oil Differential ($/Bbl)
($9.00)
$55
$3.00
28%
$3.5
2.9
$3.00
$60
$3.25
34%
$5.0
2.5
($0.41)
$65
$3.50
39%
$6.0
2.2
2-Stream Wellhead EUR (MBoe)
700
$70
$3.75
46%
$7.3
1.9
3-Stream Sales EUR (MBoe)
751
NYMEX Gas Price ($/MMBtu)
Gas Differential ($/MMBtu)
% Liquids (oil + NGL)
79%
NRI
85%
CAPEX/Well (millions)
$6.25
Well F&D ($/Boe)
$9.79
Pre-Tax PV10 (millions)
$3.5
IRR1
28%
Payout
(1)
(2)
3-Stream EUR – 751 Mboe2
Gas
20%
NGL
15%
Oil
65%
2.9 Years
Calculated for an XRL well completed with a ~9,500’ lateral, 55-stage plug-and-perf design, $6.25 mm well cost; liquids yield estimated to be ~84% in the first year and ~79% over the life of the well
EUR based on internal Company estimates derived from company and peer drilling results; first year oil recovery estimated to be ~20% of EUR
12
XRL Evolution Completed
DJ Basin development moves from 640-acre to 1,280-acre spacing
(Gross operated wells spud by year)
2013
2014
61
64
640
640




No XRLs drilled in 2013
15-18 stages
All completed using swell
packers and sliding sleeves
Averaged 600-800 lbs sand
per lateral foot
2015E
35-40
1,120
1,280
 40 stages transitioned to 55 stages by year end
 Sleeves transitioned to Plug n’ Perf Technology
 <1,000lbs sand per foot transitioned to >1,000lbs
sand per foot
 Transitioned from <9,000 laterals to >9,000 foot
laterals by year end yielding improved results
1,280




55 stages
Plug n’ Perf Technology
~9,500’ laterals
1,000+lbs sand per foot
Competitive advantage: ~80% of NE Wattenberg acreage can be developed with XRLs
(NE Wattenberg 3P Undeveloped Locations)
2013
100% 640
640
2014
2015E
75% 1,280
~80% 1,280
640
1,280
640
1,280
Reconfiguring inventory to optimize XRL drilling
13
NE Wattenberg Provides a Strategic Advantage
 Concentrated acreage position allows for
efficient and economic development
NE Wattenberg – 49,359 net acres
 1,100 identified drilling locations
 ~80% of acreage can be developed with XRL wells in
1,280-acre spacing unit
 +25% ROR at commodity price strip
 Ability to efficiently manage capital
program
 Maintain operational flexibility with no long-term drilling
rig contracts
4 XRL wells begin
initial sales in August
4 XRL wells begin
initial sales in July
 Generating greater capital efficiency gains through
40% faster drilling times
 XRL drilling program delivering very
good early-stage performance
10 XRL wells begin
initial sales in June
 Preferred completion technique with controlled flow back
leading to shallower initial declines
 Initial production data validating performance
assumptions
BBG horizontal wells (through 2Q15)
2015 planned XRL wells
14
Building Growth Platform
…but able to generate a
meaningful growth profile
Adapted to a changing macro
environment by reducing capital…
DJ Basin Production (MMBoe)1
DJ Basin Capital Expenditures ($mm)1
6
$500
$400
4
$300
$200
2
$100
0
$0
2014
1
2015E
2013
2016E
2014
2015E
2016E
Estimated capital expenditures and production volumes represent approximate mid-point of internal estimates incorporating ~35-40 XRL well drilling program for 2015 and ~40 XRL well drilling program in 2016
15
Plug-and-Perf Completions Yielding Improved Production Profile
 Enhanced design proving to be a game
changer
1,000
 ~9,500’ lateral completed with plug-and-perf

Tighter perf intervals – 60’ vs. 240’
 >1,000 lbs of sand per foot vs. <1,000 lbs of sand per foot
 Controlled flow back resulting in similar early rates and
shallower production declines
Avg. Daily Oil Rate (boe/d)
~46% increase in performance
through initial 8 months
 55-stages (three perf intervals) vs. 40-stages (one perf
interval)
100
XRL 55-Stage w/PnP (4 wells)
XRL 40-Stage w/Sliding Sleeves (12 wells)
Early Design - 40-stage Sliding Sleeve
10
1
2
3
4
5
6
7
8
9
Month
 Plug-and-Perf exhibiting improved
initial rates; shallower decline
Enhanced Design - 55-stage Plug-and-Perf
 30-day avg. = 649 Boe/d (peak oil month)
 60-day avg. = 615 Boe/d
 90-day avg. = 580 Boe/d
* Graphic representation of a 55-stage plug-and-perf completion design compared to a 40-stage sliding sleeve completion design
16
Enhancing Cost Efficiencies
Building Efficiencies Through
Longer Laterals
XRL D&C Costs Down 25%*
$9
$300
$8.25 mm
$8
Targeting 5-10% additional
cost reduction
$250
$7
(Drilling Cost/Lateral Foot)
$6.25 mm
(millions)
$6
$5
$4
$3
$200
$150
XRL well drilling days
reduced by 40% to 10days/well , “best-in-class”
well drilled in 8 days
$100
$2
$50
$1
$0
$0
2014
Drilling
Completions
2013
2015E
640
Facilities
* Based on current actual well cost of $6.25 mm for an XRL well with ~9,500’ lateral, 55-stage plug-and-perf, 1,000 lbs sand/foot
17
2014
1,120
1,280
2015E
Increasing Geologic Confidence
 Continue to refine reservoir and resource
understanding in the Niobrara A, B, C, Codell
and Greenhorn utilizing most recently
acquired core data
Prospective for up to Six Stacked Pay Zones
BBG – CB Rudd Core Well
Niobrara A
 Initial Codell tests have been drilled on
western most acreage position. Additional
delineation opportunities to the east
Niobrara B
Niobrara C
Codell
 Niobrara “A” Chalk prospective under
northern acreage
Bridge Creek Ls - Greenhorn

Initial well drilled with completion scheduled
to begin shortly
Lincoln Ls - Greenhorn
 Two potential additional targets in the
Greenhorn – Bridge Creek and Lincoln
Limestone
18
NE Wattenberg Generalized Development Spacing*
* Graphic representation of the expected 1,280-acre development pattern of the NE Wattenberg acreage; actual development may differ
19
UINTA OIL
PROGRAM
Uinta Oil Program
Wasatch, Green River Formations
Large, Scalable Program: 165,000+ net acres*

2,300 feet stacked play prospective for the Green
River and Wasatch formations
South Altamont
21,613 net acres

50+ rig year inventory

Production: 5,300 Boe/d (2Q15)

Wax crude postings, as a deduct from WTI are
averaging $8.75/bbl

YE 2014 Proved reserves: 48 MMBoe; 3P
reserves: 151 MMBoe

10 Miles
2015 plans are to drill 7 wells in East Bluebell and
8 obligation wells in Black Tail Ridge
21
East Bluebell
24,365 net acres
BTR/Lake Canyon
Gas
Production
net
acres
BBG
106,167*
Acreage
* Includes additional acreage that can be
earned through drilling
Oil Production
BBG acreage
Core and Reservoir Characterization Program
TGR3
Green River

Continue refinement of reservoir and
resource understanding in the Lower Green
River Formation pay intervals
Douglas
Creek
FD State 10-36D
BBG cored 2 wells in the TGR3, Douglas
Creek, Castle Peak and Uteland Butte pay
intervals

FD State 10-36D: cut 463 ft. core, Lower Green River

Aurora 3-32D: cut 411 ft. core, Lower Green River
3 Point Mrkr
Core

Core
East Bluebell: Increasing Technical Understanding
 Core processing and evaluation underway
Micro seismic and Completions
Aurora 3-32D
 Two wells to be monitored with micro seismic
during completions utilizing different
fracturing techniques (Slick Water and Hybrid
Gel/Slick Wtr)
22
Black Shale
Castle Peak
Uteland Butte
Core
 40-Acre Pilot Test – Six BBG wells offsetting
producing wells
- Core Well
OPERATING PLAN
AND FINANCE
2015 and 2016 Outlook
Period
Comment
3Q15
Production guidance of 1.5 MMBoe; spud 9 XRL wells; 8 XRL wells begin initial flow-back
4Q15
Spud 12 XRL wells; 4 XRL wells begin initial flow-back; 10 XRL wells expected to
reach peak oil production
2016
Anticipate capital budget of $225–$275 mm; 10-15% production growth; spud ~40 XRL wells
 2015 Guidance
Production (MMBoe)1
 Capital expenditures of $320-$350 million
8.0
 Total production of 6.1-6.5 MMBoe
 ~23% YOY growth at the mid-point
6.0
 3Q15 guidance of 1.5 MMBoe
4.0
 2016 Capital and Production Outline
 Capital expenditures of $225-$275 million
2.0
 Spud ~40 XRL wells
 Corporate production growth range of ~10-15%
 DJ Basin production growth of ~25%
0.0
2010
2011
2012
2013
DJ
1
Pro forma for previously completed asset sales, estimated production volumes for 2015 and 2016 represent approximate mid-point of guidance and internal estimates
24
2014
UOP
2015E 2016E
Robust Hedging Program Provides Predictability
 2015: ~80% of oil and natural gas production hedged for remainder of the year at an
average price of $89.81/Bbl and $4.13/MMBtu
 2016: 6,771 Bbls/d of crude oil hedged at an average price of $80.47/Bbl and 5,000
MMBtu/d of natural gas hedged at an average price of $4.10/MMBtu
 2017: 1,872 Bbls/d of crude oil hedged at an average price of $75.61/Bbl
Crude Oil
25,000
$100
10,800
Volume (mmbtu/d)
Volume (bbl/d)
12,000
Natural Gas
10,000
8,000
6,771
6,000
$80
$89.81
$20
20,000
20,000
15,000
10,000
$4.13
4,000
5,000
$80.47
5,000
2,000
$4.10
0
0
$60
2H15
$0
FY 2015
FY 2016
Hedge position as of August 6, 2015
25
FY 2016
Financially Well Positioned for 2015 and Beyond
 Borrowing base of $375 million with zero drawn and $101 million of cash and
short term investments
 Letter of credit of $26 million
 Borrowing base expected to be reaffirmed
at upcoming fall redetermination
Debt Maturities
(in millions)
$500
Borrowing Base - $375
million with zero drawn
 Total liquidity of ~$450 million at
June 30, 2015
 Nearest debt maturity is in 2019
$400
$300
$200
$100
$0
2015
26
2016
2017
2018
2019
2020
2021
2022
Why Bill Barrett Corporation?
 Leading DJ Basin position providing competitive acreage advantage
 Top-Tier basin based on rates of return
 Contiguous acreage position enhances efficiencies
 Sustainable growth underpinned by ~2,000 development locations
 Focused XRL development in NE Wattenberg
 Recent well performance delivering improved results
 ~80% of NE Wattenberg acreage can be developed with XRL wells
 XRL program provides greater growth clarity
 Projecting ~20% pro forma production growth CAGR over the next several years
 Significant growth in DJ Basin production underpinned by XRL drilling program
 Financial capacity to withstand current macro-economic environment
 Maintain strong liquidity with no near-term debt maturities
27
APPENDIX
Northeast Wattenberg: Prime Position Among Peers
Excellent position yet to be fully valued
 Located between BCEI positions
Niobrara Formation
 Adjacent to NBL Wells Ranch
East Pony/
Redtail
BCEI
 Successful extended reach
laterals within 2 miles of
BBG position
SYRG
 Successful 40-acre spacing
within 3 miles of BBG position
NBL
Loeffler Pad
NBL
Wells Ranch
CRZO
Razor/Rohn
BCEI
PDCE
Waste Mgt.
 Continuation of geologic and
geophysical parameters across
position
10 miles
29
BBG Acreage
DJ Drilling and Completions Evolution
Evolution to XRL’s completed with plug-and-perf technique and more proppant
More Frac Stages Combined with Increasing Proppant Per Lateral Foot as BBG Evolves Towards Full-Scale XRL Development
2012
2013
2014
2015
~4,000 ft. lateral, 15-18 stages,
600 lbs/ft. proppant
~4,000 ft. lateral, 17-24 stages,
600-1,000 lbs/ft. proppant
Sleeves and Swell Packers,
~4,000-9,700 ft. lateral, 16-32
stages, 700-1,200 lbs/ft. proppant
Cemented Plug and Perf Frac,
~9,000-9,700 ft lateral, 40-55
stages, 1,000-1,400 lbs/ft
proppant

Plug-and-Perf Completions Yielding Improved Production Profile
 Have methodically evolved towards longer laterals, more stages and more sand to more
efficiently and effectively develop the field
 Current completion design resulting in shallower decline curve and improved results

~9,500’ lateral completed with plug-and-perf vs. sliding sleeve,

55-stages as compared to 40-stages

>1,000 lbs of sand per foot as compared to <1,000 lbs of sand per foot

Tighter perf intervals – 60’ vs. 240’

Controlled flow back resulting in shallower initial production declines
Source: Corporate Disclosure, IHS
30
Controlled Flowback of XRL Well Providing Better Results
Leads to shallower declines and improved EURs
31
DJ Basin Infrastructure – Expected Capacities
Cheyenne Crude
Terminal 52mbbls/d
Pony Express Conversion
In Service: 230-320mbbls/d
Pony Express NE CO Lateral
2Q15: 90mbbls/d
Suncor Refinery:
96MBbls/d
White Cliffs Pipeline
In Service: 150mbbls/d
Plains Rail Facility:
2H14: 68mbbls/d
32
DJ Basin Infrastructure
 Existing local oil refining capacity and rail infrastructure >350mbbls/d
Capacity Expansion Projects
Capacity (MBbls/d)
Timing
Pony Express Pipeline
230
In Service
White Cliffs Expansion
75
In Service
Pony Express DJ Lateral
90
In Service
Saddlehorn Pipeline
Open Season Completed
H2 2016
Grand Mesa Pipeline
Open Season Completed
H2 2016
 DCP total gas processing capacity ~840 MMcf/d
Capacity Expansion Projects (MMcf/d)
Lucerne II
2015
Additions
200
Timing
In Service
 Front Range Pipeline brings NGLs access to Mt. Belvieu NGL market
NGL Pipelines Additions
Capacity (MBbls/d)
Timing
Front Range Pipeline
150
In Service
33
Uinta Basin: Well Positioned Among Peers
Wasatch, Green River Formations
DVN
EPE
CPG
NFX
CPG
QEP
UPL
NFX
LINN
10 Miles
34
BBG Acreage
RESERVES AND
SELECTED
FINANCIALS
Year-End 2014 Reserves
Year-end 2014
$4.35 per MMBtu HH and $94.99 per barrel WTI pricing used in reserve calculations
Proved
MMBoe
Proved
Probable &
Possible
Reserves
MMBoe
Gross/Net
Drilling
Locations
Denver Julesburg1
73
301
1,795/888
Uinta Oil2
Program
48
151
1,537/714
1
25
367/85
TOTAL
122
477
3,699/1,687
% OIL
69%
68%
Proved
Total Estimated 3P Reserves
Other
0
100
200
300
MMBoe
1DJ:
•
•
•
3P Reserves include up to 8 wells per drilling unit per horizon; including Niobrara B and C formations and Codell formation; majority based on extended reach laterals
750 2013YE 640 locations now 1280 locations in the DJ
380 1280 locations added in the DJ
2 Blacktail Ridge-Lake Canyon: Predominantly 80-acre spacing; East Bluebell: Predominantly 40-acre spacing
36
Year-End 2014 3P Reserves by Location
UOP 3P Reserves (151 MMBoe)
DJ 3P Reserves (301 MMBoe)
56
40
60
39
206
51
NE Wattenberg
•
•
Chalk Bluffs
Core Wattenberg
750 2013YE 640 acre locations now 1280 acre locations
380 1280 acre locations added
Blacktail Ridge/Lake Canyon


37
80-acre and160-acre spacing
Upside from downspacing
East Bluebell
South Altamont
Natural Gas and Oil Hedges
As of August 6, 2015
Swaps
Period
Oil
Volume
(Bbls/d)
3Q15
4Q15
1Q16
2Q16
3Q16
4Q16
1Q17
2Q17
3Q17
4Q17
Natural Gas
WTI Price
($/Bbl)
Volume
(MMBtu/d)
NWPL Price
($MMBtu)
10,800
$
89.81
20,000
$
4.13
10,800
$
89.81
20,000
$
4.13
7,300
$
81.65
5,000
$
4.10
7,300
$
81.65
5,000
$
4.10
6,250
$
79.11
5,000
$
4.10
6,250
$
79.11
5,000
$
4.10
2,250
$
73.88
2,250
$
73.88
1,500
$
78.16
1,500
$
78.16
38
-
-
-
-
-
-
-
-
Pro Forma Production, Price and Cost Data
Pro forma for asset sales largely completed in the fourth quarter of 2013 and third quarter of 2014.
Year Ended December 31,
2014
2013 Change
2Q15
1H15
Oil (MBbls)
1,120
2,245
3,541
2,802
26%
Natural Gas (MMcf)
1,800
3,558
6,494
5,256
24%
208
371
543
334
63%
1,628
3,209
5,166
4,012
29%
17,890
17,729
14,153
10,992
29%
$48.68
$42.89
$76.61
$81.52
-6%
2.33
2.46
4.84
3.84
26%
NGLs(per Bbl)
12.76
13.00
22.90
23.75
-4%
Combined (per Boe)
37.70
34.24
61.00
63.95
-5%
$78.44
$77.35
$78.41
$81.23
-3%
4.10
4.01
3.74
5.88
-36%
12.76
13.00
22.77
32.26
-29%
60.13
60.07
60.84
67.13
-9%
-2%
Production Data
NGLs(MBbls)
Combined volumes (MBoe)
Daily combined volumes (Boe/d)
Average Prices (before effects of realized hedges)
Oil (per Bbl)
Natural Gas (per Mcf)
Average Prices (after the effects of realized hedges)
Oil (per Bbl)
Natural Gas (per Mcf)
NGLs(per Bbl)
Combined (per Boe)
Average Costs (per Boe):
Lease operating expense
$7.01
$7.85
$8.62
$8.83
Gathering, transportation and processing expense
0.57
0.58
0.88
0.93
-6%
Production tax expense
2.34
1.98
4.80
4.38
10%
32.36
32.70
33.26
29.07
14%
7.31
6.91
8.17
12.17
-33%
Depreciation, depletion and amortization
General and administrative expense, excluding long-term
incentive compensation expense(1)
(1)
This presentation is a non-GAAP measure. Average costs per Boe for general and administrative expense, including long-term incentive compensation expense, as
presented in the Consolidated Statements of Operations, were $9.01 and $8.73 for the three and six months ended June 30, 2015, and $10.38 and $16.11 for the years
ended December 31, 2014 and 2013, respectively.
39
1H15 Production, Wells Spud and Capital Expenditures
1H 2015 CAPEX and Production
Spuds
Area
DJ Basin
Uinta Oil Project
CAPEX
Production
$millions
MBoe
Area
159
2,191
DJ Basin
19
996
Uinta Oil
Powder River Basin
1
18
Other
0
4
179
3,209
Total
$
FF&E Expenditures
Capex Incl FF&E Excl Acq
1
$
Operated
180
40
Total
Gross
16
Net
15.3
Non-Operated
Gross
Net
Total
Gross
20
5.9
36
Net
21.2
8
4.3
2
0.1
10
4.4
24
19.6
22
6.0
46
25.6
1Q15 Capital Expenditures and Production
CAPEX and Production
Spuds
Area
CAPEX
Production
$millions
MBoe
Operated
Area
Gross
Non-Operated
Net
Gross
Net
Total
Gross
Net
100
1,051
DJ Basin
9
8.9
13
3.6
22
12.5
13
511
Uinta Oil
4
2.0
2
0.1
6
2.1
Powder River Basin
1
16
13
11
15
4
28
15
Piceance Basin
0
0
Other
0
3
114
1,581
DJ Basin
Uinta Oil Project
Total
$
FF&E Expenditures
Capex Incl FF&E Excl Acq
$
114
41
Total
2015 Guidance
Capital program 100% directed at oil growth
Capex by Area
 Total capital of $320-$350 million
UOP
10%
 First half 2015 capital of ~$180 million
 Total production of 6.1–6.5 MMBoe
 ~23% YOY growth at the mid-point1
NE Wattenberg
90%
 Third quarter guidance of 1.5 MMBoe
 Lease operating expenses of $48-$52 million
 Gathering, transportation and processing costs of $4-$6
million
Production Mix
 Unused commitments of $20-$21 million2
 General and administrative expenses before non-cash,
performance-based compensation of $36-$40 million
Gas
20%
NGL
10%
Oil
70%
1Excludes
production associated with any assets that have been sold
2Primarily
related to commitments of unused pipeline natural gas transportation
42
Land Summary
As of December 31, 2014
Area
Gross Acreage
Net Acreage
Avg. Gross Project
NRI
Avg. BBG Working
Interest
Active Oil Properties
Uinta Basin – Uinta Oil Program
Blacktail Ridge/Lake Canyon
Minimum to be earned
East Bluebell
Other
110,496
123,265
36,581
47,579
317,921
55,465
50,702
24,365
21,613
152,145
82%
82%
83%
80-100%
51%
51%
70%
70-90%
47,826
12,395
22,478
2,910
85,609
81%
84%
83%
Varies
97%-100%
Varies
Total DJ Basin Program
72,479
16,127
37,751
3,857
130,214
Powder Deep Oil Program
41,113
19,492
80%
10%-65%
4,649
289,066
30,587
21,431
21,312
151,647
4,184
219,528
16,822
11,045
14,401
123,467
88%
83%
85%
83%
83%
Varies
90%
100%
55%
44%
55%
Varies
Total Uinta Oil Program
DJ Basin
Northeast Wattenberg
Wattenberg Core
Chalk Bluffs
Other
Exploration & Other Properties
Piceance Basin – Cottonwood Gulch
Paradox Basin – Yellow Jacket
Uinta Basin (Hornfrog, including to-be-earned)
DJ Basin – Sage Brush
Alberta Basin
Other
Note: Ownership interest(s) include to-be-drilled locations and should be considered estimates as interests vary over time.
43
Forward-Looking & Other Cautionary Statements
FORWARD-LOOKING STATEMENTS: This presentation (which includes oral statements made in connection with this presentation) contains forward-looking
statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended.
All written or oral statements, other than historical financial information, may be deemed to be forward-looking statements. Words such as expects, forecast,
guidance, anticipates, intends, plans, believes, seeks, estimates and similar expressions or variations of such words are intended to identify forward-looking
statements; however, these are not the exclusive means of identifying forward-looking statements. In particular, the Company is providing 2015 and 2016
operating guidance, which contains projections for certain 2015 and 2016 operational and financial metrics as well as certain projections for the third quarter of
2015.
These and other forward-looking statements in this presentation are based on management’s judgment as of the date of this presentation and are subject to
numerous risks and uncertainties. Actual results may vary significantly from those indicated in the forward-looking statements due to, among other things, oil,
NGL and natural gas price volatility, including regional price differentials; changes in operational and capital plans; costs, availability and timing of build-out of
third party facilities for gathering, processing, refining and transportation; delays or other impediments to drilling and completing wells arising from political or
judicial developments at the local, state or federal level, including voter initiatives related to hydraulic fracturing; development drilling and testing results; the
potential for production decline rates to be greater than expected; regulatory delays, including seasonal or other wildlife restrictions on federal lands;
exploration risks such as drilling unsuccessful wells; higher than expected costs and expenses, including the availability and cost of services and materials;
unexpected future capital expenditures; economic and competitive conditions; debt and equity market conditions, including the availability and costs of
financing to fund the Company’s operations; the ability to obtain industry partners to jointly explore certain prospects, and the willingness and ability of those
partners to meet capital obligations when requested; declines in the values of our oil and gas properties resulting in impairments; changes in estimates of
proved reserves; compliance with environmental and other regulations; derivative and hedging activities; risks associated with operating in one major
geographic area; the success of the Company’s risk management activities; title to properties; litigation; environmental liabilities and other factors discussed in
the Company’s reports filed with the Securities and Exchange Commission (“SEC”).
Please refer to the Company’s Annual Report on Form 10-K for the year ended December 31, 2014 filed with the SEC, specifically Item 1A, Risk Factors, and
other filings including our Current Reports on Form 8-K and Quarterly Reports on Form 10-Q, for further discussion of risk factors that may affect the forwardlooking statements. The Company assumes no obligation to publicly revise or update any forward-looking statements based on future events or circumstances
or otherwise, except as required by applicable law. All forward-looking statements are qualified in their entirety by this cautionary statement.
This presentation is neither an offer to sell nor a solicitation of an offer to buy any securities, nor shall there be any sale of any such securities in any state or
jurisdiction in which such offer, solicitation or sale would be unlawful prior to registration or qualification under the securities laws of any such state or
jurisdiction.
44
Disclosures
DISCLOSURE STATEMENTS
Please refer to the Company’s Annual Report on Form 10-K for the year ended December 31, 2014 filed with the SEC, specifically Item 1A, Risk Factors, and other filings including our
Current Reports on Form 8-K and Quarterly Reports on Form 10-Q, for further discussion of risk factors that may affect the forward-looking statements. The Company encourages you
to consider the risks and uncertainties associated with projections and other forward-looking statements and to not place undue reliance on any such statements. In addition, the
Company assumes no obligation to publicly revise or update any forward-looking statements based on future events or circumstances or otherwise, except as required by applicable
law.
Reserve Disclosure
The SEC generally permits oil and gas companies, in filings made with the SEC, to disclose 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 and certain probable and possible
reserves that meet the SEC’s definitions for such terms. In this presentation, the Company uses the terms “estimated ultimate recovery”, “EUR” or other descriptions of potential
reserves or volumes of reserves, as well as aggregated proved, probable and possible (“3P”) reserves, which the SEC guidelines restrict from being included in filings with the SEC.
The Company provides internally generated estimates for probable and possible reserves in this presentation. The estimates conform to Society of Petroleum Evaluation Engineers
(SPEE) methodology. They are not prepared or reviewed by third party engineers. The Company’s 2014 probable and possible reserve estimates are determined using year-end pricing,
as used in the calculation of proved reserves. Probable and possible reserves and other estimates of non-proved reserves are subject to significantly greater risk of recovery than
proved reserves. EURs refer to the Company’s internal estimates of per-well hydrocarbon quantities that may be potentially recovered from a hypothetical and/or actual well completed
in the area. Actual quantities that may be ultimately recovered from the Company’s interests are unknown. Factors affecting ultimate recovery include the scope of the Company’s
ongoing drilling program, which will be directly affected by the availability of capital, drilling and production costs, availability and cost of drilling services and equipment, lease
expirations, transportation constraints, regulatory approvals and other factors, as well as actual drilling results, including geological and mechanical factors affecting recovery rates.
Estimates of ultimate recovery from reserves may change significantly as development of the Company’s core assets provide additional data. In addition, the Company’s production
forecasts and expectations for future periods are dependent 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 cost increases. The Company's estimate of probable and possible
reserves, 3P reserves and EURs are provided in this presentation because management believes it is useful, additional information that is widely used by the investment community in
the valuation, comparison and analysis of companies.
Well Performance
The calculation of 30-day initial production rates measures the daily production from a well starting with the date upon which the Company determines the well has achieved peak
production and averages the daily production for the following 30 days. This date will occur at some date after oil production commences. In addition, in calculating the IP rate of a
well over a specified period of time, the calculation will exclude days on which production is impaired for mechanical, third party mid-stream or other non-geologic reasons. IP rates
and other initial indications of well performance do not necessarily reflect EURs or other long-term measures of a well’s performance. Peer data may not be comparable to results
reported by the Company.
Non-GAAP Measures
Non-GAAP measures included herein include Adjusted Net Income, Discretionary Cash Flow, Pre-Tax PV10 and General and Administrative Expenses before Non-Cash Stock-Based
Compensation. These measures are included because management believes they are useful to investors in evaluating the Company’s operating performance. These measures are
widely used in the oil and natural gas industry. Calculations of these measures may differ by company. Please refer to the Company’s first and second quarter 2015, and full-year 2014
earnings releases dated May 8, 2015, August 6, 2015, and February 25, 2015, respectively, for reconciliations of these measures to the closest GAAP measure.
ADDITIONAL INFORMATION:
Rate of return estimates do not reflect lease acquisition costs or corporate general and administrative expenses.
Initial and test results from a well do not necessarily reflect the well’s longer-term performance or the performance of other wells in the same area.
45
1099 Eighteenth Street, Suite 2300
Denver, CO 80202
303.293.9100
Website: www.billbarrettcorp.com
Investor Relations Contact:
Larry C. Busnardo
(303) 312-8514
lbusnardo@billbarrettcorp.com