CORPORATE PRESENTATION

AUGUST 2015

2

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

3

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

COMPANY OVERVIEW

5

Bill Barrett Corporation Overview

DJ BasinTop-Tier Economics

Uinta OilFuture Optionality

BBG headquarters

Well positioned with highly concentrated acreage

YE2014 proved reserves – 122 MMBoe

3P reserves – 477 MMBoe

DJ Basin provides flagship asset

Attractive economics in current oil price environment

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

Earliest debt maturity is in 2019

Concentrated Asset Portfolio

6

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

1 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

2010 2011 2012 2013 20140

20

40

60

80

100

120

140

Proved Reserves (MMBoe)1

DJ UOP

122

60%55%

105% CAGR

40%45%

2010 2011 2012 2013 2014 2015E0

2

4

6

Production (MMBoe)1

DJ UOP

6.1-6.5

45%

~60% CAGR

27%

55% 73%

7

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

8

2014 2015E 2016E0

2

4

6

8

Production (MMBoe)1

DJ UOP

2014 2015E 2016E$0

$100

$200

$300

$400

$500

$600

Capital Expenditures ($mm)1

DJ UOP

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

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

~20% CAGR

Capital Disciplined Approach

(56%)

DJ BASIN

10

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

11

Operating In the Right Basin at the Right Time

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

XRL program ranks fourth among all plays

Source: Credit Suisse Equity Research Oil and Gas Primer: E&Ps, May 2015

12

DJ Basin Rate-of-Return Assumptions

(1) 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(2) EUR based on internal Company estimates derived from company and peer drilling results; first year oil recovery estimated to be ~20% of EUR

Flat WTI Oil Price

$/bbl

Flat HH Gas Price $/mmbtu

IRRPre-Tax

PV10(millions)

Payout(Years)

$50 $2.75 22% $2.6 3.4

$55 $3.00 28% $3.5 2.9

$60 $3.25 34% $5.0 2.5

$65 $3.50 39% $6.0 2.2

$70 $3.75 46% $7.3 1.9

Description Assumptions

WTI Oil Price ($/Bbl) $55.00

Oil Differential ($/Bbl) ($9.00)

NYMEX Gas Price ($/MMBtu) $3.00

Gas Differential ($/MMBtu) ($0.41)

2-Stream Wellhead EUR (MBoe) 700

3-Stream Sales EUR (MBoe) 751

% 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 2.9 Years

700 Mboe (2-Stream) EUR with $6.25 million well cost economics

Oil 65%

Gas 20%

NGL 15%

3-Stream EUR – 751 Mboe2

13

2013

640

XRL Evolution Completed

2014

640 1,120 1,280

2015E

1280

61

(Gross operated wells spud by year)

64 35-40

No XRLs drilled in 2013 15-18 stages All completed using swell

packers and sliding sleeves Averaged 600-800 lbs sand

per lateral foot

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

55 stages Plug n’ Perf Technology ~9,500’ laterals 1,000+lbs sand per foot

DJ Basin development moves from 640-acre to 1,280-acre spacing

2013

640

2014

640 1,280

2015E

640 1280

100% 640 75% 1,280

Competitive advantage: ~80% of NE Wattenberg acreage can be developed with XRLs

Reconfiguring inventory to optimize XRL drilling

~80% 1,280

(NE Wattenberg 3P Undeveloped Locations)

14

NE Wattenberg Provides a Strategic Advantage

BBG horizontal wells (through 2Q15)2015 planned XRL wells

10 XRL wells begin initial sales in June

Concentrated acreage position allows for efficient and economic development 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

Generating greater capital efficiency gains through 40% faster drilling times

XRL drilling program delivering very good early-stage performance

Preferred completion technique with controlled flow back leading to shallower initial declines

Initial production data validating performance assumptions

NE Wattenberg – 49,359 net acres

4 XRL wells begin initial sales in July

4 XRL wells begin initial sales in August

15

2014 2015E 2016E$0

$100

$200

$300

$400

$500

DJ Basin Capital Expenditures ($mm)1

Building Growth Platform

(52%)

2013 2014 2015E 2016E0

2

4

6

DJ Basin Production (MMBoe)1

~64% CAGR

Adapted to a changing macro environment by reducing capital…

…but able to generate a meaningful growth profile

1 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

16

Plug-and-Perf Completions Yielding Improved Production Profile

Enhanced design proving to be a game changer ~9,500’ lateral completed with plug-and-perf

55-stages (three perf intervals) vs. 40-stages (one perf interval)

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

1 2 3 4 5 6 7 8 910

100

1,000

Month

Av

g.

Da

ily

Oil

Ra

te (

bo

e/d

)

XRL 55-Stage w/PnP (4 wells)

XRL 40-Stage w/Sliding Sleeves (12 wells)

~46% increase in performance through initial 8 months

Early Design - 40-stage Sliding Sleeve

Enhanced Design - 55-stage Plug-and-Perf

* Graphic representation of a 55-stage plug-and-perf completion design compared to a 40-stage sliding sleeve completion design

Plug-and-Perf exhibiting improved initial rates; shallower decline 30-day avg. = 649 Boe/d (peak oil month)

60-day avg. = 615 Boe/d

90-day avg. = 580 Boe/d

17

Enhancing Cost Efficiencies

2014 2015E$0

$1

$2

$3

$4

$5

$6

$7

$8

$9

XRL D&C Costs Down 25%*

Drilling Completions Facilities

(mil

lio

ns)

$8.25 mm

$6.25 mm

* 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

2013 2014 2015E$0

$50

$100

$150

$200

$250

$300

Building Efficiencies ThroughLonger Laterals

640 1,120 1,280

(Dri

llin

g C

ost

/Lat

eral

Fo

ot)

XRL well drilling days reduced by 40% to

10-days/well , “best-in-class” well drilled in 8 days

Targeting 5-10% additional cost reduction

18

Increasing Geologic Confidence

Prospective for up to Six Stacked Pay Zones

Niobrara A

Niobrara B

Niobrara C

Codell

Bridge Creek Ls - Greenhorn

Lincoln Ls - Greenhorn

BBG – CB Rudd Core Well

Continue to refine reservoir and resource understanding in the Niobrara A, B, C, Codell and Greenhorn utilizing most recently acquired core data

Initial Codell tests have been drilled on western most acreage position. Additional delineation opportunities to the east

Niobrara “A” Chalk prospective under northern acreage

Initial well drilled with completion scheduled to begin shortly

Two potential additional targets in the Greenhorn – Bridge Creek and Lincoln Limestone

19

NE Wattenberg Generalized Development Spacing*

* Graphic representation of the expected 1,280-acre development pattern of the NE Wattenberg acreage; actual development may differ

UINTA OIL PROGRAM

21

Uinta Oil Program

BBG Acreage

Gas ProductionOil Production

10 Miles

Wasatch, Green River Formations

2,300 feet stacked play prospective for the Green River and Wasatch formations

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

2015 plans are to drill 7 wells in East Bluebell and 8 obligation wells in Black Tail Ridge

Large, Scalable Program: 165,000+ net acres*

BBG acreage* Includes additional acreage that can be earned through drilling

East Bluebell24,365 net acres South Altamont

21,613 net acres

BTR/Lake Canyon106,167* net acres

22

Core and Reservoir Characterization Program

East Bluebell: Increasing Technical Understanding

Continue refinement of reservoir and resource understanding in the Lower Green River Formation pay intervals

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

Core processing and evaluation underway

40-Acre Pilot Test – Six BBG wells offsetting producing wells

Two wells to be monitored with micro seismic during completions utilizing different fracturing techniques (Slick Water and Hybrid Gel/Slick Wtr)

Micro seismic and Completions

FD State 10-36D

- Core Well

Co

reC

ore

Co

re

TGR3Green River

Douglas Creek

3 Point Mrkr

Black Shale

Castle Peak

Uteland Butte

Aurora 3-32D

OPERATING PLAN AND FINANCE

24

2015 Guidance Capital expenditures of $320-$350 million

Total production of 6.1-6.5 MMBoe

~23% YOY growth at the mid-point

3Q15 guidance of 1.5 MMBoe

2010 2011 2012 2013 2014 2015E 2016E0.0

2.0

4.0

6.0

8.0Production (MMBoe)1

DJ UOP

2015 and 2016 Outlook

53% CAGR

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

2016 Capital and Production Outline Capital expenditures of $225-$275 million

Spud ~40 XRL wells

Corporate production growth range of ~10-15%

DJ Basin production growth of ~25%

1 Pro forma for previously completed asset sales, estimated production volumes for 2015 and 2016 represent approximate mid-point of guidance and internal estimates

25

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

2H15 FY 20160

2,000

4,000

6,000

8,000

10,000

12,000

$60

$80

$10010,800

6,771

$89.81

$80.47

Crude Oil

Vo

lum

e (b

bl/

d)

Robust Hedging Program Provides Predictability

Hedge position as of August 6, 2015

FY 2015 FY 20160

5,000

10,000

15,000

20,000

25,000

$0

$20

20,000

5,000

$4.13

$4.10

Natural Gas

Vo

lum

e (m

mb

tu/d

)

26

2015 2016 2017 2018 2019 2020 2021 2022$0

$100

$200

$300

$400

$500

Debt Maturities(in millions)

Borrowing Base - $375 million with zero drawn

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

Total liquidity of ~$450 million at

June 30, 2015

Nearest debt maturity is in 2019

27

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

APPENDIX

29

10 miles

Niobrara Formation

BBG Acreage

Located between BCEI positions

Adjacent to NBL Wells Ranch

Successful extended reach laterals within 2 miles of BBG position

Successful 40-acre spacing within 3 miles of BBG position

Continuation of geologic and geophysical parameters across position

Excellent position yet to be fully valued

Northeast Wattenberg: Prime Position Among Peers

BCEI

East Pony/ Redtail

NBL Wells Ranch

PDCE Waste Mgt.

SYRG

CRZO Razor/RohnNBL

Loeffler Pad

BCEI

30

DJ Drilling and Completions Evolution

Evolution to XRL’s completed with plug-and-perf technique and more proppant

Source: Corporate Disclosure, IHS

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

More Frac Stages Combined with Increasing Proppant Per Lateral Foot as BBG Evolves Towards Full-Scale XRL Development

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

31

Controlled Flowback of XRL Well Providing Better Results

Leads to shallower declines and improved EURs

32

DJ Basin Infrastructure – Expected Capacities

Pony Express ConversionIn Service: 230-320mbbls/d

Pony Express NE CO Lateral2Q15: 90mbbls/d

White Cliffs PipelineIn Service: 150mbbls/d

Plains Rail Facility: 2H14: 68mbbls/d

Cheyenne Crude Terminal 52mbbls/d

Suncor Refinery: 96MBbls/d

33

DJ Basin Infrastructure

Existing local oil refining capacity and rail infrastructure >350mbbls/d

DCP total gas processing capacity ~840 MMcf/d

Front Range Pipeline brings NGLs access to Mt. Belvieu NGL market

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

Capacity Expansion Projects (MMcf/d)2015

Additions Timing

Lucerne II 200 In Service

NGL Pipelines Additions Capacity (MBbls/d) Timing

Front Range Pipeline 150 In Service

34

Uinta Basin: Well Positioned Among Peers

BBG Acreage10 Miles

Wasatch, Green River Formations

UPL

LINNNFX

CPG

EPE

DVN

NFX

CPG

QEP

RESERVES AND SELECTED

FINANCIALS

36

Year-End 2014 Reserves

ProvedMMBoe

Proved Probable &

Possible Reserves MMBoe

Gross/Net Drilling

Locations

73 301 1,795/888

48 151 1,537/714

1 25 367/85

TOTAL 122 477 3,699/1,687

% OIL 69% 68%

Series1

0 100 200 300

Denver Julesburg1

Uinta Oil2 Program

Other

Proved

Total Estimated 3P Reserves

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 DJ2 Blacktail Ridge-Lake Canyon: Predominantly 80-acre spacing; East Bluebell: Predominantly 40-acre spacing

Year-end 2014$4.35 per MMBtu HH and $94.99 per barrel WTI pricing used in reserve calculations

37

Year-End 2014 3P Reserves by Location

60

51

40

UOP 3P Reserves (151 MMBoe)

Blacktail Ridge/Lake Canyon East Bluebell South Altamont

80-acre and160-acre spacing Upside from downspacing• 750 2013YE 640 acre locations now 1280 acre locations

• 380 1280 acre locations added

206

39

56

DJ 3P Reserves (301 MMBoe)

NE Wattenberg Chalk Bluffs Core Wattenberg

38

As of August 6, 2015

Natural Gas and Oil Hedges

Swaps

Period Oil Natural Gas

Volume (Bbls/d)

WTI Price ($/Bbl)

Volume(MMBtu/d)

NWPL Price($MMBtu)

3Q15 10,800 $ 89.81 20,000 $ 4.13

4Q15 10,800 $ 89.81 20,000 $ 4.13

1Q16 7,300 $ 81.65 5,000 $ 4.10

2Q16 7,300 $ 81.65 5,000 $ 4.10

3Q16 6,250 $ 79.11 5,000 $ 4.10

4Q16 6,250 $ 79.11 5,000 $ 4.10

1Q17 2,250 $ 73.88

- -

2Q17 2,250 $ 73.88

- -

3Q17 1,500 $ 78.16

- -

4Q17 1,500 $ 78.16

- -

39

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.

(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.

2Q15 1H15 2014 2013 Change

Oil (MBbls) 1,120 2,245 3,541 2,802 26%

Natural Gas (MMcf) 1,800 3,558 6,494 5,256 24%

NGLs(MBbls) 208 371 543 334 63%

Combined volumes (MBoe) 1,628 3,209 5,166 4,012 29%

Daily combined volumes (Boe/d) 17,890 17,729 14,153 10,992 29%

Oil (per Bbl) $48.68 $42.89 $76.61 $81.52 -6%

Natural Gas (per Mcf) 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%

Oil (per Bbl) $78.44 $77.35 $78.41 $81.23 -3%

Natural Gas (per Mcf) 4.10 4.01 3.74 5.88 -36%

NGLs(per Bbl) 12.76 13.00 22.77 32.26 -29%

Combined (per Boe)60.13 60.07 60.84 67.13 -9%

Lease operating expense $7.01 $7.85 $8.62 $8.83 -2%

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%

Depreciation, depletion and amortization 32.36 32.70 33.26 29.07 14% General and administrative expense, excluding long-term

incentive compensation expense(1) 7.31 6.91 8.17 12.17 -33%

Average Costs (per Boe):

Year Ended December 31,

Average Prices (before effects of realized hedges)

Average Prices (after the effects of realized hedges)

Production Data

40

1H15 Production, Wells Spud and Capital Expenditures

CAPEX ProductionArea $millions MBoe

DJ Basin 159 2,191

Uinta Oil Project 19 996

Powder River Basin 1 18

Other 0 4

Total 179$ 3,209

FF&E Expenditures 1

Capex Incl FF&E Excl Acq 180$

1H 2015 CAPEX and Production Spuds

Area Gross Net Gross Net Gross Net

DJ Basin 16 15.3 20 5.9 36 21.2

Uinta Oil 8 4.3 2 0.1 10 4.4

Total 24 19.6 22 6.0 46 25.6

Operated Non-Operated Total

41

1Q15 Capital Expenditures and Production

CAPEX ProductionArea $millions MBoe

DJ Basin 100 1,051

Uinta Oil Project 13 511

Powder River Basin 1 16

Piceance Basin 0 0

Other 0 3

Total 114$ 1,581

FF&E Expenditures -

Capex Incl FF&E Excl Acq 114$

CAPEX and Production Spuds

Area Gross Net Gross Net Gross Net

DJ Basin 9 8.9 13 3.6 22 12.5

Uinta Oil 4 2.0 2 0.1 6 2.1

Total 13 11 15 4 28 15

Operated Non-Operated Total

42

Total capital of $320-$350 million First half 2015 capital of ~$180 million

Total production of 6.1–6.5 MMBoe ~23% YOY growth at the mid-point1

Third quarter guidance of 1.5 MMBoe

Lease operating expenses of $48-$52 million

Gathering, transportation and processing costs of $4-$6 million

Unused commitments of $20-$21 million2

General and administrative expenses before non-cash, performance-based compensation of $36-$40 million

Capital program 100% directed at oil growth

2015 Guidance

Production Mix

Oil 70%

Gas 20%

NGL 10%

Capex by Area

NE Wattenberg 90%

UOP10%

1Excludes production associated with any assets that have been sold2Primarily related to commitments of unused pipeline natural gas transportation

43

Land Summary

Area Gross Acreage Net AcreageAvg. Gross Project

NRIAvg. BBG Working

Interest

Active Oil Properties        Uinta Basin – Uinta Oil Program         Blacktail Ridge/Lake Canyon 110,496 55,465 82% 51% Minimum to be earned 123,265 50,702 82% 51% East Bluebell 36,581 24,365 83% 70% Other 47,579 21,613 80-100% 70-90%Total Uinta Oil Program 317,921 152,145             DJ Basin Northeast Wattenberg 72,479 47,826 81% Varies Wattenberg Core 16,127 12,395 84% 97%-100% Chalk Bluffs 37,751 22,478 83% Varies Other 3,857 2,910Total DJ Basin Program 130,214 85,609

Powder Deep Oil Program 41,113 19,492 80% 10%-65%

Exploration & Other Properties        Piceance Basin – Cottonwood Gulch 4,649 4,184 88% 90%Paradox Basin – Yellow Jacket 289,066 219,528 83% 100%Uinta Basin (Hornfrog, including to-be-earned) 30,587 16,822 85% 55%DJ Basin – Sage Brush 21,431 11,045 83% 44%Alberta Basin 21,312 14,401 83% 55%Other 151,647 123,467 Varies Varies

Note: Ownership interest(s) include to-be-drilled locations and should be considered estimates as interests vary over time.

As of December 31, 2014

44

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 forward-looking 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.

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DisclosuresDISCLOSURE 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.

1099 Eighteenth Street, Suite 2300Denver, CO 80202

303.293.9100Website: www.billbarrettcorp.com

Investor Relations Contact:Larry C. Busnardo (303) 312-8514

lbusnardo@billbarrettcorp.com