DEUTSCHE BANK LEVERAGED FINANCE CONFERENCE OCTOBER 2012

Forward-Looking & Other Cautionary Statements Please reference the last two pages of this presentation for important disclosures on: • Forward-looking statements • NGL Calculations • Non-GAAP measures • Reserves • Resource potential

Current production represents July 2012

2

Who We Are Premier E & P growth company, focused in prolific Rocky Mountain region • $1.3B market capitalization $2.4B enterprise value • Proved reserves 1.4 Tcfe 2011 • 22% total reserve growth • 135% oil reserve growth

• Oil and NGLs 2Q12 • 30% sales volume • 59% pre-hedge sales revenue

• Daily net production 351MMcfe • 309 MMcf/d gas • 7,140 Bbl/d oil • NGL exposure - more than 13 MMgal/month Oil Producing Area

BBG Oil Development

Gas Producing Area

BBG Gas Development BBG NGLs Development BBG Oil Exploration

3

Why Invest in Bill Barrett Corporation? Excellent people, long-term profitable growth, quality assets, big upside • Excellent 10-year track record delivering year-over-year growth • Successful transition to increased liquids for a balanced portfolio • Low-risk, visible growth from development assets • Exploration upside: Oil focused, multiple active growth catalysts

• Financial strength and flexibility • Demonstrated efficient, low-cost, disciplined operations • Management expertise and experience in region

4

Who We Are: Excellent Track Record of Profitable Growth Proved Reserves1 (Bcfe)

Production (Bcfe) 1,365

818

965

89.7

558

Dec 2007 382%

118-122

1,118 96.5

106.8

77.6

Dec 2008

Dec 2009

436%

264%

Reserve replacement

Dec 2010 263%

Dec 2011 331% 2008

ratio2

EBITDAX1 (in millions)

2009

2010

2011

2012e

Adjusted Net Income (in millions) $120

$442

$488

$489

$523 $83

$79

$84

2009

2010

2011

$272 $34

2007

1

2008

Please see Disclosure slides. for property sales.

2 Adjusted

2009

2010

2011

2007

2008

5

Financial Strength & Flexibility Strong balance sheet offers substantial liquidity • Liquidity: $900 million borrowing base with $160 million drawn (as of 9/30/12) • Successfully executed $400 million 7% Senior Notes offering in March 2012 • Completing $106 million lease financing arrangement of BBG owned facilities at 3.5%

• Flexibility: Operationally we can increase or reduce activity to keep capital program aligned with commodity price environment • Debt metrics: In line with peers, debt/EBITDAX 2.3X (TTM 2Q12) • Hedging: Reduces volatility and supports cash flow for capital program

6

Capital Structure ($ in millions)

Actual 6/30/2012

Cash & Cash Equivalents

$21

Revolving Credit Facility due 2016

$75

Borrowing Base/Commitments 5.000% Convertible Notes due 2028 (March 2015 Put)

$900 25

9.875% Senior Notes due 2016

250

7.625% Senior Notes due 2019

400

7.000% Senior Notes due 2022

400

Total Debt Stockholders' Equity Total Book Capitalization LTM EBITDAX Selected Credit Statistics Debt / LTM EBITDAX Debt / Total Book Capitalization Net Debt / YE 2011 Proved Reserves ($ / Mcfe)

$1,150 1,235 $2,385 $510 2.3x 48% $0.83

7

Manageable Debt Level & Maturities • Well-spaced debt maturities • Completed $800 million of senior notes offerings since September 2011 • Redeemed $147 million of convertible bonds (March 2012) • Bank credit facility with $900 million of commitments • Last 12-months EBITDAX: $510 million

Debt Maturity Schedule $450 7.625%

$400

7.000%

in millions

$350 $300

Bank Line

$250

9.875%

$200 $150

Remaining 5.000% Convert

$100 $50

Facilities Financing

$2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

8

Credit Metrics Modest Compared to Peers Debt / TTM EBITDAX 1.0x SM Credit rating

Ba3 / BB

2.8x

3.1x

3.5x

4.1x

2.5x

4.0x

2.3x

BBG

BRY

PXP

PVA

XCO

CRK

FST

Ba3/ BB-

Ba3/ BB-

Ba3 / BB

B2 / B

B1 / B

B2 / B

B1 / B+

Debt / Avg Daily Production ($/Mcfe) $4,444

$6,666

$7,102

$3,318

$3,378

$3,392

SM

PVA

XCO

BBG

CRK

FST

PXP

BRY

Ba3 / BB

B2/ B

B1 / B

Ba3/ BB-

B2/ B

B1 / B+

Ba3 / BB

Ba3 / BB-

$1,821

Credit rating

$6,405

Debt / YE 2011 PD Reserves ($/Mcfe) $1.20

SM Credit rating

Ba3/ BB-

$1.65

$1.72

$1.89

$2.05

$2.16

$2.40

BBG

BRY

XCO

FST

CRK

PVA

B1/ B+

B2 / B

B2 / B

Ba3 / BB

Ba3 / BB-

B1 / B

$2.90

PXP Ba3/ BB

Source: Q2 2012 10Q & BAML High Yield Energy Weekly (August 20, 2012) & Company Reports

9

Hedging Provides Price Predictability Hedges reduce volatility and support cash flow for capital program • Opportunistically add to positions over time • 2H12 hedges: ~70% of natural gas production and ~65% of oil production • 2013 hedges: ~55% of natural gas production and ~45% of oil production • 2014 hedges: getting started with 65,000 MMBtu/d at $3.81/MMBtu and 2,700 Bbl/d $96.77/Bbl 2012 (3Q-4Q): 43.2 Bcfe at $6.77/Mcfe 2013: 59.6 Bcfe at $7.33/Mcfe

Volume (Bcfe) Price ($/Mcfe)

Floor/Swap 8

Volume (Bcfe)

20

7

15 6 10 5

5 0

Price($/Mcfe)

25

4 3Q12

4Q12

1Q13

2Q13

3Q13

4Q13

Notes: As of September 14, 2012. Average floor/swap price is for illustrative purposes only and does not represent formal guidance. Excludes 2012 CIG/NWPL basis only swaps that are out-of-the-money.

10

Strong Realized Prices Maintaining high realized prices in a challenging natural gas price environment Realized Prices per Mcfe $7.81 $7.10

$7.07

$7.20-$7.60

$7.05 $6.10-$6.30

2008

2009 Gas: Pre-hedge*

*Includes NGL uplift Please see Disclosure slides.

2010 Hedging Gain

2011 Increase in Price Due to Oil

2012e

2013e

Gas: CIG Market Price

11

Driving Oil Growth: Successfully Rebalancing Portfolio • Our development portfolio has flexibility to increase liquids proportion to 40+% by 2014, predominantly oil • Driving significant oil growth going forward

% of Sales Volumes1 2008

2012e

2014 Target

6% 30%

94%

70%

60%

Oil & NGLs

1

94%

Please see Disclosure slides.

40+% 40+%

Dry Gas

73% 12

Driving Oil Growth: for Increased Value & Revenues Strong oil growth trajectory • Target nearly 80% growth in oil production for 2012 Oil Production (MMBoe)RUN

Proved Oil Reserves (MMBoe) 30.6

OIL ONLY

Oil Production

2.5-3.0

1.5 1.1

13.0 5.7

2008

0.7

0.7

2008

2009

2010

2011

2012e

8%

6%

11%

15%

30%

7.8

2009

2010

2011

% Revenue

13

Driving Oil Growth: 2012 Capital Allocation Liquids Focused All capital currently directed at oil growth • 8 rigs currently targeting oil (3 DJ, 5 Uinta) • 2012: Capital budget $850-$900 million including year-to-date acquisitions • 2013: Narrowing capital expenditure to cash flow gap 2012 Capital Budget by Area

DJ 22%

Uinta Oil 33%

Piceance 23% Exploration 11% West Tavaputs 12%

2012 Capital Budget by Resource

NGL 23%

Oil 65%

Gas 12%

14

PROPERTY DESCRIPTIONS: TWO CORE OIL PROGRAMS

Development Programs Offer Long Term, Low Risk Growth

• Commodity balanced • All drilling currently focused on oil • Minimal drilling commitments: capital flexibility • Cost discipline: low cost operator

Uinta Oil (5 rigs)

DJ Oil (3 rigs)

W. Tav Gas Piceance NGLs

Oil Producing Area

BBG Oil

Gas Producing Area

BBG Gas BBG NGLs

16

Quality Assets: Building value since year-end 2011 • Sizable oil growth 2011: proved up 135%, 3P up 200% • Continue building oil program in 2012, plan to participate in nearly 200 gross oil wells • Uinta Oil Program: Added 15,000 net acres year-to date • DJ Basin: Increased position 125% with acquisition of 41,900 net acres year-to-date

Proved Bcfe

3P Bcfe

Gross/Net Drilling Locations

Active Rigs Yearend

West Tavaputs, Uinta

461

1,171

622/594

0

Uinta Oil Program (oil)

173

787

1,688/616

5

Gibson Gulch, Piceance (NGLs)

596

733

626/604

0

Denver Julesburg (oil/NGLs)

41

141

283/151

3

Powder River CBM

56

90

168/81

0

Wind River & Other

38

122

112/38

0

TOTAL

1,365

3,044

3,499/2,084

8

PERCENT OIL

13%

25%

As of year-end 2011 Proved Probable & Possible (oil/gas)

0

200

400

600

800

1,000

1,200

1,400

17

Uinta Oil Program: Driving Substantial Oil Growth Expanded acreage, 5 rigs operating and production up 75% year-to-date •

Prolific Wasatch-Green River targets

Wasatch, Green River Formations

• Expanding giant Altamont-Bluebell field • Vertical and horizontal technologies

•

Significant land position: • 122,485 net undeveloped acres • Added 15,000 net acres year-to-date

•

Current net production: 4,970 Boe/d

•

2011 growth (36 wells):

N Altamont/Bluebell Cum: 312 MMBo/539 Bcf Roosevelt Blacktail Ridge South Altamont

Lake Canyon

• 1P reserves up 315% to 29 MMBoe • 3P reserves up 244% to 131 MMBoe • 3P gross locations increased to 1,688 10 Miles

•

2012: double our activity (67 gross operated wells): • Blacktail Ridge – Lake Canyon: 41 verticals, 9 horizontals • East Bluebell – South Altamont: 17 verticals •

Monument Butte Cum: 72 MMBo /244 Bcf

BBG Acreage BBG Rig

East Bluebell

Natural Buttes Cum: 2.3 Tcf /18 MMBo

Gas Production Oil Production Peer Operated Oil Rigs (NFX, EP, BRY, UTE, Axia)

One well: 1,300 Boe/d peak rate, 650 Boe/d avg IP

18

Uinta Oil Program: Executing Horizontal & Vertical Programs Combining horizontal and vertical programs to increase recoveries • 7 Successful Uteland Butte Hz wells 2011: • • • • •

24 hr. peak rate average: ~900 Boe/d 30-day average: ~500 Boe/d Laterals 3,100’-3,400’ with 15 frac stages On track with expected results Commence delineation 2H12: 6 wells

Wasatch, Green River Formations Blacktail Ridge

15-10-36 BTR 602 MBOE EUR

Infill Strategy

13-26-36 BTR 1,100 MBOE EUR

N

1-9-45 BTR 546MBOE EUR

14-7-46 BTR

1,046 MBOE EUR

• Testing additional horizontal zones: Wasatch and Black Shale

Lake Canyon Extension Strategy

Uteland Butte Horizontal pilot area 3,100’ laterals

• Vertical execution • • •

160 acre infill program = “Bread & Butter” 80 acre infill pilots approved Stepouts to West, South and Southwest encouraging

2 Miles

BBG Acreage

2012 Stepout Wells

Uteland Butte Wells

Drainage Elipses

Extension Strategy

19

DJ Basin: Driving Substantial Oil Growth Built sizable position since July 2011, 3 rigs operating •

Silo Field

Acreage focused on high oil-cut fairways • • • • •

•

74,820 net acre position, added 41,900 net acres in 2012 NE Wattenberg: 39,040 net acres (mostly contiguous) Wattenberg interior: 13,360 net acres Chalk Bluffs and Wyoming border region: 22,420 net acres Using latest in geologic, seismic, and operating technologies to build in Niobrara “sweet spots”

Chalk Bluffs Hereford Area

Northeast Wattenberg

Rapid production growth: 1,380 Boe/d •

Wattenberg Field

Increase of 75% since year-end

•

Proved reserves: 7 MMBoe

•

Encouraged by early well results • •

•

Niobrara Formation

NE Wattenberg well: 24 hour peak 798 Boe/d, 30-day IP avg: 517 Boe/d 2 Chalk Bluffs wells: 24 hour peak 905 Boe/d, 30-day IP avg: 437 Boe/d

2012: 33 gross/23 net horizontal Niobrara wells

50 miles

BBG Acreage

Core Wattenberg Development

Gas Production

Chalk Bluffs & Exploration

DJ Basin Oil Production

Northeast Wattenberg

20

DJ Basin: Northeast Wattenberg Strong and repeatable well results in the area •

Multiple 3rd party Niobrara horizontal producing wells in the area

•

Adjacent industry activity helpful in assessing our acreage

•

Northeast Wattenberg Upside: •

• • • • •

Increased density: 80-acre and 40-acre horizontal downspacing being tested throughout Wattenberg field ‘C’ Bench Niobrara potential Codell potential: peers report performance in lock step with Niobrara Extended laterals Pad drilling Improved drilling and completion techniques offer increased EURs

Niobrara Formation

Greeley

Wattenberg Field

6 miles

BBG Acreage

DJ Basin

Gas Production

Oil Production

Northeast Wattenberg

BBG Rig

Peer Operated Oil Rigs (NBL, BCEI, PETD)

21

EXPLORATION UPSIDE

Upside Oil Exposure: Exploration - All Oil, All Horizontal Strategically applying new technologies to “legacy plays” while building “new oil concepts” • Testing Exploratory Oil Upside: DJ and Uinta • PRB stacked oil play (64,000 net acres) •

•

S. Alberta Oil

Horizontal Shannon well • 24 hour peak rate: 523 Boe/d • 30-day average rate: 429 Boe/d • On pump: recent 600 Boe/d Drill/test: 1 Sussex & 2 Frontier wells by YE

PRB Oil

• S. Alberta Oil – Banff target (94,000 net acres) • •

3D seismic assessed Spud Banff-Bakken well 9/12

Uinta Oil

DJ Oil/NGLs

• San Juan Basin – Gallup target (36,000 net acres) • •

3D seismic complete Drill first well 4Q12

San Juan Oil

Key 2012 Oil Exploration Area

Oil Producing Area Gas Producing Area

23

Outlook: Realizing High Growth in Oil Positive operational and financial outlook moving forward •

Stand-alone growth visibility

•

Rapidly growing oil production

•

Operating discipline

•

Expansive upside potential

•

Strong realized pricing

•

Continued financial strength

24

APPENDIX

Quality Assets: Solid Reserve Replacement • 22% reserve growth (oil +135%) • 331% reserve replacement • $600 million increase in Pretax PV10 to $2.1B Net Bcfe

$1.5 Billion PV10

1,118

-107

98

6

2011 Production

Acquisitions

Price revisions

1,365

Engineering revisions and drilling additions 694

535 Proved Developed

48% YE 2010

Please see Disclosure slides.

PRICING

Proved Developed

$2.1 Billion PV10

250

2010 YE $3.95/MMBtu CIG & $75.96/Bbl WTI 2011 YE $3.93/MMBtu CIG & $92.71/Bbl WTI

51% YE 2011

26

Disciplined Cost Structure •

BBG Ranks # 7 among 40 E&Ps (BofAML)

•

Breakeven calculation includes: All-in costs*, adjustments for percentage PUDs and differential to NYMEX

All-in Breakeven Costs

$14

Breakeven ($/Mcfe)

$12

$10 $8

BBG: $5.24

Median breakeven: $6.97

$6 $4 $2 $0

Source:BofAML High Yield E&P 4/3/12 * All-in costs include operating costs, production taxes, G&A, interest expense and all-in F&D

27

Efficient Operations: Track Record of Cost Discipline Piceance (Gas & NGLs)

West Tavaputs (Gas)

Blacktail Ridge (Oil)

Reduced Drilling Days (Spud to rig release) 11

10

2007

2008

6

5

5

2009

2010

2011

10

23

9

Days

Days

9

2006

29

12

6

2006

2007

2008

2009

2010

25

Days

13

13

2011

2007

2008

2009

16

16

2010

2011

*Scale adjusted

Reduced Drilling Cost Per Foot

$113 $68

2007

2008

2009

$59

$63

2010

2011

$115

$106

Cost per Foot

Cost per Foot

$80

2006

$259

$130

$96

2006

2007

2008

2009

2010

$220 $97

2011

Cost per Foot

$131 $103

$152

2007

2008

2009

$135

$145

2010

2011

*Scale adjusted

28

Upside Exposure: Natural Gas Extensive portfolio of sizable, long-term natural gas projects • Extension plays offer multi-Tcf upside • Shale gas and basin centered gas prospects • Current extension plays • Cottonwood Gulch* • Hornfrog

West Tavaputs Mancos

Cottonwood Gulch Hornfrog

Yellow Jacket

BBG Gas Prospect

* Subject to outstanding litigation

29

Piceance Basin: Gibson Gulch Significant NGL Exposure

Williams Fork Formation

• High liquids content increases revenue (+$1.23/Mcf to company natural gas realized price in 2011)

Silt

N 3-Component 3-D Seismic

• Proved reserves: 596 Bcfe Gibson Gulch

• 3P Reserves: 733 Bcfe • Locations: 626 • Net production: 155 MMcfe/d (July 2012)

Mamm Creek

1 Mile

BBG Acreage

Gas/NGL Production

• 2012: no drilling activity Aug.-Dec.

30

Uinta Basin: West Tavaputs • Proved reserves: 461 Bcfe

Shallow – Wasatch, Mesaverde

• 3P reserves: 1,171 Bcfe

Questar Interconnect

• Locations: 622

Prickly Pear

• Net production: 111 MMcfe/d (July 2012)

Interplanetary Compressor Site

Questar Interconnect

Dry Canyon Compressor Site

Peter’s Point

• No drilling activity May-Dec.

Upside Potential: • Mancos/Niobrara Shale Gas

N

6 Miles

BBG Acreage Gas Production Pipeline

• Deep horizons

31

Typical Well Production Profiles Piceance Basin, Colorado

West Tavaputs, Uinta Basin, Utah

1.6

3.0

1.4 Grs MMcfd

Grs MMcfd

2.5 2.0 1.5 1.0

1.0 0.8 0.6 0.4

0.5

0.2

0.0

0.0 0

10

20

30

40

50

0

60

IP-Instantaneous: 2,840 Mcf/d IP-30 day: 2,131 Mcf/d EUR: 1.9 Bcfe Well Life: 42.6 years Spacing: 20 and 40-acre Well Depth avg: 7,650’ 12 Mos Cum Net Prod (MMcfe): 321 8 stage, gel fracs

10

20

30

40

50

60

Months

Months

• • • • • • • •

1.2

• • • • • • • •

IP-Instantaneous: 1,561 Mcf/d IP-30 day: 1,287 Mcf/d EUR: 0.8 Bcfe Well Life: 29 years Spacing: 10-acre Well Depth avg: 7,400’ 12 Mos Cum Net Prod (MMcfe): 175 8 stage, slickwater fracs

32

Typical Well Production Profiles: Uinta Basin, Utah Blacktail Ridge/Lake Canyon

Uteland Butte Core

350

1000

300 250 Grs BOPD

Grs BOPD

800 600 400 200

150 100 50

0

0 0

10

20

30

40

50

60

0

Months

• • • • • • • •

200

IP-Instantaneous: 800 Bbl/d IP-30 day: 388 Bbl/d EUR: 310 Mboe Well Life: 31 years Spacing: 160-acre TVD= 5,500’; MD= 8,300’ 12 Mos Cum Net Prod (MBoe): 52 15 stage, cross linked gel fracs

• • • • • • • •

10

20

30 Months

40

50

60

IP-Instantaneous: 295 Bbl/d IP-30 day: 253 Bbl/d EUR: 290 Mboe Well Life: 31 years Spacing: 160-acre Well Depth avg: 9,000’ 12 Mos Cum Net Prod (MBoe): 45 9 stage, cross linked gel fracs

33

Uinta Oil Program: Significant Upside Billions of barrels of oil yet to be tapped • Seek to increase historical recoveries of 4-6%

We are dealing with a true hydrocarbon storehouse!

• Vertical drilling:

• •

160 acre infill established 80 acre pilots are next!

• Horizontal drilling:

Green River

• Needed to produce oil from stacked, discontinuous zones over 3-4,000’ • Increased density key to maximizing recovery:

Carbonate

• Latest frac technology: Used to maximize producibility and EUR of all zones

Wasatch

• Needed to maximize oil recovery from continuous, fractured, organic rich zones • Blacktail Ridge-Lake Canyon: Uteland Butte, Wasatch, Black Shale, Mahogany • East Bluebell: assessing multiple zones • Uteland Butte is the only horizontal zone to date

Conclusion: 3P estimates do not include this upside and may be conservative

34

Uinta Oil: 2011: Horizontal Uteland Butte Summary 24 hr. peak rate

30-day avg

Well

WI / NRI

TVD of UB

Lateral Length

# of Stgs

First prod

(Bbl/d)

(Mcf/d)

(Boe/d)

(Bbl/d)

(Mcf/d)

(Boe/d)

LC Tribal 13H-20-46

56.25% / 45.7%

4,750’

3,120’

15

5/24/11

1,022

1,876

1,335

**533

1,116

719

LC Fee 12H-32-46

54.43% / 44.2%

4,700’

3,380’

15

6/23/11

630

694

745

*292

*203

*326

LC Fee 12H-28-46

56.25% / 45.7%

5,850’

3,382’

15

9/24/11

1,226

645

1,334

602

627

707

LC Fee 13H-21-46

56.25% / 45.7%

5,875’

3,222’

15

10/10/11

738

747

863

**422

701

539

BTR 13H-13-46

50% / 40.63%

6,100’

3,220’

15

11/10/11

805

687

919

**481

579

578

LC Tribal 13H-33-46

75% / 61%

5,830’

3,600’

15

11/27/11

475

182

506

221

63

232

LC Tribal 1H-27-46

56.25% / 45.7%

5,850’

3,127’

15

12/26/11

595

166

623

297

269

342

*For 12H-32-46, 30 day average is an approximation average of the first 30 days of production which is not the first 30 consecutive days. (fishing/mechanical issues) **For 13H-20-46, 13H-21-46 and 13H-13-46, wells were flowing the entire time for the 30 day average. Remaining wells needed artificial lift.

35

Uinta Oil Program: Marketing Refining capacity in basin is increasing; confident we can sell our growing production • Current agreement • 7,500 Bbl/d through 2018 • Typical 16% price deduct from WTI • Oil refined in Salt Lake City

• Salt Lake City Refining • 5 refineries have an estimated 173,000 Bbl/d total capacity; approximately 52,000 Bbl/d wax capacity • New Holly Frontier refined products pipeline to Las Vegas

• Increased capacity alternatives • Additional wax expansion at existing refineries • Proposed upgrader with 44,000 Bbl/d initial wax crude processing capacity • Rail expansion

• Currently negotiating with multiple parties to secure additional long-term capacity

36

Credit Ratios - History EBITDAX to Interest

Total Debt to Proved Reserves1 ($/Mcfe)

28.0x

$0.65

21.2x

$0.49

$0.52 $0.44

16.0x

$0.38 11.1x 8.9x

2007

2008

2009

2010

2011

Total Debt to Book Capitalization

2007

2008

2009

2010

Total Debt to EBITDAX (TTM) 43%

32%

30%

26%

2007 1

2008

Please see Disclosure slides.

2009

28%

2010

2011

1.7x

1.0x

2011

2007

1.0x

2008

0.9x

0.9x

2009

2010

2011

37

Debt Structure Offers Substantial Liquidity Position • Senior (secured) revolving credit facility • • •

$900 million borrowing base and commitments, reaffirmed October 2012 $75 million outstanding June 30, 2012 ($26 million letter of credit outstanding) Matures October 2016

• 5% convertible note due 2028 • • • •

Next put date March 2015 Continuously callable $25.3 million outstanding Trading at ~98.50

• 9 7/8% senior notes due 2016 ($250 million) • •

Issued July 2009 (First call July 2013) Trading at ~110

• 7 5/8% senior notes due 2019 ($400 million) • •

Issued September 2011 Trading at ~105

• 7% senior notes due 2022 ($400 million) • •

Issued March 2012 Trading at ~102.75

• Sale Leaseback of Compression Assets • •

Completing $106 million lease financing arrangement of BBG owned facilities at 3.5% Early Buyout Option of 36% in 2019.

Note: All senior notes are unsecured and guaranteed by subsidiaries

38

Natural Gas and Oil Hedges: Equivalents As of September 14, 2012 Swaps & Collars Period

Natural Gas / NGLs

Oil

Equivalent

Volume (MMBtu/d)

Price ($MMBtu)

Volume (Bbl/d)

Price ($/Bbl)

Volume (MMcfe)

Price ($/Mcfe)

3Q12

233,520

$4.44

5,300

$101.02

22,456

$6.44

4Q12

204,730

$4.65

6,500

$100.37

20,711

$7.13

1Q13

173,877

$3.95

6,500

$98.57

17,736

$6.74

2Q13

128,835

$4.10

6,500

$98.57

14,207

$7.48

3Q13

128,793

$4.09

6,500

$98.57

14,360

$7.48

4Q13

115,532

$4.16

6,500

$98.57

13,251

$7.78

1Q14

65,000

$3.81

2,700

$96.77

6,776

$6.76

2Q14

65,000

$3.81

2,700

$96.77

6,851

$6.76

3Q14

65,000

$3.81

2,700

$96.77

6,927

$6.76

4Q14

65,000

$3.81

2,700

$96.77

6,927

$6.76

Notes: As of September 14, 2012. Average floor/swap price is for illustrative purposes only and does not represent formal guidance. Excludes 2012 CIG/NWPL basis only swaps that are out-of-the-money.

39

Additional Swap/Collar Data As of September 14, 2012 Oil

Natural Gas Period

Swaps

Period

Basis

Volume (BBl/d)

Floor ($/Bbl)

Ceiling ($/Bbl)

3Q12

4,900

$101.72

400

$92.50

$131.30

4Q12

6,100

$100.89

400

$92.50

$131.30

-

1Q13

6,500

$98.57

-

-

-

-

2Q13

6,500

$98.57

-

-

-

6,500

$98.57

-

-

-

Price ($/MMBtu)

Volume (BBtu/d)

Price ($/MMBtu)

3Q12

223.9

$3.90

20.0

$(1.22)

4Q12

194.5

$3.99

20.0

$(1.22)

2Q13

170.0 125.0

$3.65

-

$3.69

-

Collars

Price ($/Bbl)

Volume (BBtu/d)

1Q13

Swaps Volume (BBl/d)

3Q13

125.0

$3.69

-

-

3Q13

4Q13

111.7

$3.72

-

-

4Q13

6,500

$98.57

-

-

-

1Q14

65.0

$3.81

-

-

1Q14

2,700

$96.77

-

-

-

2Q14

65.0

$3.81

-

-

2Q14

2,700

$96.77

-

-

-

-

3Q14

2,700

$96.77

-

-

-

-

4Q14

2,700

$96.77

-

-

-

3Q14

4Q14

65.0

65.0

$3.81

-

$3.81

-

NGL Period

Swaps Volume (MMBtu/d)

Price ($/MMBtu)

3Q12

9,606

$16.96

4Q12

10,274

$17.05

1Q13

3,877

$17.21

2Q13

3,835

$17.21

3Q13

3,793

$17.21

4Q13

3,793

$17.21

No NGL hedges in place for 2014 Notes: As of September 14, 2012. Average floor/swap price is for illustrative purposes only and does not represent formal guidance.

40

Land Summary As of June 30, 2012 Gross Acreage

Net Undeveloped Acreage

Average Gross Project NRI

Average BBG Working Interest

17,764 40,041

5,610 19,260

81% 83%

96% 97%

Uinta Basin – Uinta Oil Program Blacktail Ridge/Lake Canyon Minimum to be earned East Bluebell & Other Total Uinta Oil Program

120,245 144,560 86,475 351,280

28,865 57,330 36,290 122,485

82% 82% 83%

51% 51% 60%-65%

DJ Basin – Wattenberg Core Powder River – CBM

17,445 162,300

2,0252 44,7303

84% 82%

97%-100% 60%-75%

40,312 30,590 69,250

36,281 16,120 35,0454

88% 85%

90% 55%

DJ – Chalk Bluffs and other DJ – Sage Brush Paradox Basin – Yellow Jacket

32,540 81,426 441,160

17,145 35,695 339,950

83% 83%

Varies 44% 100%

Powder River Basin – Deep

144,425

52,8403

80%

10%-65%

Wind River Basin – McRae Gap1 Alberta Basin San Juan Basin (including to be earned) Other

109,345 151,165 96,395 687,120

90,025 94,240 36,500 511,020

83% 83% 78%-81% Varies

75% 55% 50% Varies

Area Development Properties Piceance – Gibson Gulch Uinta – West Tavaputs

Extension Properties Piceance Basin – Cottonwood Gulch Uinta Basin – Hornfrog (including to-be-earned) DJ Basin – Northeast Wattenberg

Exploration Properties

Note: Ownership interest include to-be-drilled locations and should be considered estimates as interests vary over time. 1 Acreage and working interest associated with the McRae Gap prospect is before deducting a potential 25% earn-in from a third party. 2 Net acreage is 13,360 acres where the Company will be actively drilling. 3 BBC owns acreage that is considered both CBM & Deep. 65,970 gross acres and 20,900 net undeveloped acres are counted in both categories. 4 Includes 55,640 gross acres and 30,300 net undeveloped acres acquired subsequent to quarter end.

41

Forward-Looking & Other Cautionary Statements Reserve figures are presented as of year-end 2011. Current production is July 2012. FORWARD-LOOKING STATEMENTS – These slides contain forward-looking statements, including statements regarding projected results and future events. In particular, the Company is providing “2012 Guidance,” which contains projections for certain 2012 operational and financial results, as well as planned drilling activity. These forwardlooking statements are based on management’s judgment as of the date of this presentation and include certain risks and uncertainties. Please refer to the Company’s Annual Report on Form 10-K for the year-ended December 31, 2011 filed with the Securities and Exchange Commission (“SEC”), and subsequent filings including our Current Reports on Form 8-K and Quarterly Reports on Form 10-Q, for a list of certain risk factors. Actual results may differ materially from Company projections and can be affected by a variety of factors outside the control of the Company including, among other things, oil, NGL and natural gas price volatility, the ability to receive drilling and other permits and rights-of-way, regulatory approvals, economic and competitive conditions, legislative or regulatory changes including initiatives related to hydraulic fracturing, derivative and hedging activities, declines in the values of our oil and gas properties resulting in impairments, changes in estimates of proved reserves, higher than expected costs and expenses, exploration and development drilling and testing results, compliance with environmental and other regulations, costs and availability of third party facilities for gathering, processing, refining and transportation, performance of acquired properties, the availability and cost of services and materials, 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, availability and costs of financing to fund the Company’s operations, unexpected future capital expenditures, 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 SEC. Bill Barrett Corporation encourages readers to consider the risks and uncertainties associated with projections and other forward-looking statements. In addition, the Company assumes no obligation to publicly revise or update any forwardlooking statements based on future events or circumstances. Calculation of Natural Gas Liquids as a Percent of Sales Volumes The Company’s natural gas production is based on wellhead volumes and its natural gas revenue includes the incremental revenue benefit from third party purchasers and processors when the company elects to receive NGL values from certain volumes of natural gas. Many oil and gas producing companies report NGL volumes and revenues separately from natural gas volumes and revenues. In order to provide a metric that is comparable to other oil and gas production companies, the Company is providing the percentage of total Company sales volumes by product including oil, natural gas and NGL revenues received from our gas purchasers or processors. The NGL volumes identified by our gas purchasers or processors are converted to an oil equivalent based on 42 gallons per barrel and compared to overall gas equivalent production based on a 1 barrel to 6 Mcf ratio.

42

Forward-Looking & Other Cautionary Statements Non-GAAP MEASURES: DISCRETIONARY CASH FLOW - is a non-GAAP financial measure. It is presented because management believes it provides useful additional information to investors for analysis of the Company’s ability to internally generate funds for exploration, development and acquisitions as well as adjusting net income for unusual items to allow for a more consistent comparison from period to period. In addition, these measures are 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. Historical discretionary cash flow is reconciled to net income each quarter in the Company’s quarterly press release of results of operations.

EBITDAX - is a non-GAAP financial measure. It is presented because management believes that it is useful to an investor for evaluating the Company’s operating performance. This is a widely used measure by investors in the oil and gas industry to measure a company’s operating performance without regard to items excluded from the calculation of such term, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired, among other factors. There are significant limitations to using EBITDAX as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect net income or loss, the lack of comparability of results of operations of different companies and the different methods of calculating EBITDAX reported by different companies. The Company’s calculation of EBITDAX is discretionary cash flow plus cash interest expense and cash tax expense added back. FINDING AND DEVELOPMENT COST – Finding and 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 Current Report on Form 8-K issued February 23, 2012.

RESERVE DISCLOSURE -The SEC, under its recently revised guidelines, permits oil and gas companies to disclose probable and possible reserves in their filings with the SEC. The Company does not plan to include probable and possible reserve estimates in its filings with the SEC. The Company has provided internally generated estimates for probable and possible reserves in this presentation. The estimates conform to SEC guidelines. They are not prepared or reviewed by third party engineers. Our probable and possible reserve estimates are determined using strip pricing, which we use internally for planning and budgeting purposes. The Company’s estimate of probable and possible reserves is 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. U.S. investors are urged to consider closely the disclosure in our Annual Report on Form 10-K for the year ended December 31, 2011, available on the Company’s website at www.billbarrettcorp.com or from the corporate offices at 1099 18th Street, Suite 2300, Denver, CO 80202. You can also obtain this form from the SEC by calling 1-800-SEC-0330 or at www.sec.gov. RESOURCE POTENTIAL - In this presentation the Company may refer to "Resource Potential“ and “Unrisked Upside,” which refer to proved, probable and possible reserves as well as theoretical resource volumes that are estimates, speculative in nature and have not been reviewed by independent engineers. Theoretical resource volumes might never be recoverable and are contingent on exploration success, technical improvements, permitting, commerciality and other factors. This presentation does not constitute an offer, solicitation, or recommendation to buy or sell Bill Barrett Corporation securities. The information herein is provided for informational purposes only. The information is current as of the dates indicated, but may become outdated or subsequently may change. Nothing herein constitutes financial, legal, tax, or other advice.

43

1099 Eighteenth Street, Suite 2300

Investor Relations:

Denver, Colorado 80202

Jennifer Martin, Vice President

303.293.9100

303.312.8155

www.billbarrettcorp.com

[email protected]