Forward-Looking & Other Cautionary Statements

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

3

Company Overview



$2.2 billion enterprise value

–

$1.2 billion market cap



Proved reserves: 197 MMBoe

–

42% oil; 42% proved developed



Total risked resources: 587 MMBoe



Long-term drilling inventory with 5,400

gross oil and gas locations



1Q14 production 27 MBoe/d:

–

38% oil

–

18% NGLs

–

44% gas



2014 activity focused in two core oil

development programs



Focus the portfolio on a few core assets



Invest in assets and people that will deliver competitive returns on capital and provide

sustainable growth in cash flow



Instill a culture that fosters optimization, creativity, efficiency and innovation



Build core positions in basins having manageable regulatory/infrastructure frameworks



Systematically divest non-core and/or mature assets through competitive processes



Maintain financial discipline with moderate debt leverage and ample liquidity



Uphold high standards for health, safety and environment

Build a sustainable oil and gas resource development business with an asset

portfolio that offers enough concentration, scale and optionality to realize high

operational efficiency, provide competitive growth, ensure financial stability and

generate superior returns for investors

5



Achieved commodity balance



Drove substantial growth in oil reserves and oil production



Reduced debt by $189 million



Executed at Northeast Wattenberg



Executed at Uinta Oil Program



Realized strong results at Powder Deep Oil Program



Increased operating margins

Delivered on key 2013 objectives

Driving Transformation

42%

40%

18%

2013 Proved Reserves

Oil Production (MMBbls)

Oil

Gas

NGL

Oil Focus Delivers High Production and Cash Flow Growth

0.0

4.0

8.0

2011

2012

2013

2014e

Oil Program Production (MMBoe)

DJ Basin

Uinta Oil Program

Powder Deep Oil

$0

$200

2011

2012

2013

2014e

mi

ll

ions

Oil Program Operating Cash Flow

DJ Basin

Uinta Oil Program

Powder Deep Oil



Strong oil production growth driven by successful DJ Basin operations



Strong cash flow growth from core programs

7

Low-risk, Long-term Growth Profile

Proved

MMBoe

Proved +

Risked

Resources

MMBoe

Gross/Net

Drilling

Locations

66

221

1,697/844

53

171

1,795/785

73

100

528/416

5

95

1,370/284

TOTAL

197

587

5,390/2,329

% OIL

42%

55%



88% growth in proved reserves at three active oil programs



80% growth in risked resources at three active oil programs



~$350 million increase in Pretax PV10



$8.30/Boe 2013 F&D cost

Gibson Gulch, Piceance (NGLs) Denver Julesburg1 (oil/NGLs) Uinta Oil2 Program (oil) Powder River Deep3 _(oil) Proved

Total Risked Resources (2013)

MMBoe

1_{DJ:Risked resources includes between 8-20 wells per section; majority based on standard length laterals} 2 _{Blacktail Ridge-Lake Canyon and East Bluebell: Predominantly 160-acre spacing}

3_{Includes both 4,000 and 9,000 foot laterals and drilling locations spread over six different formations}

Note: $3.67 per MMBtu HH and $96.91 per barrel WTI pricing used in reserve calculations

Financial Strength and Flexibility

Successfully transitioning to oil-focused portfolio while reducing debt



Year-end 2013 long-term debt reduced by $189 million to $984 million



Portfolio management focuses operations and provides funding for core assets

–

2013: Successful sale of West Tavaputs asset for $369 million, proceeds used to pay down debt

–

2014: Powder Deep Oil Program potential sale



Borrowing base of $625 million (re-affirmed Spring 2014) with $419 million of liquidity



Growing proportion of revenue from liquids, positions company for increasing margins and

strong EBITDAX growth

–

70+% 1Q14 revenue from liquids



Hedge on a 12-month forward basis to reduce risk and support capital expenditure

program

–

2014 (2Q-YE): 6.0 MMBoe; Oil: 10,071 bbls/d at $94.03/bbl; natural gas: 67,218 MMBtu/d at

$3.97/MMBtu

9



Capitalize on commodity balance by allocating capital to highest return assets and

achieving increased profit margins



Deliver unrealized value from 75,500 net acres in DJ Basin oil development

–

Strengthen returns through use of extended reach laterals

–

Demonstrate upside with development of additional zones and increased well density

–

Improve operational efficiency with optimized artificial lift and infrastructure

–

Test Chalk Bluffs



Demonstrate value in 21,500 net acres in eastern Uinta Basin oil development

–

Move into development mode at East Bluebell

–

Continue to test increased well density

–

Drive development costs lower, moving from appraisal to development stage



Divest non-core assets beginning with Powder Deep Oil



Position company for continued competitive growth and returns

2014 Objectives



Total capital of $500-550

million

–

Finance through discretionary cash

flow, asset sales and credit facility



Capex allocation

–

75% DJ Basin

–

15-20% Uinta Oil Program

–

5-10% Powder River Deep Program



Total Production of 11.0-12.2 MMBoe

–

30% YOY growth in oil production

–

190 gross/100 net wells

–

Average 5 rig operated program

Capital program 100% directed at oil growth

2014 Guidance

2014 Capex % by Area

Uinta Oil

DJ Basin

Powder

River Deep

Program

DJ Basin: Lots of Running Room

Niobrara and Codell Formations



Northeast Wattenberg: 40,200 net acres



Wattenberg interior: 13,170 net acres



Chalk Bluffs: 22,120 net acres



Target Niobrara and Codell formations with

horizontal drilling

Prime land position: ~75,500 net acres

Driving rapid growth



Proved reserves up more than 350% to 66

MMBoe



Production rapidly increasing: 6,430 Boe/d

(1Q14)



25% increase from 4Q13



137% increase from 1Q13



2014 plan: ~75% of capital program to drill or

participate in ~120 gross/72 net wells

BBG Acreage

13

1,565

6,430

0

2,000

4,000

6,000

8,000

3Q12

4Q12

1Q13

2Q13

3Q13

4Q13

1Q14

Bo

e

/d

DJ Basin Net Production and Gross Operated

Horizontal Wells Spud

DJ Basin: Production Growth

Driving continued growth

13

7

2

11

21

27

Operated

2013 Appraisal program tests multiple concepts

Northeast Wattenberg Well Results



Delineated and proved 70% of acreage



Tested Niobrara B, Niobrara C and Codell



Experimented with multiple drilling and completion

techniques



Varied artificial lift techniques based on availability of

infrastructure and GORs

Northern

Block

Southern Block

Western

Block

2013-1Q14 Wells Spud and Average* 30-day Rates by Area and Target Zone (Boe/d)

Northern Block

Southern Block

Western Block

Total

Average 30-day IP

Average 30-day IP

Average 30-day IP

Average 30-day IP

Nio. B

366

455

688

412

Nio. C

303

364

672

503

Codell

-

-

442

442

Total

364

448

561

426

*45 wells included in the average.

BBG Acreage

6 Miles Newly Reported Wells 2Q14 XRL Locations

15

DJ Basin Undeveloped Location Inventory

130

349

228

43

94

844 Net Undeveloped Locations

Core Wattenberg

NE Wattenberg (North)

NE Wattenberg (South)

NE Wattenberg

(Western)

Chalk Bluffs

Total Gross: 1,697

Long-term inventory

Northeast Wattenberg: ~70% Delineated Based on Proved Reserves

Western Block:

Net Acreage

2,000

Delineated*

100%

Proved Reserves (MMBoe) 5.0

Risked Resources (MMBoe): 10.1

Undrilled Locations

(gross/net):

110/43

Northern Block:

Net Acreage

17,700

% Delineated*

95%

Proved Reserves (MMBoe) 39.1

Risked Resources (MMBoe): 73.7

Undrilled Locations

(gross/net):

518/349

Southern Block:

Net Acreage

20,500

% Delineated*

39%

Proved Reserves (MMBoe) 16.9

Risked resources (MMBoe): 62.9

Undrilled Locations

(gross/net):

655/228

*Percent delineated based on 2013 year-end proved reserves

Northern Block

Southern Block

Western Block

BBG Acreage

17

DJ Basin – Illustrative Economics

Illustrative Economics:

EUR (MBoe, Gross)

337

Total D&C Capital ($MM)

$4.2

Rate of Return

47%

WTI for 10% ROR

$49.50

1

_{year decline}

_72%

Terminal decline

7%

Nominal Horizontal Length

4,000’

Illustrative

Economics

:

EUR (MBoe, Gross)

450

Total D&C Capital ($MM)

$4.2

Rate of Return

53%

WTI for 10% ROR

$40.30

1

_{year decline}

_70%

Terminal decline

7%

Nominal Horizontal Length

4,000’

Illustrative Economics

:

EUR (MBoe, Gross)

883

Total D&C Capital ($MM)

$7.8

Rate of Return

79%

WTI for 10% ROR

$36.25

1

_{year decline}

_57%

Terminal decline

7%

Nominal Horizontal Length

9,000’

* Assumes: WTI $90/Bbl; HH natural gas $4.50/MMBtu; NGL 37% WTI; -$10/Bbl oil price differential; Adjusts for commodity mix; Gas and NGL realized prices also reduced for gathering / processing costs. Illustrative economics are based on drilling results to date and assumptions for the 2014 drilling program and may differ from data used in assessing year-end 2013 proved reserves.

Illustrative Margin Analysis ($/Boe)

Realized price per Boe*

$56.03

LOE

$ 7.77

Production Taxes

$ 4.26

Cash Margin

$44.00

EUR Oil: 36%; Gas: 40%; NGL: 24%

EUR Oil: 56%; Gas: 28%; NGL: 16%

EUR Oil: 56%; Gas: 28%; NGL: 16%

Illustrative Margin Analysis ($/Boe)

Realized price per Boe*

$45.19

LOE

$ 5.93

Production Taxes

$ 3.36

Cash Margin

$35.90

Illustrative Margin Analysis ($/Boe)

Realized price per Boe*

$56.03

LOE

$ 5.07

Production Taxes

$ 4.17



Exploit 75,500 acre position



85 gross/65 net operated wells



Participation in 35 gross/7-8 net

non-operated wells



Drilling program focused on Northeast

Wattenberg



Primarily multi-well pad drilling



Multiple extended reach laterals



Test 40-acre downspacing



Chalk Bluffs

2014 Plan: Drives Estimated 40% Rate of Return

DJ Basin: 2014 Activity

Niobrara and Codell Formations

Upside

BBG Acreage

Uinta Oil Program

BBG Acreage Gas Production Oil Production

10 Miles

Wasatch, Green River Formations



East Bluebell: 21,550 net acres



Blacktail Ridge/Lake Canyon:

108,050* net acres



South Altamont: 22,320 net

acres

Large, Scalable Program: ~150,000 net acres



Proved reserves up 10% to 53

MMBoe



Production: 5,760 Boe/d (1Q14)



2014 plan: ~15-20% of capital plan

with ~44 gross/26 net operated wells



2Q14 added 4,500 Bbl/d firm

marketing agreement

Driving Rapid Growth

BBG Acreage

10 Miles

21

UOP: Undeveloped Location Inventory

92

37

42

Risked Resources (171 MMBoe)

Blacktail Ridge/Lake Canyon

East Bluebell

South Altamont

524

137

124

785 Net Drilling Locations

Blacktail Ridge/Lake Canyon

East Bluebell

South Altamont

(Gross 1,795)



Predominantly 160-acre spacing

UOP: East Bluebell Execution



35,750 gross/21,550 net acres



Early delineation phase: 20 wells drilled and

completed in 2013



Returns on drilling capital ~60%



Vertical wells targeting Lower Green River

formation



Planned development on 80-acre spacing with

further downspacing potential

East Bluebell Program Offers Substantial Upside

Lower Green River

6 Miles

0

2,000

4,000

1H12

2H12

1H13

2H13

East Bluebell Production (Boe/d)

BBG Acreage

2014 Plans: Capture Value at East Bluebell



34 gross/20 net wells in 2014 plan



Production: 2,390 Boe/d (1Q14)



Build out infrastructure

23

UOP: East Bluebell Wells Exceeding Type Curve

BBG Acreage

6 Miles

2013 East 2014 Plan 2013 West

•

2013 West wells tracking >250 MBoe EUR

type curve

•

2014 wells to-date exceeding type curve

•

2014 D & C costs down 20% v 2013

•

Expanding 2014 program

(Boe/d)

30-day IP

60-day IP

90-day IP

2013 West

209

195

189

2014 West

217

-

-

2013 East

136

147

150

IP Rates to-date:

East Bluebell Economics

Illustrative Economics:

EUR (MBoe, Gross)

212

Total D&C Capital ($MM)

$2.5

Rate of Return

60%

WTI for 10% ROR

$52.50

1

_{year decline}

_60%

Terminal decline

7%

Vertical Well Depth

9,000’

Oil: 97%; Gas 3%; NGL: <1%

Illustrative Margin Analysis ($/Boe)

Realized Price per Boe

$71.52

LOE

$10.50

Production Taxes

$ 4.67

Operating Margin

$56.35



161,160 gross / 67,980 net acres



Production: 1,330 Boe/d (1Q14)



Multiple oil plays show good results in

Shannon, Sussex, Frontier, Turner,

Parkman



Marketing advisor engaged to assist

with asset sale



Continue building development

inventory and participate in

non-operated drilling throughout sale

process

Stacked oil play providing positive results, but not part of long-term future

Powder Deep Oil Program

BBG Acreage

27



Capitalize on commodity balance by allocating capital to highest return assets and

achieving increased profit margins



Deliver unrealized value from 75,500 net acres in DJ Basin oil development



Demonstrate value in 21,500 net acres in eastern Uinta Basin oil development



Divest non-core assets beginning with Powder Deep Oil



Position company for continued competitive growth and returns



Maintain financial discipline with moderate debt leverage and ample liquidity



Uphold high standards for health, safety and environment

Execution, Execution, Execution

29

Hedging Provides Price Predictability



2014 hedges (2Q-YE):

–

2.8 MMBbls oil hedged at $94.03/bbl

–

17.5 Bcf gas hedged at $4.19/Mcf



Opportunistically add to positions over time

$0 $20 $40 $60 $80 0.0 0.5 1.0 1.5 2.0 2.5 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15 Pric e ($ /Boe ) Vol um e ( M M Boe ) Volume (MMBoe) Price ($/Boe)

Notes: As of April 25, 2014. Average swap price is for illustrative purposes only and does not represent formal guidance.

As of April 25, 2014

Natural Gas and Oil Hedges

*NGL volumes include propane, butanes and natural gasoline. No ethane volumes are hedged.

Swaps

Period

Oil

Natural Gas

NGLs*

Volume

(Bbls/d)

WTI Price

($/Bbl)

Volume

(MMBtu/d)

NWPL Price

($MMBtu)

Volume

Bbls/d

Price

($/Bbl)

1Q14

9,000

$94.27

65,000

$4.02

866

$54.84

2Q14

9,000

$94.27

65,000

$4.02

988

$58.61

3Q14

10,600

$93.98

65,000

$4.02

1,029

$60.18

4Q14

10,600

$93.88

71,630

$3.89

1,029

$60.18

1Q15

10,800

$90.07

20,000

$4.13

-

-

2Q15

10,300

$89.97

20,000

$4.13

-

-

3Q15

8,800

$88.87

20,000

$4.13

-

-

4Q15

8,800

$88.87

20,000

$4.13

-

-

31

Debt Instruments

($ in millions)

As of

3/31/2014

Revolving Credit Facility due 2016

$180

Borrowing Base

$625

5.000% Convertible Notes due 2028 (March 2015 Put) (currently callable)

25

7.625% Senior Notes due 2019 (callable 10/15)

400

7.000% Senior Notes due 2022 (callable 10/17)

400

Lease Financing Obligation

42

DJ Basin Infrastructure



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



Current gas processing capacity ~1.1 Bcf/d



Front Range Pipeline brings access to Mt. Belvieu market

Capacity Expansion Projects

Capacity

(MBbls/d)

Timing

Pony Express Pipeline

230

3Q14

White Cliffs Expansion

75

3Q14

Pony Express DJ Lateral

90

1Q15

Capacity Expansion Projects (MMcf/d)

2014

Additions

2015

Additions

Anadarko

300

300

DCP Midstream

100

170

NGL Pipelines Additions

Capacity (MBbls/d)

Timing

33

DJ Basin Infrastructure – Expected Capacities

Pony Express Conversion

3Q14: 230-320mbbls/d

Pony Express NE CO Lateral

1Q15: 90mbbls/d

White Cliffs Pipeline

1H14: 150mbbls/d

Plains Rail Facility:

4Q13: 68mbbls/d

Cheyenne Crude

Terminal 52mbbls/d

Suncor Refinery:

96MBbls/d

Uinta Oil Program

Operator

Current Black/Yellow

Capacity (MBbls/d)

Black/Yellow Capacity

Expansions (MBbls/d)

Chevron

15,000

~5,000

Tesoro

15,000-20,000

~20,000

Holly Frontier

10,000

14,000

Big West

~15,000

-

Silver Eagle

12,000

-

Total

65,000+

~40,000

35

Colorado Hydraulic Fracturing Initiative



12 ballot initiatives have been introduced that would empower local governments to regulate or

ban oil and gas activities, or that would increase setbacks statewide to as much as one-half

mile. One initiative would prohibit distribution of severance taxes to local governments that ban

oil and gas development.



86,000 signatures must be obtained prior to August 2014; language of several ballot initiatives

are being challenged



Coloradans for Responsible Energy Development (CRED)

–

Raising awareness and understanding of hydraulic fracturing through educational paid media (tv,

radio, print), grass roots movements, etc.



Industry is already engaged in campaign to defeat ballot initiatives in 2014 election.

Industry Approach



Oil and gas production contributes almost $30 billion a year to the Colorado economy and

supports more than 110,000 jobs.



Property taxes paid by the industry pays the salaries of ~20% of all teachers. Severance taxes

address local needs and fund water projects.



90%+ of all wells in Colorado are hydraulically fractured



Hydraulic fracturing in Colorado accounts for less than one tenth of one percent of the entire

state’s water usage



Quinnipiac University Poll (11/19/13): Colorado voters support hydraulic fracturing 51%-34%

Industry Facts

10 miles

Niobrara Formation

BBG Acreage



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/Rohn

NBL

Loeffler Pad

37

Uinta Basin: Well Positioned Among Peers

BBG Acreage

10 Miles

Wasatch, Green River Formations

UPL

LINN

NFX

CPG

EP

DVN

NFX

CPG

QEP

DJ Basin Niobrara Acreage Quality



“B” bench of the Niobrara is the primary target and is present in and surrounding BBG

leasehold



“B” bench appears to have good hydrocarbon saturation across all acreage with

additional accumulation in the “C”, “A” and Codell benches



There is no significant difference in depositional character of the “B” across BBG

acreage

A

A’

A

B2

C

Codell

39

Solid, Low-Cost Reserve Replacement



~$350 million increase in Pretax PV10



$8.30/Boe 2013 F&D cost



400% production replacement



65% proved oil reserve growth

116

2013

Production

PRICING

2012 YE $2.76/MMBtu HH & $91.21/Bbl WTI

2013 YE $3.67/MMBtu HH & $96.91/Bbl WTI

Reserve

Additions and

Revisions

Dispositions

195.0

57.0

197.0

-40.5

-14.5

83

Net MMBoe



Total capital expenditures of $500 - $550 million



Production: 11.0-12.2 MMBoe



$62 - $67 million lease operating expense



$43 - $48 million gathering, processing and transportation expense



$48 - $52 million general and administrative expense before non-cash

stock-based compensation

Profitable growth from core oil programs and maintaining capital discipline

41

Land Summary

Area

Gross Acreage

Net Acreage

Average Gross Project

NRI

Average BBG Working

Interest

Active Oil Properties

Uinta Basin – Uinta Oil Program

Blacktail Ridge/Lake Canyon 126,105 56,675 82% 51%

Minimum to be earned 124,625 51,380 82% 51%

East Bluebell 35,750 21,555 83% 70%

Other 41,165 22,320 80-100% 70-90%

Total Uinta Oil Program

DJ Basin

Northeast Wattenberg 67,440 40,180 81% Varies

Wattenberg Core 17,095 13,170 84% 97%-100%

Chalk Bluffs 39,220 22,120 83% Varies

Other 5,580 3,990

Total DJ Basin Program

Powder Deep Oil Program 161,160 67,980 80% 10%-65%

Core Natural Gas Properties

Piceance – Gibson Gulch 17,725 12,150 81% 96%

Exploration & Other Properties

Piceance Basin – Cottonwood Gulch1 _{40,310 36,280 88% 90%}

Paradox Basin – Yellow Jacket 297,280 215,875 83% 100%

Uinta Basin (Hornfrong, including to-be-earned)

DJ Basin – Sage Brush 40,270 16,375 83% 44%

Alberta Basin 86,990 58,935 83% 55%

San Juan Basin 5,855 3,875 78%-81% 50%

Other 281,470 204,000 Varies Varies

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

1 _{Subject to litigation}

.

Forward-Looking & Other Cautionary Statements

Reserve figures are presented as of December 31, 2013.

FORWARD-LOOKING STATEMENTS:

This presentation contains forward-looking statements. Forward-looking statements are dependent upon events, risks and uncertainties that may be outside the Company’s control. Our actual results could differ materially from those discussed in these forward-looking statements. In particular, the Company is confirming “2014 Operating Guidance,” which contains projections for certain 2014 operational and financial metrics. These and other forward-looking statements in this presentation, including well performance and sale of the Powder Deep Oil Program, are based on management’s judgment as of the date of this presentation and include certain risks and

uncertainties. Among a number of factors, operations plans are subject to change during the year and such changes can materially affect projected results provided in the Company’s guidance. Please refer to the Company’s Annual Report on Form 10-K for the year ended December 31, 2013 filed with the SEC, and other filings including our Current Reports on Form 8-K and Quarterly Reports on Form 10-Q, for a list of certain risk factors that may affect these forward-looking statements.

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, including regional price differentials; costs, availability and timing of build-out of third party facilities for gathering, processing, refining and transportation; the ability to receive drilling and other permits and rights-of-way in a timely manner; development drilling and testing results; the potential for production decline rates to be greater than expected; legislative or regulatory changes, including initiatives related to hydraulic fracturing; regulatory approvals, including regulatory 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 SEC. Bill Barrett

Corporation encourages readers 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.

NATURAL GAS LIQUIDS:

Effective January 1, 2013, the Company began reporting its production volumes on a three-stream basis, which separately reports NGLs extracted from the natural gas stream and sold as a distinct product.

2013 year-end reserves are presented on a three-stream basis, and year-end 2012 reserves are recalculated to reflect three-stream volumes for comparability. NGL volumes 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.

43

Forward-Looking & Other Cautionary Statements

NON-GAAP MEASURES:

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.

RESERVE and RESOURCE DISCLOSURE -The SEC permits oil and gas companies to disclose proved, 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.

We may use certain terms, such as “risked resources,” that the SEC’s guidelines strictly prohibit us from including in filings with the SEC. The calculation of risked resources, and any other estimates of reserves and resources that are not proved, probable or possible reserves are not necessarily calculated in accordance with SEC guidelines. Our estimate of risked resources is not prepared or reviewed by third party engineers, is determined using strip pricing, which we use internally for planning and budgeting purposes, and may differ from an un-risked estimate of proved, probable and possible reserves. The Company’s estimate of risked resources is provided in this release because management believes it is useful, additional information that is widely used by the investment community in the valuation, comparison and analysis of companies; however, the Company’s estimate of risked resources may not be comparable to similar metrics provided by other companies. Investors are urged to consider closely the disclosure in our Annual Report on Form 10-K for the year ended December 31, 2013, 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.

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 and are unaudited.