MAY 2014
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 Risked Resources 2
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 3
Company Vision and Strategy 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 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 4
Driving Transformation Delivered on key 2013 objectives 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 2013 Proved Reserves Oil Production (MMBbls) 4.6+ 42% 40% 2.7 3.5 18% 1.1 1.5 Oil Gas NGL 2010 2011 2012 2013 2014e 5
millions Oil Focus Delivers High Production and Cash Flow Growth 8.0 Oil Program Production (MMBoe) Oil Program Operating Cash Flow 4.0 $200 0.0 2011 2012 2013 2014e $0 2011 2012 2013 2014e DJ Basin Uinta Oil Program Powder Deep Oil 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 Cash operating margin increasing due to increased oil cut, up ~30% in 2013 6
Low-risk, Long-term Growth Profile 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 Proved Total Risked Resources (2013) Oil Gas/NGLs Proved MMBoe Year-end 2013 Proved + Risked Resources MMBoe Gross/Net Drilling Locations Denver Julesburg 1 (oil/ngls) 66 221 1,697/844 Uinta Oil 2 Program (oil) 53 171 1,795/785 Gibson Gulch, Piceance (NGLs) 73 100 528/416 Powder River Deep 3 (oil) 5 95 1,370/284 0 100 200 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 TOTAL 197 587 5,390/2,329 % OIL 42% 55% 7
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 2015: 4.7 MMBoe; Oil 9,667 bbls/d at $89.50/bbl; natural gas: 20,000 MMBtu/d at $4.13/MMBtu 8
Value Creation: 2014 Plan 2014 Objectives 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 9
2014 Guidance Capital program 100% directed at oil growth 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 2014 Capex % by Area Powder River Deep Program Uinta Oil DJ Basin 10
DJ BASIN
DJ Basin: Lots of Running Room Prime land position: ~75,500 net acres Northeast Wattenberg: 40,200 net acres Niobrara and Codell Formations Wattenberg interior: 13,170 net acres Chalk Bluffs: 22,120 net acres Target Niobrara and Codell formations with horizontal drilling 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 50 Miles BBG Acreage 2014 plan: ~75% of capital program to drill or participate in ~120 gross/72 net wells 12
Boe/d DJ Basin: Production Growth 8,000 DJ Basin Net Production and Gross Operated Horizontal Wells Spud 6,430 6,000 4,000 2,000 1,565 0 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 Operated Wells spud 13 7 2 11 21 27 21 Driving continued growth 13
Northeast Wattenberg Well Results 2013 Appraisal program tests multiple concepts 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 Western Block Northern Block Southern Block BBG Acreage 6 Miles Newly Reported Wells 2Q14 XRL Locations 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. 14
DJ Basin Undeveloped Location Inventory 844 Net Undeveloped Locations Total Gross: 1,697 43 94 130 Core Wattenberg NE Wattenberg (North) NE Wattenberg (South) 228 349 NE Wattenberg (Western) Chalk Bluffs Long-term inventory with upside from downspacing and further delineation 15
Northeast Wattenberg: ~70% Delineated Based on Proved Reserves Northern Block: Western Block: Western Block Northern Block Net Acreage 17,700 % Delineated* 95% Proved Reserves (MMBoe) 39.1 Risked Resources (MMBoe): 73.7 Undrilled Locations (gross/net): 518/349 Net Acreage 2,000 Delineated* 100% Proved Reserves (MMBoe) 5.0 Risked Resources (MMBoe): 10.1 Undrilled Locations (gross/net): 110/43 Southern Block BBG Acreage 6 Miles 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 16
DJ Basin Illustrative Economics Illustrative Economics: EUR (MBoe, Gross) 450 Total D&C Capital ($MM) $4.2 Rate of Return 53% WTI for 10% ROR $40.30 1 st year decline 70% Terminal decline 7% Nominal Horizontal Length 4,000 Illustrative Economics: EUR (MBoe, Gross) 337 Total D&C Capital ($MM) $4.2 Rate of Return 47% WTI for 10% ROR $49.50 1 st year decline 72% Terminal decline 7% Nominal Horizontal Length 4,000 Illustrative Economics: EUR (MBoe, Gross) 883 Total D&C Capital ($MM) $7.8 Rate of Return 79% WTI for 10% ROR $36.25 1 st year decline 57% Terminal decline 7% Nominal Horizontal Length 9,000 EUR Oil: 36%; Gas: 40%; NGL: 24% EUR Oil: 56%; Gas: 28%; NGL: 16% EUR Oil: 56%; Gas: 28%; NGL: 16% Illustrative Margin Analysis ($/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 $ 7.77 Production Taxes $ 4.26 Cash Margin $44.00 Illustrative Margin Analysis ($/Boe) Realized price per Boe* $56.03 LOE $ 5.07 Production Taxes $ 4.17 Cash Margin $46.79 * 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. 17
DJ Basin: 2014 Activity 2014 Plan: Drives Estimated 40% Rate of Return Niobrara and Codell Formations Exploit 75,500 acre position 85 gross/65 net operated wells Participation in 35 gross/7-8 net nonoperated wells Drilling program focused on Northeast Wattenberg Primarily multi-well pad drilling Upside Multiple extended reach laterals Test 40-acre downspacing Chalk Bluffs 50 Miles BBG Acreage 18
UINTA OIL PROGRAM
Uinta Oil Program Large, Scalable Program: ~150,000 net acres East Bluebell: 21,550 net acres Blacktail Ridge/Lake Canyon: 108,050* net acres South Altamont: 22,320 net acres Wasatch, Green River Formations Driving Rapid Growth 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 10 Miles BBG Acreage Gas Production Oil Production BBG Acreage 10 Miles 2Q14 added 4,500 Bbl/d firm marketing agreement * Includes acreage to be earned. 20
UOP: Undeveloped Location Inventory Risked Resources (171 MMBoe) 785 Net Drilling Locations (Gross 1,795) 42 124 37 92 137 524 Blacktail Ridge/Lake Canyon East Bluebell South Altamont Blacktail Ridge/Lake Canyon East Bluebell South Altamont Predominantly 160-acre spacing Upside from downspacing 21
UOP: East Bluebell Execution East Bluebell Program Offers Substantial Upside 35,750 gross/21,550 net acres Lower Green River 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 2014 Plans: Capture Value at East Bluebell 34 gross/20 net wells in 2014 plan Production: 2,390 Boe/d (1Q14) Build out infrastructure Continue delineation efforts 4,000 2,000 0 BBG Acreage 6 Miles East Bluebell Production (Boe/d) 1H12 2H12 1H13 2H13 22
UOP: East Bluebell Wells Exceeding Type Curve 2013 West wells tracking >250 MBoe EUR type curve Lower Green River 2014 wells to-date exceeding type curve 2014 D & C costs down 20% v 2013 Expanding 2014 program 6 Miles 2014 Plan 2013 West BBG Acreage 2013 East IP Rates to-date: (Boe/d) 30-day IP 60-day IP 90-day IP 2013 West 209 195 189 2014 West 217 - - 2013 East 136 147 150 23
East Bluebell Economics Illustrative Economics: EUR (MBoe, Gross) 212 Total D&C Capital ($MM) $2.5 Rate of Return 60% WTI for 10% ROR $52.50 1 st year decline 60% Terminal decline 7% Vertical Well Depth 9,000 Oil: 97%; Gas 3%; NGL: <1% Illustrative Margin Analysis ($/Boe) Realized Price per Boe $71.52 LOE $10.50 Production Taxes $ 4.67 Operating Margin $56.35 *WTI: $90/Bbl; HH: $4.50/MMBtu; -$15.30 differential to WTI 24
POWDER DEEP OIL
Powder Deep Oil Program Stacked oil play providing positive results, but not part of long-term future 161,160 gross / 67,980 net acres Production: 1,330 Boe/d (1Q14) Multiple oil plays show good results in Shannon, Sussex, Frontier, Turner, Parkman Marketing advisor engaged to assist with asset sale Continue building development inventory and participate in nonoperated drilling throughout sale process 10 Miles BBG Acreage 26
Value Creation Opportunity Execution, Execution, Execution Capitalize on commodity balance by allocating capital to highest return assets and achieving increased profit margins Deliver unrealized value from 75,500 net acres in DJ Basin oil development Demonstrate value in 21,500 net acres in eastern Uinta Basin oil development Divest non-core assets beginning with Powder Deep Oil Position company for continued competitive growth and returns Maintain financial discipline with moderate debt leverage and ample liquidity Uphold high standards for health, safety and environment 27
APPENDIX
Volume (MMBoe) Price($/Boe) Hedging Provides Price Predictability 2014 hedges (2Q-YE): 2.8 MMBbls oil hedged at $94.03/bbl 17.5 Bcf gas hedged at $4.19/Mcf Opportunistically add to positions over time As of April 25, 2014 Volume (MMBoe) Price ($/Boe) 2.5 2.0 $80 $60 1.5 1.0 $40 0.5 $20 0.0 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15 $0 Notes: As of April 25, 2014. Average swap price is for illustrative purposes only and does not represent formal guidance. 29
Natural Gas and Oil Hedges As of April 25, 2014 Swaps Period Oil Natural Gas NGLs* Volume (Bbls/d) WTI Price ($/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 $4.13 - - *NGL volumes include propane, butanes and natural gasoline. No ethane volumes are hedged. 30
Debt Instruments ($ 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 Total Debt $1,047 31
DJ Basin Infrastructure Existing local oil refining capacity and rail infrastructure >350mbbls/d Capacity Expansion Projects Capacity (MBbls/d) Timing Pony Express Pipeline 230 3Q14 White Cliffs Expansion 75 3Q14 Pony Express DJ Lateral 90 1Q15 Current gas processing capacity ~1.1 Bcf/d Capacity Expansion Projects (MMcf/d) 2014 Additions 2015 Additions Anadarko 300 300 DCP Midstream 100 170 Front Range Pipeline brings access to Mt. Belvieu market NGL Pipelines Additions Capacity (MBbls/d) Timing Front Range Pipeline 150 In Service 32
DJ Basin Infrastructure Expected Capacities Cheyenne Crude Terminal 52mbbls/d Pony Express Conversion 3Q14: 230-320mbbls/d Pony Express NE CO Lateral 1Q15: 90mbbls/d Suncor Refinery: 96MBbls/d Plains Rail Facility: 4Q13: 68mbbls/d White Cliffs Pipeline 1H14: 150mbbls/d 33
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 34
Colorado Hydraulic Fracturing Initiative Anti-Hydraulic Fracturing Initiatives 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 Industry Approach 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 Facts 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% 35
Northeast Wattenberg: Prime Position Among Peers Excellent position yet to be fully valued Successful extended reach laterals within 2 miles of BBG position Niobrara Formation East Pony/ Redtail Successful 40-acre spacing within 3 miles of BBG position Continuation of geologic and geophysical parameters across position NBL Loeffler Pad PDCE Waste Mgt. SYRG NBL Wells Ranch BCEI CRZO Razor/Rohn 10 miles BBG Acreage 36
Uinta Basin: Well Positioned Among Peers Wasatch, Green River Formations EP LINN NFX DVN NFX CPG UPL CPG QEP 10 Miles BBG Acreage 37
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 38
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 Net MMBoe 195.0-14.5 57.0 197.0-40.5 2013 Production $1.4 Billion PV 10 116 Proved Developed Dispositions PRICING 2012 YE $2.76/MMBtu HH & $91.21/Bbl WTI Reserve Additions and Revisions 83 Proved Developed $1.75 Billion PV 10 2013 YE $3.67/MMBtu HH & $96.91/Bbl WTI Please see Disclosure slides. 39
2014 Guidance Profitable growth from core oil programs and maintaining capital discipline 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 stockbased compensation 40
Land Summary As of March 31, 2013 Area Gross Acreage Net Acreage Average Gross Project Average BBG Working NRI 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 327,645 151,930 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 129,335 79,460 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 Gulch 1 40,310 36,280 88% 90% Paradox Basin Yellow Jacket 297,280 215,875 83% 100% Uinta Basin (Hornfrong, including to-be-earned) 30,585 16,820 85% 55% 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. 41
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. 42
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. 43