Investor Update. November 2014

Investor Update November 2014

Forward Looking Information Cautionary Statement for the Purpose of the Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995 This presentation includes forward looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements included in this presentation other than statements of historical fact, including, but not limited to, statements or information concerning the Company s future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, returns, budgets, costs, business strategy, objectives, and cash flow, are forward looking statements. When used in this presentation, the words could, may, believe, anticipate, intend, estimate, expect, project, budget, plan, continue, potential, guidance, strategy, and similar expressions are intended to identify forward looking statements, although not all forward looking statements contain such identifying words. Forward looking statements are based on the Company s current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes the expectations reflected in the forward looking statements are reasonable and based on reasonable assumptions, no assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. When considering forward looking statements, readers should keep in mind the risk factors and other cautionary statements described under Part I, Item 1A. Risk Factors included in the Company s Annual Report on Form 10 K for the year ended December 31, 2013, registration statements and other reports filed from time to time with the Securities and Exchange Commission ( SEC ), and other announcements the Company makes from time to time. The Company cautions readers these forward looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company s control, incident to the exploration for, and development, production, and sale of, crude oil and natural gas. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling, completion and production equipment and services and transportation infrastructure, environmental risks, drilling and other operating risks, lack of availability and security of computer based systems, regulatory changes, the uncertainty inherent in estimating crude oil and natural gas reserves and in projecting future rates of production, cash flows and access to capital, the timing of development expenditures, and the other risks described under Part I, Item 1A. Risk Factors in the Company s Annual Report on Form 10 K for the year ended December 31, 2013, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time. Readers are cautioned not to place undue reliance on forward looking statements, which speak only as of the date hereof. Should one or more of the risks or uncertainties described in this presentation occur, or should underlying assumptions prove incorrect, the Company s actual results and plans could differ materially from those expressed in any forward looking statements. All forward looking statements are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward looking statements that the Company, or persons acting on its behalf, may make. Except as otherwise required by applicable law, the Company disclaims any duty to update any forward looking statements to reflect events or circumstances after the date of this presentation. 2

CLR Value Drivers Multi decade inventory of high rate of return drilling locations in Bakken and SCOOP Largest acreage holder and producer in the Bakken Recently announced new discovery Springer oil play in Oklahoma 1.2 billion Boe of proved reserves Industry leading production growth while maintaining strong financial position From 37,000 Boe per day in 2009 to estimated 200,000 Boe per day at YE2014 5 year production total of ~190 million Boe Proactively adapting to market conditions Altering 2015 capital plans to remain flat with current 2014 activity levels, reducing planned capex by $600 million Still projecting YOY production growth of 23% to 29%, previously 26% to 30% Monetized oil hedges for $433 million of proceeds expecting recovery in WTI 3

Two World Class Platforms for Growth: Bakken and SCOOP NYSE listed: CLR Enterprise Value: ~$26B(¹) Market Cap: ~$20B Total Debt: ~$6B Focused in two premier basins with decades of organic growth Largest leaseholder, driller and producer in the Bakken and Three Forks Largest leaseholder, driller and producer in the SCOOP (Springer & Woodford) Repeatable, low risk inventory Strong production growth (23% 29% anticipated in 2015) Leveraging size and scale to drive efficiencies and lower drilling, completion and operating costs Straight forward strategy Pure play E&P Oil weighted production mix 70% oil (over 80% liquids), 30% natural gas/ngl Organic growth Low cost, high margin operator Investment grade rated SCOOP ~471,000 Net Acres Leased 3.6 Billion Boe Resource Potential BAKKEN ~1.2 Million Net Acres Leased 4.1 Billion Boe Resource Potential CLR Primary Areas of Operation (1) Market cap as of 11/11/2014 and total debt as of 9/30/2014 4

3Q14 Operational & Financial Highlights 3Q14 production: 182,335 Boe per day, up 29% over 3Q13 and 9% sequentially Bakken: 121,604 Boe per day, up 29% over 3Q13 SCOOP: 36,346 Boe per day, up 81% over 3Q13 On track for 200,000 Boe per day YE14 exit rate 200,000 150,000 100,000 Production (Boe per day) 97,583 135,919 182,335 3Q14 EBITDAX(¹) of $948 million, up 19% over 3Q13 and 9% sequentially Marketing strategy and opex focus drive strong cash margin(²) $51.26 per Boe (74%) cash margin for 3Q14 $54.14 per Boe (75%) cash margin for 9 months ended 9/30/14 Top tier recycle ratio: 4.7x(³) Proved reserves: 1.2 billion Boe(⁴) Monetized substantially all crude oil hedge positions for 2014, 2015 and 2016, generating proceeds of $433 million 50,000 (1) See EBITDAX Reconciliation to GAAP in the Appendix for a reconciliation of GAAP net income and operating cash flows to EBITDAX. (2) See Continuing to Deliver Excellent Margins in the Appendix for the method of calculating cash margin. (3) Source: Bank of America, November 5, 2014 5 (4) Internally estimated as of 6/30/14 0 $3,000 $2,500 $2,000 $1,500 $1,000 $500 $0 37,324 43,318 61,865 2009 2010 2011 2012 2013 3Q 2014 $451 EBITDAX ($MM) FY EBITDAX YTD 9/30/14 EBITDAX 3Q EBITDAX $811 $1,304 $1,963 $2,840 $948 $2,591 2009 2010 2011 2012 2013 3Q14 YTD 9/30/14

Bakken Continues to Deliver and Improve CLR Net Bakken Production of 121,604 Boe per day (3Q 2014) Up 12% over 2Q14 Up 29% over 3Q13 1000 800 Production Profile for 2015 Bakken Drilling Program 2015 CLR Bakken operated development plan 19 operated rigs 175 net (282 gross) operated Bakken wells Targeting 700 MBoe EUR per well (2015 blended average) $9.6 million CWC (2015 blended average) ~40% ROR at $80 oil and $3.50 gas Decades of drilling inventory 8 year inventory averaging 775 MBoe EUR per well( 1 ) 20 year inventory averaging 600 MBoe EUR per well(²) 18 19% recovery factor supports up to 8 wells per DSU in the Middle Bakken and Three Forks 1 horizons with standard completions Maximizing economics/optimizing recovery BOE/day 600 400 200 0 0 5 10 15 20 25 30 35 700 Mboe Model Parameters 2 Mile Lateral Length Oil IP Rate, bbl/day 925 Oil 30 day IP Rate, bbl/day 741 Oil Initial Decline 80% Oil b factor 1.50 Oil EUR, Mbo 577 Gas IP Rate, Mcf/day 945 Gas 30 Day IP Rate, Mcf/day 734 Gas Initial Decline 80% Gas b factor 1.70 Gas EUR, Mmcf 726 Equivalent EUR, Mboe 700 Minimum Decline (Oil/Gas) 6%/4% Capital, $MM 9.6 ROR Producing Months ROR vs Oil Price 100% 90% 80% 70% 60% 50% 40% 30% Gas Price: $3.50/MCF 20% $70 $80 $90 $100 $110 $120 Oil Price, $/BBL (1) Assumes a run rate of 300 gross wells drilled per year, or 2,400 wells total. (2) Assumes a run rate of 300 gross wells drilled per year, or 6,000 wells total. Excluding the 2,400 wells averaging 775 MBoe EUR, the remaining 3,600 wells average approximately 485 MBoe EUR. 6

Bakken Value Increasing Through Enhanced Completions Increasing EURs with new completion designs Tested and confirmed in Williams and Northern McKenzie Counties Over 45% average 90 day production uplift ~30% increase in EUR Based on 30 stage completions Expecting similar results in ~40% of leasehold Based on geology and early results Best results to date Hybrid completions Slickwater designs Both with higher volumes of proppant Evaluating 40 stage completion results 20 Miles CANADA MT ND Enhanced Completions Legend: Area with EUR uplift Slickwater Completion Hybrid Completion Large Proppant Volume Industry Enhanced Completion BAKKEN IMMATURE 7

SCOOP: South Central Oklahoma Oil Province 3.6 Billion Boe net resource potential High ROR oil and condensate reservoirs Woodford Springer Dominant SCOOP leasehold position: 471,000 net acres CLR net SCOOP production: 36,346 Boe per day average in 3Q14 +81% over 3Q13 2015 plan to drill 94 net (134 gross) operated SCOOP wells Additional potential STACK/Meramec, Caney, Viola, Hunton and Hoxbar NW Cana SCOOP 25 Miles Woodford Shale Thickness 50 ft 100 ft >200 ft STACK Oklahoma Texas Cana Field 8

CLR s Newest Oil Discovery: Springer Shale 2012 Stealth play becomes reality 447 MMBoe net unrisked resource potential to CLR 127 net MMBoe in the oil fairway 215 net/399 gross locations 188 net/252 gross operated locations 27 net/147 gross non operated locations 80 320 acre spacing/20% recovery factor 320 net MMBoe, or 1.9 Tcfe, in the gas/condensate fairways Reservoir in the heart of SCOOP 195,000 net acres 118,000 net acres in the oil fairway 77,000 net acres in the gas/condensate fairways Successful exploration 2014: continued confirmation program Plan to operate an average of 8 rigs in 2015 Significant resource potential upside 12 Miles CLR: Schoof 1 17H IP: 1,465 boepd CLR: Nancy J 1 28H IP: 1,815 boepd SCOOP Outline Springer Fairway Springer Fairway CLR Leasehold NFX: Jarred 1 16H IP: 1,950 boepd CLR 2013 Key Delineation Wells CLR Springer Shale Producers Non Op. Springer Shale Producer SCOOP CLR: AC Walters 1 27H IP: 1,630 boepd CLR: Ince 1 21H IP: 1,037 boepd 9

Exceptional Economics Springer Shale Oil EUR: 940 Mboe Normalized to 4,500 lateral Completed well cost: $9.7 million ROR: 86% at $80/$3.50 prices Type curve based on wells with > 60 days of production First extended lateral to be drilled in 4Q14 Delineation and density testing underway 3 rigs currently drilling delineation 5 rigs on infill pilot Springer Shale Fairway (84% Liquids) NGL 17% Gas 16% Oil 67% Boe per day 800 700 600 500 400 300 200 100 0 Springer Shale Type Curve Well Count Type Curve (Normalized to 4,500' LL) Act. Production (4,066' Avg LL) 0 0 6 12 18 24 30 36 Producing Months Springer Shale Type Curve 4,500' Oil IP Rate, Bbl/day 670 Oil Initial Decline 62% Oil b factor 1.25 Oil EUR, MBo 735 Gas IP Rate, Mcf/day 867 Gas Initial Decline 56% Gas b factor 1.4 Gas EUR, MMcf 1,230 Equivalent EUR, MBoe 940 Minimum Decline 6% Lateral Length, ft 4,500 Capital, $MM 9.7 ROR 180% 160% 140% 120% 100% Oil Differential: 2.3%, Gas Differential Premium: +38% 40 30 20 10 Oil ROR vs Oil Price Well Count 80% Gas Price: $3.50/MCF 60% $70 $80 $90 $100 $110 $120 Oil Price, $/BBL 10

SCOOP: Woodford Overview High ROR: Condensate fairway: 60% ROR, based on $80 oil and $3.50 gas Oil fairway: 22% ROR, based on $80 oil and $3.50 gas Superior well performance & economics: High productivity rock Liquids rich gas Proven resource play: Repeatable, consistent results Woodford formation up to 950 thick Scale: ~450,000 net acre leasehold Plan to operate an average of 18 rigs in 2015 Resource potential: 3.6 Billion Boe Density pilots underway Extended laterals enhancing returns CLR Acreage Oil Fairway Condensate Fairway Gas Fairway Oklahoma City 11

Higher Returns With Extended Laterals Woodford Condensate Fairway EUR: 1,725 MBoe Normalized to 7,500 lateral Completed well cost: $12.2 million ROR: 60% at $80/$3.50 prices Extended laterals: ~70% added resource for ~40% added cost Plan to drill 10,000 laterals where possible: lateral length of future locations expected to average 7,500 Extended laterals allow access to 600 900 of reservoir previously not drilled due to setback and drilling requirements for 640 acre spacing Condensate Fairway (53% Liquids) Gas 47% Oil 13% NGL 40% Boe per day 1,800 1,600 1,400 1,200 1,000 800 600 400 200 0 Condensate Fairway Type Curve 4,500' Act. Well Count Ext. Act. Well Count 4,500' Act. Production Ext. Type Curve (Normalized to 7,500' LL) Ext. Act. Production (8,700' Avg LL) 0 0 6 12 18 24 30 36 Producing Months Condensate Type Curve Data 7,500' Oil IP Rate, Bbl/day 280 Oil Initial Decline 61% Oil b factor 1.1 Oil EUR, MBo 295 Gas IP Rate, Mcf/day 7,000 Gas Initial Decline 58% Gas b factor 1.2 Gas EUR, MMcf 8,580 Equivalent EUR, MBoe 1,725 Minimum Decline 6% Lateral Length, ft 7,500' Capital, $MM 12.2 ROR 130% 110% 90% 70% 270 240 210 180 150 120 90 60 30 Condensate ROR vs Gas Price Oil Differential: 2.3%, Gas Differential Premium: +38% Well Count 50% Oil Price: $80/BBL 30% $2 $3 $4 $5 $6 Natural Gas Price, $/MCF 12

Unlocking the Woodford Oil Fairway Woodford Oil Fairway EUR: 655 MBoe Normalized to a 7,500 lateral Completed well cost: $12.2 million ROR: 22% at $80/$3.50 prices Extended laterals: ~70% added resource for ~40% added cost Plan to drill 10,000 laterals where possible: lateral length of future locations expected to average 7,500 Extended laterals allow access to 600 900 of reservoir previously not drilled due to setback and drilling requirements for 640 acre spacing NGL 26% Oil Fairway (83% Liquids) Gas 17% Oil 57% Boe per day 600 500 400 300 200 100 0 0 0 6 12 18 24 30 36 Producing Months Oil Type Curve Data 7,500' Oil IP Rate, Bbl/day 400 Oil Initial Decline 59% Oil b factor 1.1 Oil EUR, MBo 440 Gas IP Rate, Mcf/day 780 Gas Initial Decline 49% Gas b factor 1.3 Gas EUR, MMcf 1,290 Equivalent EUR, MBoe 655 Minimum Decline 6% Lateral Length, ft 7,500' Capital, $MM 12.2 Oil Fairway Type Curve Act. Well Count Ext. Act. Well Count Act. Production (4,100' Avg LL) Ext. Type Curve (Normalized to 7,500' LL) Ext. Act. Production (9,500' Avg LL) ROR 50% 40% 30% 20% Oil ROR vs Oil Price Gas Price: $3.50/MCF 120 100 80 60 40 20 Oil Differential: 2.3%, Gas Differential Premium: +38% Well Count 10% $70 $80 $90 $100 $110 $120 Oil Price, $/BBL 13

Incremental Value Captured Through NW Cana JV Formed JV with SK E&S (South Korean Based) NW Cana STACK Sold 49.9% interest in 44,000 acres and 37 producing wells for total consideration of $360 million $90 million cash at closing 5 year $270 million carry for 50% of CLR s future D&C capital Plan to operate 4 rigs in 2015 SCOOP Cana Field Competitive rates of return with carry 25 Miles Woodford Shale Thickness 50 ft 100 ft >200 ft Oklahoma Texas 14

2015 Capital Expenditures Budget Total Capital Expenditures ($4.6B) 2015 Highlights: Other Drilling $114 MM Leasehold $300 MM Other $270 MM Maintaining 2014 activity levels $4.6B CAPEX 50 rigs running Drilling capital allocation Bakken 64% SCOOP 33% NW Cana JV & Other 3% SCOOP Drilling $1,325 MM 2015 production growth of 23 29% Bakken Drilling $2,591 MM Average Operated Rigs Op & Non Op Net Wells Bakken(¹) 19 246 SCOOP(²) 26 106 Other 5 18 Totals 50 370 (1) Based on an anticipated average completed Bakken well cost of $9.6 million. (2) Based on an anticipated average completed SCOOP well cost of $11 million. 15

Cost Discipline Driving Excellent Margins ($ per Boe) $80 $70 $60 $50 $40 $30 $20 $10 $65.99 Cash Margin $48.59 $72.04 Cash Margin $53.52 $69.08 Cash Margin $51.26 $72.52 Cash Margin $54.14 74% 74% 74% 75% $3.95 $4.74 $4.40 $4.61 $2.38 $2.07 $1.82 $2.09 $5.58 $6.02 $5.80 $5.99 Strong/stable cash margins (1) Margin scales as costs remain flat Capex management and cost focus drive excellent margins $0 $5.49 $5.69 $5.80 $5.69 2012 2013 3Q2014 9 Months Ended 9/30/2014 Production Expense P/S Tax & Other G&A(²) Interest Cash Margin Avg. Realized Price per BOE(³) (1) See Continuing to Deliver Excellent Margins in the Appendix for the method of calculating cash margin. (2) Excludes G&A related to Equity based compensation and relocation expense. (3) Based on average oil equivalent price (excluding derivatives and including natural gas) 16

Capital Efficiency Industry Leading Recycle Ratio(¹) Recycle Ratio = Cash margin/f&d per Boe Exploration leadership enables low finding and development costs Efficient operator evidenced by low operating costs per Boe Oil and liquids focused, generating high margins 5.0x 4.0x Recycle Ratio Average 4.7x 3.0x 2.0x 1.6x 1.9x 2.0x 2.1x 2.2x 2.3x 2.4x 2.5x 2.9x 1.0x 0.0x COP APC OXY CXO MRO EPE WLL NBL EOG CLR (1) Bank of America, November 7, 2014. Oil weighted company comparison. 17

Strong Liquidity and Financial Profile Financial Ratios and Ratings Agency Credit Ratings Net Debt/3Q Annualized EBITDAX(¹) 1.50x Leveraged Cash Margin (9 months YTD)(²) $54.14 Moody's Baa3 Net Debt/Mid Year Proved Reserves $4.72 3 Year All in F&D ($/Boe) (YE13) $12.61 S&P BBB Investment Grade Net Debt/Sept. Avg. Daily Production $30,325 3 Year Avg. Recycle Ratio (YE13) 4.5x 2500 Debt Maturities Summary ($MM) 2000 1500 1000 500 0 No maturities in five year plan Undrawn $1,750 7.375% $200 7.125% $400 $2,000 $1,500 $1,000 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2044 Credit Facility 06/30/14 Callable 10/1/2015 Callable 4/1/2016 5% Callable 3/15/2017 4.5% (1) See appendix for reconciliation of GAAP net income and operating cash flows to EBITDAX. (2) See Continuing to Deliver Excellent Margins in the Appendix for the method of calculating cash margin. 3.8% 4.9% $700 18

Appendix

Poteet Density Project Underway Woodford Condensate Fairway Poteet Unit, NE Stephens County Within 5 miles of BEAN density test Average interest: 94% WI, 76% NRI 10 well density now drilling Drilling 95% complete Dual horizon (upper and lower Woodford) 1,026 interwell spacing (same horizon), 513 offset 7,500 laterals Simultaneous stimulation Boe per day ( 50% Liquids ) 1,800 1,600 1,400 1,200 1,000 800 600 400 200 0 2014 Full Scale Density Project Parent Well: Poteet 1 17H Poteet 1 17H (4,500' Lateral) (2012) 4,500' Type Curve 0 6 12 18 24 30 36 Producing Months 1 st sales expected 1Q 2015 2 additional density projects planned for 2015 in the condensate fairway UPPER WOODFORD LOWER WOODFORD Existing Well New Wells 20

Good Martin Density Project Underway Woodford Oil Fairway Good Martin Unit, Grady County Offsetting the Hansell well Average interest: 66% WI, 53% NRI 1 st CLR oil fairway infill 8 well density now completing Single horizon 660 spacing between wellbores 7,500 laterals Simultaneous stimulation 1 st sales expected in 4Q 2014 Boe per day ( 71% Oil ) 1,400 1,200 1,000 800 600 400 200 0 2015 Full Scale Density Project Parent Well: Hansell 1 3 34XH Hansell 1 3 34XH (9,800' Lateral) Ext. Type Curve (Normalized to 7,500' LL) 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 Producing Months 330 1320 2640 1320 330 660 UPPER WOODFORD 2 additional density projects planned for 2015 in the oil fairway LOWER WOODFORD Wells 1 MILE 21

Annual Guidance As of November 5, 2014 2014 2015 Production growth (YOY) 27% to 30% 23% to 29% Capital expenditures (non-acquisition, in $ billions) $4.55 $4.6 Operating Expenses: Production expense per Boe $5.60 to $6.00 $5.50 to $6.00 Production tax (% of oil & gas revenue) 8% to 8.5% 7.5% to 8.5% G&A expense per Boe $2.00 to $2.50 $2.25 to $2.75 Non-cash equity compensation per Boe $0.70 to $0.90 $0.75 to $0.95 DD&A per Boe $20.00 to $22.50 $20.00 to $22.50 Average Price Differentials: NYMEX WTI crude oil (per barrel of oil) ($8.00) to ($11.00) ($9.00) to ($11.00) Henry Hub natural gas (per Mcf) +$1.00 to $1.50 +$1.00 to $1.50 Income tax rate 37% 37% Deferred taxes 90% to 95% 90% to 95% 22

Continuing to Deliver Excellent Margins 2009 2010 2011 2012 2013 3Q2014 As of 9 Months Ended 9/30/14 Realized oil price ($/Bbl) $54.44 $70.69 $88.51 $84.59 $89.93 $85.49 $89.02 Realized natural gas price ($/Mcf) $2.95 $4.26 $4.87 $3.73 $4.87 $5.10 $5.80 Oil production (Bopd) 27,459 32,385 45,121 68,497 95,859 127,788 116,954 Natural gas production (Mcfpd) 59,194 65,598 100,469 174,521 240,355 327,287 304,453 Total production (Boepd) 37,324 43,318 61,865 97,583 135,919 182,335 167,696 EBITDAX ($000's) (1) $450,648 $810,877 $1,303,959 $1,963,123 $2,839,510 $947,635 $2,590,980 Key Operational Statistics (per Boe) (2) Average oil equivalent price (excludes derivatives) $44.68 $59.35 $72.45 $65.99 $72.04 $69.08 $72.52 Production expense $6.89 $5.87 $6.13 $5.49 $5.69 $5.80 $5.69 Production tax and other $2.95 $4.47 $5.82 $5.58 $6.02 $5.80 $5.99 G&A (3) $2.19 $2.35 $2.36 $2.38 $2.07 $1.82 $2.09 Interest $1.72 $3.34 $3.40 $3.95 $4.74 $4.40 $4.61 Total cash costs $13.75 $16.03 $17.71 $17.40 $18.52 $17.82 $18.38 Cash margin $30.93 $43.32 $54.74 $48.59 $53.52 $51.26 $54.14 Cash margin % 69% 73% 76% 74% 74% 74% 75% 1) See EBITDAX Reconciliation to GAAP in Appendix for a reconciliation of GAAP net income and operating cash flows to EBITDAX. 2) Average costs per Boe have been computed using sales volumes and exclude any effect of derivative transactions. 3) Excludes G&A related to Equity based compensation and relocation expense. 23

EBITDAX Reconciliation to GAAP We use a variety of financial and operational measures to assess our performance. Among these measures is EBITDAX. EBITDAX represents earnings (net income) before interest expense, income taxes, depreciation, depletion, amortization and accretion, property impairments, exploration expenses, non cash gains and losses resulting from the requirements of accounting for derivatives, non cash equity compensation expense, and losses on extinguishment of debt. EBITDAX is not a measure of net income or operating cash flows as determined by GAAP. Management believes EBITDAX is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. Further, we believe that EBITDAX is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet future debt service requirements, if any. We exclude the items listed above from net income in arriving at EBITDAX because those amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. EBITDAX should not be considered as an alternative to, or more meaningful than, net income or operating cash flows as determined in accordance with GAAP or as an indicator of a company s operating performance or liquidity. Certain items excluded from EBITDAX are significant components in understanding and assessing a company s financial performance, such as a company s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of EBITDAX. Our computations of EBITDAX may not be comparable to other similarly titled measures of other companies. See the following page for reconciliations of our net income and operating cash flows to EBITDAX for the applicable periods. 24

EBITDAX Reconciliation to GAAP The following tables provide reconciliations of our net income and operating cash flows to EBITDAX for the periods presented: In thousands 2009 2010 2011 2012 2013 3Q2014 YTD 9/30/14 Net income $ 71,338 $ 168,255 $ 429,072 $ 739,385 $ 764,219 $ 533,521 $ 863,293 Interest expense 23,232 53,147 76,722 140,708 235,275 73,912 209,728 Provision for income taxes 38,670 90,212 258,373 415,811 448,830 313,340 507,015 Depreciation, depletion, amortization and accretion 207,602 243,601 390,899 692,118 965,645 363,677 963,409 Property impairments 83,694 64,951 108,458 122,274 220,508 85,561 223,085 Exploration expenses 12,615 12,763 27,920 23,507 34,947 13,514 29,532 Impact from derivative instruments: Total (gain) loss on derivatives, net 1,520 130,762 30,049 (154,016) 191,751 (473,999) (171,801) Total cash received (paid), net 569 35,495 (34,106) (45,721) (61,555) (190) (97,217) Non cash (gain) loss on derivatives, net 2,089 166,257 (4,057) (199,737) 130,196 (473,809) (269,018) Non cash equity compensation 11,408 11,691 16,572 29,057 39,890 13,402 39,419 Loss on extinguishment of debt 24,517 24,517 EBITDAX $ 450,648 $ 810,877 $ 1,303,959 $ 1,963,123 $ 2,839,510 $ 947,635 $ 2,590,980 In thousands 2009 2010 2011 2012 2013 3Q2014 YTD 9/30/14 Net cash provided by operating activities $ 372,986 $ 653,167 $ 1,067,915 $ 1,632,065 $ 2,563,295 $ 845,398 $ 2,277,851 Current income tax provision 2,551 12,853 13,170 10,517 6,209 (826) 2,278 Interest expense 23,232 53,147 76,722 140,708 235,275 73,912 209,728 Exploration expenses, excluding dry hole costs 6,138 9,739 19,971 22,740 25,597 8,755 20,390 Gain (loss) on sale of assets, net 709 29,588 20,838 136,047 88 5,411 (952) Excess tax benefit from stock based compensation 2,872 5,230 15,618 Other, net (3,890) (3,513) (4,606) (7,587) (1,829) (1,533) (12,850) Changes in assets and liabilities 46,050 50,666 109,949 13,015 10,875 16,518 94,535 EBITDAX $ 450,648 $ 810,877 $ 1,303,959 $ 1,963,123 $ 2,839,510 $ 947,635 $ 2,590,980 25

Adjusted Earnings Reconciliation to GAAP Our presentation of adjusted earnings and adjusted earnings per share that exclude the effect of certain items are non GAAP financial measures. Adjusted earnings and adjusted earnings per share represent earnings and diluted earnings per share determined under U.S. GAAP without regard to non cash gains and losses on derivative instruments, property impairments, gains and losses on asset sales, and corporate relocation expenses. Management believes these measures provide useful information to analysts and investors for analysis of our operating results on a recurring, comparable basis from period to period. In addition, management believes these measures are used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis without regard to an entity s specific derivative portfolio, impairment methodologies, and nonrecurring transactions. Adjusted earnings and adjusted earnings per share should not be considered in isolation or as a substitute for earnings or diluted earnings per share as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies. The following table reconciles earnings and diluted earnings per share as determined under U.S. GAAP to adjusted earnings and adjusted diluted earnings per share for the periods presented. 3Q 2014 2Q 2014 3Q 2013 Diluted Diluted Diluted In thousands, except per share data After-Tax $ EPS After-Tax $ EPS After-Tax $ EPS Net income (GAAP) $ 533,521 $ 1.44 $ 103,538 $ 0.28 $ 167,498 $ 0.45 Adjustments, net of tax: Non-cash (gain) loss on derivatives, net (298,500) (0.81) 124,981 0.34 102,958 0.28 Property impairments 53,903 0.15 49,969 0.13 26,565 0.07 Gain on sale of assets, net (3,409) (0.01) (1,345) - (205) - Loss on extinguishment of debt 15,446 0.04 - - - - Corporate relocation expenses - - - - 63 - Adjusted net income (Non-GAAP) $ 300,961 $ 0.81 $ 277,143 $ 0.75 $ 296,879 $ 0.80 Weighted average diluted shares outstanding 370,528 370,334 369,761 Adjusted diluted net income per share (Non- GAAP) $ 0.81 $ 0.75 $ 0.80 26

Investor Relations Contact Information John J. Kilgallon Vice President, Investor Relations Phone: 405 234 9330 Email: John.Kilgallon@CLR.com Website: www.clr.com/investors 27