Investor Update. November 2016 NYSE: CLR

Investor Update November 2016 NYSE: CLR

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, forecasts or expectations regarding the Company s business and statements or information concerning the Company s future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, rates of return, budgets, costs, business strategy, objectives, and cash flows, 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 forwardlooking 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 these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company s control. No assurance can be given that such expectations will be correct or achieved or the assumptions are accurate. The risks and uncertainties include, but are not limited to, commodity price volatility; the geographic concentration of our operations; financial, market and economic volatility; the inability to access needed capital; the risks and potential liabilities inherent in crude oil and natural gas exploration, drilling and production and the availability of insurance to cover any losses resulting therefrom; difficulties in estimating proved reserves and other revenue based measures; declines in the values of our crude oil and natural gas properties resulting in impairment charges; our ability to replace proved reserves and sustain production; the availability or cost of equipment and oilfield services; leasehold terms expiring on undeveloped acreage before production can be established; our ability to project future production, achieve targeted results in drilling and well operations and predict the amount and timing of development expenditures; the availability and cost of transportation, processing and refining facilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing; increased market and industry competition, including from alternative fuels and other energy sources; and the other risks described under Part I, Item 1A Risk Factors and elsewhere in the Company s Annual Report on Form 10 K for the year ended December 31, 2015, 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 on which such statement is made. 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. Except as expressly stated above or otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward looking statement whether as a result of new information, future events or circumstances after the date of this presentation, or otherwise. Readers are cautioned that initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels. In particular, production from horizontal drilling in shale oil and natural gas resource plays and tight natural gas plays that are stimulated with extensive pressure fracturing are typically characterized by significant early declines in production rates. We use the term "EUR" or "estimated ultimate recovery" to describe potentially recoverable oil and natural gas hydrocarbon quantities. We include these estimates to demonstrate what we believe to be the potential for future drilling and production on our properties. These estimates are by their nature much more speculative than estimates of proved reserves and require substantial capital spending to implement recovery. Actual locations drilled and quantities that may be ultimately recovered from our properties will differ substantially. EUR data included herein remain subject to change as more well data is analyzed. 2

CLR Positioned for Industry Leading Growth Key Strengths Top quartile assets in U.S. (1) Capital efficiency more than doubled since 2014 (2) Lowest combined production expense and cash G&A (3) per Boe among oil weighted peers (4) Key Catalysts STACK Meramec Bakken uncompleted wells Bakken core SCOOP Springer Enhanced completions Adds up to 25% to CLR net unrisked resource potential ~175 gross operated wells at YE 2016, ~850 MBoe average estimated ultimate recovery (EUR) per well Expanding the core through enhanced completions Oil asset ready for full field development Improving well performance in all plays 19 operated rigs Maintained momentum and grew expertise during the last 18 months Strong balance sheet Ample liquidity 1. See slide 7 for supporting detail 2. See slide 5 for supporting detail 3. See Cash G&A Reconciliation to GAAP on slide 39 for a reconciliation of GAAP Total G&A per Boe to Cash G&A per Boe, which is a non GAAP measure 4. See slide 6 for supporting detail 3

3Q 2016 Highlights Impressive STACK and SCOOP density results increasing value Ludwig density: Eight Meramec wells flowed at a combined peak 24 hour rate of 21,354 Boe per day (70% oil); seven new wells average IP of 2,653 Boe per day May density: Seven Woodford wells flowed at a combined peak 24 hour rate of 6,881 Boe per day (77% oil); seven wells average IP of 983 Boe per day STACK costs continue to decline in over pressured oil window Standalone well: Target $8.5 million completed well cost (CWC), down $2.5 million from YE 2015 Density wells: $7.8 million CWC based on Ludwig density results Record 30 day Bakken production from enhanced stimulation Brangus North 1 2H2: 30 day cum of 51.8 MBoe (86% oil), 9,900 lateral Rath Federal 5 22H: 30 day cum of 43.3 MBoe (84% oil), 13,800 lateral 2016 Guidance updated again on continued strong outperformance Production guidance: raised to 215,000 220,000 Boe per day Exit rate production: raised to 205,000 210,000 Boe per day Production expense: lowered to $3.50 $4.00 per Boe Non cash equity compensation: lowered to $0.50 $0.70 per Boe CAPEX: increased by $180 million to $1.1 billion, due to increasing completions expect to be cash flow positive for full year 4

CLR Structural Improvement Since 2014 Capital Efficiency & Production Expense Taken to New Level $/Boe $10 $8 $6 $4 $2 $0 (1) Production and Cash G&A Costs $7.87 $7.76 $7.64 $2.38 $2.07 $2.06 $6.00 $4.97 $1.70 $1.31 $5.49 $5.69 $5.58 $4.30 $3.66 2012 2013 2014 2015 YTD 2016 Production Expense Cash G&A(1) From FY 2014 to YTD 2016: Combined production and cash G&A (1) costs DOWN 35% Continued low operating costs expected in 2017 MBoe 1,400 1,200 1,000 800 600 400 200 0 EUR Per Operated Well 1,206 1,110 126 711 104 Boe/$1,000 470 506 Boe/$1,000 41 47 54 Boe/$1,000 Boe/$1,000 Boe/$1,000 2012 2013 2014 2015 2016 Target 160 140 120 100 80 60 40 20 0 Net Boe/$1,000 (2) From FY 2014 to FY 2016 target: EUR per operated well UP 70% Capital efficiency (2) (Boe/$ invested) UP 133% 1. See Cash G&A Reconciliation to GAAP on slide 39 for a reconciliation of GAAP Total G&A per Boe to Cash G&A per Boe, which is a non GAAP measure 2. Average net revenue interest of 82% assumed for net capital efficiency Note: Capital efficiency based on reserves developed per dollar invested 5

CLR Production Expense and Cash G&A (1) Comparison $/Boe $20 $18 $16 $14 $12 $10 $8 $6 $4 $2 $0 CLR Lowest Among Select Peers (As of 2Q 2016) Group average $8+ $4.94 $5.30 $5.32 $1.22 $3.72 $5.76 $7.16 Pure play Permian peers $8.93 $9.35 $9.60 $10.47 $10.82 $11.09 CLR Peer A Peer B Peer C Peer D Peer E Peer F Peer G Peer H Peer I Peer J Production Expense Cash G&A (1) Peers include: CXO, DVN, EOG, NBL, NFX, OAS, PXD, WLL, WPX and XEC Note: Production expense for peer group excludes gathering and transportation expense; cash G&A excludes equity based compensation Source: GMP Securities, August 2016 1. See Cash G&A Reconciliation to GAAP on slide 39 for a reconciliation of CLR GAAP Total G&A per Boe to CLR Cash G&A per Boe, which is a non GAAP measure 6

CLR s Assets in Top Quartile of U.S. Plays Single Well Rate of Return @ $45 WTI & $2.50 HH 80% 70% 60% 50% 40% 30% CLR TOP QUARTILE PLAYS ~1.8 Million Net Reservoir Acres BAKKEN ~860,000 NET ACRES STACK MERAMEC/OSAGE ~186,000 NET ACRES STACK WOODFORD ~171,000 NET ACRES SCOOP WOODFORD ~369,000 NET ACRES SCOOP SPRINGER ~188,000 NET ACRES 7 ROR (%) 20% 10% 0% 10% STACK STACK Overpressured Oil oil Wattenberg Core Midland Northern Wolfcamp A & B Tier I Lower Spraberry Bakken Core Core Mboe SCOOP SCOOP Condensate SCOOP Oil Eagle Ford Tier 1 STACK Oil Marcellus NE PA STACK Wet Gas Utica Dry Gas Delaware Bone Spring & Leonard Eastern Midland Wolfcamp Marcellus SW Wet Gas and Super Rich Eagle Ford Tier 2 Central Platform Permian Marcellus SW Dry gas Non Core Cana Delaware Wolfcamp Tier II Utica Wet gas Wattenberg Noncore Midland Wolfcamp D Eagle Ford Tier 3 Southern Midland Wolfcamp Bakken Non core Powder River Basin Uinta Basin and Greater Natural Buttes Barnett Delaware Wolfcamp Tier 3 Delaware Brushy Canyon Haynesville / East Texas Fayetteville Tier 1 Canyon Lime Fayetteville Tier 2 Eaglebine Fayetteville Tier 3 Source: Bank of America Merrill Lynch, September 2016

CLR Assets Delivering Top Tier Rates of Return (1) ROR 100% 80% 60% 40% 20% Target EUR: 1,700 MBoe Avg. Lateral: 9,800 STACK Meramec Over Pressured Oil +100% ROR $8.5MM Target 2016 0% $30 $40 $50 $60 WTI Oil Price, $/BBL ROR 100% 80% 60% 40% 20% SCOOP Woodford Condensate Target Enhanced Completion EUR: 2,000 MBoe Avg. Lateral: 7,500 ~50% ROR $9.6MM Enhanced Completion Target 2016 0% $2 $3 $4 Gas Price, $/MCF 100% 80% Avg. Lateral: 9,800 ND Bakken +100% ROR 100% 80% STACK Woodford (NW Cana JDA (3) ) Target EUR: 2,150 MBoe Avg. Lateral: 9,800 ~80% ROR ROR 60% 40% 20% 850 MBoe: $3.5MM Completion cost (2) 900 MBoe: $6.0MM Target 2016 ~40% ROR ROR 60% 40% 20% $12.3MM Target 2016 0% $ 30 $ 40 $ 50 $ 60 WTI Oil Price, $/BBL 0% $2 $3 $4 Gas Price, $/MCF 1. Pre tax rate of return (ROR) is based on projected cash flow and time value of money; costs include completed well cost, production expense, severance tax and variable operating costs. $3.00 Mcf is used for oil price sensitivities and $50 WTI is used for gas price sensitivities. The description of the ROR calculation applies to any ROR reference appearing in this presentation. 2. Estimated ~175 gross operated uncompleted wells at YE 2016, $3.5MM gross cost forward incremental completion cost 3. NW Cana economics factor in a ~50% carry from JDA participant 8

SCOOP & STACK Leading Acreage Positions in Top Tier Plays Pennsylvanian Formation Atoka Sands Morrow Sands ~914,000 Net Reservoir Acres STACK Springer Sands STACK SCOOP Geologic Age Silurian Devonian Mississippian Springer Shale Meramec Osage/Sycamore Woodford Hunton Limestone TARGETED RESERVOIRS ~186,000 ~171,000 ~188,000 ~369,000 STACK SCOOP Woodford Shale Thickness 50 ft 100 ft > 200 ft CLR Leasehold 9

CLR First STACK Density Test Flows 21,354 Boe per Day Meramec Over Pressured Oil Window Ludwig density unit CLR: Ludwig Density 8 Meramec wells had combined peak 24 hour 1 Mile rate of 21,354 Boe per day (70% oil) 7 new Meramec wells had average peak 24 hour rate of 2,653 Boe per day (70% oil) Original Ludwig 1 22 15XH 24 hour rate of 2,782 Boe per day (76% oil) with cumulative 1,320 660 MICROSEISMIC SURVEY 175 Upper Meramec Middle Meramec Lower Meramec Osage Woodford production of 298 MBoe over 338 days 710 Hunton Operational efficiencies gained compared to parent well New Well Parent Well Drilling times averaged 25 days, 36% reduction CWC averaged $7.8 million, 30% reduction 10

CLR Development Underway in STACK Over Pressured Oil ~47,000 net acres in over pressured oil window de risked and ready for development CLR oil inventory overview ~55 operated units ~60% operated working interest Average density: at least 8 Meramec wells and 4 Woodford wells per 1,280 acre unit 4 unit developments currently drilling Testing up to 5 wells per zone 11 additional unit developments planned De risked portion of over pressured oil window Density Activity Over Pressured Bernhardt Density Blurton Density Gillilan Density Normally Pressured Ludwig Density Verona Density Infrastructure facilitating development Oil gathering systems Gas gathering systems Water recycling facility CLR Meramec producing wells CLR Meramec wells drilling / completing Industry Meramec well Industry Rigs CLR Rigs CLR Leasehold 11

CLR Unit Developments Currently Drilling in STACK Over Pressured Oil Window 725 Parent Well Bernhardt 5 wells in Lower Meramec and 4 wells in Woodford ~1,100 to ~1,200 inter well spacing 640 acre unit Results expected 1H 2017 705 Blurton 3 5 wells in Upper & Lower Meramec and 4 wells in Woodford ~1,000 to ~2,100 inter well spacing 1,280 acre unit Results expected 2017 785 Gillilan 4 5 wells in Upper & Lower Meramec and Woodford ~1,000 to ~1,600 inter well spacing 1,280 acre unit Results expected 2017 or 2018 675 Verona 4 wells in Upper & Lower Meramec and Woodford ~1,300 inter well spacing 1,280 acre unit Results expected 2017 or 2018 Upper Meramec Middle Meramec Lower Meramec Osage Woodford Hunton 12

STACK Meramec: Exceptional, Repeatable Results Well Name Prod Days Data as of October 27, 2016 Cum. Production (MBoe) Current Rate (Boepd) Current Flowing Pressure Boden (1) 329 505 (27% oil) 2,006 (23% oil) 3,060 psi Yocum 184 309 (99.5% gas) 1,317 (99.5% gas) 1,840 psi Ludwig (1)(2) (parent well) 338 298 (74% oil) 815 (72% oil) 1,060 psi Compton (1) 296 278 (69% oil) 616 (66% oil) 1,000 psi Madeline 141 251 (63% oil) 1,607 (61% oil) 2,665 psi Blurton (1) 285 228 (74% oil) 534 (65% oil) 1,050 psi Ladd (1) 363 219 (74% oil) 500 (67% oil) 920 psi Gillilan 171 204 (61% oil) 897 (51% oil) 875 psi Quintle (1) 181 181 (69% oil) 749 (61% oil) 775 psi Marks 408 171 (57% oil) 293 (48% oil) 685 psi Foree 178 152 (58% oil) 509 (50% oil) 500 psi Verona (2) 71 132 (69% oil) 653 (66% oil) 1,250 psi Frankie Jo 104 128 (47% oil) 904 (43% oil) 2,530 psi Oppel 109 87 (66% oil) 714 (56% oil) 1,000 psi Bernhardt (1 mile) 1. Wells not produced at maximum capacity 2. Shut in for Ludwig density stimulation 183 69 (70% oil) 239 (67% oil) 220 psi CLR Completed Wells With 90 days of production Blurton Bernhardt Frankie Jo Madeline Foree Compton Boden Yocum Fault > 300 vertical displacement CLR Meramec well CLR Leasehold Over Pressured Normally Pressured Industry Meramec well Ladd Marks Quintle Ludwig Verona Oppel Gillilan 13

De Risking STACK Through Strategic Step Outs Expanding the Play West 186,000 net acres in Meramec +30,000 net acres added since YE 2015 Wells Drilling / Completing ~95% of acreage in over pressured window Reservoir 700 1,200 thick ~40% oil, ~40% liquids rich, ~20% gas 60% HBP by YE 2016 Over Pressured Normally Pressured Project over 1,200 potential net Meramec and Woodford drilling locations Targeting 2 Meramec zones on average, 1 Woodford zone At least 12 wells per 1,280 acre unit Oil window CWC trending down $8.5 million target CWC for standalone well, down $500k from 2Q 2016 Current activity 6 rigs drilling Meramec 5 rigs drilling Woodford 4 density tests underway in oil window 23 wells waiting on completion 17 in Meramec 6 in Woodford 3Q 2016 Completion: McBee 1 3H IP: 2,110 Boe (58% oil) 4,760 LL CLR Meramec producing wells Industry Meramec well Industry Rigs CLR Meramec wells drilling / completing CLR Rigs CLR Leasehold 14

SCOOP Woodford Oil May Density Results 7 well density 6,881 Boe per day (77% oil) combined peak 24 hour rate; average 983 Boe per day per well 4,868 Boe per day (77% oil) combined peak 24 hour rate for 5 new wells; average 974 Boe per day per well Average CWC: $9.3 million $500k under standalone CWC target of $9.8 million Laterals range from 4,500 to 9,700 May Project 7 Well Density 755 Inter well Spacing May Daily Production (1) 10,000 2 Parent wells 5New May Wells 1,000MBoe Type Curve 1 Mile Boepd 1,000 Upper Woodford Lower Woodford 175 100 0 20 40 60 80 100 120 140 160 180 Days on Production 1. Normalized to 7,500 lateral 15

Bakken Performance Continues to Improve Record Wells Through Enhanced Completions Two record 30 day cumulative production: Brangus North flowed 51.8 MBoe (86% oil), 9,900 lateral Rath Federal flowed 43.3 MBoe (84% oil), 13,800 lateral Both wells used 2 3x more proppant and diverter technology Cum Boe 140,000 120,000 100,000 80,000 60,000 40,000 20,000 0 Strong Bakken Producers 0 50 100 150 Days Well Name Data as of October 30, 2016 Prod. Days Cum. Production (MBoe) Brangus North Rath Federal Nashville Maryland 900 MBoe type curve Current Rate (Boepd) Maryland 2 16H (1) 160 128.0 689 Nashville 2 21H (1) 123 120.2 903 Maryland IP: 1,264 Boe Recent completions MB,TF1,TF2 Nashville IP: 1,417 Boe MB or TF1 MB and TF1 MB and TF1 Brangus North IP: 2,493 Boe MB,TF1,TF2,TF3 Rath Federal IP: 2,395 Boe Brangus North 1 2H2 61 105.2 1,625 Rath Federal 5 22H 75 91.5 898 1. Maryland s current rate is as of 10/19/16 and Nashville s current rate is as of 9/6/16 CLR Leasehold 2015 Operated Spuds 2016 Operated Spuds 20 miles 16

Beginning Work to Capitalize on Uncompleted Bakken Wells Valuable uncompleted well (1) inventory Adding 9 gross operated completions in 2016 above original budget Projecting ~175 uncompleted wells (2) at YE 2016 Excluding 15 wells that will be stimulated but not produced with first sales until 2017 850 MBoe average EUR (upside potential with larger enhanced completions) Over 100% ROR for incremental gross completion cost of $3.5 million for uncompleted wells at $50 WTI and $3.00 Mcf Adding stimulation crews Two stimulation crews currently working Plan to have 4 stimulation crews working by YE 2016 Projected YE 2016 uncompleted well locations MB,TF1,TF2 MB,TF1,TF2,TF3 MB and TF1 CLR Leasehold Uncompleted wells 20 miles 1. Uncompleted wells are a gross operated number 2. Up from 135 uncompleted wells at YE 2015 17

Focus on Bakken Core Capital Efficiency at New Level F&D (1) Costs per Boe Down 70% Capital Efficiency (3) Up 242% F&D Cost (4) $30 $25 $20 $15 $10 $5 $27.40 per Boe $9.1 MM $24.15 per Boe $7.9 MM $21.73 per Boe $9.8 MM $10.67 per Boe $7.0 MM $8.13 per Boe $6.0 MM $25 $20 $15 $10 $5 Well Cost (2) ($MM) EUR per Well (MBoe) 1,000 900 800 700 600 500 400 300 200 100 405 MBoe 399 MBoe 41 36 Boe/$1,000 Boe/$1,000 550 MBoe 46 Boe/$1,000 800 MBoe 94 Boe/$1,000 900 MBoe 123 Boe/$1,000 160 140 120 100 80 60 40 20 Capital Efficiency (Net Boe/$1,000) (4) $0 $0 0 FY 2012 FY 2013 FY 2014 2H FY 2015 2016 FY 2012 FY 2013 FY 2014 2H FY 2015 2016 Target Target 1. F&D cost is net and computed by taking the CWC divided by Boe 2. Actuals for CLR operated wells spud in 2012, 2013, 2014, 2015 and 2016 projected 3. Capital efficiency based on reserves developed per dollar invested 4. Average net revenue interest of 82% assumed for net F&D and net capital efficiency 0 18

CLR Bakken Differentials Improving 90+% of Bakken Barrels on Pipe Energy Transfer DAPL Expected Online: 2017 450,000 to 570,000 Bopd 3,500 Bakken Takeaway Capacity Thousand Bopd 3,000 2,500 2,000 1,500 1,000 500 2009 2010 2011 2012 2013 2014 2015 2016 2017 EST EST Local Refining Pipeline Rail Bakken Production Rail Pipeline Future Pipeline Energy Transfer ETCOP Expected Online: 2017 450,000 to 570,000 Bopd North Dakota Pipeline Authority and CLR estimates 19

Avg. Realized $/Boe (3) Low Costs (1) Competitively Positions CLR in Any Environment $80 $70 $60 $50 $40 $30 $20 $10 $0 $44.68 $30.93 69% $59.35 $43.32 73% $72.45 $54.74 76% $65.99 $48.59 $72.04 $53.52 74% 74% $66.53 $48.86 73% $31.48 $19.15 61% $23.91 $13.12 55% $3.40 $1.72 $3.34 $3.95 $4.74 $4.49 $2.95 $4.47 $5.82 $5.58 $6.02 $5.54 $3.86 $2.19 $2.35 $2.36 $2.38 $2.07 $2.06 $2.47 $4.08 $1.70 $1.74 $6.89 $5.87 $6.13 $1.31 $5.49 $5.69 $5.58 $4.30 $3.66 2009 2010 2011 2012 2013 2014 2015 YTD 2016 Production Expense Cash G&A (2) Production/Severance Tax & Other Interest Cash Margin (1) $10.79 per Boe, ~12% lower than FY 2015 1. Cash margin presented on this slide represents the Company s average sales price for a period expressed in barrels of oil equivalent (Boe) less production expenses, production taxes, G&A expenses (exclusive of non cash equity compensation expenses), and interest expense, all expressed on a per Boe basis. Cash margin does not reflect all activities of the Company that give rise to cash inflows and outflows and specifically excludes income and costs associated with derivative settlements, service operations, exploration activities, asset dispositions, and various non operating activities. These items are excluded from the computation of cash margin because they can vary significantly from period to period in a manner that does not correlate with changes in the Company s production and sales volumes. Therefore, these items are not typically utilized by management on a per Boe basis in assessing the performance of the Company s E&P operations from period to period. See Continuing to Deliver Strong Margins on slide 35 for additional details on the method for calculating cash margin. 2. See Cash G&A Reconciliation to GAAP on slide 39 for a reconciliation of GAAP Total G&A per Boe to Cash G&A per Boe, which is a non GAAP measure 3. Based on average oil equivalent price (excluding derivatives and including natural gas) 20

Strong Liquidity & Financial Profile Unsecured Credit Facility Ample liquidity with $2.75 billion revolver; can upsize to $4.0 billion (1) No borrowing base redetermination Net Debt (3) / 3Q 2016 Annualized EBITDAX (4) 4.40x Net Debt (3) /3Q 2016 Avg. Daily Production Financial Metrics (2) $32,779 Net Debt (3) / TTM EBITDAX (4) 4.13x Net Debt (3) /YE 2015 Proved Reserves $5.56 2 year extension option beyond 2019 (1) Financial Strength Redeeming 2020 Notes and 2021 Notes on 11/10/16 No near term debt maturities (Earliest is $500 million in 11/2018) ($MM) 3,000 2,500 2,000 1,500 1,000 No maturities for ~2 years $2.75 billion credit facility LIBOR + 1.5% Debt Maturities Summary $2,455 Undrawn Bonds will be redeemed 11/10/16 500 $1,000 4.3% average interest rate YTD $500 7.375% $700 $295 $400 $200 0 2016 2017 2018 2019 2020 2021 2022 2023 2024 2044 Revolver Callable Callable Callable Balance 10/1/15 4/1/16 3/15/17 1. With lender consent 10/31/16 2. All ratios are as of 9/30/16, except where noted 3. Net debt is a non GAAP measure and represents total debt as reflected on the Company s balance sheet of $6.83 billion, less cash and cash equivalents of $19.5 million as determined under GAAP as of September 30, 2016 4. See slide 37 for reconciliation of GAAP net income and net cash provided by operating activities to EBITDAX, which is a non GAAP measure 7.125% 5.0% $2,000 4.5% $1,500 3.8% 4.9% 21

Updated 2016 Guidance Production & Capital Guidance as of August 2016 Guidance as of November 2016 Production (Boe per day) 210,000 220,000 215,000 220,000 Capital expenditures (non acquisition) $920 million $1.1 billion Operating Expenses Production expense ($ per Boe) $3.75 $4.25 $3.50 $4.00 Production tax (% of oil & gas revenue) 6.75% 7.25% 6.75% 7.25% Cash G&A expense (1) ($ per Boe) $1.20 $1.60 $1.20 $1.60 Non cash equity compensation ($ per Boe) $0.65 $0.85 $0.50 $0.70 DD&A ($ per Boe) $20.00 $22.00 $20.00 $22.00 Average Price Differentials NYMEX WTI crude oil ($ per barrel of oil) ($7.00) ($8.00) ($7.00) ($8.00) Henry Hub natural gas (2) ($ per Mcf) $0.00 ($0.65) $0.00 ($0.65) Income tax rate 38% 38% Deferred taxes 90% 95% 90% 95% Bolded item above in guidance denotes a change from the previous disclosure 1. See Cash G&A Reconciliation to GAAP on slide 39 for a reconciliation of GAAP total G&A per Boe to cash G&A per Boe, which is a non GAAP measure 2. Includes natural gas liquids production in differential range 22

CONTACT INFORMATION J. Warren Henry Vice President, Investor Relations & Research Phone: 405 234 9127 Email: Warren.Henry@CLR.com Alyson L. Gilbert Manager, Investor Relations Phone: 405 774 5814 Email: Alyson.Gilbert@CLR.com Website: www.clr.com/investors 23

REFERENCE MATERIALS 24

Updated 2016 Capital Budget Allocation Leasehold $93 $1.1 Billion in non-acquisition capex ($ in millions) Other $68 2016 wells with first production NW Cana JDA $64 Rigs Gross Operated Wells Net Operated Wells Total Net Wells (1) STACK Drilling $208 SCOOP Drilling $214 Bakken Drilling $453 Bakken 4 29 23 46 SCOOP 4 33 25 28 STACK 6 32 17 19 NW Cana JDA & Other 5 25 10 11 Totals 19 119 75 104 1. Represents projected net operated & non-operated wells 25

Historical Organic Growth Boe Per Day 250,000 200,000 150,000 100,000 50,000 Targeting 215,000 to 220,000 Boe per Day Production Average in 2016 STACK / NW Cana SCOOP Bakken Legacy 207,840~217,500 9% 32% 52% MMBoe 1,400 1,200 1,000 800 600 400 200 Total Proved Reserves Down 9% YOY with 47% Reduction in WTI Prices STACK / NW Cana SCOOP Bakken Legacy 1,226 7% 34% 54% 0 7% 2010 2011 2012 2013 2014 2015 3Q'16 2016E 0 5% 2010 2011 2012 2013 2014 2015 For 3Q 2016: Natural Gas 44% 56% Oil For YE 2015: Natural Gas 43% 57% Oil 26

Enhanced Completions Type Curves Boe per day 10,000 1,000 100 STACK Over Pressured Oil Type Curve Well Count Type 1,700 Curve MBoe (Normalized Type Curve (Norm. to 9,800' to LL) 9,800 LL) Act. Production (Norm. to 9,800 LL) Series2 40 30 20 10 Well Count Boe per day 10,000 1,000 SCOOP Condensate Fairway Type Curve Enhanced Well Count Enhanced 2,000 MBoe Condensate Type Curve Fairway (Norm. Production to 7,500 LL) Enhanced Act. Production Condensate (Norm. Fairway to 7,500 TC LL) (7,500' LL) 40 30 20 10 Well Count 10 10,000 Boe per day 1,000 100 0 0 6 12 18 24 Producing Months 30 36 Bakken Type Curve 30 Well Count 900 MBOE MBoe Type TC BOEPD Curve (Norm. to 9,800 LL) 2016 Act. Production Actual BOEPD (Norm. to 9,800 LL) 20 10 Well Count 100 10,000 Boe per day 1,000 0 0 6 12 18 24 30 36 Producing Months NW Cana JDA Type Curve Well Count Type 2,150 Curve MBoe (Normalized Type Curve to (Norm. 9,800' to LL) 9,800 LL) Act. Production (Normalized (Norm. to 9,800 to 9,800') LL) 40 30 20 10 Well Count 10 0 0 6 12 18 24 30 36 Producing Months 100 0 0 6 12 18 24 30 36 Producing Months 27

Boden Yocum Unique Results Defined by Fault Yocum designed to test down thrown side of fault identified from 3D seismic east of Boden Boden 1 15 10XH Upper Meramec Yocum 1 35 26XH Upper Meramec Up to 525 of vertical displacement on fault ~400 Boden on up thrown side of fault in condensate window Yocum on down thrown side of fault in gas window Only fault of this magnitude identified by 3D seismic/well control that could influence production Boden 1 15 10XH IP: 1,000 Bopd, 15.0 MMcfd 15,747 GOR Days online: 329 Cum Prod: 505 MBoe (27% oil) Current rate: 2,006 Boepd (23% oil) Results increase acreage in gas window by 2% Yocum 1 35 26XH IP: 17 Bopd, 14 MMcfd 824,000 GOR Days online: 184 Cum Prod: 309 MBoe (99.5% gas) Current rate: 1,317 Boepd (99.5% gas) 5mi 28

SCOOP Woodford Condensate Window Density Projects Strong Repeatable Results 10,000 Poteet Daily Production(1) 10,000 Honeycutt Daily Production (1) 10 New Poteet Wells 9 New Honeycutt Wells 1,725 7500' MBoe Neck Type Curve 7500' 1,725 Neck MBoe Type Type Curve Curve MCFED MCFED 1,000 1,000 Unit cumulative production: 44,246 MMcfe (7% oil) Unit cumulative production: 31,562 MMcfe (28% oil) 100 0 90 180 270 360 450 540 630 Days on Production 100 0 60 120 180 240 300 360 420 480 540 Days on Production Vanarkel Daily Production (1) Newy Daily Production (1) 10,000 10,000 MCFED 1,000 100 Unit cumulative production: 20,593 MMcfe (25% oil) New Vanarkel Wells 7 New Vanarkel Wells Woodford 1,725 MBoe Condensate Type Curve 7500' Type Curve Enhanced Woodford Completion Condensate 2,000 MBoe 7500' Type Type Curve Curve 0 90 180 270 360 Days on Production 1. Normalized to 7,500 lateral; Cumulative production as of 10/30/16 MCFED 1,000 100 Unit cumulative production: 27,137 MMcfe (15% oil) 7 New Newy Wells 1,725 MBoe Type Curve Enhanced Completion 2,000 MBoe Type Curve 0 30 60 90 120 150 180 Days on Production 29

SCOOP Woodford Condensate Growing Through Step Outs and Enhanced Completions Enhanced completions increasing performance Delivering 40% production uplifts Increased type curve EUR by 15% to 2,000 MBoe > 100% ROR for incremental capital of $400,000 (1) ~50% more proppant per foot on average 4 rigs drilling 400,000 350,000 300,000 Enhanced Completions Offset Wells 1,725 MBOE Type Curve 250,000 Cum BOE 200,000 150,000 100,000 180 days ~40% higher than offsets 60+ miles 6 Miles 50,000 0 0 30 60 90 120 150 180 210 240 270 300 Days 24 wells with > 180 days of production 1. When compared to offset production at $50 WTI and $3.00 Mcf 12 Miles CLR Leasehold CLR Enhanced Completion Woodford HZ Producing Well Gas Condensate Oil 30

SCOOP Woodford Oil Enhanced Completions Success Increase EUR 30% 23 enhanced completions outperform legacy offsets ~30% increase in 180 day rate ~30% increase in EUR to 1.3 MMBoe per well for 2 mile lateral ~30% ROR (1) for $9.8 million CWC At least 50,000 net acres upgraded to new EUR model Oil Window Enhanced Completions MAY INFILL 200,000 180,000 160,000 Enhanced completions (23 wells) Offset wells 1,340 MBoe Type Curve 6 Miles Cum Boe 140,000 120,000 100,000 80,000 60,000 180 days ~30% higher than offsets 40,000 20,000 0 0 50 100 150 200 Days 1. Assumes $50 WTI and $3.00 Mcf 12 Miles CLR Leasehold CLR Enhanced Completion Woodford HZ Producing Well Gas Condensate Oil 31

SCOOP Springer Oil Rich Asset Untested upside Longer laterals 7,500 to 10,000 Enhanced completions SCOOP 10,000 Boe per day 1,000 100 10 940 MBoe Type Curve Well Count Type Curve (Normalized to 4,500' LL) Act. Production (Normalized to 4,500') 0 6 12 18 24 30 36 Producing Months 90 80 70 60 50 40 30 20 10 0 Well Count Hartley Pilot Jeanna Pilot ROR 100% 80% 60% Target EUR: 940 MBoe Avg. Lateral: 4,500 Springer ROR 40% 20% $7.0MM Target 2016 $7.8MM YE 2015 0% $30 $40 $50 $60 WTI Oil Price, $/BBL Springer Fairway 12 Miles Current Springer Density Test CLR Leasehold CLR Springer Shale Producers Non Op. Springer Shale Producer 32

SCOOP Woodford Non Strategic Asset Sale Closed October 14, 2016 $296 million sale price ~30,000 net acres Net production of ~700 Boepd Outline of leasehold sale Minimal proved reserves (less than 1%) CLR Leasehold Woodford Producing Well CLR 2016 Completion 33

Bakken Non Strategic Asset Sale Closed September 30, 2016 CANADA $215 million sale price 80,000 net acres Non strategic acreage 68,000 net acres in Williams County, North Dakota 12,000 net acres in Roosevelt County, Montana Outline of leasehold and production sold MB or TF1 MB,TF1,TF2 MB and TF1 MB and TF1 MB,TF1,TF2,TF3 Net production of ~2,700 Boepd Minimal proved reserves (less than 1%) CLR Leasehold 2015 Operated Spuds c 2016 Operated Spuds 34

Continuing to Deliver Strong Margins (1) 2009 2010 2011 2012 2013 2014 2015 3Q 2016 YTD 2016 Realized oil price ($/Bbl) $54.44 $70.69 $88.51 $84.59 $89.93 $81.26 $40.50 $37.66 $33.51 Realized natural gas price ($/Mcf) $2.95 $4.26 $4.87 $3.73 $4.87 $5.40 $2.31 $2.02 $1.57 Oil production (Bopd) 27,459 32,385 45,121 68,497 95,859 121,999 146,622 116,277 131,873 Natural gas production (Mcfpd) 59,194 65,598 100,469 174,521 240,355 313,137 450,558 549,374 524,441 Total production (Boepd) 37,324 43,318 61,865 97,583 135,919 174,189 221,715 207,840 219,280 EBITDAX ($000's) (2) $450,648 $810,877 $1,303,959 $1,963,123 $2,839,510 $3,776,051 $1,978,896 $386,789 $1,229,507 Key Operational Statistics (per Boe) (3) Average oil equivalent price (excludes derivatives) $44.68 $59.35 $72.45 $65.99 $72.04 $66.53 $31.48 $26.42 $23.91 Production expense $6.89 $5.87 $6.13 $5.49 $5.69 $5.58 $4.30 $3.50 $3.66 Production tax and other $2.95 $4.47 $5.82 $5.58 $6.02 $5.54 $2.47 $1.81 $1.74 Cash G&A (4) $2.19 $2.35 $2.36 $2.38 $2.07 $2.06 $1.70 $1.63 $1.31 Interest $1.72 $3.34 $3.40 $3.95 $4.74 $4.49 $3.86 $4.29 $4.08 Total of selected costs $13.75 $16.03 $17.71 $17.40 $18.52 $17.67 $12.33 $11.23 $10.79 Cash margin (1) $30.93 $43.32 $54.74 $48.59 $53.52 $48.86 $19.15 $15.19 $13.12 Cash margin % 69% 73% 76% 74% 74% 73% 61% 57% 55% 1. Cash margin represents the Company s average sales price for a period expressed in barrels of oil equivalent (Boe) less production expenses, production taxes, G&A expenses (exclusive of non cash equity compensation expenses), and interest expense, all expressed on a per Boe basis. Cash margin does not reflect all activities of the Company that give rise to cash inflows and outflows and specifically excludes income and costs associated with derivative settlements, service operations, exploration activities, asset dispositions, and various non operating activities. These items are excluded from the computation of cash margin because they can vary significantly from period to period in a manner that does not correlate with changes in the Company s production and sales volumes. Therefore, these items are not typically utilized by management on a per Boe basis in assessing the performance of the Company s E&P operations from period to period. 2. See EBITDAX reconciliation to GAAP on slide 37 for a reconciliation of GAAP net income and net cash provided by operating activities to EBITDAX, which is a non GAAP measure. 3. Average costs per Boe have been computed using sales volumes and exclude any effect of derivative transactions. 4. See Cash G&A Reconciliation to GAAP on slide 39 for a reconciliation of GAAP Total G&A per Boe to Cash G&A per Boe, which is a non GAAP measure 35

EBITDAX Reconciliation to GAAP We use a variety of financial and operational measures to assess our performance. Among these measures is EBITDAX. We define EBITDAX as earnings (net income (loss)) 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 net cash provided by operating activities 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 (loss) and net cash provided by operating activities 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 (loss) or net cash provided by operating activities 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 (loss) and net cash provided by operating activities to EBITDAX for the applicable periods. 36

EBITDAX Reconciliation to GAAP The following tables provide reconciliations of our net income (loss) and net cash provided by operating activities to EBITDAX for the periods presented: In thousands 2009 2010 2011 2012 2013 2014 2015 3Q 2016 YTD 2016 Net income (loss) $ 71,338 $ 168,255 $ 429,072 $ 739,385 $ 764,219 $ 977,341 $ (353,668) $ (109,621) $ (427,348) $ (567,025) Interest expense 23,232 53,147 76,722 140,708 235,275 283,928 313,079 82,074 244,949 325,124 Provision (benefit) for income taxes 38,670 90,212 258,373 415,811 448,830 584,697 (181,417) (65,276) (259,254) (342,048) Depreciation, depletion, amortization and accretion 207,602 243,601 390,899 692,118 965,645 1,358,669 1,749,056 414,671 1,320,423 1,781,201 Property impairments 83,694 64,951 108,458 122,274 220,508 616,888 402,131 57,689 202,728 283,729 Exploration expenses 12,615 12,763 27,920 23,507 34,947 50,067 19,413 3,987 8,726 13,458 Impact from derivative instruments: Total (gain) loss on derivatives, net 1,520 130,762 30,049 (154,016) 191,751 (559,759) (91,085) (15,237) 21,768 5,228 Total cash received (paid), net 569 35,495 (34,106) (45,721) (61,555) 385,350 69,553 5,274 83,241 104,260 Non cash (gain) loss on derivatives, net 2,089 166,257 (4,057) (199,737) 130,196 (174,409) (21,532) (9,963) 105,009 109,488 Non cash equity compensation 11,408 11,691 16,572 29,057 39,890 54,353 51,834 13,228 34,274 45,819 Loss on extinguishment of debt 24,517 EBITDAX (non GAAP) $ 450,648 $ 810,877 $ 1,303,959 $ 1,963,123 $ 2,839,510 $ 3,776,051 $ 1,978,896 $ 386,789 $ 1,229,507 $ 1,649,746 TTM at 9/30/16 In thousands 2009 2010 2011 2012 2013 2014 2015 3Q 2016 YTD 2016 TTM at 9/30/16 Net cash provided by operating activities $ 372,986 $ 653,167 $ 1,067,915 $ 1,632,065 $ 2,563,295 $ 3,355,715 $ 1,857,101 $ 366,167 $ 863,888 $ 1,305,497 Current income tax provision (benefit) 2,551 12,853 13,170 10,517 6,209 20 24 (10) 2 4 Interest expense 23,232 53,147 76,722 140,708 235,275 283,928 313,079 82,074 244,949 325,124 Exploration expenses, excluding dry hole costs 6,138 9,739 19,971 22,740 25,597 26,388 11,032 3,960 8,493 13,028 Gain on sale of assets, net 709 29,588 20,838 136,047 88 600 23,149 6,158 103,174 103,392 Tax benefit (deficiency) from stock based compensation 2,872 5,230 15,618 13,177 (9,460) (9,460) (9,460) Other, net (3,890) (3,513) (4,606) (7,587) (1,829) (17,279) (10,044) (2,002) (9,023) (11,043) Changes in assets and liabilities 46,050 50,666 109,949 13,015 10,875 126,679 (228,622) (60,098) 27,484 (76,796) EBITDAX (non GAAP) $ 450,648 $ 810,877 $ 1,303,959 $ 1,963,123 $ 2,839,510 $ 3,776,051 $ 1,978,896 $ 386,789 $ 1,229,507 $ 1,649,746 37

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 and gains and losses on asset sales. Management believes these measures provide useful information to analysts and investors for analysis of our operating results. 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 property dispositions. 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 tables reconcile 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 2016 3Q 2015 YTD 2016 YTD 2015 In thousands, except per share data $ Diluted EPS $ Diluted EPS $ Diluted EPS $ Diluted EPS Net income (loss) (GAAP) $ (109,621) $ (0.30) $ (82,423) $ (0.22) $(427,348) $ (1.15) $(213,992) $ (0.58) Adjustments: Non cash (gain) loss on derivatives (9,963) (34,610) 105,009 (26,011) Property impairments 57,689 96,697 202,728 321,130 Gain on sale of assets (6,158) (288) (103,174) (22,930) Total tax effect of adjustments (14,800) (22,888) (76,447) (87,078) Total adjustments, net of tax 26,768 0.08 38,911 0.10 128,116 0.34 185,111 0.50 Adjusted net income (loss) (Non GAAP) $ (82,853) $ (0.22) $ (43,512) $ (0.12) $ (299,232) $ (0.81) $ (28,881) $ (0.08) Weighted average diluted shares outstanding 370,483 369,599 370,327 369,499 Adjusted diluted net income (loss) per share (Non GAAP) $ (0.22) $ (0.12) $ (0.81) $ (0.08) 38

Cash G&A Reconciliation to GAAP Our presentation of cash general and administrative ( G&A ) expenses per Boe is a non GAAP measure. We define cash G&A per Boe as total G&A determined in accordance with U.S. GAAP less non cash equity compensation expenses and corporate relocation expenses, expressed on a per Boe basis. We report and provide guidance on cash G&A per Boe because we believe this measure is commonly used by management, analysts and investors as an indicator of cost management and operating efficiency on a comparable basis from period to period. In addition, management believes cash G&A per Boe is used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis of G&A spend without regard to stock based compensation programs which can vary substantially from company to company. Cash G&A per Boe should not be considered as an alternative to, or more meaningful than, total G&A per Boe 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 total G&A per Boe as determined under U.S. GAAP to cash G&A per Boe for the periods presented. 2009 2010 2011 2012 2013 2014 2015 3Q 2016 YTD 2016 Total G&A per Boe (GAAP) $3.03 $3.09 $3.23 $3.42 $2.91 $2.92 $2.34 $2.32 $1.88 Less: Non cash equity compensation per Boe ($0.84) ($0.74) ($0.73) ($0.82) ($0.80) ($0.86) ($0.64) ($0.69) ($0.57) Less: Relocation expenses per Boe ($0.14) ($0.22) ($0.04) Cash G&A per Boe (non GAAP) $2.19 $2.35 $2.36 $2.38 $2.07 $2.06 $1.70 $1.63 $1.31 39