Investor Update. October 2018

Investor Update October 2018

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 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 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, 2017, 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: Continues To Deliver On Breakout Year 3Q18 Update Generate Sustainable Free Cash Flow & Returns Annual FCF Approaching $1 Billion (1) Annual ROCE 13-15% (2) Dividend Under Consideration 20-24% Annual Production Growth Bakken up 23% YoY STACK up 58% YoY SCOOP up 10% YoY 2018 Oil-Weighted Growth 3Q18 Oil Volumes up 5% over 2Q18 (164,605 Bopd) 4Q18 Oil Volumes Expected to Grow ~10% over 3Q18 Oil as % Production: 57% in September 4Q18 Production Ramp Up to 70 Bakken Wells to be Completed (~40% of 2018) Up to 18 SpringBoard Wells to be Completed Achieve Debt Targets Targeting $5.4-$5.6 Billion Net Debt (3) at YE18 Targeting $5 Billion Net Debt in 2019 1. Free cash flow is a non-gaap measure. With respect to this projected amount, please see slide 28 for an explanation of the factors that make a quantitative reconciliation of this forward-looking estimate to U.S. GAAP not possible. 2018 average WTI of $68 is assumed in our model for free cash flow. 2. See the calculation of ROCE for historical periods on slide 35. 3. Net debt is a non-gaap measure. With respect to this projected amount, please see slide 29 for an explanation of the factors that make a quantitative reconciliation of this forward-looking estimate to U.S. GAAP not possible. 3

CLR s Path to Sustainable, Positive Cash-Flow Growth Boepd 400,000 300,000 200,000 100,000 0 STACK SCOOP Bakken Legacy Exploration / Asset Accumulation Asset Development 242,637 290,000-300,000 2010 2011 2012 2013 2014 2015 2016 2017 2018E +22% YoY 2018 Production (1) Millions ($) $2,000 $1,000 $0 -$1,000 -$2,000 -$526 -$845 -$1,393 Outspend (2) Free Cash Flow (2) -$999 -$1,329 -$875 $845MM $227MM Approach $1B Outspend Asset Divestiture Proceeds Free Cash Flow Projected Free Cash Flow 2010 2011 2012 2013 2014 2015 2016 2017 2018E 4x YoY 2018 FCF (2) ROCE (3) 30% 20% 10% 0% -10% $96 $95 $97 $95 $79 Average WTI Price (4) 13%-15% $50 $51 $65 23% 22% 17% 19% 16% $43-2% -1% 4% 2010 2011 2012 2013 2014 2015 2016 2017 2018E 3.5x YoY 2018 ROCE (3) 1. Calculated at the midpoint of annual production guidance. 2. Free cash flow / outspend is a non-gaap measure. See slide 28 for a definition of this measure and a reconciliation of the historical amounts to the most comparable U.S. GAAP measure. Also, with respect to projected amounts, please see slide 28 for an explanation of the factors that make a quantitative reconciliation of this forward-looking estimate to U.S. GAAP not possible. 2016 & 2017 totals are inclusive of asset divestiture proceeds of $631 million and $144 million, respectively. 2018 average WTI of $68 is assumed in our model for free cash flow. 3. See the calculation of ROCE for historical periods on slide 35. 4. Average WTI price is the SEC price used for reserve calculations; rounded to the nearest dollar. 4

CLR: Lowest Cost, Oil-Weighted Growth & Peer-Leading Capital Efficiency $8.50 $8.00 $7.50 Lowest Cost Per Boe (1) 350% 300% Highest Recycle Ratio CLR 95% of rigs focused on oil and liquids-rich assets LOE per Boe $7.00 $6.50 $6.00 $5.50 $5.00 $4.50 $4.00 CLR YTD AVG (2) $3.50 20% 30% 40% 50% 60% 70% 80% Oil Production % (Excludes Liquids) Avg. Unhedged Recycle Ratio (3) 250% 200% 150% 100% 50% $8 $12 $16 $20 $24 Avg. Unhedged Margins per Boe (4) 100% of CLR crude oil is currently unhedged 2018 CLR Peer Avg (5) Growth 20% - 24% ~14% FCF Approach $1B (6) ~$300 MM FCF Yield ~3.9% (7) ~0.6% Select peers for all charts include: APC, CXO, DVN, EOG, NBL, NFX, OAS, PXD, WLL, WPX, XEC. 1. Source: Public company filings as of 2Q18, except for CLR. 2. Average year-to-date 9/30/2018 production expense and oil production %. 3. Source: Stephens. Recycle ratio is calculated as margins divided by F&D per Boe. 2014-2017. 4. Source: Stephens. Margins are calculated as E&P revenue less LOE, TT&O, cash G&A & interest expense per Boe. 2015-18E. 5. Source: 2018 Bloomberg consensus estimates as of 3Q18. 6. Free cash flow is a non-gaap measure. See slide 28 for a definition of this measure and for an explanation of the factors that make a quantitative reconciliation of this forward-looking estimate to U.S. GAAP not possible. 2018 average WTI of $68 is assumed in our model for free cash flow. 7. Free cash flow yield, a non-gaap measure, is calculated as forecasted 2018 free cash flow divided by market cap as of September 30, 2018. See slide 28 for an explanation of the factors that make a quantitative reconciliation of this forward-looking measure to U.S. GAAP not possible. 5

Bakken 3Q18 Highlights 3Q18 Update Returns Better Than Ever Entire 2017 Bakken Program Paid Out by the End of 3Q18 (133 Operated Wells) (1) Uplifted Well Performance All CLR Top 10 30-Day Rate Bakken Wells in Past 12 Mos. 42 Completions in 3Q18: 2,013 Boepd Avg. per Well (2) Bakken Record Production Record CLR Quarter: 167,643 Boepd (128,497 Bopd) Strong Growth 6% Production Growth over 2Q18 23% Production Growth over 3Q17 4Q18 Production Ramp Up to 70 Gross Operated Wells to be Completed 1. 2017 Bakken Program consists of 133 gross operated wells with first production in 2017. 2. Maximum average 24-hour IP rate. 6

CLR Bakken Production & Returns Delivering Record Results Gross ND Bakken Production (Bo per Day Aug-18) CLR: #1 Bakken Producer 160,000 140,000 120,000 100,000 80,000 60,000 CLR: #1 Lease Position with Deep Inventory ~1,700 Bakken wells completed (1) 4,000+ Bakken wells in inventory ~800,000 net reservoir acres 8 rigs drilling CLR is ~12% of ND Bakken Production CLR Select Peers (2) 2 stim crews working; 4 stim crews at YE18 ROR 300% 250% 200% 150% 100% 50% CLR: Bakken Returns Better Than Ever 1,200 MBoe 980 MBoe 800 MBoe 603 MBoe 430 MBoe 0% 2011 $55 $60 $65 $70 $75 $80 $85 WTI Oil Price, $/BBL CLR: 1.2 MMBoe Unit Type Curve 175% ROR (3) at $70 WTI 2018 2017 2015 2014 Average 750 well spacing Entire 2017 Bakken Program Paid Out by the End of 3Q18 (133 Operated Wells) (4) 1. As of 3Q18. 2. Source: NDIC. Select peers include COP, OAS, WLL, HES, MRO, XOM. 3. ROR is based on $70 WTI and $3.00 Henry Hub with $8.4 MM of Capex. See ROR footnote on slide 22. 4. 2017 Bakken Program consists of 133 gross operated wells with first production in 2017. 7

Two More 30-Day Rate Bakken Wells Added To Top Ten List Cumulative Production (Boe) 300,000 250,000 200,000 150,000 100,000 50,000 0 84 Bakken 60-Stage Completions (1) vs. Type Curve 0 40 80 120 160 200 240 280 Days Top 10 CLR-Operated Bakken Wells 60-Stage All Optimized Completions High Stage Completions 1,200 MBoe Mboe Type Curve 30 Day Avg Daily Oil 30 Day Avg Daily Gas 30 Day Avg Daily BOE Quarter 1 Mountain Gap 7-10H 2,603 3,001 3,104 2Q18 2 Monroe 6-2H 2,278 3,546 2,869 4Q17 3 Mountain Gap 8-10H1 2,264 2,798 2,730 2Q18 4 Lansing 6-25H 1,995 3,725 2,616 1Q18 5 Uhlman Federal 3-7H 1,989 2,835 2,461 2Q18 6 Pittsburgh 3-7H 1,951 2,615 2,387 2Q18 7 Wiley 8-25H 1,777 3,071 2,289 3Q18 8 Vardon 2-14H 1,682 3,033 2,188 1Q18 9 Tarentaise Federal 1-19H 1,671 2,728 2,126 4Q17 10 Mountain Gap 3-10H 1,784 1,859 2,094 3Q18 Top 10 CLR-Operated Bakken Wells 20 Miles 6 5 2 4 CLR 30-Day Record Wells CLR Acreage 8 30 miles 7 1 3 10 9 40 miles 1. 84 operated optimized high stage completions for MB, TF1, and TF2 wells through 3Q18 with down days removed. 8

Uplifted Well Performance Continues To Expand Across Bakken Field Industry-Wide Bakken Units with Well(s) that Produced +100,000 Boe in First 90 Days 2000-2014 (First 15 Years) 185 Wells (12 Wells/Year) 2015-2Q18 (Past 3.5 Years) 563 Wells (161 Wells/Year) CLR Acreage CLR wells or units with wells >100MBoe in 90 Days Wells or units with wells >100MBoe in 90 Days Approximate Bakken Field Outline 100 mi 9

SCOOP & STACK 3Q18 Highlights 3Q18 Update 3 Meramec Units Flow at Combined 74,260 Boepd from 18 Wells (1) (Avg. 4,126 Boepd/Well) (2) Jalou: Industry Record 4,234 Boepd Avg. per Well (~58% Oil) Homsey: 3,521 Boepd Avg. per Well (~59% Oil) Simba: 4,622 Boepd Avg. per Well (~13% Oil) STACK Geology and Execution Matters All CLR STACK Units in Over-Pressured Window Thick, High Quality Meramec Reservoirs Industry Leading Unit Results; Unit Wells Outperform Type Curves 3Q18 South Production 120,246 Boepd 25% Production Growth over 3Q17 SCOOP SpringBoard On Track 9 Springer Wells Flow-Back; 8 Wells in Various Stages of Completions 9 Woodford/Sycamore Wells Drilled SpringBoard Efficiency Gains 100% Oil, Gas and Water Production Piped To Date Marketing Infrastructure in Place: $2 Differential to WTI 1. Combined 24-hour IP rate from 18, 2-mile equivalent wells. 2. Average 24-hour IP rate per well from 18, 2-mile equivalent wells. 10

STACK: 3 Meramec Units Flow At Initial Combined Rate Of 74,260 Boepd From 18 Wells (1) In Over-Pressured Window Per Unit Combined 24-Hour IP: 74,260 Boepd (Average 4,126 Boepd per Well) (2) Unit 2-Mi Equiv. Wells/Unit Bopd/Unit Mcfpd/Unit Boepd/Unit Jalou 6 14,820 63,522 25,404 Zip Code Matters: All CLR STACK Units In Over-Pressured Window Homsey 6 12,425 52,207 21,127 Simba 6 3,728 144,004 27,729 Total 18 30,973 259,733 74,260 Over-Pressured Normal-Pressured Over-Pressured Oil Window Unit 2-Mi Equiv. Wells/Unit Bopd/Well Mcfpd/Well Boepd/Well Jalou 6 2,470 10,587 4,234 Homsey 6 Wells Oil Homsey 6 2,071 8,701 3,521 Over-Pressured Condensate Window Unit 2-Mi Equiv. Wells/Unit Bopd/Well Mcfpd/Well Boepd/Well Simba 6 621 24,001 4,622 Oil-Focused Development Underway Up to 65 operated units to be developed in over-pressured oil and condensate windows 4 rigs focusing on unit development 1 rig currently HBP ing SK JDA Simba 6 Wells Condensate Jalou 6 Wells Oil 1. Combined 24-hour IP rate from 18, 2-mile equivalent wells. 2. Average 24-hour IP rate per well from 18, 2-mile equivalent wells. *CLR acreage position not shown for competitive purposes. 11

STACK Meramec Over-Pressured Oil Window Jalou & Homsey Unit Wells Outperforming Unit Type Curve Jalou Unit Wells Producing ~75% Above Type Curve (1) Combined unit 24-hour IP: 14,820 Bopd & 63,522 Mcfd (25,404 Boepd) Average 24-hour IP per well: 2,470 Bopd & 10,587 Mcfd (4,234 Boepd) Industry record rate for unit wells in the STACK over-pressured oil window Includes 6, 2-mile equivalent Meramec wells: 4 wells in Upper Meramec 2 wells in Lower Meramec Avg. Cumulative BOE 80,000 70,000 60,000 50,000 40,000 30,000 20,000 10,000 0 6 Jalou Wells Outperforming Type Curve (1) +75% 1,200 MBOE Type Curve (Normalized to 9800' LL) Average Jalou Cumulative BOE 0 6 12 18 24 30 Producing Days Homsey Unit Wells Producing ~15% Above Type Curve (1) Combined unit 24-hour IP: 12,425 Bopd, 52,207 Mcfd (21,127 Boepd) Average 24-hour IP per well: 2,071 Bopd, 8,701 Mcfd (3,521 Boepd) Includes 6, 2-mile equivalent Meramec wells: 4 wells in Upper Meramec 2 wells in Lower Meramec Avg. Cumulative BOE 80,000 70,000 60,000 50,000 40,000 30,000 20,000 10,000 0 6 Homsey Wells Outperforming Type Curve (1) +15% 1,200 MBOE Type Curve (Normalized to 9800' LL) Average Homsey Cumulative BOE 0 6 12 18 24 30 Producing Days 1. Average production of 6 unit wells. 12

STACK Meramec Over-Pressured Oil Window Maximizing Value Through Optimal Unit Development Jalou & Homsey unit wells outperforming unit type curve by 15-75% These 6-well units are approaching the performance of 8-well units in CLR s unit development model Results confirm maximum economics achieved with up to 8 wells per unit: Average 2 zones per unit Up to 4 wells per zone +100% ROR (1) 8-10 months payout (1) 9,800 lateral Unit PV-10 ($ in MM) STACK Meramec Over-Pressured Oil Unit Economic Model $120 $100 $80 $60 $40 $20 $0 Uplift Supported by Jalou/Homsey Results Max. Economics Achieved with 6-8 Wells Well Count 1 2 4 6 8 10 Unit EUR (2) 1,700 3,400 6,000 8,000 9,600 10,500 300% 250% 200% 150% 100% 50% 0% Unit ROR% $9.5 million CWC Unit PV-10 $23 MM $46 MM $85 MM $100 MM $102 MM $90 MM Unit ROR 200% 200% 190% 140% 122% 94% 1. All references to ROR, PV-10, and payout are based on $70 WTI and $3.00 gas, see ROR footnote on slide 22. 2. EUR in MBoe. 13

STACK Meramec: Over-Pressured Condensate Window Simba Unit Wells Outperforming Parent Type Curve Simba Unit Wells Producing ~35% Above Parent Type Curve (1) Combined unit 24-hour IP: 3,728 Bopd, 144,004 Mcfd (27,729 Boepd) Average 24-hour IP per well: 621 Bopd, 24,001 Mcfd (4,622 Boepd) Includes 6 Meramec unit wells: 3 wells in Upper Meramec 3 wells in Lower Meramec Results will help define unit development model for STACK over-pressured condensate window Average Cumulative Boe 80,000 70,000 60,000 50,000 40,000 30,000 20,000 10,000 0 6 Simba Wells Outperforming Parent Type Curve (1) +35% 2,400 MBOE Type Curve (Normalized to 9800' LL) Average Simba Cumulative BOE 0 6 12 18 24 30 Producing Days 1. Average production of 6 unit wells. 14

SCOOP Project SpringBoard Potential To Increase CLR Oil Production 10% Over Next 12 Months High Impact Oil Project Project SpringBoard Proceeding On Schedule 400 MMBoe resource potential(1) 70-square miles of contiguous leasehold ~45,000 gross acres (~33,000 net) ~2,000 net acres added through trades in 3Q18 CLR-Operated Non-Operated Springer - Completing Developed Springer - Drilling Woodford - Drilling 17 of 18 Wells in Row 1 Drilled 9 Wells Flowing-Back 8 Wells Completing CLR-operated with ~75% avg. working interest 14 rigs drilling Springer (~85% Oil) 31 total operated units, up to 100 wells to drill 8 rigs drilling 9 wells flowing-back 8 wells in various stages of completions Woodford / Sycamore (~70% Oil) 35 total operated units, up to 250 wells to drill 6 rigs drilling 9 wells drilled to date 1. Gross unrisked resource potential. 15

SCOOP: SpringBoard s Operational Advantage SpringBoard Operational Efficiencies Cushing, OK $1MM per well Woodford/Sycamore drilling savings realized from no intermediate casing string 100% oil, gas and water production piped to date 100% of SpringBoard water production recycled through CLR-operated recycling facilities Crude Oil Marketing Advantage Planned Water Recycling Facility CLR Headquarters Project SpringBoard High quality, 46 o API crude with low water cut Benefiting from existing pipeline infrastructure Oil differentials below $2.00/barrel 50 miles to CVR Refinery 100 miles to Cushing CVR Refinery 25 miles CLR Acreage Basin Pipeline (100 mi) Velocity Pipeline (50 mi) 16

~$215MM In Proceeds Received From Minerals Venture Closing Mineral Ownership Creates New Growth Vehicle For CLR Capitalizing on CLR s proprietary knowledge of assets and operations to increase net revenue interest (NRI) Accelerating value through strategic alignment with CLR drilling schedule Owning Minerals Enhances Returns By Increasing Net Revenue Interest (3) Operator Leasehold (81.25% NRI) + Minerals Royalty (18.75% NRI) = Enhanced Returns (100% NRI) Continuing to grow minerals portfolio: 18.75% NRI ~$375MM combined incremental investment over next 3 years (CLR: $25MM/year) (1) CLR to fund 20% of future acquired 81.25% NRI + 18.75% NRI = 81.25% NRI minerals for 25%-50% of total revenue (2) 1. Future funding is subject to achieving agreed upon development thresholds. 2. Based on achieving certain predetermined targets. 3. Example for illustration purposes only and assumes a 100% working interest and acquisition of full unit royalty. 17

CLR Vision For Adding Value Through Minerals Short Term: Enhanced Returns ~$600MM total investment (1) Strategic focus on CLR-operated assets ~4x Potential Value (3) Accelerate value through strategic drilling CLR benefits from carry structure/enhanced NRI Long Term: Multi-$ Billion IPO Potential Most comparable structure to date (2) has generated ~4x return on investment (3) +$125MM Invested +$125MM Invested +$125MM Invested Initial Investment Year 1 Year 2 Year 3 Future Returns 1. Includes $375 million incremental investment. 2. Based on Viper Energy Partners, a mineral company owned and operated by an E&P company. 3. Statement is made based on the historic performance of Viper Energy Partners. While CLR s mineral assets and structure are different, CLR believes similar performance is possible. 18

Contact Information Rory Sabino Vice President, Investor Relations Phone: 405-234-9620 Email: Rory.Sabino@CLR.com Lucy Guttenberger Senior Investor Relations Associate Phone: 405-774-5878 Email: Lucy.Guttenberger@CLR.com Website: www.clr.com/investors 19

Reference Materials 20

2018 Guidance Production & Capital Capital expenditures budget (non-acquisition) 2018 Guidance $2.7 billion Production (Boe per day) 290,000-300,000 Exit rate production (Boe per day) 315,000-325,000 Operating Expenses Production expense ($ per Boe) $3.50 - $3.75 (updated (1) ) Production tax (% of net oil & gas revenue) 7.6% - 8.0% Cash G&A expense (2) ($ per Boe) $1.20 - $1.65 Non-cash equity compensation ($ per Boe) $0.40 - $0.50 DD&A ($ per Boe) $17.00 - $18.00 Average Price Differentials NYMEX WTI crude oil ($ per barrel of oil) ($3.50) - ($4.50) Henry Hub natural gas (3) ($ per Mcf) $0.00 - +$0.50 1. Updated from a prior guidance range of $3.00 to $3.50. 2. Cash G&A is a non-gaap measure and excludes the range of values shown for non-cash equity compensation per Boe in the item appearing immediately below. Guidance for total G&A (cash and non-cash) is an expected range of $1.60 - $2.15 per Boe. See Cash G&A Reconciliation to GAAP on slide 34 for a reconciliation of GAAP Total G&A per Boe to Cash G&A per Boe, which is a non-gaap measure. 3. Includes natural gas liquids production in differential range. 21

2018 Drilling Program ROR - Top-Tier Rates of Return by Play (1) ROR 300% 275% 250% 225% 200% 175% 150% 125% 100% 75% 50% 25% 0% Target EUR: 1,200 MBOE Avg. Lateral: 9,800 $8.4MM Budget 2018 Bakken $60 $65 $70 $75 $80 WTI Oil Price, $/BBL 175% ROR $24.14/$1.03 PV0 Breakeven $29.90/$1.28 PV10 Breakeven ROR 200% 175% 150% 125% 100% 75% STACK Over-Pressured Oil Target EUR: 1,200 MBOE Avg. Lateral: 9,800 50% 120% ROR 25% $23.47/$1.01 PV0 Breakeven $9.5MM Budget 2018 $31.46/$1.35 PV10 Breakeven 0% $60 $70 $80 WTI Oil Price, $/BBL ROR 200% 175% 150% 125% 100% 75% Target EUR: 1,500 MBOE Avg. Lateral: 9,800 SCOOP Woodford Oil 50% 80% ROR 25% $21.62/$0.93 PV0 Breakeven $11.7MM Budget 2018 $31.16/$1.34 PV10 Breakeven 0% $60 $65 $70 $75 $80 WTI Oil Price, $/BBL ROR Springer Oil Target EUR: 1,200 MBOE Avg. Lateral: 7,500 200% 175% 150% 125% 100% 75% 50% 215% ROR 25% $20.45/$0.88 PV0 Breakeven $9.5MM Budget 2018 $25.59/$1.10 PV10 Breakeven 0% $60 $65 $70 $75 $80 WTI Oil Price, $/BBL 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 Henry Hub is used for oil price sensitivities and $70 WTI is used for gas price sensitivities. The description of the ROR calculation applies to any ROR reference appearing in this presentation. 22

2018 Drilling Program ROR - Top-Tier Rates of Return by Play (1) ROR 200% 175% 150% 125% 100% SCOOP Woodford Condensate Target EUR: 2,300 MBOE Avg. Lateral: 7,500 75% 50% 90% ROR $23.44/$1.00 PV0 Breakeven 25% $10.8MM Budget 2018 $32.35/$1.39 PV10 Breakeven 0% $2.00 $3.00 $4.00 Gas Price, $/MCF ROR 200% 175% 150% 125% 100% 75% Target EUR: 2,400 MBOE Avg. Lateral: 9,800 STACK Condensate 50% 85% ROR 25% $23.29/$1.00 PV0 Breakeven $10.6MM Budget 2018 $33.20/$1.42 PV10 Breakeven 0% $2.00 $3.00 $4.00 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 Henry Hub is used for oil price sensitivities and $70 WTI is used for gas price sensitivities. The description of the ROR calculation applies to any ROR reference appearing in this presentation. 23

2018 Drilling Program Area Type Curves vs. Actual 10,000 Bakken Type Curve Well Count 1,200 MBOE Type Curve (Normalized to 9800' LL) 160 140 10,000 STACK Over-Pressured Oil Type Curve Well Count 1,200 MBOE Type Curve (Normalized to 9800' LL) 200 180 BOE per day 1,000 100 Actual Production (Normalized to 9800' LL and Down Days Included) 120 100 80 60 40 20 Well Count BOE per day 1,000 100 Actual Production (Normalized to 9800' LL and Down Days Included) 160 140 120 100 80 60 40 20 Well Count 10 0 0 6 12 18 24 30 36 Producing Months 10 0 0 6 12 18 24 30 36 Producing Months 10,000 SCOOP Woodford Oil Type Curve Well Count 1,500 MBOE Type Curve (Normalized to 9800' LL) 60 10,000 Springer Oil Type Curve Well Count 1,200 MBO Type Curve (Normalized to 7500' LL) 20 BOE per day 1,000 100 Actual Production (Normalized to 9800' LL and Down Days Included) 50 40 30 20 Well Count BOE per day 1,000 100 Actual Production (Normalized to 7500' LL and Down Days Included) 15 10 5 Well Count 10 10 0 0 6 12 18 24 30 36 Producing Months 10 0 0 6 12 18 24 30 36 Producing Months 24

2018 Drilling Program Area Type Curves vs. Actual 10,000 SCOOP Woodford Condensate Type Curve Well Count 2,300 MBOE Type Curve (Normalized to 7500' LL) 70 60 10,000 STACK Condensate Type Curve Well Count 2,400 MBOE Type Curve (Normalized to 9800' LL) 40 BOE per day 1,000 100 Actual Production (Normalized to 7500' LL and Down Days Included) 50 40 30 20 Well Count BOE per day 1,000 100 Actual Production (Normalized to 9800' LL and Down Days Included) 30 20 10 Well Count 10 10 0 0 6 12 18 24 30 36 Producing Months 10 0 0 6 12 18 24 30 36 Producing Months 25

Continued Focus On Net Debt Reduction Completed Partial Call of 5% Senior Notes Due 2022 on August 16, 2018 Represented 20% ($400MM) of the $2B in aggregate principal amount then outstanding of these notes Financial Metrics 1.49x: Net debt (1) / 3Q 2018 Annualized EBITDAX (1) 1.65x: Net debt (1) / TTM EBITDAX (1) ($MM) 2,000 1,500 1,000 500 0 Debt Maturities Summary 5.0% 4.5% $1,600 Remaining $1,500 3.8% 4.375% $1,000 $1,000 4.9% $700 2018 2019 2020 2021 2022 2023 2024 2028 2044 Callable 3/15/17 Financial Strength Earliest debt maturity is 2022 bonds (callable) 4.5% average interest rate in 3Q18 Unsecured Credit Facility Ample liquidity with $1.5B revolver; fully undrawn at 10/29/18 ($MM) 7,000 6,000 5,000 4,000 3,000 2,000 1,000 0 $7,106 Net Debt (1) Declining $6,563 $6,310 $5,945 $5,000 YE 2015 YE 2016 YE 2017 3Q 2018 Long Term Target 1. Net debt and EBITDAX are non-gaap measures. See slides 29-31 for definitions and reconciliations of these measures to the most comparable U.S. GAAP financial measures. 26

Continuing To Deliver Strong Margins (1) 2015 2016 2017 3Q 2018 Crude oil net sales price ($/Bbl) (2) $40.50 $35.51 $45.70 $65.78 Natural gas net sales price ($/Mcf) (2) $2.31 $1.87 $2.93 $3.12 Oil production (Bopd) 146,622 128,005 138,455 164,605 Natural gas production (Mcfpd) 450,558 533,442 625,093 793,793 Total production (Boepd) 221,715 216,912 242,637 296,904 EBITDAX ($000's) (3) $1,978,896 $1,881,889 $2,363,617 $999,882 Key Operational Statistics (per Boe) (4) Oil equivalent net sales price (excludes derivatives) ($/Boe) (2) $31.48 $25.55 $33.65 $44.85 Production expenses $4.30 $3.65 $3.66 $3.77 Production taxes $2.47 $1.79 $2.35 $3.60 Cash G&A (5) $1.70 $1.53 $1.64 $1.18 Interest expense $3.86 $4.04 $3.32 $2.68 Total of selected costs $12.33 $11.01 $10.97 $11.23 Margin (1) $19.15 $14.54 $22.68 $33.62 Margin % 61% 57% 67% 75% 1. Margin represents the Company s average net 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. 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, litigation settlement and various non-operating activities. These items are excluded from the computation of 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 slide 33 for a discussion and calculation of net sales prices, which are non-gaap measures for 2018. 3. See EBITDAX reconciliation to GAAP on slides 30-31 for a reconciliation of GAAP net income/loss and net cash provided by operating activities to EBITDAX, which is a non-gaap measure. 4. Average costs per Boe have been computed using sales volumes and exclude any effect of derivative transactions. 5. See Cash G&A Reconciliation to GAAP on slide 34 for a reconciliation of GAAP Total G&A per Boe to Cash G&A per Boe, which is a non-gaap measure. 27

Free Cash Flow/Outspend Reconciliation To GAAP Our presentation of free cash flow is a non-gaap measure. We define free cash flow as cash flows from operations before changes in working capital items less capital expenditures, excluding acquisitions, plus non-controlling interest capital contributions, less distributions to non-controlling interests. The inclusion of non-controlling interest capital contributions and distributions, expected to begin in the fourth quarter of 2018, is related to our newly formed relationship with Franco-Nevada to fund a portion of certain mineral acquisitions which are included in our capital expenditures and operating results. Free cash flow is not a measure of net income or cash flows as determined by U.S. GAAP and should not be considered an alternative to, or more meaningful than, the comparable GAAP measure. Management believes that these measures are useful to management and investors as a measure of a company s ability to internally fund its capital expenditures and to service or incur additional debt. These measures eliminate the impact of certain items that management does not consider to be indicative of the Company s performance from period to period. From time to time the Company provides forwardlooking free cash flow estimates, including for free cash flow yield; however, the Company is unable to provide a quantitative reconciliation of the forwardlooking non-gaap measure to its most directly comparable forward-looking GAAP measure because management cannot reliably quantify certain of the necessary components of such forward-looking GAAP measure. The reconciling items in future periods could be significant. The following table reconciles historical net cash provided by operating activities as determined under U.S. GAAP to free cash flow (outspend) amounts for the periods presented. In thousands 2010 2011 2012 2013 2014 2015 2016 2017 3Q 2018 YTD 2018 Net cash provided by operating activities (GAAP) $653,167 $1,067,915 $1,632,065 $2,563,295 $3,355,715 $1,857,101 $1,125,919 $2,079,106 $860,748 $2,500,741 Exclude: Changes in working capital items 50,667 109,949 13,015 10,875 126,679 (228,622) 162,216 (1,415) 72,705 54,405 Less: Capital expenditures (1) (1,229,851) (2,023,165) (3,038,405) (3,573,573) (4,811,647) (2,503,317) (1,074,345) (1,995,246) (790,816) (2,101,311) Free cash flow (outspend) (non-gaap) ($526,017) ($845,301) ($1,393,325) ($999,403) ($1,329,253) ($874,838) $213,790 $82,445 $142,637 $453,835 (1) Capital expenditures are calculated as follows: In thousands 2010 2011 2012 2013 2014 2015 2016 2017 3Q 2018 YTD 2018 Cash paid for capital expenditures $1,083,401 $2,035,642 $4,118,105 $3,739,431 $4,716,787 $3,080,255 $1,164,514 $1,953,198 $763,227 $2,134,210 Less: Total acquisitions (7,337) (200,931) (1,143,778) (268,200) (203,948) (60,975) (35,911) (40,007) (3,339) (77,047) Plus: Change in accrued capital expenditures & other 147,997 173,591 49,039 89,482 290,782 (519,949) (59,062) 79,222 30,928 44,148 Plus: Exploratory seismic costs 5,790 14,863 15,039 12,860 8,026 3,986 4,804 2,833 - - Capital expenditures $1,229,851 $2,023,165 $3,038,405 $3,573,573 $4,811,647 $2,503,317 $1,074,345 $1,995,246 $790,816 $2,101,311 28

Net Debt Reconciliation To GAAP Net debt is a non-gaap measure. We define net debt as total debt less cash and cash equivalents as determined under U.S. GAAP. Net debt should not be considered an alternative to, or more meaningful than, the comparable GAAP measure. Management uses net debt to determine the Company s outstanding debt obligations that would not be readily satisfied by its cash and cash equivalents on hand. We believe this metric is useful to analysts and investors in determining the Company s leverage position since the Company has the ability to, and may decide to, use a portion of its cash and cash equivalents to reduce debt. This metric is sometimes presented as a ratio with EBITDAX in order to provide investors with another means of evaluating the Company s ability to service its existing debt obligations as well as any future increase in the amount of such obligations. At September 30, 2018, the Company s net debt amounted to $5.94 billion, representing total debt of $5.96 billion less cash and cash equivalents of $13 million. From time to time the Company provides forwardlooking net debt forecasts; however, the Company is unable to provide a quantitative reconciliation of the forward-looking non-gaap measure to its most directly comparable forward-looking GAAP measure because management cannot reliably quantify certain of the necessary components of such forward-looking GAAP measure. The reconciling items in future periods could be significant. The following table reconciles total debt as determined under U.S. GAAP to net debt for the periods presented. In thousands 2015 2016 2017 3Q 2018 Total debt (GAAP) $ 7,117,788 $ 6,579,916 $ 6,353,691 $ 5,957,667 Less: Cash and cash equivalents (11,463) (16,643) (43,902) (12,896) Net debt (non-gaap) $ 7,106,325 $ 6,563,273 $ 6,309,789 $ 5,944,771 29

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 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 as applicable. EBITDAX is not a measure of net income or net cash provided by operating activities as determined by U.S. 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 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 these 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 U.S. 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. 30

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 2015 2016 2017 3Q 2018 TTM Net income (loss) $ (353,668) $ (399,679) $ 789,447 $ 314,169 $ 1,632,494 Interest expense 313,079 320,562 294,495 73,409 299,413 Provision (benefit) for income taxes (181,417) (232,775) (633,380) 97,466 (364,083) Depreciation, depletion, amortization and accretion 1,749,056 1,708,744 1,674,901 469,333 1,847,644 Property impairments 402,131 237,292 237,370 23,770 114,267 Exploration expenses 19,413 16,972 12,393 2,324 7,149 Impact from derivative instruments: Total (gain) loss on derivatives, net (91,085) 67,099 (90,432) 2,025 (3,881) Total cash (paid) received on derivatives, net 69,553 89,522 32,401 (1,477) 23,344 Non-cash (gain) loss on derivatives, net (21,532) 156,621 (58,031) 548 19,463 Non-cash equity compensation 51,834 48,097 45,868 11,730 46,586 Loss on extinguishment of debt -- 26,055 554 7,133 7,687 EBITDAX (non-gaap) $ 1,978,896 $ 1,881,889 $ 2,363,617 $ 999,882 $ 3,610,620 In thousands 2015 2016 2017 3Q 2018 TTM Net cash provided by operating activities $ 1,857,101 $ 1,125,919 $ 2,079,106 $ 860,748 $ 3,231,866 Current income tax provision (benefit) 24 (22,939) (7,781) (7,778) (15,559) Interest expense 313,079 320,562 294,495 73,409 299,413 Exploration expenses, excluding dry hole costs 11,032 12,106 12,217 2,324 7,129 Litigation Settlement -- -- (59,600) -- (59,600) Gain on sale of assets, net 23,149 304,489 55,124 1,510 62,681 Tax benefit (deficiency) from stock-based compensation 13,177 (9,828) -- -- -- Other, net (10,044) (10,636) (8,529) (3,036) (10,109) Changes in assets and liabilities (228,622) 162,216 (1,415) 72,705 94,799 EBITDAX (non-gaap) $ 1,978,896 $ 1,881,889 $ 2,363,617 $ 999,882 $ 3,610,620 31

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, losses on certain litigation settlements, gains and losses on asset sales, losses on extinguishment of debt and theimpactofu.s.tax reform legislation as applicable. 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 an alternative to, or more meaningful than, 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 dilutedearnings per share as determined under U.S. GAAP to adjusted earnings and adjusted diluted earnings per share for the periods presented. Three months ended September 30, 2018 2017 In thousands, except per share data $ Diluted EPS $ Diluted EPS Net income (GAAP) $ 314,169 $ 0.84 $ 10,621 $ 0.03 Adjustments: Non-cash loss on derivatives 548 2,939 Property impairments 23,770 35,130 Gain on sale of assets (1,510) (3,562) Loss on extinguishment of debt 7,133 - Total tax effect of adjustments (1) (7,093) (12,966) Total adjustments, net of tax 22,848 0.06 21,541 0.06 Adjusted net income (non-gaap) $ 337,017 $ 0.90 $ 32,162 $0.09 Weighted average diluted shares outstanding 374,623 373,015 Adjusted diluted net income per share (non-gaap) $ 0.90 $0.09 Nine months ended September 30, 2018 2017 In thousands, except per share data $ Diluted EPS $ Diluted EPS Net income (loss) (GAAP) $ 790,580 $ 2.11 $ (52,467) $ (0.14) Adjustments: Non-cash (gain) loss on derivatives 12,013 (65,481) Property impairments 86,715 209,819 Gain on sale of assets (8,261) (703) Loss on extinguishment of debt 7,133 - Total tax effect of adjustments (1) (23,147) (54,026) Total adjustments, net of tax 74,453 0.20 89,609 0.24 Adjusted net income (non-gaap) $ 865,033 $ 2.31 $ 37,142 $ 0.10 Weighted average diluted shares outstanding 374,762 373,588 Adjusted diluted net income per share (non-gaap) $ 2.31 $ 0.10 1. Computed by applying a combined federal and state statutory tax rate of 24% in effect for 2018 and 38% in effect for 2017 to the pre-tax amount of adjustments associated with our operations in the United States. 32

Net Sales Prices Reconciliation To GAAP On January 1, 2018, we adopted Accounting Standards Update 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net), which impacted the presentation of our crude oil and natural gas revenues. We adopted the new rules using a modified retrospective transition approach whereby changes have been applied only to the most current period presented and prior period results have not been adjusted to conform to current presentation. Under the new rules, revenues and transportation expenses associated with production from our operated properties are now reported on a gross basis compared to net presentation in the prior year. For non-operated properties, we receive a net payment from the operator for our share of sales proceeds which is net of costs incurred by the operator, if any. Such non-operated revenues are recognized at the net amount of proceeds received, consistent with our historical practice. As a result, beginning January 1, 2018 the gross presentation of revenues from our operated properties differs from the net presentation of revenues from non-operated properties. This impacts the comparability of certain operating metrics, such as per-unit sales prices, when such metrics are prepared in accordance with U.S. GAAP using gross presentation for some revenues and net presentation for others. In order to provide metrics prepared in a manner consistent with how management assesses the Company s operating results, and to achieve comparability with prior period metrics for analysis purposes, we may present crude oil and natural gas sales net of transportation expenses, which we refer to as net crude oil and natural gas sales, a non-gaap measure. Average sales prices calculated using net crude oil and natural gas sales are referred to as net sales prices, a non-gaap measure, and are calculated by taking revenues less transportation expenses divided by sales volumes, whether for crude oil or natural gas, as applicable. Management believes presenting our revenues and sales prices net of transportation expenses is useful because it normalizes the presentation differences between operated and non-operated revenues and allows for a useful comparison of net realized prices to NYMEX benchmark prices on a Company-wide basis. The following table presents a reconciliation of crude oil and natural gas sales (GAAP) to net crude oil and natural gas sales and related net sales prices (non-gaap) for the three and nine months ended September 30, 2018. Information is also presented for the three and nine months ended September 30, 2017 for comparative purposes. Three months ended September 30, 2018 Three months ended September 30, 2017 In thousands Crude oil Natural gas Total Crude oil Natural gas Total Crude oil and natural gas sales (GAAP) $1,038,558 $234,680 $1,273,238 $550,451 $154,367 $704,818 Less: Transportation expenses (39,336) (6,672) (46,008) Net crude oil and natural gas sales (non-gaap for 2018) $999,222 $228,008 $1,227,230 $550,451 $154,367 $704,818 Sales volumes (MBbl/MMcf/MBoe) 15,190 73,029 27,361 12,722 56,401 22,123 Net sales price (non-gaap for 2018) $65.78 $3.12 $44.85 $43.27 $2.74 $31.86 Nine months ended September 30, 2018 Nine months ended September 30, 2017 In thousands Crude oil Natural gas Total Crude oil Natural gas Total Crude oil and natural gas sales (GAAP) $2,891,722 $632,896 $3,524,618 $1,512,990 $452,226 $1,965,216 Less: Transportation expenses (119,939) (22,620) (142,559) Net crude oil and natural gas sales (non-gaap for 2018) $2,771,783 $610,276 $3,382,059 $1,512,990 $452,226 $1,965,216 Sales volumes (MBbl/MMcf/MBoe) 44,183 209,069 79,028 34,975 162,515 62,061 Net sales price (non-gaap for 2018) $62.73 $2.92 $42.80 $43.26 $2.78 $31.67 33

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, 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. 2015 2016 2017 3Q 2018 2018 Guidance Total G&A per Boe (GAAP) $2.34 $2.14 $2.16 $1.61 $1.60 - $2.15 Less: Non-cash equity compensation per Boe ($0.64) ($0.61) ($0.52) ($0.43) ($0.40) - ($0.50) Cash G&A per Boe (non-gaap) $1.70 $1.53 $1.64 $1.18 $1.20 - $1.65 34

Calculation Of Return On Capital Employed (ROCE) The following table shows the calculation of ROCE: In thousands, except per share data 2010 2011 2012 2013 2014 2015 2016 2017 Net income (loss) $ 168,255 $ 429,072 $ 739,385 $ 764,219 $ 977,341 $ (353,668) $ (399,679) $ 789,447 Impact from derivative instruments: Total (gain) loss on derivatives, net 130,762 30,049 (154,016) 191,751 (559,759) (91,085) 67,099 (90,432) Total cash received (paid), net 35,495 (34,106) (45,721) (61,555) 385,350 69,553 89,522 32,401 Non-cash (gain) loss on derivatives, net 166,257 (4,057) (199,737) 130,196 (174,409) (21,532) 156,621 (58,031) Provision (benefit) for income taxes 90,212 258,373 415,811 448,830 584,697 (181,417) (232,775) (633,380) Non-cash equity compensation 11,691 16,572 29,057 39,890 54,353 51,834 48,097 45,868 Interest expense 53,147 76,722 140,708 235,275 283,928 313,079 320,562 294,495 Loss on extinguishment of debt -- -- -- -- 24,517 -- 26,055 554 Adjusted EBIT $ 489,562 $ 776,682 $ 1,125,224 $ 1,618,410 $ 1,750,427 $ (191,704) $ (81,119) $ 438,953 Total equity $ 1,208,155 $2,308,126 $ 3,163,699 $ 3,953,118 $ 4,967,844 $ 4,668,900 $4,301,996 $5,131,203 Total long term debt 907,264 1,236,909 3,491,994 4,650,889 5,928,878 7,117,788 6,579,916 6,353,691 Capital employed $ 2,115,419 $3,545,035 $6,655,693 $ 8,604,007 $10,896,722 $11,786,688 $ 10,881,912 $11,484,894 ROCE 23.1% 21.9% 16.9% 18.8% 16.1% -1.6% -0.7% 3.8% 35