Investor Update. As of May 2016 NYSE: CLR

Transcription

1 Investor Update As of May 2016 NYSE: CLR

2 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 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

3 1Q 2016 Highlights Outpacing guidance Full year production guidance raised to 205,000 to 215,000 Boe per day Record 1Q 2016 production of 230,802 Boe per day (12% YoY production growth) LOE and G&A below guidance Cash costs down 17% from FY 2015 Operational efficiencies continue to translate to the bottom line (changes from YE 2015) STACK oil window target CWC down $500,000 to $9.5 million; spud to TD days down 32% Bakken CWC down $500,000 to $6.3 million; stimulation costs down $500,000 Excellent, repeatable results from over pressured STACK wells Foree XH IP: 2,061 Boe per day (69% oil), 7,200 lateral Bernhardt 1 13H IP: 1,046 Boe per day (77% oil), 4,550 lateral Quintle 1R 10 3XH: IP 2,150 Boe per day (71% oil), 9,850 lateral (still cleaning up) Enhanced completions increasing performance throughout the Company SCOOP Woodford: 35% 40% production uplift from offsets over first 90 to 180 days Bakken: 45% 60% production uplift from offsets over first 180 days Strong liquidity $1.88 billion available under credit facility as of April 29, 2016 Long term debt only increased by ~$20 million from 4Q 2015 through April 29,

4 2016 Outlook Building on 2015 Achievements 2016 priorities Cash flow neutrality Debt reduction STACK delineation CWC reductions Operational efficiencies 2016 budget Capex of $920 million to maintain average production of 205,000 to 215,000 Boe per day (updated from 200,000 Boe per day) Cash flow neutral at ~$37 WTI; cash flow positive at current WTI strip prices and capital budget $150 to $200 million annualized cash flow impact from ±$5 move in WTI 19 operated drilling rigs (32% reduction from 2015 average) 2.5 completion crews in south; 0 to 1 in Bakken 2016 play drivers Over pressured window in STACK shows ~3x production uplift compared to normally pressured wells Enhanced completions in SCOOP Woodford are generating 40% increase in initial 180 day production rates Bakken DUCs (drilled and uncompleted wells) provide catalyst for high cost forward ROR with $3.5 million incremental completion cost; projected YE 2016 DUC EUR average of 850 MBoe per well 4

5 CLR Assets Are Top Tier in U.S. Single Well Breakeven For North American Oil Plays* $90 $80 $70 $60 $50 $40 $30 $20 $10 $0 CLR TOP TIER PLAYS Source: Evercore ISI, January Included are 155,000 net acres of Continental s Woodford rights 2. Included are 214,000 net acres of Continental s Springer rights BAKKEN ~1,030,000 NET ACRES STACK MERAMEC/OSAGE (1) ~171,000 NET ACRES SCOOP WOODFORD (2) ~430,000 NET ACRES SCOOP SPRINGER ~214,000 NET ACRES SCOOP Liquids Bakken (800 MBoe EUR) SCOOP Liquids Bakken (800 mboe EUR) 1,000MBoe Midland Wolfcamp Spraberry (HZ) Wattenberg Inner / Middle STACK SCOOP Springer Southern Cana Condensate Eagleford Oil SCOOP Oil 800MBoe Midland Wolfcamp Bakken (600 MBoe mboe EUR) Eagleford Condensate Wolfberry Wattenberg Extended Lateral Northern Colorado Bone Spring Delaware Wolfcamp (Central) 575MBoe Midland Wolfcamp Delaware Wolfcamp (NW) Three Forks Wattenberg Core Generic MidCon Liquids Green River Vertical (Uinta) Southern Midland Southern Cana Oil Cana Woodford Delaware Wolfcamp (South) Ute. Butte Hz Miss Lime *To generate a 10% after tax IRR 2.0 Million Net Reservoir Acres STACK WOODFORD ~155,000 NET ACRES 5

6 Top Tier Rates of Return 100% 80% Target EUR: 1,700 MBoe Avg. Lateral: 9,800 STACK Over Pressured Oil 100% 80% SCOOP Woodford Condensate Target Enhanced Completion EUR: 2,000 MBoe Historic EUR: 1,725 MBoe Avg. Lateral: 7,500 ROR 60% 40% ROR 60% 40% 20% $9.5MM Target 2016 $11MM YE % $30 $40 $50 $60 WTI Oil Price, $/BBL 20% $9.6MM Enhanced Completion Target 2016 $9.5MM Historic Completion YE % $2 $3 $4 Gas Price, $/Mcf 100% 80% Avg. Lateral: 9,800 ND Bakken 100% 80% Target EUR: 2,150 MBoe Avg. Lateral: 9,800 NW Cana JDA (2) 60% 60% ROR 40% ROR 40% 20% 850 MBoe: $3.5MM Completion cost (1) 900 MBoe : $6.0MM Target MBoe : $6.8MM YE % WTI Oil Price, $/BBL 20% $12.3MM Target 2016 $12.9MM YE % $2 $3 $4 Gas Price, $/Mcf Note: $2.25 gas used for oil price sensitivities and $45 WTI used for gas price sensitivities 1. Estimated 195 DUC s at YE 2016, $3.5MM gross incremental completion cost 2. NW Cana economics factor in a ~50% carry from JDA participant 6

7 Historical Organic Growth 250, ,000 Targeting 205,000 to 215,000 Boe per Day Average in 2016 SCOOP Bakken Legacy 230,802 28% ~210,000 1,400 1,200 1,000 Total Proved Reserves Down 9% YOY with 47% Reduction in WTI Prices SCOOP Bakken Legacy 1,226 34% Boe Per Day 150, ,000 60% MMBoe % , % Q' E 0 12% For 1Q 2016: Natural Gas 37% 63% Oil For YE 2015: Natural Gas 43% 57% Oil 7

8 SCOOP & STACK Leading Acreage Positions in Top Tier Plays STACK ~970,000 Net Reservoir Acres STACK Meramec/Osage ~171,000 Net Acres (1) STACK Woodford ~155,000 Net Acres SCOOP Woodford ~430,000 Net Acres (2) SCOOP Springer ~214,000 Net Acres STACK Woodford Shale Thickness 50 ft 100 ft > 200 ft CLR Leasehold SCOOP 1. Included are 155,000 net acres of Continental s Woodford rights 2. Included are 214,000 net acres of Continental s Springer rights 8

9 STACK Exceptional, Repeatable Meramec Results New oil window completions Foree: IP 2,061 Boepd (69% oil), 3,300 PSI FCP, 7,200 lateral Bernhardt: IP 1,046 Boepd (77% oil), 2,145 PSI FCP, 4,550 lateral Quintle: IP 2,150 Boepd (71% oil), 2,125 PSI FCP, 9,850 lateral (still cleaning up) 5 additional wells testing 5 in oil window, 1 in condensate window New Wells Quintle 1R 10 3XH: IP 2,150 Boepd (still cleaning up) Foree XH: IP 2,061 Boepd Completed Wells Blaine Over Pressured Normally Pressured Existing Wells Blurton 1 7 6XH IP: 2,333 Boepd (78% oil) Ladd 1 8 5XH IP: 2,205 Boepd (79% oil) Strong early performance: Well Name Days Online Cum Production Current Rate Current Pressure Bernhardt 1 13H: IP 1,046 Boepd Marks XH IP: 994 Boepd (73% oil) Blurton MBoe (77% Oil) 692 Boepd (76% Oil) 1,400 psi Ludwig XH IP: 2,782 Boepd (76% oil) Compton 118 Boden 149 Ladd 184 Ludwig MBoe (70% Oil) 239 MBoe (28% Oil) 129 MBoe (76% Oil) 249 MBoe (75% Oil) 836 Boepd (69% Oil) 1,268 Boepd (26% Oil) 487 Boepd (74% Oil) 681 Boepd (72% Oil) 1,700 psi 4,700 psi 1,200 psi 1,600 psi Industry Meramec 2 mi. Lateral CLR Meramec 2 mi. Lateral Industry Meramec 1mi. Lateral CLR Meramec 1 mi. Lateral CLR Leasehold Compton XH IP: 2,547 Boepd (71% oil) Boden XH IP: 3,508 Boepd (28% oil) mi Note: Wells not produced at maximum capacity 9

10 STACK Efficiencies Already Being Realized Oil window CWC down 5% Target CWC $9.5MM, down $500k 5 Wells Completing Cycle times reduced ~32% Spud to TD at ~30 days, down from 44 days in 2015 ~95% of acreage in over pressured window ~3x uplift in 90 day rates (1) Thicker reservoir (700 1,200 thick) ~90% liquids rich ~55% HBP, 70% by YE 2016 Frankie Jo XH Gillilan XH Madelin 1 9 4XH Over Pressured Normally Pressured Ludwig Density Verona XH 2016 plans 6 rigs targeting Meramec 5 rigs targeting Woodford First density test commenced Ludwig density in oil window 2 additional density tests planned 1. By comparison to normally pressured producing wells. Data normalized to 9,800 lateral Yocum XH Industry Meramec 2 mi. Lateral CLR Meramec 2 mi. Lateral Industry Meramec 1mi. Lateral CLR Meramec 1 mi. Lateral CLR Planned 2016 Completion Industry Drilling Rigs CLR Leasehold CLR Drilling Rigs CLR wells completing / testing 10

11 STACK Over Pressured Oil Economic Model Boe Per Day 10,000 1, STACK Over Pressured Oil Type Curve (9,800 Lateral) ~75% ROR Based on $45 WTI & $2.25 Nat Gas Producing Months STACK Over Pressured Oil 9,800 Type Curve Data CWC: $9.5 Million Oil IP Rate, bbl/day 1,522 Oil 30 day IP Rate, bbl/day 1,327 Oil Initial Decline 76% Oil b factor 1.20 Oil EUR, MBo 984 Gas IP Rate, Mcf/day 3,795 Gas 30 Day IP Rate, Mcf/day 3,557 Gas Initial Decline 60% Gas b factor 1.20 Gas EUR, MMcf 4,326 Equivalent EUR, MBoe 1,705 Minimum Decline 6% Type Curve Based on Early Results from 14 Wells 11

12 STACK First Density Pilot Underway Ludwig Density Pilot in Blaine County Located in over pressured oil window Ludwig Density Pilot 1,280 acre spacing unit 9,800 laterals 1 Mile 8 Meramec wells 4 in Upper Meramec 4 in Middle Meramec 1 in Woodford Enhanced completions to be applied Applying advanced technology Micro seismic monitoring Core sampling Petro physical analysis 4 rigs currently drilling ~ , Upper MRMC Middle MRMC Lower MRMC OSGE WDFD HNTN New Well Existing Well Results expected 4Q

13 SCOOP Woodford Enhanced Completions Delivering 35% to 40% production uplifts 15% type curve EUR increase to 2,000 MBoe Greater than 100% ROR for incremental capital of $400,000 (1) ~50% more proppant per foot on average Cumulative Production (Boe) 300, , , , ,000 50,000 Enhanced Completion Wells Weighted Offset Average 1,725 Mboe Type Curve 35% uplift 40% uplift SANDY XH 2,481 Boe (17% oil) GRETTA XH 2,546 Boe (38% oil) Days 15 wells with > 90 days of production; 7 with > 180 days of production CLR Leasehold CLR Enhanced Completion Woodford Producing Well 1. When compared to offset production at $45 WTI and $2.25 natural gas 13

14 SCOOP Woodford Completion Efficiencies Realized 2X the Proppant Load for Less Cost 2,000 Proppant Load 1,000 Completion Cost 900 Proppant per Lateral Foot (#/ft) 1,600 1, ,451 Completion Cost per Lateral Foot ($/Ft) $759 $ Poteet/Honeycutt Infills Vanarkel/Newy Infills 0 Poteet/Honeycutt Infills Vanarkel/Newy Infills 14

15 SCOOP Woodford 4 th Condensate Density Project Completed Newy 8 well density project 7 new wells combined peak IP rate: 87 MMcf per day, 3,928 Bo per day (21% oil) 2,639 Boe per day per well 85% working interest Newy Density Project 1,280 acre spacing unit 9,850 laterals Repeatable results Map depicts CLR operated wells only CLR Well 330 1,320 2,640 1, Newy Project Avg IP 2,639 Boepd / well UPPER Vanarkel Project Avg IP 1,959 Boepd / well 100 LOWER Poteet Project Avg IP 2,771 Boepd / well Honeycutt Project Avg IP 2,734 Boepd / well New Well Existing Well 2 miles 15

16 Northern Region Bakken Petroleum System Isopach CLR Leasehold 16

17 Bakken Focusing on the Core at Reduced Costs Average EUR up 13% from target average EUR: 900 MBoe per well (1) 2015 average EUR: 800 MBoe per well (1) Enhanced CWC reduced to $6.3 million Down from $6.8 million (2) at YE 2015 Targeting $6.0 million by YE 2016 Valuable DUC (3) inventory Projecting ~195 DUCs (4) at YE MBoe average EUR $3.5 million incremental completion cost ($500,000 reduction) Over 100% ROR for incremental completion cost for DUCs at $45 WTI and $2.25 gas Outlines of Productive Bakken and Three Forks Reservoirs 1. Target EUR for 2015 and 2016 spuds, normalized to 9,800 lateral 2. For two mile laterals with 30 stages 3. DUCs are a gross operated number 4. Up from 135 DUCs at YE

18 Bakken Capital Efficiency Continues to Improve Well Cost ($MM) $10 $9 $8 $7 $6 $5 $4 $3 $2 $1 $0 $9.8 MM (1) $21.73 per Boe Declining F&D Costs $7.0 MM $10.67 per Boe $6.3 MM $8.54 per Boe FY 2014 FY 2015 Current Estimate $25 $20 $15 $10 $5 $0 Net F&D Cost ($/Boe) (3) Current vs. FY 2014 Current Well Cost Est. Capital Efficiency -36% +154% Est. F&D Cost Target EUR -61% +64% EUR per Well (MBoe) 1, Improving Capital Efficiency (2) 550 MBoe (1) 46 Boe/$1, MBoe 94 Boe/$1, MBoe (target) 117 Boe/$1,000 FY 2014 FY 2015 Current Estimate Capital Efficiency (Net Boe/$1,000) (3) 1. CLR-Operated North Dakota MB, TF1 & TF2 wells spud in 2014, 2015 and 2016 Projected 2. Capital efficiency based on reserves developed per dollar invested 3. Average net revenue interest of 82% assumed for net F&D and net capital efficiency 18

19 CLR Bakken Differentials Decreasing Through Increased Pipeline Capacity Thousand Bopd 3,500 Bakken Takeaway Capacity 3,000 2,500 2,000 1,500 1, EST EST Local Refining Pipeline Rail Bakken Production Enbridge Sandpiper Expected Online: ,000 Bopd Thousand Bopd Jan 09 ~80% of CLR Bakken Barrels on Pipe Jul 09 Jan 10 Jul 10 Jan 11 Jul 11 Jan 12 Jul 12 Jan 13 Jul 13 Jan 14 Jul 14 Jan 15 Jul 15 Jan 16 CLR Piped CLR Railed Energy Transfer DAPL Expected Online: YE ,000 to 570,000 Bopd Rail Pipeline Future Pipeline Energy Transfer ETCOP Expected Online: YE ,000 to 570,000 Bopd North Dakota Pipeline Authority and CLR estimates 19

20 Avg. Realized $/Boe (3) Low Cash Cost Competitively Positions CLR $80 $70 $60 $50 $40 $30 $20 $10 $0 $44.68 $ % $59.35 $ % $72.45 $ % $65.99 $48.59 $72.04 $ % 74% $66.53 $ % $31.48 $ % $19.27 $3.40 $3.34 $3.95 $4.74 $4.49 $9.07 $1.72 $2.95 $4.47 $ % $5.58 $6.02 $5.54 $3.86 $2.19 $2.35 $2.36 $2.38 $2.07 $2.06 $2.47 $3.87 $1.70 $1.46 $6.89 $1.11 $5.87 $6.13 $5.49 $5.69 $5.58 $4.30 $ Q 2016 Low cash cost of $10.20 per Boe, 17% lower than FY 2015 Production Expense G&A (1) Production/Severance Tax & Other Interest Cash Margin (2) 1. Excludes G&A related to equity based compensation and relocation expense 2. See Continuing to Deliver Strong Margins in the appendix for the method of calculating cash margin 3. Based on average oil equivalent price (excluding derivatives and including natural gas) 20

21 Strong Liquidity & Financial Profile Unsecured Credit Facility Ample liquidity with $2.75 billion revolver and ability to upsize to $4.0 billion (1) Net Debt/TTM EBITDAX (3) 3.88x Net Debt/1Q 2016 Avg. Daily Production Financial Metrics (2) Net Debt/YE 2015 Proved Reserves $5.87 $31,164 Cash Margin 1Q % ~$1.88 billion available on revolver No borrowing base redetermination 3,000 2,500 No maturities for ~2.5 years Debt Maturities Summary 2 year extension option beyond 2019 (1) Financial Strength No near term debt maturities (Earliest is $500 million in 11/2018) ($MM) 2,000 1,500 1, $2.75 billion credit facility LIBOR + 1.5% $500 $1,880 Undrawn 0 $ % average interest rate Revolver Callable Callable Callable Balance 10/1/15 4/1/16 3/15/17 1. With lender consent 4/29/16 2. All ratios are as of 3/31/16, except where noted 3. See appendix for reconciliation of GAAP net income and operating cash flows to EBITDAX $ % 7.125% $ % $2, % $1, % $1, % $700 21

22 Industry Leading Recycle Ratio Recycle Ratio (As of 4Q 2015) CLR Peer A Peer B Peer C Peer D Peer E Peer F Peer G Peer H Peer I Peer J Peer K Recycle Ratio = Operating Margin ($/Boe) / PDP F&D Cost ($/Boe) Recycle ratio. This measure represents the cash earned per Boe produced vs. the cost of getting that barrel out of the ground. Seaport calculated the proved developed finding and development cost for FY Peers include: APA, APC, CXO, DVN, EOG, HES, NBL, NFX, OXY, PXD & WLL Source: Seaport Global Securities, LLC, April

23 2016 Guidance Production & Capital 2016 Guidance Production (Boe per day) (revised) 205, ,000 Capital expenditures (non acquisition) $920 million Operating Expenses Production expense ($ per Boe) $4.25 $4.75 Production tax (% of oil & gas revenue) 6.75% 7.25% G&A expense ($ per Boe) $1.25 $1.75 Non cash equity compensation ($ per Boe) $0.65 $0.85 DD&A ($ per Boe) $20.00 $22.00 Average Price Differentials NYMEX WTI crude oil ($ per barrel of oil) ($7.00) ($9.00) Henry Hub natural gas (1) ($ per Mcf) $0.00 ($0.65) Bolded item above in guidance denotes a change from the previous disclosure 1. Includes natural gas liquids production in differential range Income tax rate 38% Deferred taxes 90% 95% 23

24 APPENDIX 24

25 2016 Capital Budget Allocation Leasehold $78 NW Cana JDA $62 STACK Drilling $142 $920 Million in Non Acquisition Capex ($ in Millions) Other $58 SCOOP Drilling $260 Bakken Drilling $320 63% YOY Decrease in Capex Rigs Gross Operated Wells Net Operated Wells Total Net Wells (1) Bakken SCOOP STACK NW Cana JDA & Other Totals YE 15 DUCs YE 16 DUCs (2) Bakken (3) Oklahoma Totals Wells With First Production 1. Represents projected net operated & non operated wells 2. Represents projected gross operated DUCs 3. DUC inventory has average EUR of 850 MBoe per well 25

26 SCOOP Woodford Density Pilots Expanding and Derisking Density testing to define optimum spacing Five in the condensate window Good Martin Unit Project # of Wells Status Poteet 10 Producing Honeycutt 10 Producing May Unit Vanarkel 8 Producing Newy 8 Producing Two in the oil window Project # of Wells Status Good Martin 8 Producing May 7 Waiting on Completion Poteet Unit Newy Unit Vanarkel Unit Honeycutt Unit Efficiencies building Testing hybrid, higher intensity completions Higher proppant volumes Well cycle times improving Water recycling Ample infrastructure and growing CLR Leasehold Current WDFD Density Test Woodford Producing Well CLR Completion 26

27 SCOOP Woodford Condensate Window Density Projects Strong Repeatable Results 10,000 MCFED Honeycutt Daily Production (1) 9 New Honeycutt Wells 1,725 MBoe Type Curve CLR Well Vanarkel Project 8 Well Density 660 Inter well Spacing 1, Days on Production Poteet Project 10 Well Density 513 Inter well Spacing Honeycutt Project 10 Well Density 513 Inter well Spacing 10,000 Poteet Daily Production (1) 10 New Poteet Wells 1,725 MBoe Type Curve 10,000 Vanarkel Daily Production (1) MCFED 1,000 MCFED 1,000 New 7 New Vanarkel Vanarkel Wells Wells 1,725 1,725 MBoe Type Type Curve Enhanced Woodford Completion Condensate 2,000 MBoe 7500' Type Type Curve Curve Days on Production 1. Normalized to 7,500 lateral Days on Production 27

28 SCOOP Woodford Sustainable Drilling Efficiencies Realized Newy Project Set two company records: 2 mile lateral: spud to TD in 47.5 days (Newy 8) Record MD for horizontal well in OK at 26,289 (Newy 6) Vanarkel Project Set two company spud to TD drilling records: 1 mile lateral: 31 days (Lowrance 2 10H) 1.5 mile lateral: 40 days (Vanarkel XH) Measured Depth (FT) 0 5,000 10,000 15,000 Poteet Average 1Q'15 Honeycutt Average 2Q'15 Vanarkel Average 3Q 15 Newy Average 4Q 15 20,000 Infill Improvements Poteet/Honeycutt to Vanarkel/Newy ~39% increase in drilled ft/day ~58% decrease in $/lat ft ~44% decrease in $/ft 25, Days 28

29 SCOOP Springer Oil Asset Waiting for Higher Prices Current 2016 plans No drilling planned Reservoir being delineated and HBP d by Woodford drilling Deferring asset development for higher oil price SCOOP Results in line with 940 MBoe type curve Hartley Pilot Boe per day 10,000 1, Springer Shale Type Curve Well Count Type Curve (Normalized to 4,500' LL) Act. Production (Normalized to 4,500') Producing Months Well Count Springer Fairway 12 Miles Jeanna Pilot Current Springer Density Test CLR Leasehold CLR Springer Shale Producers Non Op. Springer Shale Producer 29

30 Bakken Enhanced Completions Continue to Deliver 110, ,000 90,000 80,000 EUR Up Another 5% From 4Q % 45% increase in EUR Production Uplift ~60% Slickwater (53 Wells) (10% higher than last quarter) ~45% Hybrid (65 Wells) (10% higher than last quarter) Cum Boe 70,000 60,000 50,000 40,000 30,000 20,000 10,000 Average Standard Completion Offsetting Legacy Wells Days Slickwater Hybrid Base Note: Enhanced Slickwater and Hybrid 30 stage Well Completions in Williams and McKenzie Counties 30

31 Continuing to Deliver Strong Margins Q 2016 Realized oil price ($/Bbl) $54.44 $70.69 $88.51 $84.59 $89.93 $81.26 $40.50 $25.72 Realized natural gas price ($/Mcf) $2.95 $4.26 $4.87 $3.73 $4.87 $5.40 $2.31 $1.36 Oil production (Bopd) 27,459 32,385 45,121 68,497 95, , , ,469 Natural gas production (Mcfpd) 59,194 65, , , , , , ,998 Total production (Boepd) 37,324 43,318 61,865 97, , , , ,802 EBITDAX ($000's) (1) $450,648 $810,877 $1,303,959 $1,963,123 $2,839,510 $3,776,051 $1,978,896 $314,609 Key Operational Statistics (per Boe) (2) Average oil equivalent price (excludes derivatives) $44.68 $59.35 $72.45 $65.99 $72.04 $66.53 $31.48 $19.27 Production expense $6.89 $5.87 $6.13 $5.49 $5.69 $5.58 $4.30 $3.76 Production tax and other $2.95 $4.47 $5.82 $5.58 $6.02 $5.54 $2.47 $1.46 G&A (3) $2.19 $2.35 $2.36 $2.38 $2.07 $2.06 $1.70 $1.11 Interest $1.72 $3.34 $3.40 $3.95 $4.74 $4.49 $3.86 $3.87 Total cash costs $13.75 $16.03 $17.71 $17.40 $18.52 $17.67 $12.33 $10.20 Cash margin $30.93 $43.32 $54.74 $48.59 $53.52 $48.86 $19.15 $9.07 Cash margin % 69% 73% 76% 74% 74% 73% 61% 47% 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. 31

32 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 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 (loss) and operating cash flows 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 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 (loss) and operating cash flows to EBITDAX for the applicable periods. 32

33 EBITDAX Reconciliation to GAAP The following tables provide reconciliations of our net income (loss) and operating cash flows to EBITDAX for the periods presented: In thousands Q 2016 Net income (loss) $ 71,338 $ 168,255 $ 429,072 $ 739,385 $ 764,219 $ 977,341 $ (353,668) $ (198,326) Interest expense 23,232 53,147 76, , , , ,079 80,953 Provision (benefit) for income taxes 38,670 90, , , , ,697 (181,417) (121,346) Depreciation, depletion, amortization and accretion 207, , , , ,645 1,358,669 1,749, ,992 Property impairments 83,694 64, , , , , ,131 78,927 Exploration expenses 12,615 12,763 27,920 23,507 34,947 50,067 19,413 3,066 Impact from derivative instruments: Total (gain) loss on derivatives, net 1, ,762 30,049 (154,016) 191,751 (559,759) (91,085) (41,052) Total cash received (paid), net ,495 (34,106) (45,721) (61,555) 385,350 69,553 39,189 Non cash (gain) loss on derivatives, net 2, ,257 (4,057) (199,737) 130,196 (174,409) (21,532) (1,863) Non cash equity compensation 11,408 11,691 16,572 29,057 39,890 54,353 51,834 9,206 Loss on extinguishment of debt 24,517 EBITDAX $ 450,648 $ 810,877 $ 1,303,959 $ 1,963,123 $ 2,839,510 $ 3,776,051 $ 1,978,896 $ 314,609 In thousands Q 2016 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 $ 278,902 Current income tax provision (benefit) 2,551 12,853 13,170 10,517 6, Interest expense 23,232 53,147 76, , , , ,079 80,953 Exploration expenses, excluding dry hole costs 6,138 9,739 19,971 22,740 25,597 26,388 11,032 3,066 Gain on sale of assets, net ,588 20, , , Excess tax benefit from stock based compensation 2,872 5,230 15,618 13,177 Other, net (3,890) (3,513) (4,606) (7,587) (1,829) (17,279) (10,044) (3,973) Changes in assets and liabilities 46,050 50, ,949 13,015 10, ,679 (228,622) (44,454) EBITDAX $ 450,648 $ 810,877 $ 1,303,959 $ 1,963,123 $ 2,839,510 $ 3,776,051 $ 1,978,896 $ 314,609 33

34 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 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 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 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. 1Q Q Q 2015 In thousands, except per share data After Tax $ Diluted EPS After Tax $ Diluted EPS After Tax $ Diluted EPS Net income (loss) (GAAP) $ (198,326) $ (0.54) $ (139,677) $ (0.38) $ (131,971) $ (0.36) Adjustments, net of tax: Non cash (gain) loss on derivatives, net (1,155) 2, (5,778) (0.01) Property impairments 49, , , Gain on sale of assets, net (67) (135) (1,284) Adjusted net loss (Non GAAP) $ (150,467) $ (0.41) $ (86,644) $ (0.23) $ (33,819) $ (0.09) Weighted average diluted shares outstanding 370, , ,385 Adjusted diluted net loss per share (Non GAAP) $ (0.41) $ (0.23) $ (0.09) 34

35 CONTACT INFORMATION J. Warren Henry Vice President, Investor Relations & Research Phone: Alyson L. Gilbert Manager, Investor Relations Phone: Website: 35