Bank of America Merrill Lynch 2015 Global Energy Conference

Transcription

1 Bank of America Merrill Lynch 2015 Global Energy Conference 1

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 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, 2014, 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 3Q 2015 HIGHLIGHTS DEVELOPING OVER-PRESSURED STACK LUDWIG XH IP: 2,782 BOE PER DAY (76% OIL) LADD 1-8-5XH IP: 2,181 BOE PER DAY (79% OIL) MARKS 1-9-4XH IP: 994 BOE PER DAY (73% OIL) POSITIVE UPDATES TO GUIDANCE 24% TO 26% YOY PRODUCTION GROWTH 32% REDUCTION IN 3Q CASH COSTS PER BOE FROM FY 2014 CAPITAL DISCIPLINE REDUCED BAKKEN RIG & COMPLETION CREWS TO ACHIEVE CASH FLOW NEUTRALITY AT $50 WTI 25% DECLINE IN COMPLETED WELL COST (CWC) OPERATIONAL EFFICIENCIES SINCE YE % REDUCTION IN BAKKEN DRILLING TIME (SPUD TO TD) 48% REDUCTION IN SCOOP WOODFORD DRILLING TIME FOR DENSITY TESTS (SPUD TO TD) 28% REDUCTION IN LIFTING COST FROM FY 2014 WTI DIFFERENTIALS DECREASE TO $7.54 (75% OF BAKKEN PRODUCTION ON PIPE) INCREASED LIQUIDITY $1.9 BILLION AVAILABLE UNDER CREDIT FACILITY REDUCE INTEREST EXPENSE 3

4 4Q 2015 AND 2016 OUTLOOK PRIORITIES CONTINUE TO FOCUS ON: CASH FLOW NEUTRALITY STACK DELINEATION CWC REDUCTIONS OPERATIONAL EFFICIENCIES REMAINING OPPORTUNISTIC 2016 MAINTENANCE CAPEX SCENARIO CAPEX OF ~$1.5 BILLION TO $1.6 BILLION REQUIRED TO MAINTAIN 200,000 BOE PER DAY AVERAGE FOR 2016 CASH FLOW NEUTRAL AT ~$50 WTI PLAN TO ANNOUNCE 2016 GUIDANCE LATE DECEMBER 2015 OR EARLY JANUARY

5 PORTFOLIO OF WORLD-CLASS ASSETS FOR LONG-TERM GROWTH BAKKEN ~1,074,000 NET ACRES ASSET BAKKEN SCOOP Woodford STAGE OF DEVELOPMENT First stage of full-field development underway Expanding and derisking STACK* ~146,300 NET ACRES SCOOP WOODFORD ~445,000 NET ACRES SCOOP Springer NW CANA JDA Best Discovery Award for 2014 Oil and Gas Investor Magazine Generating value from previously idle asset NW CANA JDA ~31,400 NET ACRES SCOOP SPRINGER ~210,000 NET ACRES STACK New resource play established 2Q 2015 *INCLUDED ARE 31,400 NET ACRES REPRESENTING CONTINENTAL RESOURCES WOODFORD RIGHTS IN NW CANA JDA 5

6 RATES OF RETURN ROR 100% 80% 60% 40% 20% Target EUR: 800 MBoe Avg. Lateral: 9,800 BAKKEN $7.0MM Current CWC (27% Reduction YTD) $9.6MM CWC YE % $40 $50 $60 $70 WTI Oil Price, $/BBL ROR 100% 80% 60% 40% 20% SCOOP WOODFORD CONDENSATE Target EUR: 1,725 MBoe Avg. Lateral: 7,500 $9.6MM Current CWC (21% Reduction YTD) $12.2MM CWC YE % $2 $3 $4 Gas Price, $/MCF 100% 80% Target EUR: 940 MBoe Avg. Lateral: 4,500 SCOOP SPRINGER NW CANA (1) 100% 80% Target EUR: 2,150 MBoe Avg. Lateral: 9,800 ROR 60% 40% ROR 60% 40% 20% $7.8MM Current CWC (20% Reduction YTD) $9.7MM CWC YE % $40 $50 $60 $70 WTI Oil Price, $/BBL 20% $12.9MM Current CWC 0% $2 $3 $4 Gas Price, $/MCF 1. NW CANA ECONOMICS FACTOR IN A ~50% CARRY FROM JDA PARTICIPANT 6

7 EXCEPTIONAL ORGANIC GROWTH 250, ,000 SCOOP Bakken Legacy PRODUCTION GROWTH 1,400 1,200 TOTAL PROVED RESERVES 228,300 1,351 30% SCOOP Bakken Legacy 27% BOE PER DAY 150, ,000 59% MMBOE 1, % 50, % Q'15 2Q'15 3Q'15 0 9% NATURAL GAS 35% 65% OIL NATURAL GAS 36% 64% OIL 7

8 SOUTHERN REGION LEADING ACREAGE POSITIONS IN THREE PLAYS STACK NW CANA JDA SCOOP SPRINGER ~210,000 NET ACRES STACK ~146,300 NET ACRES* NW CANA JDA ~31,400 NET ACRES SCOOP WOODFORD ~445,000 NET ACRES SCOOP Woodford Shale Thickness 50 ft 100 ft > 200 ft CLR Leasehold *INCLUDED ARE 31,400 NET ACRES REPRESENTING CONTINENTAL RESOURCES WOODFORD RIGHTS IN NW CANA JDA. 8

9 STACK ANOTHER QUALITY ASSET FOR CLR PORTFOLIO EXCELLENT POSITION IN PLAY ~146,300 NET ACRES ~95% IN OVER-PRESSURED WINDOW ~90% LIQUIDS-RICH ~60% HBP OUTSTANDING MERAMEC RESULTS 2,782 BOEPD, 2,100 PSI FCP (LUDWIG) 2,181 BOEPD, 2,000 PSI FCP (LADD) 994 BOEPD, 625 PSI FCP (MARKS) 73% TO 79% OIL Ladd 1-8-5XH Marks 1-9-4XH Ludwig XH 3 WELLS DRILLING AND 1 WELL WOC CURRENT PLANS THROUGH YEAR END 2-3 OPERATED DRILLING RIGS 2-3 ADDITIONAL WELLS TO SPUD Industry Over-pressured 2 mi. lateral Industry Normallypressured 2 mi. lateral CLR Drilling Rigs Industry Over-pressured 1 mi. lateral Industry Normallypressured 1 mi. lateral CLR Hz Meramec Wells Over- Pressured Normally- Pressured Industry Drilling Rigs CLR Planned Wells 2015 CLR Leasehold 9

10 STACK CLR SUPERIOR POSITION IN PLAY OBSERVATIONS FROM INDUSTRY- WIDE ACTIVITY IP24: 2,181 Boepd (79% Oil) CLR: Ladd 1-8-5XH LL: 9,742ft 57 MERAMEC & OSAGE WELLS WITH MONTHLY PRODUCTION 39 NORMALLY-PRESSURED 18 OVER-PRESSURED IP24: 10,547 Mcfepd (52% Gas) LL: 4,768 ft IP24: 1,820 Boepd (84% Oil) LL: 10,150 ft IP24: 994 Boepd (73% Oil) CLR: Marks 1-9-4XH LL: 10,092ft IP24: 2,782 Boepd (76% Oil) CLR: Ludwig XH LL: 9,711 ft OVER-PRESSURE WINDOW 3X UPLIFT IN 90 DAY RATES (1) THICKER RESERVOIR 700 1,200 THICK IP24: 1,649 Boepd (68% Oil) LL: 4,982 ft RAPIDLY BEING DE-RISKED CURRENTLY 25 ACTIVE RIGS 20 TARGETING MERAMEC 5 TARGETING OSAGE ~50% LOCATED IN OVER- PRESSURED WINDOW IP24: 10,440 Mcfepd (91% Gas) LL: 4,732 ft Industry Over-pressured 2 mi. lateral Industry Normallypressured 2 mi. lateral CLR Drilling Rigs Industry Drilling Rigs CLR Leasehold IP24: 10,800 Mcfepd (83% Gas) LL: 4,688 ft Industry Over-pressured 1 mi. lateral Industry Normallypressured 1 mi. lateral CLR Hz Meramec Wells CLR Planned Wells 2015 Over- Pressured IP24: 1,749 Boepd (59% Oil) LL: 4,945 ft Normally- Pressured 1) BY COMPARISON TO NORMALLY-PRESSURED PRODUCING WELLS. DATA NORMALIZED TO 9,800 LATERAL LENGTH 10

11 SCOOP WOODFORD EXPANDING AND DERISKING DENSITY TESTING TO DEFINE OPTIMUM SPACING FIVE IN THE CONDENSATE WINDOW PROJECT # OF WELLS STATUS POTEET 10 PRODUCING HONEYCUTT 10 PRODUCING VANARKEL 8 WAITING ON COMPLETION NEWY 8 DRILLING SYMPSON 10 PREPARING TO DRILL TWO IN THE OIL WINDOW PROJECT # OF WELLS STATUS GOOD MARTIN 8 PRODUCING MAY 7 WAITING ON COMPLETION WELL COSTS REDUCED ~21% CURRENTLY $9.6MM FOR 7,500 LATERAL EFFICIENCIES BUILDING TESTING HYBRID, HIGHER-INTENSITY COMPLETIONS WELL CYCLE TIMES IMPROVING WATER RECYCLING AMPLE INFRASTRUCTURE AND GROWING CURRENT PLANS THROUGH YEAR END ~7-8 OPERATED DRILLING RIGS Triple H 1-30H IP: 1,037 Boepd (68% Oil) Sympson Unit Poteet Unit Gentry XH IP: 17,018 Mcfepd (85% Gas) CLR Leasehold Current WDFD Density Test Woodford Producing Well CLR 2015 Completion Good Martin Unit May Unit Early XH IP: 1,448 Boepd (65% Oil) Silver Stratton XH IP: 13,168 Mcfepd (58% Gas) Newy Unit Vanarkel Unit Honeycutt Unit 11

12 HONEYCUTT DENSITY PILOT WOODFORD CONDENSATE FAIRWAY HONEYCUTT DENSITY PILOT 10-WELL DENSITY (1 LEGACY, 9 NEW) DUAL HORIZON 9 NEW WELLS HAD COMBINED PEAK PRODUCTION RATES OF 93,271 MCFPD AND 9,058 BOPD (37% OIL) AVERAGE OWNERSHIP: 50% WORKING INTEREST CLR Well Poteet Project -10 Well Density -513 Inter-well Spacing Vanarkel Project -8 Well Density -660 Inter-well Spacing Honeycutt Project -10 Well Density -513 Inter-well Spacing 1, ,640 1, Wells shut in for offsetting stimulation 262 1, UPPER LOWER 1. NORMALIZED TO 7,500 LATERAL 12 1 MILE 513 SPACING BETWEEN WELL BORES LATERALS RANGE FROM 5,314 TO 10,236 1,026 SPACING IN SAME HORIZON AVERAGE 7,369

13 SCOOP WOODFORD DRILLING EFFICIENCIES BEING REALIZED VANARKEL PROJECT SET TWO COMPANY SPUD-TO-TD DRILLING RECORDS: - 1 MILE LATERAL: 31 DAYS (LOWRANCE 2-10H) MILE LATERAL: 40 DAYS (VANARKEL XH) OPERATIONAL EFFICIENCIES OPTIMIZED BHA COMBINATIONS INCREASED TOOL LONGEVITY OPTIMIZED MUD WEIGHT UPGRADED TO SPEED WELLHEAD CONTINUE TO MONITOR VENDOR PERFORMANCE IMPROVEMENTS BEING APPLIED TO CURRENT AND FUTURE DRILLING PROJECTS Measured Depth (ft.) 0 5,000 10,000 15,000 20,000 25,000 Poteet Average - 1Q 2015 Honeycutt Average - 2Q 2015 Vanarkel Average - 3Q % REDUCTION Days 48% REDUCTION IN DAYS (SPUD TO TD) 45% REDUCTION IN AVG DRILLING COST 13

14 SCOOP SPRINGER CONTINUED SUCCESS WITH OIL FAIRWAY STEP-OUTS 2 DENSITY TESTS PRODUCING JEANNA PILOT 4-WELL DENSITY HARTLEY PILOT 4-WELL DENSITY COMPLETED 6 NET (7 GROSS) OPERATED AND NON- OPERATED WELLS IN 3Q 2015 CURRENT PLANS THROUGH YEAR END NO DRILLING PLANNED RESERVOIR BEING DELINEATED AND HBP D BY WOODFORD DRILLING DEFERRING ASSET DEVELOPMENT FOR HIGHER OIL PRICE RESULTS IN LINE WITH 940 MBOE TYPE CURVE Jantz Family 1-33H IP: 1,210 Boepd (77% Oil) Hartley Pilot Jeanna Pilot SCOOP Sawyer 1-23H IP: 1,343 Boepd (83% Oil) Walters West 1-34H IP: 1,476 Boepd (78% Oil) Boe per day Springer Shale Results Well Count Type Curve (Normalized to 4,500' LL) Act. Production (Normalized to 4,500') Producing Months SPRINGER FAIRWAY 12 Miles Current Springer Density Test CLR Leasehold 14 Well Count CLR Springer Shale Producers Non-Op. Springer Shale Producer

15 NORTHERN REGION Bakken Petroleum System Isopach CLR Leasehold 15

16 BAKKEN FOCUSING ON THE CORE OUTLINES OF PRODUCTIVE BAKKEN AND THREE FORKS RESERVOIRS AVERAGE EUR UP 45% FROM TARGET AVERAGE EUR 800 MBOE PER WELL 2014 AVERAGE EUR 550 MBOE PER WELL FINDING AND DEVELOPMENT COSTS PER BOE CUT BY 50% CANADA MB, TF1, TF2 MB & TF1 ENTERING FULL-FIELD DEVELOPMENT ~60% OF WELLS TO BE DRILLED ON INTER-WELL SPACING WITHIN ZONE CURRENT PLANS THROUGH YEAR END ~8 OPERATED DRILLING RIGS MB or TF1 CLR LEASEHOLD 2014 OPERATED SPUDS 2015 OPERATED SPUDS MB: Middle Bakken Reservoir TF1 TF2 TF3: Three Forks Reservoirs 18 Miles MB & TF1 MB, TF1, TF2/TF3 16

17 BAKKEN CAPITAL EFFICIENCY DOUBLED IN 2015 WELL COST ($MM) $10 $9 $8 $7 $6 $5 $4 $3 $2 $1 $0 DECLINING F&D COSTS $9.8 MM (1) $21.50 per Boe $7.0 MM $10.67 per Boe FY 2014 Q $25 $20 $15 $10 $5 $0 NET F&D COST ($/BOE) (3) CURRENT WELL COST EST. CAPITAL EFFICIENCY -30% +100% ESTIMATED F&D COST TARGET EUR -50% +45% EUR PER WELL (MBOE) IMPROVING CAPITAL EFFICIENCY (2) MBOE (1) 47 Boe/$1, MBOE (target) 94 Boe/$1,000 FY 2014 Q CAPITAL EFFICIENCY (NET BOE/$1,000) (3) 1. CLR-OPERATED NORTH DAKOTA MB, TF1 & TF2 WELLS SPUD IN 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 17

18 BAKKEN DRILLING EFFICIENCIES CONTINUE TO IMPROVE Spud to TD (Avg)* SPUD TO TD DAYS - 15% REDUCTION YTD FEET PER DAY - 22% FASTER YTD 80% OF WELLS 16.5 DAYS SPUD TO TD Days Q Q Q 2015 LATERAL DRILLING DAYS - 26% REDUCTION YTD FEET PER DAY - 39% FASTER YTD 75% OF WELLS 5.5 LATERAL DAYS COMPANY RECORDS - TWO-MILE LATERAL DRILLED IN 2.4 DAYS - THREE-MILE LATERAL DRILLED IN 6.4 DAYS * FOR TWO-MILE LATERALS ONLY Days Lateral Drilling Days (Avg)* Q Q Q 2015

19 CLR BAKKEN DIFFERENTIALS IMPROVING THROUGH INCREASED PIPELINE CAPACITY Thousand BOPD 3,500 3,000 2,500 2,000 1,500 1, BAKKEN TAKEAWAY CAPACITY? Enbridge Sandpiper Expected Online: 1Q ,000 Bopd Enbridge Line 9 Reversal Expected Online: ,000 to 300,000 Bopd EST. Local Refining Pipeline Rail Bakken Production Thousand BOPD Jan-09 Jul-09 75% OF CLR BAKKEN BARRELS NOW ON PIPE Jan-10 Jul-10 Jan-11 Jul-11 Jan-12 Jul-12 Jan-13 Jul-13 Jan-14 Jul-14 Jan-15 Jul-15 Energy Transfer DAPL Expected Online: 4Q ,000 Bopd Rail Pipeline Barge Transportation Future Pipeline CLR Piped CLR Railed North Dakota Pipeline Authority and CLR Estimates 19

20 LOW CASH COST COMPETITIVELY POSITIONS CLR Avg. Realized $/BOE (3) $80 $70 $60 $50 $40 $30 $20 $10 $0 $44.68 $ % $59.35 $ % $72.45 $ % $65.99 $48.59 $72.04 $ % 74% $66.53 $ % $31.65 $ % $37.82 $ % $29.90 $17.90 $3.40 $3.34 $3.95 $4.74 $4.49 $1.72 $2.95 $4.47 $5.82 $5.58 $6.02 $5.54 $4.08 $3.75 $3.78 $2.19 $2.35 $2.36 $2.63 $2.38 $2.07 $2.06 $2.95 $1.85 $2.27 $1.34 $1.95 $6.89 $5.87 $6.13 $5.49 $5.69 $5.58 $5.05 $4.39 $ Q Q Q 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) 60% PRODUCTION EXPENSE G&A (1) PRODUCTION/SEVERANCE TAX & OTHER INTEREST CASH MARGIN (2) 20 Low cash cost of $12.00 per BOE, 32% lower than FY 2014

21 INVESTMENT GRADE FINANCIAL PROFILE UNSECURED CREDIT FACILITY AMPLE LIQUIDITY WITH $2.75 BILLION REVOLVER AND ABILITY TO UPSIZE TO $4.0 BILLION ~$1.9 BILLION AVAILABLE ON REVOLVER 3,000 Net Debt/TTM EBITDAX (2) 2.59x Net Debt/3Q 2015 Avg. Daily Production FINANCIAL RATIOS (1) $31,076 Net Debt/YE 2014 Proved Reserves 3 Year Avg. Recycle Ratio (YE 2014) DEBT MATURITIES SUMMARY $ x NO BORROWING BASE REDETERMINATION 2-YEAR EXTENSION OPTION BEYOND 2019 FINANCIAL STRENGTH NO NEAR-TERM DEBT MATURITIES (EARLIEST IS $500 MILLION IN 11/2018) INVESTMENT GRADE CREDIT RATING MOODY S: Baa3 S&P: BBB- ($MM) 2,500 2,000 1,500 1, No maturities for 3 years 1. ALL RATIOS ARE AS OF 9/30/15, EXCEPT WHERE NOTED 2. SEE APPENDIX FOR RECONCILIATION OF GAAP NET INCOME AND OPERATING CASH FLOWS TO EBITDAX. $2.75 billion credit facility 21 $500 $1,870 UNDRAWN LIBOR % 4.3% AVERAGE 7.125% $880 INTEREST RATE 7.375% $200 $ % $2, % $1, % $1, % Revolver Balance 11/4/15 Callable 10/1/15 Callable 4/1/16 Callable 3/15/17 $700

22 EXCEEDING 2015 PLAN PRODUCTION & CAPITAL DECEMBER 2014 GUIDANCE AUGUST 2015 GUIDANCE UPDATED 2015 GUIDANCE Production growth (YOY) 16% to 20% 19% to 23% 24% to 26% Capital expenditures (non-acquisition, in $ millions) $2,700 $2,700* $2,700* Operating Expenses Production expense ($ per Boe) $5.50 to $6.00 $4.75 to $5.25 $4.00 to $4.50 Production tax (% of oil & gas revenue) 7.5% to 8.5% 7.5% to 8.5% 7.5% to 8.0% G&A expense ($ per Boe) $2.00 to $2.50 $1.75 to $2.25 $1.70 to $2.00 Non-cash equity compensation ($ per Boe) $0.75 to $0.95 $0.70 to $0.80 $0.65 to $0.75 DD&A ($ per Boe) $20.00 to $22.50 $20.00 to $22.50 $20.00 to $22.50 Average Price Differentials NYMEX WTI crude oil ($ per barrel of oil) ($7.00) to ($10.00) ($7.00) to ($10.00) ($7.00) to ($9.00) Henry Hub natural gas (1) ($ per Mcf) $0.00 to ($0.50) $0.00 to ($0.50) $0.00 to ($0.50) * TARGETING $2.45B TO $2.5B FOR FULL-YEAR INCLUDES NATURAL GAS LIQUIDS PRODUCTION IN DIFFERENTIAL RANGE 22

23 2015 CAPITAL EXPENDITURES BUDGET $2.7B BUDGET NET WELLS (1) $2.45 TO $2.5B NET WELLS (1) BAKKEN SCOOP WOODFORD SCOOP SPRINGER NW CANA JDA & OTHER TOTAL PROJECTED GROSS OPERATED WELLS WOC AT YE 2015 WOC AT YE 2014 (FOR COMPARISON) ~100 ~ DRILLING CAPITAL ALLOCATION: BAKKEN: 65% SCOOP: 30% - WOODFORD: 26% - SPRINGER: 4% NW CANA JDA & OTHER: 5% AVERAGE ~28 OPERATED RIGS IN YOY PRODUCTION GROWTH OF 24-26% 1. INCLUDES OPERATED AND NON-OPERATED WELLS WITH FIRST PRODUCTION WOC = WAITING ON COMPLETION 23

24 APPENDIX 24

25 POTEET DENSITY PILOT WOODFORD CONDENSATE FAIRWAY POTEET DENSITY PILOT 10-WELL DENSITY DUAL HORIZON 10 WELLS HAD COMBINED PEAK PRODUCTION RATES OF 146,840 MCFPD AND 3,240 BOPD AVERAGE OWNERSHIP: 94% WORKING INTEREST 1016 Testing for the OCC required 24 hour shut in for individual wells 1. NORMALIZED TO 7,500 LATERAL 513 SPACING BETWEEN WELL BORES 1,026 SPACING IN SAME HORIZON LATERALS RANGE FROM 4,552 TO 10,110 25

26 SCOOP TYPE CURVES Boe per day 1,800 1,600 1,400 1,200 1, Woodford Condensate Type Curve 4,500' Act. Well Count Ext. Act. Well Count 4,500' Act. Production Ext. Type Curve (Normalized to 7,500' LL) Ext. Act. Production (8,800' Avg LL) Producing Months Well Count Boe per day Springer Shale Type Curve Well Count Type Curve (Normalized to 4,500' LL) Act. Production (Normalized to 4,500') Producing Months Well Count 1,725 MBoe Model Parameters 7,500 Lateral Length Oil IP Rate, Bbl/day 280 Oil 30 day IP Rate, bbl/day 262 Oil Initial Decline 61% Oil b factor 1.1 Oil EUR, MBo 295 Gas IP Rate, Mcf/day 7,000 Gas 30 day IP Rate, MCF/day 6,595 Gas Initial Decline 58% Gas b factor 1.2 Gas EUR, MMcf 8,580 Equivalent EUR, MBoe 1,725 Minimum Decline 6% Capital, $MM MBoe Model Parameters 4,500 Lateral Length Oil IP Rate, Bbl/day 670 Oil 30 day IP Rate, bbl/day 618 Oil Initial Decline 62% Oil b factor 1.25 Oil EUR, MBo 735 Gas IP Rate, Mcf/day 867 Gas 30 day IP Rate, MCF/day 810 Gas Initial Decline 56% Gas b factor 1.4 Gas EUR, MMcf 1,230 Equivalent EUR, MBoe 940 Minimum Decline 6% Capital, $MM

27 ENHANCED COMPLETIONS CONTINUE TO DELIVER 90-DAY PRODUCTION COMPARISON FOR 30-STAGE COMPLETIONS IN BAKKEN (1) Cum BOE 60,000 55,000 50,000 45,000 40,000 35,000 30,000 25,000 20,000 15,000 10,000 5, % - 45% INCREASE IN EUR Days PRODUCTION UPLIFT ~50% Slickwater (46 Wells) ~35% Hybrid (52 Wells) AVERAGE STANDARD COMPLETION OFFSETTING LEGACY WELLS 1. ENHANCED SLICKWATER AND HYBRID 30-STAGE WELL COMPLETIONS IN WILLIAMS AND MCKENZIE COUNTIES NOTE: ECONOMICS AT $60/BBL OIL AND $3.00/MCF GAS 27

28 CONTINUING TO DELIVER STRONG MARGINS Q Q Q 2015 Realized oil price ($/Bbl) $54.44 $70.69 $88.51 $84.59 $89.93 $81.26 $38.56 $49.84 $38.95 Realized natural gas price ($/Mcf) $2.95 $4.26 $4.87 $3.73 $4.87 $5.40 $2.70 $2.31 $2.23 Oil production (Bopd) 27,459 32,385 45,121 68,497 95, , , , ,472 Natural gas production (Mcfpd) 59,194 65, , , , , , , ,834 Total production (Boepd) 37,324 43,318 61,865 97, , , , , ,278 EBITDAX ($000's) (1) $450,648 $810,877 $1,303,959 $1,963,123 $2,839,510 $3,776,051 $439,427 $647,009 $472,221 Key Operational Statistics (per Boe) (2) Average oil equivalent price (excludes derivatives) $44.68 $59.35 $72.45 $65.99 $72.04 $66.53 $31.65 $37.82 $29.90 Production expense $6.89 $5.87 $6.13 $5.49 $5.69 $5.58 $5.05 $4.39 $4.00 Production tax and other $2.95 $4.47 $5.82 $5.58 $6.02 $5.54 $2.63 $2.95 $2.27 G&A (3) $2.19 $2.35 $2.36 $2.38 $2.07 $2.06 $1.85 $1.34 $1.95 Interest $1.72 $3.34 $3.40 $3.95 $4.74 $4.49 $4.08 $3.75 $3.78 Total cash costs $13.75 $16.03 $17.71 $17.40 $18.52 $17.67 $13.61 $12.43 $12.00 Cash margin $30.93 $43.32 $54.74 $48.59 $53.52 $48.86 $18.04 $25.39 $17.90 Cash margin % 69% 73% 76% 74% 74% 73% 57% 67% 60% 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. 28

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 (net income) before interest expense, income taxes, depreciation, depletion, amortization and accretion, property impairments, exploration expenses, non-cash gains and losses resulting from the requirements of accounting for derivatives, non-cash equity compensation expense, and losses on extinguishment of debt. EBITDAX is not a measure of net income or operating cash flows as determined by GAAP. Management believes EBITDAX is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. Further, we believe that EBITDAX is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet future debt service requirements, if any. We exclude the items listed above from net income 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 or operating cash flows as determined in accordance with GAAP or as an indicator of a company s operating performance or liquidity. Certain items excluded from EBITDAX are significant components in understanding and assessing a company s financial performance, such as a company s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of EBITDAX. Our computations of EBITDAX may not be comparable to other similarly titled measures of other companies. See the following page for reconciliations of our net income and operating cash flows to EBITDAX for the applicable periods. 29

30 EBITDAX RECONCILIATION TO GAAP The following tables provide reconciliations of our net income and operating cash flows to EBITDAX for the periods presented: In thousands Q Q Q 2015 Net income (loss) $ 71,338 $ 168,255 $ 429,072 $ 739,385 $ 764,219 $ 977,341 $ (131,971) $ 403 $ (82,423) Interest expense 23,232 53,147 76, , , ,928 75,063 78,442 79,399 Provision (benefit) for income taxes 38,670 90, , , , ,697 (54,021) 4,142 (48,744) Depreciation, depletion, amortization and accretion 207, , , , ,645 1,358, , , ,809 Property impairments 83,694 64, , , , , ,561 76,872 96,697 Exploration expenses 12,615 12,763 27,920 23,507 34,947 50,067 14, Impact from derivative instruments: Total (gain) loss on derivatives, net 1, ,762 30,049 (154,016) 191,751 (559,759) (32,755) 4,737 (46,527) Total cash received (paid), net ,495 (34,106) (45,721) (61,555) 385,350 23,435 13,182 11,917 Non-cash (gain) loss on derivatives, net 2, ,257 (4,057) (199,737) 130,196 (174,409) (9,320) 17,919 (34,610) Non-cash equity compensation 11,408 11,691 16,572 29,057 39,890 54,353 11,263 16,165 12,861 Loss on extinguishment of debt , EBITDAX $ 450,648 $ 810,877 $ 1,303,959 $ 1,963,123 $ 2,839,510 $ 3,776,051 $ 439,427 $ 647,009 $ 472,221 In thousands Q Q Q 2015 Net cash provided by operating activities $ 372,986 $ 653,167 $ 1,067,915 $ 1,632,065 $ 2,563,295 $ 3,355,715 $ 522,190 $ 394,622 $ 498,680 Current income tax provision (benefit) 2,551 12,853 13,170 10,517 6, Interest expense 23,232 53,147 76, , , ,928 75,063 78,442 79,399 Exploration expenses, excluding dry hole costs 6,138 9,739 19,971 22,740 25,597 26,388 5, Gain (loss) on sale of assets, net ,588 20, , ,070 20, Excess tax benefit from stock-based compensation 2,872 5, , ,177 Other, net (3,890) (3,513) (4,606) (7,587) (1,829) (17,279) (6,775) 3,039 (3,889) Changes in assets and liabilities 46,050 50, ,949 13,015 10, ,679 (159,065) 150,219 (115,497) EBITDAX $ 450,648 $ 810,877 $ 1,303,959 $ 1,963,123 $ 2,839,510 $ 3,776,051 $ 439,427 $ 647,009 $ 472,221 30

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, gains and losses on asset sales, and losses on extinguishment of debt. 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. 3Q Q 2014 YTD 2015 YTD 2014 In thousands, except per share data After-Tax $ Diluted EPS After-Tax $ Diluted EPS After-Tax $ Diluted EPS After-Tax $ Diluted EPS Net income (loss) (GAAP) $ (82,423) $ (0.22) $ 533,521 $ 1.44 $ (213,992) $ (0.58) $ 863,293 $ 2.33 Adjustments, net of tax: Non-cash (gain) loss on derivatives, net (21,458) (0.06) (298,500) (0.81) (16,126) (0.04) (169,481) (0.46) Property impairments 60, , , , (Gain) loss on sale of assets, net (174) - (3,409) (0.01) (14,214) (0.04) Loss on extinguishment of debt , , Adjusted net income (loss) (Non-GAAP) $ (43,512) $ (0.12) $ 300,961 $ 0.81 $ (28,881) $ (0.08) $ 850,402 $ 2.29 Weighted average diluted shares outstanding 369, , , ,632 Adjusted diluted net income (loss) per share (Non-GAAP) $ (0.12) $ 0.81 $ (0.08) $

32 CONTACT INFORMATION J. Warren Henry Vice President, Investor Relations & Research Phone: Alyson L. Gilbert Senior Investor Relations Analyst Phone: Website: 32