974 MMcfe/d. 2.9 Tcfe

Transcription

1 1 The Oil and Gas Conference August 16, 2016

2 Forward looking Statements This presentation contains projections and other forward looking statements within the meaning of Section 27A of the U.S. Securities Act of 1933 and Section 21E of the U.S. Securities Exchange Act of These projections and statements reflect the Company s current views with respect to future events and financial performance. No assurances can be given, however, that these events will occur or that these projections will be achieved, and actual results could differ materially from those projected as a result of certain factors. A discussion of these factors is included in the Company s periodic reports filed with the U.S. Securities and Exchange Commission. Contact: Karen Acierno Director Investor Relations kacierno@cimarex.com Cimarex Energy Co Lincoln Street, Suite 3700 Denver, CO

3 Who is Cimarex? Market cap... $12.4B Debt/Adj. EBITDA 1 2.8x Production (2Q16) Proved reserves. 974 MMcfe/d 2.9 Tcfe % Natural gas 52% % Proved developed 75% R/P Ratio x Quarterly dividend of $0.08/share 1 June 30,

4 What s Important Returns drive decisions Balanced portfolio of assets Premier position in the Delaware Basin and Mid Con region Flexibility through commodity cycles Idea generation and track record of strong execution Strong financial position Conservative debt levels and ample liquidity $642mm in cash at June 30,

5 Reserves Growth Proved Reserves (Tcfe) * Oil NGL Gas *Adjusted for negative price revisions. 5 5

6 Production Growth Daily Production (MMcfe) Net Debt Adjusted Production/Share (MMcfe) 4 1, , % 51% 51% 53% 53% E Oil & NGL Natural Gas

7 Hedge Strategy Hedged Volumes as of 6/30/16 MMcfe/d 3Q16 4Q16 1Q17 2Q17 3Q17 Average Target volume is ~50% of oil and ~50% of gas production Methodical approach Five quarter duration Bias toward costless collars Downside protection Some upside price exposure Average commodity prices of current collars: Crude oil: $40.92 X $49.94 PEPL gas: $2.25 X $2.83 El Paso Permian gas: $2.36 X $2.92 Gas (MMcf/d) Oil (bbl/d) 7

8 2016 E&D Investment Drilling & Completion Capital ~$600 million $750mm (up from previous $650 $700mm guidance) Multiple projects/multiple zones Delaware Basin Acreage obligations Upper & Lower Wolfcamp in Culberson County Reeves infill development Mid Continent region Meramec delineation and acreage retention Continue Woodford infill Flexibility to right size capital Five rigs from three Accelerated completions Larger stimulations 8

9 Completion Evolution Continues Pounds of Sand per Lateral Foot Jan. '15 July '15 Jan. '16 July '16 Culberson Upper Wolfcamp 1,250 1,650 1,650 2,500 Culberson Lower Wolfcamp 1,250 1,250 1,250 2,400 Reeves Upper Wolfcamp 1,300 1,700 1,700 2,500 Meramec 1,250 1,800 2,700 2,800 Woodford 2,000 2,500 3,000 3,500 9

10 Biggest Opportunity Delaware Basin Wolfcamp ~230,000 net acres in the fairway Multiple Wolfcamp Targets Culberson/White City Area 100,000+ net acres Upper & Lower Wolfcamp JDA with Chevron Reeves County 80,000 net acres Upper Wolfcamp 10

11 Culberson Area Wolfcamp Details 100,000+ net acres; JDA with 2013 Chevron main objectives 20 Drilling long lateral to hold Lower acreage Wolfcamp C & D Wolfcamp wells producing Two rigs; ~20 wells 11 Upper Wolfcamp long laterals producing 41 wells to date; 30 day average IP of 6.5 MMcfe/d Downspacing pilot flowing back Product mix of 45% gas; 26% oil; 29% NGL New Upsize oil gathering frac stages in place First 20 stage test has 30 day average IP of 8.4 MMcfe/d Hidalgo plant (MarkWest) on line as scheduled Testing Wolfcamp A Experiment with long laterals Stacked lateral test Design downspacing pilot 11

12 Resilient Long Lateral Returns Culberson County Wolfcamp 10,000 ft. lateral BTax IRR* 200% 175% 150% 125% 100% 75% 50% 25% Upper Wolfcamp Lower Wolfcamp 0% $20 $30 $40 $50 $60 Oil Price *Assumes $2.00/Mcf natural gas, full NGL recovery, NGL price is 30% of oil price. All product prices are realized

13 Long Lateral Performance Culberson Lower Wolfcamp Cumulative Production (MBOE) 70% Increase Fifteen 10,000 foot laterals Average 30 day peak IP of 2,361 BOE/d (25% oil; 46% gas; 29% NGL) Flying Ebony Average 30 day peak IP of 3,127 BOE/d (23% oil; 47% gas; 30% NGL) 36% higher than previous completions Completed using 2,400 lb/ft; 48 stages Days Flying Ebony 10,000 ft. lateral* Tim Tam *Flying Ebony well excluded from average. 13

14 Improving Upper Wolfcamp Completion Design Culberson County Cumulative Production (MBOE) 22% Increase Four 10,000 ft. laterals completed to date Wells with new frac have ~1,650 lb/ft of sand 30 day peak IP of 2,098 BOE/d (55% oil; 28% gas; 17% NGL) Days New frac (2 wells) Old frac (2 wells) 14

15 Culberson County Upper Wolfcamp Pilot Six well downspacing pilot 7,500 foot laterals Stacked/staggered well pattern Sunny s Halo section testing eight wells/section Sunny s Halo Gato del Sol Gato del Sol testing six wells/section $8.8mm well cost Upper Wolfcamp Completed with 2,400 pounds of sand per foot On production Parent Well 15 15

16 Culberson County Tim Tam Infill Development First Lower Wolfcamp Infill Five 10,000 foot laterals Six wells per two section unit Staggered well pattern Waiting on 4Q Completion D Barbaro Prewit Omaha Lower Wolfcamp Tim Tam Forward Pass 200 Parent Well 16 16

17 Reeves County Focus Area Cabinet State Big Timber Targeting Upper Wolfcamp Nine long laterals producing Average 30 day peak IP of 1,577 BOE/d (51% oil; 28% gas; 21% NGL) Best wells to date 10k ft: Big Timber has avg. 30 day peak IP of 3,309 BOE/d (49% oil; 27% gas; 24% NGL) 5k ft: Cabinet State has avg. 30 day peak IP of 2,170 BOE/d (60% oil; 22% gas; 18% NGL) First infill development completing Six 10k ft. laterals Stack/Stagger pattern Meets acreage obligations 17 17

18 Bigger Completion Improves Avalon Results Lea County Cumulative Production (MBOE) 119% Increase 13,700 net acres 250 locations Includes Avalon and Leonard Assumes 80 acre spacing 150 Triste Draw 25 #7H Triste Draw 25 7H Old frac Days 18 Recent spacing pilot

19 Mid Continent Overview Meramec and Woodford Stacked Targets Meramec: 115,000 net prospective acres 90,000 derisked Woodford: 135,000 net undeveloped acres (88% HBP) Meramec play outline Woodford play outline Cana core 19

20 Meramec: The Big Picture Peterson Sims 5,000 ft. Meramec well 10,000 ft. Meramec well Meramec play outline 19 5,000 ft laterals have avg. 30 day peak IP of 8.4 MMcfe/d 42% gas; 36% oil; 22% NGL Five10,000 ft laterals with avg. 30 day peak IP of 13.3 MMcfe/d 44% gas; 34% oil; 22% NGL Oil yield ranges from bbl/ MMcfe Delineation continues Peterson well has best IP to date 19MMcfe/d (54% oil; 30% gas; 16% NGL) Sims wells IP of 12.8MMcfe/d (29% Oil; 46% gas; 25% NGL) Downspacing pilot underway 20

21 Meramec Long Lateral Performance 1,400 1,200 1, Cumulative Production (MMCFE) 61% Increase 61% uplift after 120 days Five 10,000 ft laterals have 30 day peak IP of 13.3 MMcfe/d 44% gas; 34% oil; 22% NGL Oil yields range from 37 to 278 Bbl/MMcf 19 5,000 ft laterals have 30 day peak IP of 8.4 MMcfe/d 42% gas; 36% oil; 22% NGL Oil yields range from Bbl/MMcf 200 Average 10,000 ft lateral (5 wells) Average 5,000 ft lateral (19 wells) Days 21

22 Meramec Spacing Pilots Meramec Osage Woodford Stacked/Staggered Pilot Eight total wells Four Meramec wells Stacked/staggered spacing Testing 10 wells per section Four Woodford wells Testing 9 wells per section Completions in 2H16 Partner operated (Alma) downspacing pilot producing Average 30 day IP of 1,400 BOE/d (60% oil) 46% working interest 22

23 Woodford Shale Activity Cana Woodford Activity Map Operated Well Non operated Well Long history of activity Participated in 817 gross wells since 2007 Eastern core infill underway 6 sections; 2 operated 47 gross (22 net) wells Completions begin in early September Row 4 Infill Eastern Core Infill 23

24 2,400 2,000 Woodford: Completion Evolution Continues Cumulative Production Per Well Average (MMcfe) Armacost section developed using larger completion Per well production in line with earlier sections Tighter spacing means more production per section: 1,600 Cum. Production Per Section (Bcfe) 1, Armacost (9 infill wells) Haley (8 infill wells) Hartz (8 infill wells) Days Armacost Haley Hartz Gas NGL Oil 24 24

25 Well positioned for 2016 and Beyond Diverse asset portfolio with solid returns Strong financial position Investment grade rating with stable outlook at both S&P and Moody s Flexibility to adapt to commodity environment Emphasis on improved productivity Focus on retaining our attractive acreage position 25 25

26 Appendix 26 26

27 2016 Guidance 2016 Production, Unit Expense and Capital Guidance Third Quarter Full Year Production Total Equivalent (Mmcfe/d) ,000 % Liquids 53% 53% Capital Expenditures $750 million Expenses ($/Mcfe): Remainder of '16 Production $ Transportation, processing & other DD&A and ARO accretion* General and administrative** Taxes other than income (% of oil and gas revenue) % *Excludes the potential impact of any future ceiling test write downs **During the second quarter, a voluntary Early Retirement Incentive Program resulted in cash severance payments of $4.8 million ($0.05/Mcfe) 27 27

28 Hedges Average Third Fourth First Second Third Fourth Oil: Quarter Quarter Quarter Quarter Quarter Quarter WTI Oil Collars (1) Volume (Bbl/d) 9,000 9,000 9,000 9,000 5,000 6,821 Wtd Avg Floor Purchased (put) $ $ $ $ $ $ $ Wtd Avg Ceiling Sold (call) $ $ $ $ $ $ $ WTI Oil Three Way Collars (1) Volume (Bbl/d) 3,000 3,000 1,005 Wtd Avg Floor Sold (put) $ $ $ $ $ $ $ Wtd Avg Floor Purchased (put) $ $ $ $ $ $ $ Wtd Avg Ceiling Sold (call) $ $ $ $ $ $ $ Total WTI Oil Collars Volume (Bbl/d) 12,000 12,000 9,000 9,000 5,000 7, Average Third Fourth First Second Third Fourth Gas: Quarter Quarter Quarter Quarter Quarter Quarter PEPL Collars (2) Volume (MMBtu/d) 60,000 70,000 60,000 60,000 40,000 10,000 49,945 Wtd Avg Floor $ 2.28 $ 2.35 $ 2.29 $ 2.29 $ 2.38 $ 2.75 $ 2.33 Wtd Avg Ceiling $ 2.82 $ 2.86 $ 2.86 $ 2.86 $ 2.94 $ 3.05 $ 2.87 El Paso Perm Collars (2) Volume (MMBtu/d) 50,000 50,000 50,000 50,000 20,000 36,594 Wtd Avg Floor $ 2.37 $ 2.37 $ 2.37 $ 2.37 $ 2.30 $ $ 2.36 Wtd Avg Ceiling $ 2.89 $ 2.89 $ 2.95 $ 2.95 $ 2.93 $ $ 2.92 Total Natural Gas Collars Volume (MMBtu/d) 110, , , ,000 60,000 10,000 86,539 (1) WTI refers to West Texas Intermediate oil prices as quoted on the New York Mercantile Exchange. (2) PEPL refers to Panhandle Eastern Pipe Line Tex/OK Mid Continent. El Paso Perm is El Paso Permian Basin index; both as quoted in Platt s Inside FERC. 28

29 Cana Area Production MMcfe/day 450 Row 4 Drilling Commenced Row 4 Completions Began Q1 13 Q2 13 Q3 13 Q4 13 Q1 14 Q2 14 Q3 14 Q4 14 Q1 15 Q2 15 Q3 15 Q4 15 Q1 16 Q2 16 Gas NGL Oil 29 29

30 Permian Basin Production 100 MBOE/day Q1 13 Q2 13 Q3 13 Q4 13 Q1 14 Q2 14 Q3 14 Q4 14 Q1 15 Q2 15 Q3 15 Q4 15 Q1 16 Q2 16 Oil NGL Gas 30 30

31 Permian Region Provides Multiple Opportunities Multiple projects/multiple zones Wolfcamp shale (oil & gas) Bone Spring sands (oil) Avalon Shale (oil window) 2016 Focus Wolfcamp Long Laterals Meeting acreage obligations 31

32 Upsized Frac Improves Second Bone Spring Results White City 5,000 ft lateral Cumulative Production (MBOE) Focus Area % Increase Days 15 stages from nine 100 locations identified First 7,000 ft lateral has average 30 day peak IP of 2,753 BOE/d (68% oil) HBP acreage; infrastructure in place Upsized Completion Original Completion 32

33 Culberson County Downspacing Pilot Results Barbaro Two four well pilots; 5,000 ft laterals Barbaro Pilot 80 acre spacing (8 wells/section) 20 stage completion; 1,200 lbs/foot Prewit Omaha Pilot 107 acre spacing (6 wells/section) 16 stage completion;1,200 lbs/foot Results lead to design of first Lower Wolfcamp infill development Prewit-Omaha 33 33

34 Non GAAP Reconciliation Reconciliation of Net Income to EBITDA and Adjusted EBITDA 1 ($ in Millions) LTM Net income (loss) $ 565 $ 507 $ (2,409) $ (1,850) Income tax expense (benefit) (1,373) (1,063) Interest expense, net of capitalized DD&A and ARO accretion EBITDA 1,541 1,659 (2,939) (2,245) Impairment of oil and gas properties - - 3,717 2,775 Adjusted EBITDA 1,541 1, The above table provides a reconciliation from generally accepted accounting principles (GAAP) net income (loss) to EBITDA and adjusted EBITDA (non GAAP), which excludes ceiling test impairments 34 34

35 Non GAAP Reconciliation Reconciliation of cash flow from operations Net cash provided by operating activities $ 128 $ 257 Change in operating assets Three months Ended June 30, (in millions) and liabilities 18 (5) Adjusted cash flow from operations $ 147 $ 252 Finding & development (F&D) cost 2015 Proved Reserves adds (Bcfe) Revisions of previous estimates (276.2) Extensions & discoveries [C] Purchase of reserves - Total adds [A] Total capital $MM [B] $ 877 All-sources F&D ($/Mcfe) [B]/[A] $ 5.75 Drilling (excl. revisions) F&D ($/Mcfe) [B]/[C] $ 2.05 Debt/Cap Calculation Long-term debt (principal) $ 1,500 Stockholders' Equity 2,347 Total capitalization $ 3,847 Long-term debt/total capitalization Debt/Adj. EBITDA Calculation June 30, (in millions) 39% Twelve months Ended December 31, LTM /30/2016 Long-term debt (principal) 1,500 1,500 1,500 Adj. EBITDA 1, Debt/Adj. EBITDA 0.9x 1.9x 2.8x 1 Management believes that the non GAAP measure of adjusted cash flow from operations is useful information for investors because it is used internally and is accepted by the investment community as a means of measuring the company's ability to fund its capital program and dividends, without fluctuations caused by changes in current assets and liabilities, which are included in the GAAP measure of cash flow from operating activities. It is also used by professional research analysts in providing investment recommendations pertaining to companies in the oil and gas exploration and production industry. 2 Management believes this non GAAP measure is useful information as it is a common statistic used in the investment community to assist with analysis of the financial condition of an entity