CORPORATE PRESENTATION. May 2018

Transcription

1 CORPORATE PRESENTATION May 2018

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 XEC Statistical Summary Market Cap 1 $ 9 billion Debt/Adj. EBITDA 2 1.2x Daily Production (1Q 18) Proved Reserves (YE 17) % Natural gas 48% % Proved Developed 83% R/P Ratio 8.0x 206 MBOE 559 MMBOE Quarterly Dividend $0.16/share 1 As of May 7, As of and for the twelve months ended 3/31/18. See Appendix for non-gaap definitions and reconciliations to nearest comparable GAAP measure. 3

4 Who is Cimarex? Returns driven E&P company Balanced portfolio of assets Premier position in the Delaware Basin and Mid-Continent region Flexibility through commodity cycles Continuous idea generation Strong, disciplined execution Solid financial position Conservative debt levels and ample liquidity $464 million in cash at March 31,

5 2017 Achievements Improved well performance Enhanced completion design Allows tighter development well spacing Six successful spacing pilots announced in 2017 Additional spacing tests underway Result: infill development that preserves returns while adding locations (NPV) 5

6 Return driven production growth continues in 2018 Daily Production (MBOE) High return projects expected to generate 2018 production growth of 11 16% Oil expected to grow 21 26% Oil growth estimated at 30 35% 4Q18 vs 4Q17 30% 31% 28% 30% 33% E Oil NGL Natural Gas 6

7 2018 Capital Investment Program Woodford Meramec Avalon Bone Spring Other D&C Capital $ billion Wolfcamp E&D Capital of $ billion 29% increase from 2017 Within cash available D&C Capital $ billion 82% of Total E&D capital Permian Basin ~70% Mid-Continent ~30% Additional $80 90 million budgeted for midstream/other Operating 13 drilling rigs Ten in Permian Three in Mid-Continent Five completion crews Three in Permian Two in Mid-Continent 7

8 2018 Production Growth Daily Production (MBOE) Net Wells Online A 1QA 2QE 3QE 4QE 2018E Oil 1QA 2QE 3QE 4QE Wells Drilling or WOC at 12/31/18 Permian Mid-Continent 8

9 2018 Delaware Basin Plans Total D&C Capital Economies of Scale Activity by Area Bone Spring Single well Eddy Ward Reeves Avalon $ mm 80 Net Wells Wolfcamp Multi-well Lea Culberson 9

10 Delaware Basin Wolfcamp Overview 2017/18 wells Lower Wolfcamp Upper Wolfcamp Bone Spring ~216,000 net acres in the fairway Multiple Wolfcamp Targets Culberson/White City Area ~100,000+ net acres Upper & Lower Wolfcamp JDA with Chevron Reeves County ~63,000 net acres Upper Wolfcamp Lea County ~32,000 net acres Ward County ~16,000 net acres 195 total Wolfcamp wells drilled 109 long laterals (>7,000 ) 10

11 Culberson / White City Wolfcamp Details Charismatic 5 3,271 BOE/d (1,882 b/d) Owl Draw 12 2,521 BOE/d (1,393 b/d) Lower Wolfcamp Upper Wolfcamp Operated SWD 100,000+ net acres; JDA with Chevron in Culberson County 72 long lateral wells Seattle Slew spacing pilot producing Animal Kingdom infill drilling Positive results from Western Culberson Upper Wolfcamp delineation Five wells with average 30-day peak initial production of 2,724 BOE/d (56% oil) 11

12 Well Productivity Improvements Long Lateral Upper Wolfcamp Wells Completion Generation IP180 (BOE/d) 2,000 1,500 1, Gen 1 Gen 2 Gen 3 Gen ,000-ft. lateral Upper Wolfcamp wells drilled since 2013 Improvement in well productivity seen through enhanced completion design Returns get better with each design change Current wells have IRRs that range from % ATAX Provides strong fully burdened returns 10,000-ft. infill wells have IP180s that are 90% of parent wells Infill Oil (b/d) 12

13 Resilient Long Lateral Returns Culberson Long Lateral Wolfcamp BTAX IRR* 300% 200% 100% 0% $30 $40 $50 $60 $70 Realized Oil Price Upper Wolfcamp - $2/Mcf Upper Wolfcamp - $1/Mcf Lower Wolfcamp - $2/Mcf Lower Wolfcamp - $1/Mcf *Assumes full NGL recovery, NGL price is 30% of oil price 13

14 Culberson County Tim Tam Development Lower Wolfcamp Cumulative Production (MBOE) Tim Tam infill wells generated 67%+ ATAX return Infills have surpassed parent wells in both landing zones Results lead to 14 wells per section test Animal Kingdom currently drilling Tim Tam spacing Days Parent well (lower landing) Tim Tam Infill well (lower landing) Parent well ( upper landing) Tim Tam Infill well (upper landing) Lower Wolfcamp Lower Wolfcamp 1, Animal Kingdom spacing 225 1, ,216 1,756 14

15 Reeves County Focus Area Dixieland State ,505 BOE/d (1,464 b/d) Snowshoe Pagoda State Wood State 34 long lateral wells Targeting Upper Wolfcamp 28 10,000-ft. laterals producing Average 30-day peak IP of 1,809 BOE/d (49% oil) Two downspacing pilots producing Wood State (12 wells/section) Pagoda State (16 wells/section) Snowshoe development waiting on completion 8 wells; 3 landings (18 wells/section) Upper Wolfcamp Operated SWD 15

16 Reeves County Strong Infill Well Results Cumulative Production (MBOE) Days Upper Wolfcamp 10,000-ft. laterals Wood State: 6 wells testing 12 wells per section Surpassed Big Timber, previously best long lateral to date Average well performing 28% above parent well Pagoda State: 4 wells testing 16 wells per section Average well performing 16% above parent well Big Timber well Wood State parent well Average Wood State well Average Pagoda State well Upper Wolfcamp Pagoda spacing Upper Wolfcamp Wood State spacing

17 Lea County Upper Wolfcamp Avalon Bone Spring Thyme APY 2,059 BOE/d (1,416 b/d) Triste Draw Hallertau Coriander AOC ,333 BOE/d (2,248 b/d) Red Tank Red Hills Exciting multi-pay area $225 million capital spend in 2018 Two Avalon wells brought online in 1Q 18 Coriander AOC 1-12 State 1H with average 30-day peak IP of 3,333 BOE/d (67% oil) Thyme APY Fed 9H with average 30-day peak IP of 2,059 BOE/d (69% oil) Avalon activity 24,000 net prospective acres Triste Draw infill spacing pilot waiting on completion Wolfcamp activity 32,000 net prospective acres Hallertau infill spacing pilot producing 17

18 Permian Basin Residue Gas Takeaway Sales agreements in place >98% of forecasted production through October 2019 El Paso or Waha index pricing Own and operate two gas gathering systems Triple Crown Culberson/Eddy Counties Matterhorn Reeves County Connected to multiple gas processors with inter- and intrastate outlets Long-term sales agreements in place for NGL volumes 18

19 Permian Basin Oil Takeaway Sales agreements in place for oil volumes through 2018 & 2019 Strategic partnerships in core areas Pipelines in place Purchase obligations Midland index pricing ~70% oil production on pipe Plains pipeline Plains pipeline (under construction) Energy Transfer pipeline Offloading Site NGL Gas Oil Q1 18 Permian Revenue 19

20 Permian Basin Water Management Saltwater Disposal System Own and operate salt water disposal (SWD) systems in Culberson, Eddy and Reeves Improves operating costs Recycling produced water for completion operations 40% of total water procured in 2017 was recycled Cost savings of ~$1.10/bbl of water Culberson Wolfcamp wells use 87% recycled water for completions; Reeves Wolfcamp wells use 46% Secured SWD agreements in Lea County 20

21 Mid-Continent Basin 2018 Outlook Total D&C Capital Economies of Scale Activity by Area Woodford Meramec Single well Other Woodford Meramec $ million Multi-well 41 Net Wells Lone Rock 21

22 Mid-Continent Overview Meramec and Woodford Stacked Targets Meramec: 116,500 net prospective acres 100% HBP Woodford: 136,500 net undeveloped acres (88% HBP) Meramec play outline Woodford play outline Cana core 22

23 Meramec The Big Picture Dupree BIA 1H 2,877 BOE/d (1,597 b/d) Tillman BIA 1H 2,389 BOE/d (1,069 b/d) Mike Com 1H 4,353 BOE/d (433 b/d) 5,000 ft Meramec 10,000 ft Meramec Meramec play outline Average 30-day Peak IP (b/d) 2,500 2,000 1,500 1, N10W Rocky 1-17H 1,912 BOE/d (1,282 b/d) Oil Rate (b/d) Improving well results driving activity Thirteen 10,000-ft. lateral wells brought online in 2017 Average 30-day IP of 2,383 BOE/d (37% oil) Four Meramec developments planned in 2018 Formulating development plans in the 14N-10W area 40 industry downspacing pilots online or underway in the play XEC has interest or data on all but nine Oil BOE Oil per 1000' lateral 0 23

24 Meramec Development Plans Mike Com 1H 5,000 ft Meramec 10,000 ft Meramec Meramec play outline Lehman 14N10W Steve O Miss Mary Woolfolk / NIB 2018 developments Steve O 6 wells with 8 wells/section spacing (currently completing) Lehman 6 wells with 8 wells/section spacing Miss Mary 3 wells with 8 wells/section spacing (waiting on completion) Future 14N-10W development Stacked Meramec/Woodford Operate almost all of the 24,000 gross acres Average 62% working interest Successfully tested 19 wells per section (Leon Gundy) Positive results with zone completion sequence at Woolfolk/NIB Another zone completion test planned 24

25 Woodford Activity 14N10W Clyde Copeland Long history of activity Emerging Lone Rock play yielding best results to date Clyde Copeland high density spacing pilot yielding good results Formulating development plans in the 14N-10W area Lone Rock Operated well Non-operated well 25

26 Lone Rock Activity Woodford Jimmie Com 10.2 MMcfed (368 b/d) Shelly Meyers 1H 13.4 MMcfed (535 b/d) Hines Federal 1H 17.2 MMcfed (1,016 b/d) Average Cumulative Production per Well (MBOE) 500 1st Gen (~1,440 lb/ft) nd Gen (~2,800 lb/ft) 3rd Gen (~2,800 lb/ft) JD Hoppinscotch Best Woodford returns in portfolio ~16,000 net contiguous acres Multiple completion design factors enhance productivity Infill testing: Shelly testing 8 and 12 wells per section (currently completing) Woodford well spacing Shelly Spacing well spacing JD Hoppinscotch testing 8 wells per section in Woodford (currently drilling) JD Hoppinscotch Spacing Days Meramec Woodford

27 Well-positioned for 2018 Solid returns from large portfolio Strong financial position $464 million of cash on the balance sheet at March 31, 2018 Emphasis on execution Preserve returns in inflationary environment Idea generation Technical enhancements to completion design Testing even tighter infill well spacing Ultimate field optimization provides best returns to shareholders 27

28 Appendix 28

29 2018 Guidance Second Quarter Full Year Daily Production (MBOE) % Oil 33% Capital Expenditures ($billion) E & D $ D & C $ Midstream/Other $ Expenses ($/BOE) Production $ Transportation, processing & other $ DD&A and ARO accretion $ General and administrative $ Taxes other than income (% of oil and gas revenue) % 29

30 Hedges as of May 7, Second Quarter Third Quarter Fourth Quarter First Quarter Second Quarter Third Quarter OIL WTI Oil Collars 1 Volume (Bbl/d) 31,000 27,000 21,000 15,000 15,000 8,000 Weighted Average Floor Weighted Average Ceiling WTI Swaps 2 Volume (Bbl/d) 15,000 21,000 16,000 13,000 13,000 8,000 Weighted Average Differential 3 (0.78) (1.94) (2.25) (2.60) (2.60) (3.93) GAS PEPL Collars 4 Volume (MMBtu/d) 130, ,000 70,000 60,000 60,000 30,000 Weighted Average Floor Weighted Average Ceiling El Paso Perm Collars 5 Volume (MMBtu/d) 100,000 80,000 60,000 50,000 50,000 30,000 Weighted Average Floor Weighted Average Ceiling Total Natural Gas Collars Volume (MMBtu/d) 230, , , , ,000 60,000 Notes: 1 WTI refers to West Texas Intermediate oil prices as quoted on the New York Mercantile Exchange 4 PEPL refers to Panhandle Eastern Pipe Line Tex/OK Mid-Continent as quoted on Platt s Inside FERC 2 Index price on basis swaps is WTI Midland as quoted by Argus Americas Crude 5 El Paso Perm refers to El Paso Permian Basin index as quoted on Platt s Inside FERC 3 Index price on basis swaps is WTI NYMEX less weighted average differential shown in table 30

31 Permian Region Production Daily Production (MBOE) Q4 14 Q1 15 Q2 15 Q3 15 Q4 15 Q1 16 Q2 16 Q3 16 Q4 16 Q1 17 Q2 17 Q3 17 Q4 17 Q1 18 Oil NGL Natural Gas 31

32 Mid-Continent Region Production Daily Production (MBOE) Q4 14 Q1 15 Q2 15 Q3 15 Q4 15 Q1 16 Q2 16 Q3 16 Q4 16 Q1 17 Q2 17 Q3 17 Q4 17 Q1 18 Oil NGL Natural Gas 32

33 Non-GAAP Reconciliation Reconciliation of Net Income to EBITDA and Adjusted EBITDA 1 ($ in Millions) LTM 3/31/18 Net income (loss) $(2,580) $ (409) $ 494 $ 550 Income tax expense (benefit) (1,472) (214) Interest expense, net of capitalized DD&A and ARO accretion EBITDA (3,256) (161) 1,196 1,264 Impairment of oil and gas 4, Adjusted EBITDA ,196 1,264 Debt Adjusted Shares (Using trailing 12-mo (TTM) stock price) LTM 3/31/18 Basic shares outstanding (in 000s) 95,124 95,437 95,433 Debt adjusted shares outstanding YE Debt, net TTM stock price 847, ,099, ,036, Equivalent shares issued using TTM stock price 7,362 9,644 9,565 Debt adjusted shares using TTM stock price 102, , ,998 1 The above table provides a reconciliation from generally accepted accounting principles (GAAP) net income (loss) to non-gaap EBITDA and non-gaap adjusted EBITDA, which excludes ceiling test impairments 33

34 Non-GAAP Reconciliation Reconciliation of cash flow from operations 1 Three months Ended Mar 31, ($ in Millions) Net cash provided by operating activities $ 250 $ 383 Change in operating assets and liabilities 16 (16) Adjusted cash flow from operations $ 266 $ 367 Debt/Cap calculation ($ in Millions) Mar 31, 2018 Long-term debt (principal) $ 1,500 Stockholders equity 2,752 Total capitalization 4,252 Long-term debt/total capitalization 35% Finding & development (F&D) cost 2017 Additions to proved reserves (MMBOE) Revisions of previous estimates (10.0) Extensions & discoveries Purchase of reserves 0.2 Total Additions (all sources) Total Capital ($MM) $ 1,281 F&D Costs (all sources) ($/BOE) $ 8.71 Debt/Adjusted EBITDA calculation Twelve months Ended Mar 31, LTM ($ in Millions) Long-term debt (principal) $1,500 $1,500 $1,500 Adjusted EBITDA 597 1,196 1,264 Debt/Adjusted EBITDA 2.5x 1.3x 1.2x Drilling F&D cost (extensions & discoveries) ($/BOE) $ Management uses the non GAAP measure of adjusted cash flow from operations 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. Management believes this non GAAP measure provides useful information to investors for the same reasons, and that it is also used by professional research analysts in providing investment recommendations pertaining to companies in the oil and gas exploration and production industry. 34

35 Permian Basin Pilot Details Culberson Lower Wolfcamp Animal Kingdom development Eight wells testing 14 wells per section Currently drilling Animal Kingdom spacing Red Hills Upper Wolfcamp Hallertau development Five wells testing 12 wells per section Producing Hallertau spacing Lower Wolfcamp ,216 1,216 Upper Wolfcamp Reeves Upper Wolfcamp Snowshoe development Eight wells testing 18 wells per section Waiting on completion Snowshoe spacing Red Tank Avalon Triste Draw development Six wells testing 20 wells per section Waiting on completion Triste Draw spacing Upper Wolfcamp Avalon

36 Culberson County Upper Wolfcamp Development Extrapolated Average Cumulative Production per 7,500-ft. well (MBOE) Similar, strong early cumulative per well production testing 6, 8 or 12 wells per section Upper Wolfcamp development to begin in 2018 Two developments planned Days Gato average well (6 wells/section) Sunny's average well (8 wells/section) Seattle Slew average well (12 wells/section) 36

37 Clyde Copeland Results Cumulative Production (MBOE) Increased density pilot 8 wells testing 16 and 20 wells per section Results positive for future well spacing Interference testing on-going Days Osage Woodford Clyde Copeland development well spacing well spacing 80 Average well (20 well spacing) Average well (16 well spacing) Average parent well (9 well spacing) 37