J.P. Morgan Energy Equity Conference June 19, 2018
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 1934. 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 303-285-4957 Cimarex Energy Co. 1700 Lincoln Street, Suite 3700 Denver, CO 80203 303-295-3995 2
XEC Statistical Summary Market Cap 1 $ 8.3 billion Debt/Adj. EBITDA 2 1.2x Daily Production (1Q 18) 206 MBOE Proved Reserves (YE 17) 559 MMBOE % Natural gas 48% % Proved Developed 83% R/P Ratio 8.0x Quarterly Dividend $0.16/share 1 As of June 11, 2018 2 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
Who is Cimarex? Returns driven E&P company Focused on full cycle returns 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, 2018 Decades of drilling inventory 4
Recent Accomplishments Sale of Ward County assets announced $570 million Portfolio Optimization High-grading of investment opportunities Enhanced completion design continues to yield improved well performance Additional spacing tests and developments underway Infill development to maximize returns and resource recovery 5
Focused on Full-Cycle Economics D&C Capital as a % of Total E&D Actual Project Results* Half Cycle IRR Fully Burdened IRR Cimarex culture built on maximizing fully burdened after-tax rate of return on investment Rigorous technical evaluation of all aspects of E&D to improve economic return + D&C + Midstream SWD Overhead + Land Capital $1500/acre + Pre-drill and post-drill lookback evaluation of expected to actual results *2017 project with 36 gross wells. 6
Solid History of Returns and a Bright Future Ahead 50% 40% 30% 20% 10% 0% Cash Return on Capital Employed (CROCE) 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 Three-year outlook*: Maintenance capital of $700mm per year projected to keep production flat $1.2 billion of D&C capital per year generates ~10% production CAGR ~13% oil production CAGR CROCE of 30% XEC Peer Avg.*** At $55 oil/$2.00 gas realized prices, XEC can grow production 10% per year and generate $500-600mm of free cash flow** *2019-2021 **Free cash flow is defined as cash provided by operating activities less D&C capital, capitalized overhead, production and midstream capital and dividends. It excludes proceeds from announced asset sale. ***Peer avg. comprised of members of the S&P 500 E&P Index. 7
Return driven production growth continues in 2018 Daily Production (MBOE) 145 164 161 190 211-221 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% 2014 2015 2016 2017 2018E Oil NGL Natural Gas 8
2018 Capital Investment Program Woodford Meramec Avalon Bone Spring Other D&C Capital $1.3 1.4 billion Wolfcamp E&D Capital of $1.6 1.7 billion 29% increase from 2017 Within cash available D&C Capital $1.3 1.4 billion 82% of Total E&D capital Permian Basin ~70% Mid-Continent ~30% Additional $80 90 million budgeted for midstream/other Operating 12 drilling rigs Nine in Permian Three in Mid-Continent Six completion crews Three in Permian Three in Mid-Continent 9
2018 Delaware Basin Plans Total D&C Capital Economies of Scale Activity by Area Bone Spring Single well Eddy Ward Reeves Avalon $885 935mm 80 Net Wells Wolfcamp Multi-well Lea Culberson 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 Sale pending 195 total Wolfcamp wells drilled 109 long laterals (>7,000 ) 11
Well Productivity Improvements Long Lateral Upper Wolfcamp Wells (Culberson, Reeves and Ward Counties) Completion Generation IP180 (BOE/d) 2,000 1,500 1,000 500 52 10,000-ft. lateral Upper Wolfcamp wells drilled in Permian Basin 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 90-140% ATAX Provides strong fully burdened returns 0 Gen 1 Gen 2 Gen 3 Gen 4 Oil (b/d) 12
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
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 waiting on completion Positive results from Western Culberson Upper Wolfcamp delineation Five wells with average 30-day peak initial production of 2,724 BOE/d (56% oil) 14
Culberson County Tim Tam Development Lower Wolfcamp Cumulative Production (MBOE) 700 600 500 400 300 200 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 waiting on completion Tim Tam spacing 100 0 0 60 120 180 240 300 360 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 1,756 200 Animal Kingdom spacing 225 1,216 225 1,216 1,756 15
Reeves County Focus Area Dixieland State 55-6 2,505 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 currently completing 8 wells; 3 landings (18 wells/section) Upper Wolfcamp Operated SWD 16
Reeves County Strong Infill Well Results Cumulative Production (MBOE) 600 500 400 300 200 100 0 0 60 120 180 240 300 360 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 680 340 680 Upper Wolfcamp Wood State spacing 880 340 880 17
Lea County Upper Wolfcamp Avalon Bone Spring Thyme APY 2,059 BOE/d (1,416 b/d) Triste Draw Hallertau Coriander AOC 1-12 3,333 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 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 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 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 21
Mid-Continent Basin 2018 Outlook Total D&C Capital Economies of Scale Activity by Area Woodford Meramec Single well Other Woodford Meramec $375 425 million Multi-well 41 Net Wells Lone Rock 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 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) 2,000 1,500 1,000 500 14N10W Rocky 1-17H 1,912 BOE/d (1,282 b/d) Lateral Length (ft) 10,000 8,000 6,000 4,000 2,000 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 0 2014 2015 2016 2017 Oil BOE Average LL 0 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 4 wells with 6 wells/section spacing Miss Mary 3 wells with 8 wells/section spacing 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 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 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) 400 300 200 2nd 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 440 12 well spacing Shelly Spacing 660 8 well spacing JD Hoppinscotch testing 8 wells per section in Woodford (waiting on completion) JD Hoppinscotch Spacing 100 0 0 60 120 180 240 300 Days Meramec Woodford 640 160 27
Well-positioned for 2018 Solid returns from large portfolio Strong financial position $464 million of cash on the balance sheet at March 31, 2018 Emphasis on execution Preserve returns in inflationary environment Idea generation Technical enhancements to completion design Testing even tighter infill well spacing Ultimate field optimization provides best returns to shareholders Our future looks bright 28
Appendix 29
2018 Guidance Second Quarter Full Year Daily Production (MBOE) 200 209 211 221 % Oil 33% Capital Expenditures ($billion) E& D $1.6 1.7 D & C $1.3 1.4 Midstream/Other $0.08 0.09 Expenses ($/BOE) Production $3.80 4.30 Transportation, processing & other $2.40 3.00 DD&A and ARO accretion $7.50 8.10 General and administrative $1.20 1.50 Taxes other than income (% of oil and gas revenue) 5.75 6.25% 30
Hedges as of May 25, 2018 2018 2019 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 47.97 47.67 48.76 49.07 49.07 50.00 Weighted Average Ceiling 58.35 58.25 59.33 61.49 61.49 66.21 WTI Midland 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) 130,000 100,000 70,000 60,000 60,000 30,000 Weighted Average Floor 2.35 2.28 2.21 2.17 2.17 1.93 Weighted Average Ceiling 2.66 2.52 2.46 2.42 2.42 2.18 El Paso Perm Collars 5 Volume (MMBtu/d) 100,000 80,000 60,000 50,000 50,000 30,000 Weighted Average Floor 2.15 2.06 1.97 1.88 1.88 1.60 Weighted Average Ceiling 2.43 2.28 2.19 2.12 2.12 1.87 Total Natural Gas Collars Volume (MMBtu/d) 230,000 180,000 130,000 110,000 110,000 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 31
2018 Production Growth Daily Production (MBOE) 190 206 200-209 211-221 Net Wells Online 49 50 34 23 15 2017A 1QA 2QE 3QE 4QE 2018E Oil 1QA 2QE 3QE 4QE Wells Drilling or WOC at 12/31/18 Permian Mid-Continent 32
Permian Region Production Daily Production (MBOE) 100 99 94 96 107 105 112 114 75 74 81 87 80 85 86 85 50 25 0 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 33
Mid-Continent Region Production Daily Production (MBOE) 75 81 74 70 68 77 82 77 71 74 81 85 85 88 91 50 25 0 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 34
Non-GAAP Reconciliation Reconciliation of Net Income to EBITDA and Adjusted EBITDA 1 ($ in Millions) 2015 2016 2017 LTM 3/31/18 Net income (loss) $(2,580) $ (409) $ 494 $ 550 Income tax expense (benefit) (1,472) (214) 188 166 Interest expense, net of capitalized 55 62 52 49 DD&A and ARO accretion 741 400 462 498 EBITDA (3,256) (161) 1,196 1,264 Impairment of oil and gas 4,033 758 - - Adjusted EBITDA 778 597 1,196 1,264 Debt Adjusted Shares (Using trailing 12-mo (TTM) stock price) 2016 2017 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 847,124 115.07 1,099,466 114.00 1,036,190 108.33 Equivalent shares issued using TTM stock price 7,362 9,644 9,565 Debt adjusted shares using TTM stock price 102,485 105,082 104,998 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 35
Non-GAAP Reconciliation Reconciliation of cash flow from operations 1 Three months Ended Mar 31, ($ in Millions) 2017 2018 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) Debt/Adjusted EBITDA calculation Twelve months Ended Mar 31, LTM ($ in Millions) 2016 2017 2018 Extensions & discoveries 156.8 Purchase of reserves 0.2 Long-term debt (principal) $1,500 $1,500 $1,500 Total Additions (all sources) 147.0 Total Capital ($MM) $ 1,281 F&D Costs (all sources) ($/BOE) $ 8.71 Adjusted EBITDA 597 1,196 1,264 Debt/Adjusted EBITDA 2.5x 1.3x 1.2x Drilling F&D cost (extensions & discoveries) ($/BOE) $ 8.17 1 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. 36
Non-GAAP Reconciliation Cash Return on Capital Employed (CROCE) Cash Flow from Operating Activities+ After-tax Interest Expense Average Book Equity + Average Debt 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 Cash flow from operating activities 1,367 675 1,130 1,292 1,193 1,324 1,619 726 626 1,097 Effective Tax Rate 37% 36% 37% 37% 37% 37% 37% 36% 34% 28% Stockholder's equity 2,349 2,038 2,610 3,131 3,390 3,834 4,332 2,458 2,043 2,568 Debt 591 393 350 405 750 924 1,500 1,500 1,500 1,500 Capitalization 2,941 2,431 2,960 3,536 4,140 4,758 5,832 3,958 3,543 4,068 Interest expense 33 40 37 36 49 55 73 86 83 75 Capitalized int (22) (23) (29) (29) (35) (32) (36) (31) (21) (23) Net interest exp 11 17 8 7 14 23 37 55 62 52 CROCE 41% 26% 42% 40% 31% 30% 31% 16% 18% 30% 37
Clyde Copeland Results Cumulative Production (MBOE) 350 300 250 200 150 Increased density pilot 8 wells testing 16 and 20 wells per section Results positive for future well spacing Interference testing on-going 100 50 0 0 60 120 180 240 300 Days Osage Woodford Clyde Copeland development 330 16 well spacing 528 20 well spacing 80 Average well (20 well spacing) Average well (16 well spacing) Average parent well (9 well spacing) 38
Permian Basin Pilot Details Culberson Lower Wolfcamp Animal Kingdom development Eight wells testing 14 wells per section Waiting on completion Animal Kingdom spacing Red Hills Upper Wolfcamp Hallertau development Five wells testing 12 wells per section Producing Hallertau spacing Lower Wolfcamp 225 225 1,216 1,216 Upper Wolfcamp 880 50 Reeves Upper Wolfcamp Snowshoe development Eight wells testing 18 wells per section Currently completing Snowshoe spacing Red Tank Avalon Triste Draw development Six wells testing 20 wells per section Waiting on completion Triste Draw spacing Upper Wolfcamp 190 880 880 375 Avalon 500 380 39