4Q18 EARNINGS PRESENTATION February 2019
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
Cimarex Energy Snapshot NYSE symbol: XEC Market Cap 1 : $7.3 billion Enterprise Value 1 : $8.8 billion Debt/EBITDA 2 : 0.9x Annual Dividend: $0.80 (1.1% yield) 4Q18 Production: 251 MBOE/d, 80 MBO/d 2019E Capex: $1.35 - $1.45 billion 2019E Production Growth: 13%-22% 1 As of February 19, 2019 2 As of and for the twelve months ended 12/31/18. See Appendix for non-gaap definitions and reconciliations to nearest comparable GAAP measure. 3
2018 Achievements Generated solid financial & operational results EPS of $8.32 on revenues of $2.3 billion; adjusted cash flow from operations totaled $1.5 billion Solid execution resulted in production growth of 18% Sold properties in Ward County, Texas Reinvesting proceeds in pending acquisition of Reeves County assets Several meaningful spacing pilots in 2018 Animal Kingdom Lower Wolfcamp Snowshoe Upper Wolfcamp Hallertau Upper Wolfcamp Infill development maximizes returns and present value 4
2018 Growth in Production and Reserves Daily Production (MBOE) 42% Proved Reserves (MMBOE) 600 300 416 27% 31% Oil NGL Natural Gas 522 222 MBOE 485 482 559 591 Oil/BOE growth of 18%/17% Y/Y Pro Forma Ward sale, Oil/BOE growth of 24%/19% Total E&D capital $1.57 billion D&C capital of $1.34 billion 122 net wells brought online YE18 proved reserves: 591 MMBOE Increase of 6% Y/Y PDP now 85% of total proved Reserve replacement of 168% of 2018 production 0 2013 2014 2015 2016 2017 2018E Oil NGL Natural Gas 5
Margin % Cash Operating Margin Expansion $/BOE OPEX & Cash Margin Declining Cash Costs and Increased Realized Prices Driving Margin Expansion 75% $50 70% 65% 68% 65% 70% $45 $40 $35 60% $30 55% 55% 54% $25 $20 50% $15 $10 45% $14.2 $10.7 $9.5 $9.6 $8.6 $5 40% 2014 2015 2016 2017 2018 Cash Operating Costs Margin Margin % $0 Cash operating costs include: LOE, Transportation, Production Tax, G&A Realized prices exclude hedge gain/loss 6
2019 Capital Investment Program Meramec 10% Bone Spring 4% Woodford 4% Avalon 2% Other 2% D&C Capital $1.1 1.2 billion Wolfcamp 78% E&D Capital of $1.35 1.45 billion 11% decrease Y/Y Free cash flow neutral at $52.50 WTI, $50 WTI excluding dividend D&C Capital $1.1 1.2 billion 84% of Total E&D capital Permian Basin ~85% Mid-Continent Region ~15% Additional $60 70 million budgeted for midstream Currently operating 11 rigs 10 in Permian One in Mid-Continent 7
2019 Net Wells Online 2019 Activity: 83 net wells (average operated lateral length: 9,050 ) 33 34 23 20 6 1QE 2QE 3QE 4QE Wells Waiting on Completion Permian Basin Mid-Continent at 12/31/19 8
Return Driven Production Growth Continues in 2019 Daily Production (MBOE) 190 222 250-270 High return projects expected to generate 2019 production growth of 13 22% Oil expected to grow 15 30% in 2019 161 Three-year oil CAGR: 23% 28% 30% 31% 32% 2016 2017 2018 2019E Oil NGL Natural Gas 9
$MM - Cumulative FCF Hitting Our Stride: Generating Free Cash Flow 1 Cumulative Free Cash Flow (2016-18 vs. 2019-21) Cumulative Free Cash Flow: $600 $400 $200 $0 ($200) ($400) ($600) 2016-2018A $53 WTI ($532) 2019-2021E $100 $50 WTI $600 $55 WTI 1 Free Cash Flow = Cash Flow - Total Capital Dividend (Annual $0.80) 2 Total Capital = Total E&D+ Midstream + Other 19-21E: $100-$600 MM 16-18A: ($532 MM) Average Annual Oil Growth: 19-21E: 15% 16-18A: 11% Average Annual Total Capital: 19-21E: $1.50 billion 16-18A: $1.25 billion Performance Drivers: Consistent development program enhancing efficiencies Increasing well productivity Leveraging infrastructure Lowering production and capital costs 10
Delaware Basin Overview 259,000 total net acres 85% of 2019 D&C Budget Currently running 10 rigs, 3 completion crews Stacked pay opportunities provides multi-zone development opportunities Upper and Lower Wolfcamp Second and Third Bone Spring Avalon Wolfcamp Bonespring Spring Avalon 11
2019 Delaware Basin Plans CULBERSON REEVES EDDY LEA Total D&C Capital Wells Drilled by County Average Lateral Length by County Wolfcamp $935 $1,020mm Lea Eddy 66 Net Wells Reeves 10,000 8,000 6,000 4,000 2,000 Culberson 0 Bone Spring Avalon 12
Permian Basin Oil Takeaway Sales agreements in place for oil volumes through 2019 Strategic partnerships in core areas Pipelines in place Purchase obligations Midland index pricing ~80% of oil production on pipe Plains pipeline Plains pipeline (under construction) Energy Transfer pipeline Offloading Site 13
Permian Basin Residue Gas & NGL Takeaway Sales agreements in place 97% of forecasted production through 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 14
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 53% of total water procured in 2018 was recycled Cost savings of ~$1.20/bbl of water Culberson Wolfcamp wells use 97% recycled water for completions; Reeves Wolfcamp wells use 48% Secured SWD agreements in Lea County 15
Delaware Basin Culberson/White City Crawford 27-26 FEE 2H Kingman 45 State Unit 3H 3 rd Bone Spring Lower Wolfcamp Upper Wolfcamp Operated SWD 100,000+ net acres JDA with Chevron in Culberson 34% of 2019 D&C capital Targeting Upper and Lower Wolfcamp, Bone Spring New 3 rd Bone Spring landing zone adds resource potential Kingman 45 State Unit 3H IP30: 2,917 BOE/d, 1,965 BO/d White City: Upper Wolfcamp further delineated Crawford 27-26 FEE 2H IP30: 2,455 BOE/d, 1,701 BO/d 16
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 17
Delaware Basin Reeves County Snowshoe Upper Wolfcamp Operated SWD 61,853 net acres 38% of 2018 D&C capital Targeting Upper Wolfcamp Snowshoe: 18 wells/section Eight well test producing Three developments drilled and completed in 2019 18
Delaware Basin Lea County Upper Wolfcamp Avalon Bone Spring Triste Draw Vaca Draw Red Tank Red Hills 31,384 net acres 5% of 2018 D&C capital Targeting Upper Wolfcamp, Avalon, Bone Spring Triste Draw (Avalon) 6 wells testing 20 wells/section, producing Vaca Draw: Two developments planned in 2019: One Wolfcamp One Avalon 19
Mid-Continent Overview 14N10W Meramec outline Woodford outline Cana Core Lone Rock 326,000 net acres 15% of 2019 D&C capital Currently running one rig, one completion crew Woodford: 135,625 net undeveloped acres Participated in >950 wells Meramec: 116,500 net acres 14N-10W area: formulating Woodford/Meramec co-development plans Operate 90% of ~24,000 gross acres, 60% WI 20
Woodford Meramec Mid-Continent Basin 2019 Plans Total D&C Capital Average Lateral Length by Play Woodford Meramec $165 $180mm 17 Net Wells 10,000 9,000 8,000 7,000 6,000 5,000 4,000 3,000 2,000 1,000 0 21
Mid-Continent Meramec Dupree Cumulative 5,430 BOE/d, 3,147 Bo/d Dupree 5,000 ft Meramec 10,000 ft Meramec Meramec play outline 14N10W Lehman Billy/Wort/Miss Mary 116,500 net acres 100% HBP 10% of 2019 D&C capital Recent Developments Lehman: 4 wells on 6 well spacing, flowing back Billy/Wort/Miss Mary: 3-5 well spacing Dupree: 2 wells with average IP30 of 2,972 BOE/d; 1,574 BO/d 22
Disciplined Financial Positioning Debt/TTM EBITDA Significant Liquidity $2.1 billion of liquidity, including $801mm of cash (12/31/18) Conservative Leverage 0.90x Debt/TTM EBITDA (12/31/18) Investment Grade Debt $750 million 3.900% senior unsecured notes due in 2027 $750 million 4.375% senior unsecured notes due in 2024 XEC Debt/EBITDA 3.0x 2.5x 2.0x 1.5x 1.0x 0.5x 0.0x 2010 2011 2012 2013 2014 2015 2016 2017 2018 Debt/TTM EBITDA Average 23
Positioned for Success Enduring Culture Maximizing full-cycle return on invested capital Idea driven, technical emphasis Premier Portfolio Generating strong returns Decades of top-tier inventory Profitable Growth 2019 Oil Production Growth: 15%-30% Strong Financial Position Low leverage and liquidity provides opportunities 24
Appendix 25
2019 Guidance 1Q19E FY19E Production (MBOE/d) 245-257 250-270 Oil Production (MBO/d) 75-81 78-88 Capital Expenditures ($billion) E & D $1.35 1.45 D & C $1.1 1.2 Midstream/Other $0.06 0.07 Expenses ($/BOE) Production $3.20 3.70 Transportation, processing & other $2.30 2.90 DD&A and ARO accretion $7.75 8.75 General and administrative $1.00 1.30 Taxes other than income (% of oil and gas revenue) 5.5 6.5% 26
Hedges as of February 20, 2019 OIL WTI Oil Collars 1 First Quarter Second Quarter 2019 2020 Third Quarter Fourth Quarter First Quarter Volume (Bbl/d) 31,689 33,000 26,000 18,000 10,000 2,000 Second Quarter Weighted Average Floor 53.85 53.70 55.23 57.56 58.00 50.00 Weighted Average Ceiling 66.79 66.62 69.46 70.90 73.20 62.60 WTI Swaps 2 Volume (Bbl/d) 29,000 29,000 24,000 16,000 7,000 7,000 GAS Weighted Average Differential 3 (5.46) (5.46) (6.50) (7.79) (0.40) (0.40) PEPL Collars 4 Volume (MMBtu/d) 139,667 150,000 120,000 90,000 60,000 30,000 Weighted Average Floor 2.04 2.03 1.94 1.94 1.96 1.95 Weighted Average Ceiling 2.40 2.39 2.32 2.37 2.38 2.26 El Paso Perm Collars 5 Volume (MMBtu/d) 86,556 90,000 70,000 40,000 20,000 10,000 Weighted Average Floor 1.67 1.67 1.49 1.40 1.45 1.50 Weighted Average Ceiling 1.94 1.95 1.79 1.73 1.92 2.13 Waha Collars 6 Volume (MMBtu/d) 36,556 40,000 40,000 40,000 30,000 10,000 Weighted Average Floor 1.40 1.41 1.41 1.41 1.43 1.50 Weighted Average Ceiling 1.71 1.73 1.73 1.73 1.79 1.90 Total Natural Gas Collars Volume (MMBtu/d) 262,779 280,000 230,000 170,000 110,000 50,000 Notes: 1 WTI refers to West Texas Intermediate oil prices as quoted on the New York Mercantile Exchange 4 PEPL refers to Panhandle Eastern Pipe Line Tex/OK Mid-Continent as quoted on Platt s Inside FERC 2 Index price on basis swaps is WTI Midland as quoted by Argus Americas Crude 5 El Paso Perm refers to El Paso Permian Basin index as quoted on Platt s Inside FERC 3 Index price on basis swaps is WTI NYMEX less weighted average differential shown in table 6 Waha refers to West Texas Natural Gas Index ( Waha ) as quoted in Platt s Inside FERC. 27
Non-GAAP Reconciliation Reconciliation of Net Income to EBITDA and Adjusted EBITDA 1 Saltwater Disposal System ($ in Millions) 2015 2016 2017 2018 Net income (loss) $ (2,580) $ (409) $ 494 $ 792 Income tax expense (benefit) (1,472) (214) 188 231 Interest expense, net of capitalized 55 62 52 47 DD&A and ARO accretion 741 400 462 598 EBITDA (3,256) (161) 1,196 1,668 Impairment of oil and gas 4,033 758 Adjusted EBITDA 778 597 1,196 1,668 Debt Adjusted Shares (Using trailing 12-mo (TTM) stock price) 2016 2017 2018 Basic shares outstanding (in 000s) 95,124 95,437 95,756 Debt adjusted shares outstanding YE Debt, net 847,124 1,099,466 699,334 TTM stock price 115.07 114.00 93.77 Equivalent shares issued using TTM stock price 7,362 9,644 7,458 Debt adjusted shares using TTM stock price 102,485 105,082 103,214 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 28
Non-GAAP Reconciliation Reconciliation of cash flow from operations 1 Saltwater Disposal System Twelve Months Ended December 31, ($ in Millions) 2017 2018 Debt/Cap calculation ($ in Millions) Dec 31, 2018 Long-term debt (principal) 1,500 Net cash provided by operating activities $ 1,097 $ 1,551 Stockholders equity 3,330 Change in operating assets and liabilities 89 (17) Total capitalization 4,830 Adjusted cash flow from operations $ 1,186 $ 1,534 Long-term debt/total capitalization 31% Finding & development (F&D) cost Additions to proved reserves (MMBOE) 2018 Revisions of previous estimates (22.7) Extensions & discoveries 158.5 Purchase of reserves Total Additions (all sources) 135.8 Debt/Adjusted EBITDA calculation Twelve Months Ended December 31, ($ in Millions) 2016 2017 2018 Long-term debt (principal) $1,500 $1,500 $1,500 Adjusted EBITDA 597 1,196 1,668 Total Capital ($MM) $ 1,570 F&D Costs (all sources) ($/BOE) $ 11.56 Debt/Adjusted EBITDA 2.5x 1.3x 0.9x Drilling F&D cost (extensions & discoveries) ($/BOE) $ 9.91 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. 29