CORPORATE PRESENTATION

August 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 Contact: future events and financial performance. No Karen Acierno assurances can be given, however, that Director – Investor Relations these events will occur or that these [email protected] projections will be achieved, and actual 303-285-4957 results could differ materially from those Cimarex Energy Co. 1700 Lincoln Street, Suite 3700 projected as a result of certain factors. A Denver, CO 80203 discussion of these factors is included in the 303-295-3995 Company’s periodic reports filed with the U.S. Securities and Exchange Commission.

2 XEC – Statistical Summary

Market Cap1 $ 9.0 billion Debt/Adj. EBITDA2 1.1x Daily Production (2Q18) 211 MBOE/d 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 August 6, 2018 2 As of and for the twelve months ended 6/30/18. 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 – $411 million in cash at June 30, 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 . Cimarex culture built on Actual Project Results* maximizing fully burdened after-tax rate of return on investment Half Cycle IRR . Rigorous technical evaluation of all aspects Fully Burdened IRR of E&D to improve economic return

. Pre-drill and post-drill lookback evaluation of expected to actual D&C + Midstream + SWD + Overhead + Land results Capital $1500/acre

*2017 project with 36 gross wells.

6 Solid History of Returns and a Bright Future Ahead

Cash Return on Capital Employed (CROCE) 50% Three-year outlook*:

40% . Maintenance capital of $700mm per year projected 30% to keep production flat . $1.2 billion of D&C capital 20% per year generates ~10%

10% production CAGR – ~13% oil production CAGR 0% 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 – 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 cumulative 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) 214-221 . 14-18% pro forma* year-over-

190 year growth – Oil up 20-25% 164 161 145

31% 31% 30% 30% 28%

2014 2015 2016 2017 2018E *for the previously announced sale of assets in Ward County.

Oil NGL Natural Gas

8 2018 Production Growth

Daily Production Net Wells Online (MBOE) 49

214-221 211 206 206-215 190 38 37

23

15

2017A 1QA 2QA 3QE 4QE 2018E 1QA 2QA 3QE 4QE Wells Drilling or Oil Permian Mid-Continent WOC at 12/31/18

9 2018 Capital Investment Program

. E&D Capital of $1.6 – 1.7 billion – 29% increase from 2017

Other – Within cash available . D&C Capital $1.3 – 1.4 billion Meramec – 82% of Total E&D capital – Permian Basin ~70% D&C Capital – Mid-Continent ~30% $1.3 – 1.4 billion Woodford Wolfcamp . Additional $80 – 90 million budgeted for midstream/other

Avalon . Operating 13 drilling rigs Bone Spring – Ten in Permian – Three in Mid-Continent . Six completion crews – Five in Permian – One in Mid-Continent

10 2018 Delaware Basin Plans

Total D&C Capital Economies of Scale Activity by Area

Ward Single Bone well Eddy Spring Reeves

Avalon $885 – 935mm 82 Net Wells Lea Multi-well

Wolfcamp Culberson

11 Delaware Basin Wolfcamp Overview

2017/18 wells Lower Wolfcamp . 196,000 net acres in the Upper Wolfcamp Bone Spring fairway . Multiple Wolfcamp Targets – Culberson/White City Area . 100,000+ net acres . Upper & Lower Wolfcamp . JDA with Chevron – Reeves County . 59,000 net acres . Upper Wolfcamp – Lea County . 31,000 net acres – Ward County . Sale close expected 3Q . 204 Wolfcamp wells drilled – 112 long laterals (>7,000’)

12 Well Productivity Improvements Long Lateral Upper Wolfcamp Wells (Culberson and Reeves Counties) . 49 –10,000-ft. lateral Upper Completion Generation IP180 (BOE/d) Wolfcamp wells drilled in Permian Basin since 2013 2,000 . Improvement in well productivity seen through enhanced

1,500 completion design . Returns get better with each design change

1,000 – Current wells have IRRs that range from 90-140% ATAX . Provides strong fully burdened returns 500

0 Gen 1 Gen 2 Gen 3 Gen 4

Oil (b/d)

13 Resilient Long Lateral Returns Culberson Long Lateral Wolfcamp

BTAX IRR* 400%

300%

200%

100%

0% $30 $40 $50 $60 $70 Realized Oil Price Upper Wolfcamp - $2/Mcf Lower Wolfcamp - $2/Mcf Upper Wolfcamp - $1/Mcf Lower Wolfcamp - $1/Mcf

*Assumes full NGL recovery, NGL price is 30% of oil price 14 Culberson / White City Wolfcamp Details

Lower Wolfcamp Upper Wolfcamp Operated SWD . 100,000+ net acres; JDA with Chevron in Culberson County . 75 long lateral wells . Lower Owl Draw 12 2,521 BOE/d Wolfcamp infill – completing (1,393 b/d) . Positive results from Western Culberson Upper Wolfcamp

Carry Back 6 delineation State A 1H Currently – Five wells with average 30-day Flowing Back peak initial production of 2,724 BOE/d (56% oil)

Charismatic 5 3,271 BOE/d (1,882 b/d) 37 2H 2,750 BOE/d (1,158 b/d)

15 Culberson County – Tim Tam Development Lower Wolfcamp

Cumulative Production . Tim Tam infill wells generated 67%+ (MBOE) ATAX return 700 . Infills have surpassed parent wells in both landing zones 600 Tim Tam spacing 500

1,756’ 400 200’ 1,756’

300 WolfcampLower

200 . Results lead to 14 wells per section test 100 – Animal Kingdom waiting on 0 completion 0 60 120 180 240 300 360 Days Animal Kingdom spacing

Parent well (lower landing) 225’ 1,216’ Tim Tam Infill well (lower landing) Parent well ( upper landing) 225’ 1,216’

Tim Tam Infill well (upper landing) WolfcampLower

16 Reeves County Focus Area

. 36 long lateral wells – Targeting Upper Wolfcamp . 28 – 10,000-ft. laterals producing – Average 30-day peak IP of 1,809 BOE/d (49% oil) Dixieland State 55-6 2,505 BOE/d . Two downspacing pilots producing (1,464 b/d) – Wood State (12 wells/section) – Pagoda State (16 wells/section) Snowshoe . Snowshoe development flowing back

Pagoda State – 8 wells; 3 landings (18 wells/section)

Wood State

Upper Wolfcamp Operated SWD

17 Reeves County – Strong Infill Well Results

Cumulative Production (MBOE) . Upper Wolfcamp 600 – 10,000-ft. laterals . 500 Wood State: 6 wells testing 12 wells per section 400 – Surpassed Big Timber, previously best long lateral to date 300 – Average well performing 28% above parent well 200 . Pagoda State: 4 wells testing 16 100 wells per section – Average well performing 16% above 0 parent well 0 60 120 180 240 300 360 Days

Big Timber well Pagoda spacing Wood State spacing

Wood State parent well 680’ 880’

Average Wood State well 340’ 340’ Average Pagoda State well 680’ 880’ Upper WolfcampUpper Upper WolfcampUpper

18 Lea County Thyme APY Coriander AOC 1-12 4,600’ Lateral 9,500’ Lateral 2,059 BOE/d 3,333 BOE/d (1,416 b/d) (2,248 b/d) . Exciting multi-pay area Upper Wolfcamp Avalon . 2018 Capex: $225 million Bone Spring . Two Avalon wells brought online in 1Q18 – Coriander AOC 1-12 State 1H Triste Draw – Thyme APY Fed 9H . Avalon activity – 24,000 net prospective acres Red Tank – Triste Draw infill spacing pilot

Red Hills waiting on completion Hallertau Infill 4,200’ Avg Lateral . Wolfcamp activity 6 Well Avg 1,295 BOE/d (783 b/d) – 31,000 net prospective acres – Hallertau six well infill spacing pilot producing . IP30 Avg: 1,295 Boe/d (783 Bbls/d), 4,200’ avg lateral

19 Permian Basin – Residue Gas Takeaway

. Sales agreements in place – 98% of forecasted production through December 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

20 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 . ~70% of oil production on pipe; increasing to >80% by YE18

Gas Plains pipeline Plains pipeline (under construction) NGL Energy Transfer pipeline Oil Offloading Site

2Q18 Permian Revenue 21 Permian Basin Water Management

. Own and operate salt water Saltwater Disposal System 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 ~90% recycled water for completions; Reeves Wolfcamp wells use ~60% . Secured SWD agreements in Lea County

22 Mid-Continent Basin 2018 Outlook

Total D&C Capital Economies of Scale Activity by Area

Other Woodford Meramec Woodford Meramec Single well

$375 – 425 41 Net Wells million Multi-well

Lone Rock

23 Mid-Continent Overview Meramec outline Woodford outline . Meramec and Woodford Stacked Targets . Meramec: 116,500 net prospective acres – 100% HBP . Woodford: 136,000 net undeveloped acres

Cana Core 24 Meramec – The Big Picture

Dupree BIA 1H 1 Mile 2,877 BOE/d . 116,00 net acres (1,597 b/d) Rocky 1-17H – 100% HBP 1 Mile Gresham Com 1H 1,912 BOE/d . Improving well results driving activity 2 Mile (1,282 b/d) 5,813 BOE/d – Four developments planned in 2018 (484 b/d) . 40 industry downspacing pilots

Mike Com 1H online or underway in the play 14N10W 2 Mile 4,353 BOE/d – XEC has interest or data in 31 (433 b/d) 5,000 ft Meramec . Formulating development plans 10,000 ft Meramec Meramec play outline

Average 30-day Peak IP Lateral Length (b/d) (ft) 2,000 10,000

8,000 1,500 6,000 1,000 4,000 500 2,000

0 0 2014 2015 2016 2017 Oil BOE Average LL 25 Meramec Development Plans

. 2018 developments – Steve O – 6 wells (2 mile laterals) with 8 wells/section Lehman spacing (flowing back) – Lehman – 4 wells (1 mile) with 6 Steve O wells/section spacing Miss Mary – Miss Mary – 3 wells (1 mile) with 8 wells/section spacing Mike Com 1H Woolfolk / NIB Gresham Com 1H . 14N-10W development 2 Mile 14N 10W – Stacked Meramec/Woodford – Operate 90% the 24,000 acres 5,000 ft Meramec 10,000 ft Meramec – Average 60% working interest Meramec play outline – Positive recent 14N-10W results – Successfully tested 19 wells per section (Leon Gundy) – Positive results with zone completion sequence at Woolfolk/NIB

26 Woodford Activity

Operated well Non-operated well . Participated in 959 wells 14N 10W drilled since 2007 – 325 operated wells . Emerging Lone Rock play Clyde Copeland yielding best results to date . Formulating development plans in the 14N-10W area

Lone Rock

27 Lone Rock Activity

. Best Woodford returns in portfolio Jimmie Com 6,700’ Lateral 10.2 MMcfed Meyers 1H . ~16,000 net contiguous acres (368 b/d) 8,000’ Lateral 13.4 MMcfed Hines Federal 1H . (535 b/d) 9,500’ Lateral Multiple completion design factors 17.2 MMcfed (1,016 b/d) enhance productivity . Infill Development tests:

JD Hoppinscotch Shelly - testing 8 and 12 wells per Shelly section (flowing back)

Shelly Spacing Woodford Woodford 440’ 660’ Average Cumulative Production per Well (MBOE) 12 well spacing 8 well spacing 600 1st Gen (~1,440 lb/ft) 2nd Gen (~2,800 lb/ft) 500 3rd Gen (~2,800 lb/ft) JD Hoppinscotch - testing 8 wells per 400 section in Woodford, stacked Meramec/Woodford (flowing back) 300 JD HoppinscotchSpacing 200 Meramec 100 160’ 640’ Woodford 0 0 60 120 180 240 300 360 Days 28 Well-positioned for 2018

. Solid returns from large portfolio . Strong financial position – $411 million of cash on the balance sheet at June 30, 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

29 Appendix

30 2018 Guidance

3Q18E FY18E

Production (MBOE/d) 206 - 215 214-221 Oil Production (Bbls/d) 61,500 – 64,500 66,000 – 68,000

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 $1.15 – 1.45 Taxes other than income (% of oil and gas revenue) 5.75 – 6.25%

31 Hedges as of August 3, 2018

2018 2019

Third Fourth First Second Third Fourth Quarter Quarter Quarter Quarter Quarter Quarter OIL WTI Oil Collars1 Volume (Bbl/d) 35,000 29,000 23,000 23,000 16,000 8,000 Weighted Average Floor 49.80 51.03 51.83 51.83 53.50 57.00 Weighted Average Ceiling 60.49 61.74 63.77 63.77 67.13 68.04

WTI Midland Swaps2 Volume (Bbl/d) 27,000 22,000 19,000 19,000 14,000 6,000 Weighted Average Differential (3.89) (4.56) (5.17) (5.17) (6.84) (10.73)

GAS PEPL Collars3 Volume (MMBtu/d) 130,000 100,000 90,000 90,000 60,000 30,000 Weighted Average Floor 2.19 2.12 2.08 2.08 1.92 1.90 Weighted Average Ceiling 2.48 2.42 2.39 2.39 2.26 2.33

El Paso Perm Collars3 Volume (MMBtu/d) 100,000 80,000 70,000 70,000 50,000 20,000 Weighted Average Floor 1.92 1.81 1.73 1.73 1.50 1.35 Weighted Average Ceiling 2.14 2.03 1.95 1.95 1.74 1.55

Waha Collars3 Volume (MMBtu/d) 10,000 10,000 10,000 10,000 10,000 10,000 Weighted Average Floor 1.35 1.35 1.35 1.35 1.35 1.35 Weighted Average Ceiling 1.56 1.56 1.56 1.56 1.56 1.56

Total Natural Gas Collars Volume (MMBtu/d) 240,000 190,000 170,000 170,000 120,000 60,000

1 WTI refers to West Texas Intermediate oil prices as quoted on the New York Mercantile Exchange. 2 Index price on basis is WTI NYMEX less the weighted average WTI Midland differential, as quoted by Argus Americas Crude. 3 PEPL refers to Panhandle Eastern Pipe Line Tex/OK Mid-Continent Index, El Paso Perm refers to El Paso Permian Basin Index, and Waha refers to West Texas (Waha) Index, all as quoted on Platt’s Inside FERC. 32 Permian Region Production

Daily Production (MBOE) 125 122

112 114 107 105 99 100 96 94

87 85 86 85 81 80 75

50

25

0 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 Oil NGL Natural Gas

33 Mid-Continent Region Production

Daily Production (MBOE) 91 88 89 85 85 82 81 77 77 74 74 75 70 71 68

50

25

0 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 Oil NGL Natural Gas

34 Non-GAAP Reconciliation

Reconciliation of Net Income to EBITDA and Adjusted EBITDA1 LTM ($ in Millions) 2015 2016 2017 6/30/18

Net income (loss) $ (2,580) $ (409) $ 494 $ 593 Income tax expense (benefit) (1,472) (214) 188 150 Interest expense, net of capitalized 55 62 52 47 DD&A and ARO accretion 741 400 462 535 EBITDA (3,256) (161) 1,196 1,325

Impairment of oil and gas 4,033 758 — — Adjusted EBITDA 778 597 1,196 1,325

Debt Adjusted Shares (Using trailing 12-mo (TTM) stock price) LTM 2016 2017 6/30/18

Basic shares outstanding (in 000s) 95,124 95,437 95,393 Debt adjusted shares outstanding YE Debt, net 847,124 1,099,466 1,089,177 TTM stock price 115.07 114.00 104.42 Equivalent shares issued using TTM stock price 7,362 9,644 10,431 Debt adjusted shares using TTM stock price 102,485 105,082 105,824

1The 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 operations1 Debt/Cap calculation Six Months Ended Jun 30, June 30, ($ in Millions) 2018 ($ in Millions) 2017 2018 Long-term debt (principal) 1,500 Net cash provided by operating activities $ 505 $ 704 Stockholders equity 2,886

Change in operating assets and 40 12 Total capitalization 4,386 liabilities Adjusted cash flow from operations $ 545 $ 717 Long-term debt/total capitalization 34%

Finding & development (F&D) cost Debt/Adjusted EBITDA calculation 2017 Twelve months Ended Dec 31 LTM Additions to proved reserves (MMBOE) ($ in Millions) 2016 2017 6/30/18 Revisions of previous estimates (10.0) Long-term debt $1,500 $1,500 $1,500 Extensions & discoveries 156.8 (principal) Purchase of reserves 0.2 Total Additions (all sources) 147 Adjusted EBITDA 597 1,196 1,325

Debt/Adjusted EBITDA 2.5x 1.3x 1.1x Total Capital ($MM) $ 1,281 F&D Costs (all sources) ($/BOE) $ 8.71

Drilling F&D cost (extensions & discoveries) ($/BOE) $ 8.17

1Management 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) . Increased density pilot 350 – 8 wells testing 16 and 20 wells 300 per section

250 . Results positive for future

200 well spacing – Interference testing on-going 150

100 Clyde Copeland development 50 Osage 80’ 0 Woodford 0 60 120 180 240 300 330’ 528’ Days 16 well spacing 20 well spacing Average well (20 well spacing) Average well (16 well spacing) Average parent well (9 well spacing)

38 Permian Basin Development Pilot Details

. Culberson Lower Wolfcamp - Animal Kingdom Animal Kingdom spacing – Eight wells testing 14 wells per section 225’ – Waiting on completion 1,216’ 225’ 1,216’ Lower WolfcampLower

. Red Hills (Lea) Upper Wolfcamp - Hallertau Hallertau spacing – Six wells testing 12 wells per section 880’ 50’ – Producing 225’ Upper Wolfcamp Upper

. Reeves Upper Wolfcamp - Snowshoe Snowshoe spacing – Eight wells testing 18 wells per section 880’ 190’ – Currently completing 375’

880’ Upper Wolfcamp Upper

. Red Tank (Lea) Avalon - Triste Draw Triste Draw spacing – Six wells testing 20 wells per section – Waiting on completion 380’ Avalon 500’

39