CORPORATEPRESENTATION

November 2018

2

Forward-looking Statements

This presentation contains projections andother forward-looking statements within themeaning of Section 27A of the U.S.Securities Act of 1933 and Section 21E of theU.S. Securities Exchange Act of 1934.These projections and statements reflect theCompany’s current views with respect tofuture events and financial performance. Noassurances can be given, however, thatthese events will occur or that theseprojections will be achieved, and actualresults could differ materially from thoseprojected as a result of certain factors. Adiscussion of these factors is included in theCompany’s periodic reports filed with theU.S. Securities and Exchange Commission.

Contact:

Karen AciernoDirector – Investor Relationskacierno@cimarex.com303-285-4957

Cimarex Energy Co.1700 Lincoln Street, Suite 3700Denver, CO 80203303-295-3995

3

Cimarex Energy Snapshot

NYSE symbol: XEC

Market Cap1: $8.0 billion

Enterprise Value1: $8.6 billion

Debt/EBITDA2: 1.1x

Annual Dividend3: $0.72 (0.9% yield)

Daily Production: 219 MBOE, 64 MBO

2018E Capex: $1.6-$1.7 billion

2018E Production Growth: 17%-18%

1 As of November 5, 20182 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 Annualized yield of announced 3Q18 dividend

4

Cimarex Energy Overview

• Maximizing full-cycle return on invested capitalEnduring Culture

• Creating value, generating top-tier returnsProven Track Record

• Core positions in the Permian and Anadarko BasinsPremier Portfolio

• Trailing 10-year average CROCE: 30%• 10-year production growth CAGR: 11%

Profitable Growth

• Low leverage and liquidity provides opportunitiesStrong

Financial Position

5

The Culture of Cimarex

Maximize Full-Cycle Returns

Idea GenerationDriven by Rigorous

Technical Evaluation

Acreage Concentration

Increasing Economies of Scale, Returns

Inventory ExpansionInnovation and

ExplorationFocused Execution

Focused on Maximizing IRR, NPV

Financial Discipline

Strong Returns, Cash Flow Growth, Liquidity,

Optionality

Lookback Evaluation

Improves Economic Returns, Operational

Efficiencies

6

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Drilling &Completion

Midstream SWD Overhead Land -$1,500/acre

% of Fully-Burdened Investment ATAX IRR

What are Fully-Burdened Returns?

2017 XEC project, includes 36 gross wells.Flat oil & natural gas realized prices of $55.00/$2.00

Half-Cycle

Fully-Burdened

+ + + +

Half-Cycle vs Fully-Burdened Returns(% of Fully-Burdened Investment vs IRR)

7

History of Outsized Returns

Cash Return on Capital Employed (CROCE)XEC vs S&P 500 E&P Peers

0%

10%

20%

30%

40%

50%

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

XEC Peer Avg.***

8

XEC Generating Top-Tier Returns

Source: Stifel estimatesE&P estimates based on Stifel estimates, S&P 500 estimates based on consensusCROCE = (CFFO + Interest (1-tax))/ (Avg Capital Employed)

2018 Cash Return on Capital Employed (CROCE)XEC vs S&P 500

0%

5%

10%

15%

20%

25%

30%

CRO

CE (

%) Average

9

Delaware Basin – Overview 259,000 total net acres

70% of 2018 D&C Budget Currently running 12 rigs, 2

completion crews

Stacked pay opportunities provides multi-zone development opportunities– Upper and Lower Wolfcamp

– Second and Third Bone Spring

– Avalon

WolfcampBonesprinAvalon

WolfcampBone SpringAvalon

10

0

500

1,000

1,500

2,000

Gen 1 Gen 2 Gen 3 Gen 4

Oil (b/d)

54 –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

Well Productivity ImprovementsLong Lateral Upper Wolfcamp Wells(Culberson and Reeves Counties)

Completion GenerationIP180 (BOE/d)

11

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

Permian Basin – Oil Takeaway

Plains pipelinePlains pipeline (under construction)Energy Transfer pipelineOffloading Site

12

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

Permian Basin – Residue Gas & NGL Takeaway

13

Low er WolfcampUpper WolfcampOperated SWD

Carry Back 6 State A 1H

4,220 BOE/d, 2,446 b/d

Delaware Basin – Culberson/White City

100,000+ net acres, JDA with Chevron in Culberson 25% of 2018 D&C capital Targeting Upper and Lower

Wolfcamp, Bone Spring Western delineation

continues to unlock value– Six well average: 30-day IP

of 3,427 Boe/d (56% oil) Animal Kingdom: (WOC)

Lower Wolfcamp– 8 wells testing 14

wells/section

1,216’

1,216’225’

Low

er W

olfc

amp

Animal Kingdom spacing

225’

Animal Kingdom –

8 WellsFlowing Back

14

Resilient Long Lateral ReturnsCulberson Long Lateral Wolfcamp

0%

100%

200%

300%

400%

$30 $40 $50 $60 $70Realized Oil Price

Upper Wolfcamp - $2/Mcf Lower Wolfcamp - $2/Mcf

Upper Wolfcamp - $1/Mcf Lower Wolfcamp - $1/Mcf

BTAX IRR*

*Assumes full NGL recovery, NGL price is 30% of oil price

15

Wood State

Snowshoe

Pagoda State

Upper WolfcampOperated SWD

Delaware Basin – Reeves County

61,853 net acres 25% of 2018 D&C capital Targeting Upper Wolfcamp Wood State: 12 well/section

– Development wells 28% above parent wells

Pagoda State: 16 wells/section– Development wells 16% above

parent wells

Snowshoe: 18 wells/section– 8 wells test flowing back

16

Delaware Basin – Lea County

31,384 net acres 12% of 2018 D&C capital Targeting Upper Wolfcamp,

Avalon, Bone Spring Vaca Draw 20-17 Lease IP30s:

– Upper Wolfcamp: 4,645 BOE/D (3,032 BO/D)

– Avalon: 2,733 BOE/D (2,051 BO/D)

– Leonard: 3,413 BOE/D (2,522 BO/D)

Triste Draw (Avalon) – 6 wells testing 20 wells/section,

completing

Red Hills

Red Tank

Triste Draw

Upper WolfcampAvalonBone Spring

Vaca Draw 20-17

Red Hills Unit 17 – 5,164 BOE/d,

3,611 BO/d

17

Mid-Continent – Overview

326,000 net acres 30% of 2018 D&C capital 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– $2 billion development (net)– Successfully tested 19

wells/section (Leon Gundy)

Cana Core

14N10W

Lone Rock

18

Mid-Continent – Meramec

116,500 net acres – 100% HBP

15% of 2018 D&C capital 40 industry development

pilots active, XEC has interest or data in 31 2018 Developments

– Steve O: 6 wells on 8 well spacing (flowing back)

– Lehman: 4 wells on 6 well spacing

– Miss Mary: 3 wells on 8 well spacing

5,000 ft Meramec10,000 ft MeramecMeramec play outline

Steve O

14N10W

Lehman

Miss Mary

19

Mid-Continent – Woodford

135,625 net undeveloped acres 15% of 2018 D&C capital Lone Rock (16,000 net acres)

yielding best Woodford results to date, completion optimization driving results– Shelly: 5 wells testing 8 and 12

wells per section (flowing back)– JD Hoppinscotch: 4 wells on 8

well spacing (flowing back)

14N-10W area: formulating development plans

Lone Rock

14N 10W

Shelly JD Hoppinscotch

Operated wellNon-operated well

Sweeny 8.24H 1,755 BOE/d, 667 b/d

Kim Anderson Farm 1-23H2,164 BOE/d, 717 b/d

20

Cash Operating Margin ExpansionDeclining LOE and Increasing Realized Prices Driving Margin Expansion

Cash operating costs include: LOE, Transportation, Production Tax, G&A

Realized prices exclude hedge gain/loss

$0

$5

$10

$15

$20

$25

$30

$35

0%

10%

20%

30%

40%

50%

60%

70%

1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18

$/B

oe O

PEX

& M

argi

n

Mar

gin

%

Cash Operating Costs Margin Margin %

21

2018 Program Overview

Production - MBOE/d

Net Wells Online – 2018E

*Pro forma excludes Ward County volumes

Capital Program ($mm)E&D Capital $1,600 - $1,700D&C Capital $1,300 - $1,400Midstream/Other $80 - $90D&C as % of E&DPermianMid-Continent

Production GuidanceTotal (MBoe/d) 218 - 221Oil(MBbls/d) 66.0 - 67.2

Pro Forma* Y/Y GrowthTotal (MBoe/d) 17% - 18%Oil(MBbls/d) 21% - 23%

2018E

2018E

82%70%30%

2018E

1QA 2QA 3QA 4QE Wells Drillingor WOC at12/31/18Mid-Continent Permian

46

1523

34

51

1QA 2QA 3QA 4QE 2018EOIL

238-247218-221

22

Disciplined Financial Positioning• $1.9 billion of liquidity, including $864mm of cash (3Q18)Significant

Liquidity

• 1.1x Debt/TTM EBITDA (3Q18)Conservative Leverage

• $750 million 3.900% senior unsecured notes due in 2027• $750 million 4.375% senior unsecured notes due in 2024

Investment Grade Debt

XEC Debt/EBITDA

0.0x

0.5x

1.0x

1.5x

2.0x

2.5x

3.0x

2010 2011 2012 2013 2014 2015 2016 2017 3Q18

Debt

/TTM

EBI

TDA

Debt/TTM EBITDA Average

23

Positioned for Success

• Maximizing full-cycle return on invested capital• Idea driven, technical emphasis

Enduring Culture

• Generating strong returns• Decades of top-tier inventory

Premier Portfolio

• 2018 Oil Production Growth: 21%-23%Profitable Growth

• Low leverage and liquidity provides opportunitiesStrong

Financial Position

24

Appendix

25

2018 Guidance

4Q18E FY18E

Production (MBOE/d) 238 - 247 218-221

Oil Production (MBbls/d) 73.0 - 78.0 66.0 – 67.2

Capital Expenditures ($billion)E & D $1.6 – 1.7

D & C $1.3 – 1.4

Midstream/Other $0.08 – 0.09

Expenses ($/BOE)Production $3.35 – 3.80

Transportation, processing & other $2.40 – 3.00

DD&A and ARO accretion $7.00 – 7.60

General and administrative $1.10 – 1.40

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

26

Hedges as of October 30, 20182018 2019 2020

Fourth Quarter

First Quarter

Second Quarter

Third Quarter

Fourth Quarter

First Quarter

Second Quarter

OILWTI Oil Collars1

Volume (Bbl/d) 37,000 31,000 31,000 24,000 16,000 8,000 —Weighted Average Floor 52.97 53.94 53.94 55.67 58.50 60.00 —Weighted Average Ceiling 64.79 66.88 66.88 70.03 71.94 75.85 —

WTI Swaps2

Volume (Bbl/d) 29,000 29,000 29,000 24,000 16,000 7,000 7,000Weighted Average Differential3 (5.01) (5.46) (5.46) (6.50) (7.79) (0.40) (0.40)

GASPEPL Collars4

Volume (MMBtu/d) 123,261 120,000 120,000 90,000 60,000 30,000 —Weighted Average Floor 2.09 2.05 2.05 1.93 1.93 1.97 —Weighted Average Ceiling 2.43 2.42 2.42 2.34 2.42 2.51 —

El Paso Perm Collars5

Volume (MMBtu/d) 86,630 80,000 80,000 60,000 30,000 10,000 —Weighted Average Floor 1.78 1.69 1.69 1.48 1.37 1.40 —Weighted Average Ceiling 2.01 1.92 1.92 1.74 1.60 1.70 —

Waha Collars6

Volume (MMBtu/d) 26,630 30,000 30,000 30,000 30,000 20,000 —Weighted Average Floor 1.38 1.38 1.38 1.38 1.38 1.40 —Weighted Average Ceiling 1.67 1.67 1.67 1.67 1.67 1.73 —

Total Natural Gas CollarsVolume (MMBtu/d) 236,521 230,000 230,000 180,000 120,000 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 FERC3 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

Permian Region ProductionDaily Production(BOE)

81

9994

8780

85 86 85

96

107 105

112 114

122 121

0

25

50

75

100

125

1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18

Oil NGL Natural Gas

28

Mid-Continent Region ProductionDaily Production(MBOE)

7470 68

7782

77

7174

8185 85

8891

89

0

25

50

75

100

1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18

Oil NGL Natural Gas

97

29

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

Permian Basin Water Management

Saltwater Disposal System

30

Investment Sensitivities Highlight Asset Quality and Depth

Assuming 10% annual production CAGR over the next three years, Cimarex can generate $500-600mm of cumulative free cash flow

*Assumes $55/$2.00 realized prices*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.

2019-2021Cumulative Free Cash

Growth Sensitivities Boe Oil Flow ($mm)* CROCEMaintenance Case 700 Flat FlatGrowth Sensitivity 1,200 10% 13% $500-$600 30%

Production Growth (3-Yr CAGR)Capex

($mm)

31

Culberson Lower Wolfcamp - Animal Kingdom– Eight wells testing 14 wells per section– Waiting on completion

Red Hills (Lea) Upper Wolfcamp - Hallertau– Six wells testing 12 wells per section– Producing

Reeves Upper Wolfcamp - Snowshoe– Eight wells testing 18 wells per section– Currently completing

Red Tank (Lea) Avalon - Triste Draw– Six wells testing 20 wells per section– Waiting on completion

Permian Basin Development Pilot Details

1,216’

1,216’225’

Low

er W

olfc

amp

Animal Kingdom spacing

225’

Snowshoe spacing880’

880’

375’

Upp

er W

olfc

amp

190’

500’

380’

Ava

lon

Triste Draw spacing

Hallertau spacing880’

Upp

er W

olfc

amp

50’

225’

32

Non-GAAP ReconciliationReconciliation of Net Income to EBITDA and Adjusted EBITDA1

($ in Millions) 2015 2016 2017LTM

9/30/18

Net income (loss) $ (2,580) $ (409) $ 494 $ 650

Income tax expense (benefit) (1,472) (214) 188 143

Interest expense, net of capitalized 55 62 52 47

DD&A and ARO accretion 741 400 462 560

EBITDA (3,256) (161) 1,196 1,400

Impairment of oil and gas 4,033 758 — —

Adjusted EBITDA 778 597 1,196 1,400

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

Debt Adjusted Shares (Using trailing 12-mo (TTM) stock price)

2016 2017LTM

9/30/18

Basic shares outstanding (in 000s) 95,124 95,437 95,603Debt adjusted shares outstanding

YE Debt, net 847,124 1,099,466 636,054TTM stock price 115.07 114.00 102.43

Equivalent shares issued using TTM stock price 7,362 9,644 6,210

Debt adjusted shares using TTM stock price 102,485 105,082 101,813

33

Non-GAAP ReconciliationReconciliation of cash flow from operations1 Debt/Cap calculation

Nine Months Ended September 30, ($ in Millions)

Sept 30, 2018

($ in Millions) 2017 2018Long-term debt (principal) 1,500

Net cash provided by operating activities $ 756 $ 1,158 Stockholders equity 3,026

Change in operating assets and liabilities 73 (52) Total capitalization 4,526

Adjusted cash flow from operations $ 829 $ 1,105 Long-term debt/total capitalization 33%

Finding & development (F&D) cost2017

Additions to proved reserves (MMBOE)Revisions of previous estimates (10.0)

Extensions & discoveries 156.8

Purchase of reserves 0.2

Total Additions (all sources) 147

Total Capital ($MM) $ 1,281

F&D Costs (all sources) ($/BOE) $ 8.71

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

Debt/Adjusted EBITDA calculationTwelve months Ended Dec 31 LTM

($ in Millions) 2016 2017 9/30/18

Long-term debt (principal) $1,500 $1,500 $1,500

Adjusted EBITDA 597 1,196 1,400

Debt/Adjusted EBITDA 2.5x 1.3x 1.1x

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.

34

Non-GAAP ReconciliationCash Return on Capital Employed (CROCE)

Cash Flow from Operating Activities+ After-tax Interest ExpenseAverage 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 1,097Effective 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 2,568Debt 591 393 350 405 750 924 1,500 1,500 1,500 1,500Capitalization 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 75Capitalized 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%