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J.P. Morgan Inaugural Energy Equity ConferenceJune 27‐29, 2016

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Forward‐looking StatementsThis 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 AciernoDirector – Investor Relationskacierno@cimarex.com303‐285‐4957

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

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Market cap……………………...…….....….$11.0B

Debt/Adj. EBITDA1……………...…………...………..2.2x

Production (1Q16)………………...……..973 MMcfe/d

Proved reserves………………...…….. 2.9 Tcfe

% Natural gas………………...……..52%

% Proved developed………………...……..75%

R/P Ratio………………...…….. 8.1x

Quarterly dividend of $0.08/share

Who is Cimarex?

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1 March 31, 2016

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• Returns drive decisions

• Balanced portfolio of assets

— Premier position in the Delaware Basin and Mid‐Con region— Flexibility through commodity cycles

• Idea generation and track record of strong execution

• Strong financial position

— Conservative debt levels and ample liquidity — $677mm in cash at March 31, 2016

What’s Important

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5

2.32.5

3.12.9

3.3

0.4

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

2012 2013 2014 2015 2015*

Oil NGL Gas

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Reserves GrowthProved Reserves(Tcfe)

*Adjusted for negative price revisions.

6

6

Production Growth

Daily Production(MMcfe)

48%51%

51%53% 53%

627693

869

985 940‐970

0

250

500

750

1,000

2012 2013 2014 2015 2016E

Oil & NGL Natural Gas

2.342.56

3.28

3.55

0

1

2

3

4

2012 2013 2014 2015

Net Debt Adjusted Production/Share(MMcfe)

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• Quarterly hedging program targets 10% of expected oil and gas volumes over next five quarters— Methodical approach

• Bias toward costless collars

—Provides downside protection

—Maintains some upside price exposure

Daily Hedged Volumes

0

30

60

90

120

0

5,000

10,000

15,000

20,000

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

Oil (Bbl/d)

Gas (MMcf/d)

Oil (Bbl/d) Gas (MMcf/d)

14 24 24 21 21 11 0% of 1Q16 Oil & Gas Volumes

Hedge Strategy Targets 50% of Oil & Gas Volumes

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• $650‐700mm (up $50mm from previous guidance)

• Multiple projects/multiple zones

• Delaware Basin— Acreage obligations— Upper & Lower Wolfcamp in Culberson

County— Reeves infill development

• Mid‐Continent region— Meramec delineation and acreage

retention— Continue Woodford infill

• Flexibility to right size capital

2016 E&D InvestmentDrilling & Completion Capital

$475‐$500mm

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• ~230,000 net acres in the fairway

• Multiple Wolfcamp Targets— Culberson/White City Area

• 100,000+ net acres• Upper & Lower Wolfcamp• JDA with Chevron

— Reeves County • 80,000 net acres• Upper Wolfcamp

Biggest Opportunity ‐ Delaware Basin Wolfcamp

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• 100,000+ net acres• 2013 main objectives— Drilling to hold acreage— Wolfcamp C & D

• Two rigs; ~20 wells• 41 wells to date; 30‐day

average IP of 6.5 MMcfe/d• Product mix of 45% gas;

26% oil; 29% NGL

— Upsize frac stages• First 20‐stage test has 30‐day

average IP of 8.4 MMcfe/d

— Testing Wolfcamp A — Experiment with long laterals— Stacked lateral test— Design downspacing pilot

• 100,000 net acres; JDA with Chevron

• 19 long‐lateral Lower Wolfcamp wells producing

• Ten Upper Wolfcamp long laterals producing— Downspacing pilot underway

• New oil gathering in place

Culberson Area Wolfcamp Details

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• Fourteen 10,000‐foot laterals

— Average 30‐day peak IP of 2,306 BOE/d (25% oil; 46% gas; 29% NGL)

Long Lateral Performance

Cumulative Production (MBOE)

Culberson Lower Wolfcamp

0

100

200

300

400

500

600

0 60 120 180 240 300 360

Days

10,000‐ft. lateral Tim Tam

69% Increase

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Resilient Long Lateral Returns

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Culberson County Wolfcamp – 10,000‐ft. lateral

*Assumes $2.00/Mcf natural gas, full NGL recovery, NGL price is 30% of oil price. All product prices are realized.

BTax IRR*

Oil Price

0%

25%

50%

75%

100%

125%

150%

175%

200%

$20 $30 $40 $50 $60

Upper Wolfcamp

Lower Wolfcamp

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• Seven 7,500‐ft. laterals

— Two with larger completion• Larger completions have 34%

production uplift (125 days)

— Avg. 30‐day peak IP of 1,879 BOE/d (51% oil; 30% gas; 19% NGL)

Improving Upper Wolfcamp Completion Design

Cumulative Production (MBOE)

Culberson County

34% Increase

0

50

100

150

200

250

0 30 60 90 120 150 180

Days

New frac (2 wells) Old frac (5 wells)

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• Three 10,000‐ft. laterals

— One with larger completion• Larger completion has 23%

production uplift (120 days)

— 30‐day peak IP of 2,139 BOE/d (52% oil; 29% gas; 19% NGL)

Improving Upper Wolfcamp Completion Design

Cumulative Production (MBOE)

Culberson County

0

50

100

150

200

250

0 30 60 90 120

Days

New frac (1 well) Old frac (2 wells)

23% Increase

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• Six‐well downspacing pilot— 7,500‐foot laterals— Stacked/staggered well

pattern• Sunny’s Halo section testing

eight wells/section• Gato del Sol testing six

wells/section• Completions begin in May• First production expected

midyear • $8.8mm well cost

Culberson County – Upper Wolfcamp Pilot

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Gato del Sol

Upp

er W

olfc

amp

Sunny’s Halo

125’

675’ 900’

Parent Well

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• First Lower Wolfcamp Infill• Five 10,000‐foot laterals— 107‐acre spacing (6 wells/section)— Staggered well pattern

• Currently drilling— Completion in 4Q

Culberson County – Tim Tam Infill Development

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Barbaro

Prewit‐Omaha

Tim Tam

Forward Pass

Parent Well

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• Targeting Upper Wolfcamp • Nine long laterals producing— Average 30‐day peak IP of 1,577

BOE/d (51% oil; 28% gas; 21% NGL)

• Best well to date— Big Timber has avg. 30‐day peak IP

of 3,309 BOE/d (49% oil; 27% gas; 24% NGL)

• First infill development now drilling— Six 10k‐ft. laterals— Stack/Stagger pattern— Meets acreage obligations

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Reeves County Activity

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• Meramec and Woodford Stacked Targets

• Meramec: 115,000 net prospective acres — 60% downdip; 40% updip— 70,000 de‐risked— Downspacing pilots underway

• Woodford: 128,000 net prospective acres (86% HBP)

Cana core

Meramec play outline

Mid‐Continent Overview

Woodford play outline

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• Long history of activity— Participated in 817 gross wells

since 2007

• Eastern core infill underway— 6 sections; 2 operated— 47 gross (22 net) wells— Currently drilling— Completions begin in October

Woodford Shale Activity

Operated WellNon‐operated Well

Cana‐Woodford Activity Map

Row 4 Infill

Eastern Core Infill

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Woodford: Consistent Results Across Acreage

0

400

800

1,200

1,600

2,000

2,400

0 60 120 180 240 300 360

Days

Golden (8 infill wells)Hartz (8 infill wells)Haley (8 infill wells)Phillips/Armacost (11/9 infill wells)

Cumulative Production (MMcfe)

2.1 2.1 2.2

Golden Hartz Haley

Gas NGL Oil

First Year Cumulative Production (Bcfe)

Row 4 Infill

Eastern Core Infill

Golden Haley

Hartz

Phillips, Armacost

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• 18 5,000‐ft laterals have avg. 30‐day peak IP of 8.3 MMcfe/d

• Three10,000‐ft laterals with avg. 30‐day peak IP of 13.6 MMcfe/d— Product mix averages 44% gas;

33% oil; 23% NGL— Oil yield ranges from 11‐486 bbl/

MMcfe

• Downspacing pilots underway

Cana core

Meramec play outline

5,000‐ft. Meramec well

10,000‐ft. Meramec well

Meramec: The Big Picture

Woodford play outline

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• 62% uplift after 120 days• Three 10,000‐ft laterals have

30‐day peak IP of 13.6 MMcfe/d — 45% gas, 32% oil, 23% NGL — Oil yields range from 37 to 278

Bbl/MMcf

• 18‐ 5,000‐ft laterals have 30‐day peak IP of 8.3 MMcfe/d

— 43% gas, 23% NGL, 34% oil

— Oil yields range from 11‐486 Bbl/MMcf

Meramec Long Lateral Performance

Cumulative Production (MMCFE)

0

200

400

600

800

1,000

1,200

1,400

0 60 120

Days

Average 10,000‐ft lateral (3 wells)

Average 5,000‐ft lateral (18 wells)

62% Increase

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• Stacked/Staggered Pilot— Eight total wells; two rigs working— Four Meramec wells

• Stacked/staggered spacing• Testing 10 wells per section

— Four Woodford wells• Testing 9 wells per section

— Completions in 2H16

• Partner‐operated downspacing pilot— Testing 5 wells per section— Wells are flowing

Meramec Spacing Pilots

Osage

Woodford

Meramec

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• Diverse asset portfolio with solid returns

• Strong financial position

— Investment grade rating with stable outlook at both S&P and Moody’s

• Flexibility to adapt to commodity environment

• Emphasis on improved productivity

• Focus on retaining our attractive acreage position

Well‐positioned for 2016 and Beyond

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Appendix

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26

2016 Guidance

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2016 Production, Unit Expense and Capital Guidance

Second Quarter Full‐YearProductionTotal Equivalent (Mmcfe/d) 935‐965 940‐970

% Liquids 52% 53%

Capital Expenditures $650‐$700 million

Expenses ($/Mcfe): Remainder of '16Production $0.80 ‐ $0.90Transportation, processing & other 0.45 ‐ 0.55DD&A and ARO accretion* 1.30 ‐ 1.50General and administrative 0.19 ‐ 0.23Taxes other than income (% of oil and gas revenue) 5.5 ‐ 6.0%

*Excludes the potential impact of any future ceiling test write‐downs

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Hedges

(1) WTI refers to West Texas Intermediate oil prices as quoted on the New York Mercantile Exchange.(2) PEPL refers to Panhandle Eastern Pipe Line Tex/OK Mid‐Continent. El Paso Perm is El Paso Permian Basin index; both as quoted in

Platt’s Inside FERC.

2016 2017

Second Third Fourth First Second Third Fourth

Oil: Quarter Quarter Quarter Total Quarter Quarter Quarter Quarter Total

WTI Oil Collars (1)

Volume (Bbl/d) 4,000 9,000 9,000 5,519 9,000 9,000 5,000 ‐ 5,723 Wtd Avg Floor Purchased (put) 35.00$ 39.17$ 39.17$ 38.42$ 39.17$ 39.17$ 42.50$ ‐$ 39.90$ Wtd Avg Ceiling Sold (call) 42.50$ 47.92$ 47.92$ 46.94$ 47.92$ 47.92$ 52.26$ ‐$ 48.88$

WTI Oil Three‐Way Collars (1)

Volume (Bbl/d) 3,000 3,000 3,000 3,000 ‐ ‐ ‐ ‐ ‐ Wtd Avg Floor Sold (put) 40.00$ 40.00$ 40.00$ 40.00$ ‐$ ‐$ ‐$ ‐$ ‐$ Wtd Avg Floor Purchased (put) 50.00$ 50.00$ 50.00$ 50.00$ ‐$ ‐$ ‐$ ‐$ ‐$ Wtd Avg Ceiling Sold (call) 60.00$ 60.00$ 60.00$ 60.00$ ‐$ ‐$ ‐$ ‐$ ‐$

2016 2017

Second Third Fourth First Second Third Fourth

Gas: Quarter Quarter Quarter Total Quarter Quarter Quarter Quarter Total

PEPL Collars (2)

Volume (MMBtu/d) 30,000 60,000 60,000 40,109 50,000 50,000 30,000 ‐ 32,356 Wtd Avg Floor 2.32$ 2.28$ 2.28$ 2.32$ 2.20$ 2.20$ 2.25$ ‐$ 2.21$ Wtd Avg Ceiling 2.75$ 2.82$ 2.82$ 2.81$ 2.82$ 2.82$ 2.90$ ‐$ 2.84$

El Paso Perm Collars (2)

Volume (MMBtu/d) 33,297 50,000 50,000 38,388 50,000 50,000 20,000 ‐ 29,836 Wtd Avg Floor 2.45$ 2.37$ 2.37$ 2.44$ 2.37$ 2.37$ 2.30$ ‐$ 2.36$ Wtd Avg Ceiling 2.90$ 2.89$ 2.89$ 2.92$ 2.95$ 2.95$ 2.93$ ‐$ 2.95$

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229 216 217

226

255

310

406

384

350 333

322

385

419

‐

50

100

150

200

250

300

350

400

450

Q1 13 Q2 13 Q3 13 Q4 13 Q1 14 Q2 14 Q3 14 Q4 14 Q1 15 Q2 15 Q3 15 Q4 15 Q1 16

Gas NGL Oil

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MMcfe/day

Cana Area Production

Row 4 Drilling Commenced

Row 4 Completions Began

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29

Permian Basin Production

46

53

59 55

58

6568

74

81

9994

87

80

‐

10

20

30

40

50

60

70

80

90

100

Q1 13 Q2 13 Q3 13 Q4 13 Q1 14 Q2 14 Q3 14 Q4 14 Q1 15 Q2 15 Q3 15 Q4 15 Q1 16

Oil NGL Gas

MBOE/day

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• Multiple projects/multiple zones— Wolfcamp shale (oil & gas)— Bone Spring sands (oil)— Avalon Shale (oil window)

• 2016 Focus— Wolfcamp Long Laterals— Meeting acreage obligations

Permian Region Provides Multiple Opportunities

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• 15 stages from nine• 100 locations identified• First 7,000 ft lateral has average

30‐day peak IP of 2,753 BOE/d (68% oil)

• HBP acreage; infrastructure in place

Upsized Frac Improves Second Bone Spring Results

70% Increase

Cumulative Production (MBOE)

White City – 5,000‐ft lateral

0

20

40

60

80

100

120

140

160

180

200

0 30 60 90 120 150 180

Days

Upsized Completion Original Completion

Focus Area

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• Two four‐well pilots; 5,000‐ft laterals

• Barbaro Pilot— 80‐acre spacing (8 wells/section)— 20‐stage completion; 1,200 lbs/foot

• Prewit‐Omaha Pilot— 107‐acre spacing (6 wells/section)— 16‐stage completion;1,200 lbs/foot

• Results lead to design of first Lower Wolfcamp infill development

Culberson County – Downspacing Pilot Results

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Barbaro

Prewit-Omaha

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Shallow Decline of Upsized Fracs

(BOE/d)

Strong Performance from Key Culberson Wolfcamp Wells

1,500

2,500

1,365

2,450

‐

500

1,000

1,500

2,000

2,500

3,00030‐day IP

Days 30‐60

Days 60‐90

90 day average1,250 1,095

‐

400

800

1,200

1,600

Lower Wolfcamp Upper Wolfcamp

Twenty Grand5,000 ft. lateral

First Year Cum:0.6 Bcf (wet gas)

135 Mbbls

Tim Tam5,000 ft. lateral

First Year Cum:1.0 Bcf (wet gas)

89 Mbbls

Gallant Fox10,000 ft. lateral

First Year Cum:2.1 Bcf (wet gas)

149 Mbbls

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• Four spacing pilots; 18 total wells— Testing 6 & 8 wells/section— Average 30‐day peak rate of

1,012 BOE/d (70% oil; 17% gas; 13% NGL)

• ~250 locations— Includes Avalon and Leonard— Assumes 80‐acre spacing

• 13,700 net acres identified as prospective in Lea County— All HBP

Delaware Basin Avalon Shale: Spacing Pilots

Indicates spacing pilot

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Non‐GAAP Reconciliation

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($ in Millions) 2013 2014 2015 LTM

Net income (loss) 565$ 507$ (2,409)$ (2,180)$

Income tax expense (benefit) 329 299 (1,373) (1,251)

Interest expense, net of capitalized 23 37 55 59

DD&A and ARO accretion 624 816 788 700

EBITDA 1,541 1,659 (2,939) (2,672)

Impairment of oil and gas properties - - 3,717 3,343

Adjusted EBITDA 1,541 1,659 778 671

Reconciliation of Net Income to EBITDA and Adjusted EBITDA

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Non‐GAAP Reconciliation

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2016 2015

Net cash provided by operating activities $ 85 $ 113

Change in operating assets

and liabilities (3) 74

Adjusted cash flow from operations $ 82 $ 187

(in millions)

Three months

Ended March 31,

Debt/Cap Calculation

2015

Proved Reserves adds (Bcfe)

Revisions of previous estimates (276.2)

Extensions & discoveries [C] 428.7

Purchase of reserves -

Total adds [A] 152.5

Total capital $MM [B] 877$

All-sources F&D ($/Mcfe) [B]/[A] 5.75$

Drilling (excl. revisions) F&D ($/Mcfe) [B]/[C] 2.05$

Reconciliation of cash flow from operations

Finding & development (F&D) cost

2016

Long-term debt (principal) $ 1,500

Stockholders' Equity 2,614

Total capitalization $ 4,114

Long-term debt/total capitalization 36%

March 31,

(in millions)

Debt/Adj. EBITDA Calculation

Twelve months

Ended December 31, LTM

2014 2015 3/31/2016

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

Adj. EBITDA 1,659 778 671

Debt/Adj. EBITDA 0.9x 1.9x 2.2x