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BAML Global Energy ConferenceMiami | November 10‐11, 2015

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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……………………...…….....….$11.1B

Debt/Adj. EBITDA1……………...…………...………..1.5x

Production (3Q15)………………...……..979 MMcfe/d

Proved reserves………………...…….. 3.1 Tcfe

% Natural gas………………...……..53%

% Proved developed………………...……..77%

R/P Ratio………………...…….. 9.9x

Quarterly dividend of $0.16/share

Who is Cimarex?

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1 LTM, as of September 30, 2015

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• Returns drive decisions

• Our balanced portfolio of assets

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

• Idea generation and track record of strong execution

• Strong financial position

— Conservative debt levels and ample liquidity —May equity offering; $730mm net proceeds

What’s Important

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5

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Sound Decisions = Solid Growth

0

500

1,000

1,500

2,000

2,500

3,000

3,500

2012 2013 2014

Oil NGL Gas

350

444

343

425

693

869

0

250

500

750

1,000

2013 2014 2015E

Oil & NGL Natural Gas

+14%983‐991

2,2592,497

3,132

Daily Production(MMcfe)

Proved Reserves(Bcfe)

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Regional Diversity Provides Flexibility

Permian Basin Mid‐Continent

Third Quarter 2015 Production Mix

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• Total: $900‐$950 million• Currently seven operated rigs• Expect 12 operated rigs by

year‐end— Spud Culberson Wolfcamp A

downspacing pilot in 4Q— Meramec pilot to begin in 4Q

2015 E&D Investment Plan

Drilling & Completion Capital$769mm

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• Multiple projects/multiple zones• Delaware Basin— Begin Wolfcamp D development

in Culberson County— Continue Wolfcamp A pilot— Bone Spring sands (oil)— First Reeves infill development

• Mid‐Continent region— Continue Meramec spacing

pilots— Begin new Woodford infill

Capital Allocation*Drilling & Completion

2016 ‐ How it looks today

*Total 2016 capital allocation assumes current strip prices and a 12 operated rig program

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• ~235,000 net acres in the fairway

• Multiple Wolfcamp Targets— Culberson/White City Area

• 100,000+ net acres• Wolfcamp A, C & D• JDA with Chevron

— Reeves County • 80,000 net acres• Wolfcamp A & B/C

— Ward County• 37,000 net acres

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

• 13 Wolfcamp D long laterals

— Avg. 30‐day peak IP of 2,308 BOE/d (25% oil; 46% gas; 29% NGL)

• Wolfcamp A downspacing pilot spuds in 4Q

• New oil gathering in place

• $25mm on infrastructure in 2015

Culberson Area Wolfcamp Details

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• Thirteen 10,000‐foot laterals

• Average 30‐day peak IP of 2,308 BOE/d (25% oil; 46% gas; 29% NGL)

Long Lateral Performance

Cumulative Production (MBOE)

Culberson Wolfcamp D

0

100

200

300

400

500

600

0 60 120 180 240 300 360

Days

10,000‐ft. lateral Tim Tam

63% Increase

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Long Laterals Provide Upsized Returns

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Culberson County Wolfcamp D

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500

1000

1500

2000

2500

3000

0 12 24 36 48

Months

10,000 ft. lateral 5,000 ft. lateral

BOE/day 5,000 ft. lateral 10,000 ft. lateral Well Cost ($MM) $7.1 $11.2 BTAX IRR 48% 75% NPV10 ($MM) $4.6 $12.5

Realized prices: Oil ‐ $50/Bbl; Gas ‐ $3.00/Mcf; NGL ‐ $12.50/Bbl (full recovery)

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Resilient Long Lateral Returns

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Culberson County Wolfcamp D well – 10,000‐ft. lateral

*All product prices are realized; assumes full NGL recovery.

BTax IRR*

Oil Price

0%

20%

40%

60%

80%

100%

120%

140%

160%

$30 $40 $50 $60 $70

$3 gas; NGL ‐ 35% of oil price

$3 gas; NGL ‐ 25% of oil price

$2 gas; NGL ‐ 25% of oil price

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

• Sunny’s Halo section testing 8 wells/section; Gato del Sol testing 6 wells/section

• Wells spuds in 4Q15— First production expected midyear

• $8.8mm well cost

Culberson County – Wolfcamp A Pilot

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Gato del Sol

Wol

fcam

p A

Sunny’s Halo

125’

675’ 900’

Parent Well

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• First Wolfcamp D Infill• Drill five 10,000‐foot laterals— 107‐acre spacing (6 wells/section)

• Wells to be staggered in the Wolfcamp D

• Spud in first quarter of 2016— First production expected mid‐year

Culberson County – Tim Tam Infill Development

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Barbaro

Prewit‐Omaha

Tim Tam

Forward Pass

Parent Well

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• 15 wells with average 30‐day peak IP of 1,344 BOE/d* (910 bo/d)

• 15 stages from nine• 100 locations identified• Latest 7,000 ft lateral has average 30‐

day peak IP of 2,753 BOE/d* (68% oil)• HBP acreage; infrastructure in place*Three stream.

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40

60

80

100

120

140

160

180

0 30 60 90 120 150 180

Days

Upsized Completion Original Completion

Upsized Frac Improves Second Bone Spring Results

64% Increase

Cumulative Production (MBOE)

White City Area

Focus Area

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Reeves County • 8 Wolfcamp A 10k‐ft. laterals— Average 30‐day peak IP of 1,575 BOE/d

(50% oil; 28% gas; 22% NGL)

• Best well in Upper A zone— Big Timber well has avg. 30‐day peak IP

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

• 2016 plans— First Wolfcamp A infill development

2015 Activity in Reeves & Ward Counties

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• 2015 capex of ~$256mm • Row 4 completions done— Impacts 4Q15 production

• Upcoming activity— Eastern core infill: drilling in

1Q; completions in 2Q— Possible long lateral infill in

2H16

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

Mid‐Continent Woodford Shale Opportunity

Operated WellNon‐operated Well

Cana‐Woodford Activity Map

Row 4 Infill

Golden Section

Haley Section

Hartz Section Eastern Core Infill

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Woodford: Consistent Results Across Acreage

Golden Section

Haley Section

Hartz Section

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400

800

1,200

1,600

2,000

2,400

0 60 120 180 240 300 360

Days

Golden Hartz Haley

Cumulative Production (MMCFE)

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• First 10,000‐ft lateral has 30‐day peak IP of 16.0 MMcfe/d — 57% gas, 28% NGL, 15% oil— Second well producing— Third long lateral drilling

• First stacked/staggered Meramec test producing— Two wells 270’ apart vertically;

660’ horizontally

• Eleven 5,000‐ft. wells to date w/ avg. 30‐day peak IP of 9.3 MMcfe/d — 47% gas, 29% oil, 24% NGL

• 115,000 net prospective acres — 60% downdip; 40% updip— 70,000 de‐risked

Meramec: The Big Picture

Cana core

Meramec play outline

5,000‐ft. Meramec well

Updip

Downdip

10,000‐ft. Meramec well

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• First 10,000‐ft. lateral avg. 30‐day peak IP of 16.0 MMcfe/d (57% gas, 15% oil, 28% NGL)

• 72% uplift in 30‐day peak IP from eleven 5000‐foot average

Meramec Long Lateral Performance

Cumulative Production (MMCFE)

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200

400

600

800

1,000

1,200

0 60 120 180

Days

Average 5,000‐ft lateral 10,000‐foot lateral (Clayton)

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• Stacked/Staggered Pilot— Eleven total wells— Wells spud in 4Q— Six Meramec wells

• Staggered between upper and lower zones

• Testing 10 wells per section; five per landing zone

— Five Woodford wells• Testing 9 wells per section

• Downspacing pilot— Partner operated— Testing 5 wells per section— Drilling underway

Meramec Next Step: Spacing Pilots

Meramec

Woodford

Osage

Cana core

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• Diverse asset portfolio with solid returns

• Strong financial position

• Flexibility to adapt to commodity environment

• Emphasis on improved productivity

Well‐positioned for 2015 and Beyond

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Appendix

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2015 Guidance

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2015 Production, Unit Expense and Capital Guidance

Fourth Quarter Full‐YearProductionTotal Equivalent (Mmcfe/d) 980‐1,010 983‐991

% Liquids 52% 53%

Capital Expenditures 900‐$950 million

Expenses ($/Mcfe): Remainder of '15Production $0.77 ‐ $0.87Transportation, processing & other 0.45 ‐ 0.55DD&A and ARO accretion 1.65 ‐ 1.85General and administrative* 0.23 ‐ 0.27Taxes other than income (% of oil and gas revenue) 5.5 ‐ 6.0%

*Includes $0.05/Mcfe related to a charitable contribution commitment

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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.

First Second Third Fourth

Oil: Quarter Quarter Quarter Quarter Total

2016WTI Oil Three‐Way Collars (1)

Volume (Bbl) 273,000 273,000 276,000 276,000 1,098,000 Wtd Avg Floor Sold (put) 40.00$ 40.00$ 40.00$ 40.00$ 40.00$ Wtd Avg Floor Purchased (put) 50.00$ 50.00$ 50.00$ 50.00$ 50.00$ Wtd Avg Ceiling Sold (call) 60.00$ 60.00$ 60.00$ 60.00$ 60.00$

First Second Third Fourth

Gas: Quarter Quarter Quarter Quarter Total

2016PEPL Collars (2)

Volume (MMBtu) 910,000 910,000 920,000 920,000 3,660,000 Wtd Avg Floor 2.70$ 2.70$ 2.70$ 2.70$ 2.70$ Wtd Avg Ceiling 2.85$ 2.85$ 2.85$ 2.85$ 2.85$

El Paso Perm Collars (2)

Volume (MMBtu) 1,820,000 1,210,000 920,000 920,000 4,870,000 Wtd Avg Floor 2.75$ 2.75$ 2.75$ 2.75$ 2.75$ Wtd Avg Ceiling 3.12$ 3.09$ 3.06$ 3.06$ 3.09$

2017El Paso Perm Collars (2)

Volume (MMBtu) 900,000 910,000 ‐ ‐ 1,810,000 Wtd Avg Floor 2.75$ 2.75$ ‐$ ‐$ 2.75$ Wtd Avg Ceiling 3.36$ 3.36$ ‐$ ‐$ 3.36$

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161 156

184

215 229

216 217 226

255

310

406

384

350 333

322

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100

150

200

250

300

350

400

450

Q1 12 Q2 12 Q3 12 Q4 12 Q1 13 Q2 13 Q3 13 Q4 13 Q1 14 Q2 14 Q3 14 Q4 14 Q1 15 Q2 15 Q3 15

Gas NGL Oil

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MMcfe/day

Cana Area Production

Row 4 Drilling Commenced

Row 4 Completions Began

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Permian Basin Production

40 41

46 49

46

53

59 55

58

6568

74

81

9994

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20

30

40

50

60

70

80

90

100

Q1 12 Q2 12 Q3 12 Q4 12 Q1 13 Q2 13 Q3 13 Q4 13 Q1 14 Q2 14 Q3 14 Q4 14 Q1 15 Q2 15 Q3 15

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)

• 2015 Focus— Wolfcamp Long Laterals— Meeting acreage obligations— White City Bone Spring

Permian Region Provides Multiple Opportunities

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Thick, Multi‐pay Wolfcamp Section

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Culberson Area100,000 net acres

Reeves County80,000 net acres

Ward County37,000 net acres

IIndicates producing zone.

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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 Wolfcamp D 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

1,365

2,450

1,500

2,500

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500

1,000

1,500

2,000

2,500

3,00030‐day IP

Days 30‐60

Days 60‐90

90 day average1,0951,250

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400

800

1,200

1,600

Wolfcamp D Wolfcamp A

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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Performance of Upsized Fracs in Cana‐Woodford Core

(MMcfe/d)

10.2

9.2

10.38.78.2

8.8

0

2

4

6

8

10

12

Golden Hartz Haley

30‐day IP

Days 30‐60

Days 60‐90

90 day average

Oil Yield(Bbl/MMcf) 21 30 46

Golden Section

Haley Section

Hartz Section

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Non‐GAAP Reconciliation

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($ in Millions) 2012 2013 2014 LTM

Net income (loss) 354$ 565$ 507$ (1,703)$

Income tax expense (benefit) 207 329 299 (955)

Interest expense, net of capitalized 14 23 37 49

DD&A and ARO accretion 527 624 816 846

EBITDA 1,102 1,541 1,659 (1,763)

Impairment of oil and gas properties - - - 2,752

Adjusted EBITDA 1,102 1,541 1,659 989

Reconciliation of Net Income to EBITDA and Adjusted EBITDA

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Non‐GAAP Reconciliation

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2015 2014

Net cash provided by operating activities $ 206 $ 502

Change in operating assets

and liabilities (27) (62)

Adjusted cash flow from operations $ 179 $ 440

Three months

Ended Sep. 30

(in millions)

Debt/Cap Calculation

2014

Proved Reserves adds (Bcfe)

Revisions of previous estimates 104.8

Extensions & discoveries [C] 813.9

Purchase of reserves 133.6

Total adds [A] 1,052.3

Total capital $MM [B] 2,131$

All-sources F&D ($/Mcfe) [B]/[A] 2.03$

Drilling (excl. revisions) F&D ($/Mcfe) [B]/[C] 2.62$

Reconciliation of cash flow from operations

Finding & development (F&D) cost

2015

Long-term debt $ 1,500

Stockholders' Equity 3,434

Total capitalization $ 4,934

Long-term debt/total capitalization 30%

Sep. 30,

(in millions)

Debt/Adj. EBITDA Calculation

Twelve months

Ended December 31, LTM

2013 2014 9/30/15

Long-term debt 924 1,500 1,500

Adj. EBITDA 1,541 1,659 989

Debt/Adj. EBITDA 0.6x 0.9x 1.5x