1

BAML Energy ConferenceMiami | November 2014

2

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

Mark BurfordVP – Capital Markets & Planning

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

3

• Focused on idea generation and execution

• Diverse portfolio of assets provides flexibility

— Balanced commodity mix: Proved reserves are 52% natural gas— Regional optionality: Permian Basin and Mid‐Continent

• Strong balance sheet

— No bank debt— Sale of non‐core assets provides cash at year end— Net debt/total capitalization: 18%

• Long‐term time horizon

Cimarex Value Proposition

3

4

• Expect full‐year 2014 production growth of 25% —Mid‐Continent operations driving

gas (+23%) and NGL (+45%) growth

— Permian Basin projects driving 16% oil growth

• Horizontal volume growth driving earnings and cash flow— YTD Net Income up 20% — Cash Flow up 35%

Strong Growth Momentum

Daily Production(MMcfe)

350303

357

324

348627

705

0

300

600

900

2012 2013 2014E

Oil & NGL Natural Gas

+25%864‐870

5

Product and Regional Diversity

RevenueMix Area

3Q 2014 Production: 942 MMcfe/d

6

2014 E&D Investment PlanTotal Capital: $1.95 billion By Region:

Drilling80%

Land, Seismic & Cap.

Overhead14%

Facilities & Other6%

• Robust Permian opportunity set commands 74% of capex• Mid‐Continent investment set to increase in 2015

• Cana‐Woodford infill accelerating• Mid‐year acquisition consolidates position

7

• Delaware Basin focus— 90+ industry rigs working— 18 Cimarex‐operated rigs

• Multiple projects targeting multiple zones— Avalon Shale (oil window)

— Bone Spring sands (oil)— Wolfcamp shale (oil & gas)

Permian Basin Region

8

2014 Permian Drilling Capital

• Delineation, development and downspacing tests• Wolfcamp program includes multiple extended laterals

in the second half

Total Permian$1.2 billion

Wolfcamp $650 million

9

• Invest $360mm in 2014 to drill 86 gross (50 net) wells

• 60 gross (32 net) wells YTD

• Three areas■ New Mexico 2nd & 3rd Bone Spring

(Eddy & Lea Counties)• 23 operated wells YTD• 30‐day average peak IP*: 962

BOE/d; 749 bo/d■ Texas 3rd Bone Spring (Ward County)

• 7 operated wells YTD• 30‐day average peak IP*: 989

BOE/d (763 bo/d)■ Culberson County 2nd Bone Spring

• 12 operated wells YTD• 30‐day average peak IP*: 1,026

BOE/d (606 bo/d)

*Two stream.

Delaware Basin ‐ Bone Spring Activity

.

10

Delaware Basin Avalon Shale

• Seven wells completed to date— 30‐day average peak IP of 909

BOE/d (69% oil)

• Upsized frac design unlocks oil window in the Avalon

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

• 200+ locations identified• 13 net wells planned in 2014• $160mm of capex

11

• ~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• 42,000 net acres• Wolfcamp A & B/C

Delaware Basin Wolfcamp Fairway

12

Thick, Multi‐pay Wolfcamp Section

12

Culberson Area100,000 net acres

Reeves County80,000 net acres

Ward County42,000 net acres

IIndicates producing zone.

13

• 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• Joint Development Area with CVX• Long laterals in Wolfcamp D show

significant uplift— 30‐day average peak IP of 2,660

BOE/d vs. 1,500 BOE/d on 5k’— 40% gas, 27% oil, 33% NGL

• Additional long laterals planned in 4Q (Wolfcamp D & A)

• Wolfcamp A wells average 1,192 BOE/d (54% oil)

• Downspacing pilots producing— Stacked C/D lateral test — 4‐well, 80‐acre downspacing pilot has

average 30‐day peak IP of1,103 BOE/d

• $35mm midstream investment in 2014 ($27mm YTD)

Culberson Focus Area Wolfcamp

14

Upsized Returns from Long Lateral with Upsized Frac

14

BOE/day

Culberson County Wolfcamp D Wells

0

500

1000

1500

2000

2500

3000

0 6 12 18 24 30 36 42 48

MonthsOld Completion ‐ 5,000 ft. lateral; 12 stages (12‐well average)

New Completion ‐ 5,000 ft. lateral; 20 stages (4‐well average)

Long lateral ‐ 10,000 ft.; 43 stages (single well ‐ Gallant Fox)

Old New LongWell Cost ($MM) $8.0 $9.0 $13.5BT IRR 30% 90% 161%NPV10 ($MM) $4.0 $12.2 $31.6

Assumptions: Oil ‐ $90/bbl; Gas ‐ $4/Mcf; NGL ‐ $30/bbl (full recovery)

15

Shallow Decline of Upsized Fracs

(BOE/d)

Performance of Key Culberson County Wolfcamp Wells

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 average

1,095

‐

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

Twenty Grand5,000 ft. lateral

Wolfcamp D Wolfcamp A

Tim Tam5,000 ft. lateral

Gallant Fox10,000 ft. lateral

16

Upsized Returns – Oil Price Sensitivity

16

Culberson County Wolfcamp D WellsBefore Tax IRR

Realized Oil PriceAssumes $3.50/Mcf gas; $25/bbl NGL

37%45%

60%65%

74%

89%

113%122%

$50 $60 $75 $80

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

17

Reeves County • Four‐well, 80‐acre spacing test

producing— Wells average 1,029 BOE/d

(49% oil); 30‐day peak IP• Nearby acreage available for

long laterals• Offset long lateral completing— Top‐tier returns implied

• $35mm midstream investment in 2014 ($28mm YTD)

Ward County• 12 wells producing with average 30‐

day peak IP of 648 BOE/d; 477 bo/d (74%)

• Optimizing completion & landing zone

Reeves & Ward Counties

17

4Q Long lateral

18

• E&D capex of $480mm • Woodford shale capex of

~$360mm — Upsized frac boosts results— Production grew 44% year‐

over‐year— Complimentary $238mm

acquisition in May— 128,000 net acres prospective

for Woodford Shale (86%HBP)

• Drilling already underway on 2015 infill development program

Mid‐Continent Highlights

Operated WellNon‐operated Well

Cana‐Woodford Activity Map

Golden Section

Hartz Section

2015 Infill

19

19

Upsized Production from Upsized FracCana‐Woodford Shale Completion ComparisonAverage 30‐day Peak IP(MMcfe/d)

Hartz Section

Golden Section

5%

8%

12%

0.0

2.0

4.0

6.0

8.0

10.0

12.0

Old Completion Golden Section Hartz Section

Gas NGLs Oil

10.29.6

6.7

20

• Redefinition of Woodford underway— Glenda well has 30‐day

peak IP of 12.4 MMcfe/d• 69% gas

— Leota well has 30‐day peak IP of 11.4 MMcfe/d

• Includes 662 bo/d

— First 10,000 foot lateral drilled in Woodford

• 30‐day peak IP of 12.9 MMcfe/d (20% oil)

• 7 Meramec tests in 2014— First well has 30‐day peak

IP of 9.4 MMcfe/d (306 bo/d)

— 70k net acres (86% HBP)

Mid‐Continent

Woodford test (Leota)

Regional Activity Map

Meramec test & Woodford long

lateral (Bomhoff)Woodford test (Glenda)

21

• Diverse portfolio with strong returns

—Multiple Delaware Basin opportunities — Cana‐Woodford upside & re‐delineation— Continuous generation of ideas

• Production growth driving cash flow

• Strong balance sheet

— Sale of non‐core assets provides cash at year end

• Long track record of profitable growth

Well Positioned for 2015 and beyond

21

22

Appendix

22

23

Upsized Wolfcamp Frac

Old Frac Design:

5,000‐foot lateral; 12 stages; 4mm lbs of sand

5,000‐foot lateral; 20 stages; 6mm lbs of sand

New Frac Design:

24

24

MMcfe/day

Cana‐Woodford Production

161 156

184

215 229

216 217 226

255

310

406

‐

50

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

Gas NGL Oil

25

25

Permian Production Growth

29 30

34 36

40 41

46 49

46

53

59

55 58

6668

‐

10

20

30

40

50

60

70

Q1 11 Q2 11 Q3 11 Q4 11 Q1 12 Q2 12 Q3 12 Q4 12 Q1 13 Q2 13 Q3 13 Q4 13 Q1 14 Q2 14 Q3 14

Oil NGL Gas

MBOE/day

26

2014 Guidance

26

Fourth Quarter Full‐YearProduction*Total Equivalent (Mmcfe/d) 930‐955 864‐870

% Liquids 51% 51%

Expenses ($/Mcfe):Production $1.08 ‐ $1.12Transportation, processing & other 0.61 ‐ 0.65

DD&A and ARO accretion 2.55 ‐ 2.65

General and administrative 0.23 ‐ 0.27

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

5.3 ‐ 5.7%

Capital Expenditures $1.95 billion

2014 Production, Unit Expense and Capital Guidance

27

Permian Basin Oil Takeaway Capacity1

27

Existing Takeaway Capacity (Mbo/d)

Local Refineries 400

Oil Pipelines 1,575

Total Existing capacity 1,975

Upcoming Capacity Additions (Mbo/d)Long‐Haul Expansions In‐Service CapacityCactus 2Q15 200Permian Express Phase II 3Q15 230 Total Long‐Haul Expansion 430

Gathering ExpansionsMonahans to Crane (PAA) 4Q14 100Sunrise (PAA) 1Q15 200Upton to McCamey (PAA) Early 2015 200 Total Gathering Expansions 500

• New gathering lines expected to increase utilization on longhaul pipelines

1 Source: Company data

28

Culberson County Wolfcamp Pilots

28

Stacked Lateral Test• Wolfcamp C & D• Two wells• Producing/Evaluating

80‐acre Spacing Pilot• Wolfcamp D• Four wells• Producing/Evaluating

29

Reeves County Wolfcamp Pilots

29

80‐acre Spacing Pilot• Wolfcamp A• Four wells• Producing/Evaluating

Stacked/Staggered Spacing Pilot• Wolfcamp A• Six wells• Flowing Back

30

Hedges

OilWeighted Average Price

Period Index (1) Type Bbl/d Floor Ceiling

Oct. - Dec. '14 WTI Collar 12,000 $85.00 $103.47

GasWeighted Average Price

Period Index (1) Type MMBTU/d Floor Ceiling

Oct. - Dec. '14 PEPL Collar 80,000 $3.51 $4.57

Oct. - Dec. '14 PermEP Collar 60,000 $3.62 $4.50

(1) WTI refers to West Texas Intermediate oil price as quoted on the New York Mercantile Exchange. PEPL refers to Panhandle Eastern Pipe Line Tex/OK Mid-Continent index and PermEp is El Paso Permian Basin index both as quoted in Platt’s Inside FERC.

31

Non‐GAAP Reconciliation

31

($ in Millions) 2011 2012 2013

Net income (loss) 530$ 354$ 565$

Income tax expense (benefit) 312 207 329

Interest expense, net of capitalized 7 14 23

DD&A and ARO accretion 402 527 624

EBITDA 1,250 1,102 1,541

Reconciliation of Net Income to EBITDA and Adjusted EBITDA

32

Non‐GAAP Reconciliation

32

2014 2013

Net cash provided by operating activities $ 1,272 $ 941

Change in operating assets

and liabilities 20 92

Adjusted cash flow from operations $ 1,292 $ 1,033

(in millions)

Nine months

Ended September 30,

Debt/Cap Calculation

2013

Proved Reserves adds (Bcfe)

Revisions of previous estimates (216.1)

Extensions & discoveries [C] 727.3

Purchase of reserves 0.5

Total adds [A] 511.7

Total capital $MM [B] 1,603$

All-sources F&D ($/Mcfe) [B]/[A] 3.13$

Drilling (excl. revisions) F&D ($/Mcfe) [B]/[C] 2.20$

Reconciliation of cash flow from operations

Finding & development (F&D) cost

2014

Long-term debt $ 1,500

Stockholders' Equity 4,430

Total capitalization $ 5,930

Long-term debt/total capitalization 25%

September 30,

(in millions)