CORPORATE PRESENTATION February 2018 Forward-looking Statements - - PowerPoint PPT Presentation

CORPORATE PRESENTATION

February 2018

2

Forward-looking Statements

This presentation contains projections and

• ther forward-looking statements within the

meaning

• f

Section 27A

• f

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

• ccur
• r

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 Acierno Director – Investor Relations kacierno@cimarex.com 303-285-4957 Cimarex Energy Co. 1700 Lincoln Street, Suite 3700 Denver, CO 80203 303-295-3995

3

Who is Cimarex?

1 As of February 14, 2018 2 As of and for the twelve months ended 12/31/17. See Appendix for non-GAAP definitions and reconciliations to nearest comparable GAAP

measure.

Market Cap1 $ 10 billion Debt/Adj. EBITDA2 1.3x

Production (4Q 17)

201 MBOE/d Proved Reserves (YE 17) 559 MMBOE

— % Natural gas 48% — % Proved Developed 83% — R/P Ratio 8.0x

Quarterly Dividend $0.08/share

4

• Returns drive our decisions
• 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 – $401 million in cash at December 31, 2017

What’s Important

5

• Improved well performance

– Enhanced completion design – Allows tighter development well spacing

• Six successful spacing pilots announced in 2017

– Additional spacing tests underway

• 14-wells/section Lower Wolfcamp in Culberson County
• 18-wells/section Upper Wolfcamp in Reeves County
• Wolfcamp and Avalon tests in Lea County, NM
• Woodford spacing in Lone Rock
• Result: infill development that preserves returns while adding

locations (NPV)

2017 Achievements

6

• Debt-adjusted production growth

per share of 15% year-over-year

• Oil led the way growing 27% and

grew 36% 4Q17 vs 4Q16

• Total E&D capital – $1.28 billion

– D&C capital of $980 million – 98 net wells brought on production

• Proved reserves – 559 MMBOE

– Increase of 16%: PUDs now 17% of total proved – Replaced 211% of 2017 production

30% 25% 45% Oil NGL Natural Gas

2017 Growth in Production and Reserves

Proved Reserves (MMBOE)

416 522 485 482 559 2013 2014 2015 2016 2017 Oil NGL Natural Gas

Daily Production (MBOE)

Total 190 MBOE/D

7

26 18 30 24 47 1QA 2QA 3QA 4QA Wells Drilling & Waiting on Completion at 12/31/17 Permian Basin Mid-Continent

2017 Net Wells Online

98 net wells completed in 2017

8

• High return projects expected to

generate 2018 production growth

• f 11 – 16%
• Oil expected to grow 21 – 26% in

2018

– Oil growth estimated at 29 – 34% 4Q18 vs 4Q17

Return driven production growth continues in 2018

Daily Production (MBOE)

30% 31% 28% 30% 33% 145 164 161 190 211-221 2014 2015 2016 2017 2018E Oil NGL Natural Gas

9

• E&D Capital of $1.6 – 1.7 billion

– 29% increase from 2017 – Within cash available

• D&C Capital $1.3 – 1.4 billion

– 82% of Total E&D capital – Permian Basin ~70% – Mid-Continent Region ~30%

• Additional $80 – 90 million

budgeted for midstream

• Currently operating 14 rigs

– Ten in Permian – Four in Mid-Continent

2018 Capital Investment Program

Wolfcamp Bone Spring Avalon Woodford Meramec Other

D&C Capital $1.3 – 1.4 billion

10

13 32 51 31 48 1QE 2QE 3QE 4QE Wells Drilling & Waiting on Completion at 12/31/18 Permian Basin Mid-Continent

2018 Net Wells Online

127 net wells planned in 2018

11

2018 Delaware Basin Plans

Wolfcamp Avalon Bone Spring $890 – 940mm

Total D&C Capital

Reeves Culberson Lea Eddy Ward

Economies of Scale

Multi-well Single well 83 Net Wells

Wells Drilled by Area

• ~90% multi-well drilling or takes

advantage of existing facilities

12

• ~216,000 net acres in the

fairway

• Multiple Wolfcamp Targets

– Culberson/White City Area

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

– Reeves County

• ~63,000 net acres
• Upper Wolfcamp

– Lea County

• ~32,000 net acres

– Ward County

• ~16,000 net acres
• 188 total Wolfcamp wells drilled

– 103 long laterals (>7,000’)

Delaware Basin Wolfcamp Overview

2017/18 wells Lower Wolfcamp Upper Wolfcamp Bone Spring

13

• 100,000+ net acres; JDA with

Chevron in Culberson County

• 68 long lateral wells
• Seattle Slew spacing pilot

producing

• Animal Kingdom infill drilling
• Positive results from Western

Culberson Upper Wolfcamp delineation

– Four wells with average 30-day peak initial production of 2,587 BOE/D (56% oil) – Fifth well on production

Culberson / White City Wolfcamp Details

Lower Wolfcamp Upper Wolfcamp Operated SWD

American Pharoah 3,047 BOE/d (53% oil) Wigeon 2,359 BOE/d (30% oil) Lord Murphy 2,207 BOE/d (60% oil) Sir Barton 3,035 BOE/d (54% oil) Kingman 45 2,057 BOE/d (58% oil)

14

• Changes to completion design

have resulted in better wells

• Fifteen wells with new frac

design have average 30-day peak IP of 2,172 BOE/D (52% oil)

– ~30% increase in first year cumulative production

• Now testing new landings within

Upper Wolfcamp zone

Improving Upper Wolfcamp Results

100 200 300 400 500 600 700 60 120 180 240 300 360 Days Old Completion New Completion

Cumuative Production (MBOE)

Culberson Area Long Lateral Upper Wolfcamp

15

Production Improvement - Upper Wolfcamp

731 871 1,239 1,482 1,749 500 1,000 1,500 2,000 2013 2014 2015 2016 2017

5,058 5,309 6,926 8,409 9,750

Average Lateral Length (ft)

180 day Average Daily Production per Well (BOE)

Delaware Basin Upper Wolfcamp Wells

16

Resilient Long Lateral Returns

Culberson Long Lateral Wolfcamp

0% 50% 100% 150% 200% $30 $40 $50 $60 $70 Realized 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

17

• Tim Tam infill wells generated

67%+ ATAX return

• Infills have surpassed parent wells

in both landing zones

• Results lead to 14 wells per

section test

– Animal Kingdom now drilling

• 100

200 300 400 500 600 700 60 120 180 240 300 360 Days

Parent well (lower landing) Tim Tam Infill well (lower landing) Parent well ( upper landing) Tim Tam Infill well (upper landing)

Culberson County – Tim Tam Development

1,756’ 1,756’ 200’

Lower Wolfcamp

Tim Tam spacing Cumulative Production (MBOE)

Lower Wolfcamp

1,216’ 1,216’ 225’

Lower Wolfcamp

Animal Kingdom spacing

225’

18

• Similar, strong early cumulative

per-well production testing 6, 8

• r 12 wells per section
• Upper Wolfcamp development

to begin in 2018

– Two developments planned

100 200 60 120 180 Days

Gato average well (6 wells/section) Sunny's average well (8 wells/section) Seattle Slew average well (12 wells/section)

Culberson County – Upper Wolfcamp Development

Extrapolated Average Cumulative Production per 7,500 ft well (MBOE)

19

• 32 long lateral wells

– Targeting Upper Wolfcamp

• 26 – 10,000 ft laterals producing

– Average 30-day peak IP of 1,774 BOE/D (49% oil)

• Two downspacing pilots producing

– Wood State (12 wells/section) – Pagoda State (16 wells/section)

• Snowshoe development drilling

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

Reeves County Focus Area

Wood State Snowshoe Pagoda State

Upper Wolfcamp Operated SWD

20

• Upper Wolfcamp

– 10,000 ft laterals

• Wood State: 6 wells testing 12 wells

per section

– Surpassed Big Timber, previously best long lateral to date – Average well performing 28% above parent well

• Pagoda State: 4 wells testing 16

wells per section

– Average well performing 20% above parent well

Reeves County – Strong Infill Well Results

Pagoda spacing

680’ 680’ 340’ Upper Wolfcamp

Wood State spacing

880’ 880’ 340’ Upper Wolfcamp

100 200 300 400 500 600 60 120 180 240 300 360 Days Big Timber well Wood State parent well Average Wood State well Average Pagoda State well

Daily Production (MBOE)

21

• Exciting multi-pay area
• $225 million capital spend in 2018
• Avalon activity

– 24,000 net prospective acres – Triste Draw infill spacing pilot currently drilling

• Wolfcamp activity

– 32,000 net prospective acres – Hallertau infill spacing pilot waiting

• n completion

Lea County

Red Hills Red Tank Triste Draw Hallertau

Upper Wolfcamp Avalon Bone Spring

22

Mid-Continent Basin 2018 Outlook

Meramec Woodford $370 – 420 million

Total D&C Capital

Meramec Lone Rock Other Woodford

Economies of Scale

Multi-well Single well 43 Net Wells

Activity by Area

• ~75% multi-well drilling takes

advantage of existing facilities

23

• Meramec and Woodford

Stacked Targets

• Meramec: 116,500 net

prospective acres

– 100% HBP

• Woodford: 136,500 net

undeveloped acres (88% HBP)

Mid-Continent Overview

Cana core

Meramec play outline

Woodford play outline

24

• 52 wells producing with average

lateral length of ~7,100 ft

– Average 30-day IP of 1,742 BOE/D (38% oil)

• Thirteen – 10,000 ft lateral wells

brought online in 2017

– Average 30-day IP of 2,383 BOE/D (37% oil)

• 28 downspacing pilots on-line or

underway in the play

– XEC has interest or data on all but four

• Formulating development plans in

the 14N-10W area

– Stacked Meramec & Woodford – Operated almost all of the 24,000 acres leased – Average 62% working interest

Meramec – The Big Picture

5,000 ft Meramec 10,000 ft Meramec Meramec play outline

Tillman BIA 1H 2,389 BOE/d (45% oil) Dupree BIA 1H 2,877 BOE/d (56% oil) Rocky 1-17H 1,912 BOE/d (67% oil) Woolfolk 2H 2,878 BOE/d (18% oil) 14N10W Mike Com 1H 4,353 BOE/d (10% oil)

25

• 2018 developments

– Steve O - developing remaining section with 8 well spacing – Lehman - developing remaining section with 8 well spacing – Miss Mary - testing landing zone with 8 well spacing

• Future14N-10W develoment

– Stacked Meramec/Woodford – Successfully tested 19 wells per section (Leon Gundy) – Positive results with zone completion sequence at Woolfolk/NIB

• Another zone completion test

planned

Meramec Development Plans

5,000 ft Meramec 10,000 ft Meramec Meramec play outline

14N10W Steve O Lehman Miss Mary Woolfolk /NIB Mike Com 1H

26

• Long history of activity
• Emerging Lone Rock play

yielding best results to date

• Clyde Copeland high density

spacing pilot yielding good results

• Formulating development

plans in the 14N-10W area

• Long lateral Leota Jacobs

infill deferred to 2019

Woodford Activity

Operated well

Non-operated well

Clyde Copeland Lone Rock 14N10W Leota Jacobs

27

• Increased density pilot

– 8 wells testing 16 and 20 wells per section

• Results positive for future

well spacing

– Interference testing on-going

Clyde Copeland Results

50 100 150 200 30 60 90 120 150 180 Days Average well (20 well spacing) Average well (16 well spacing) Average parent well (9 well spacing)

Cumulative Production (MBOE)

Woodford Osage 330’

16 well spacing

80’ 528’

20 well spacing Clyde Copeland development

28

• Best Woodford returns in portfolio
• ~16,000 net contiguous acres
• Multiple completion design

factors enhance productivity

• Infill testing:

– Shelly testing 8 and 12 wells per section (currently drilling) – JD Hoppinscotch testing 8 wells per section in Woodford

Lone Rock Activity

Shelly Hines Federal 1H 17.2 MMcfed (38% oil) Meyers 1H 13.4 MMcfed (24% oil) Jimmie Com 10.2 MMcfed (22% oil) Woodford

100 200 300 30 60 90 120 150 180 210 Days

1st Gen (~1,440 lb/ft) 2nd Gen (~2,800 lb/ft) 3rd Gen (~2,800 lb/ft)

Average Cumulative Production per Well (MBOE)

Woodford 440’

12 well spacing

660’

8 well spacing Shelly Spacing

JD Hoppinscotch

Woodford 640’

JD Hoppinscotch Spacing

160’ Meramec

29

• Solid returns from large portfolio
• Strong financial position

– $401 million of cash on the balance sheet at 12/31/17

• 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

Well-positioned for 2018

30

Appendix

31

2018 Guidance

First Quarter Full Year Daily Production (BOE) 198 – 207 211 – 221 % Oil 33% Capital Expenditures ($billion) E & D $1.6 – 1.7 D & C $1.3 – 1.4 Midstream $0.08 – 0.09 Expenses ($/BOE) Production $3.75 – 4.35 Transportation, processing & other $3.20 – 3.80 DD&A and ARO accretion $7.50 – 8.10 General and administrative $1.20 – 1.50 Taxes other than income (% of oil and gas revenue) 5.0 – 5.5%

32

Hedges as of February 14, 2018

2018 2019 First Quarter Second Quarter Third Quarter Fourth Quarter First Quarter Second Quarter Third Quarter OIL WTI Oil Collars1 Volume (Bbl/d) 29,000 29,000 25,000 19,000 13,000 13,000 6,000 Weighted Average Floor 47.28 47.83 47.48 48.63 48.92 48.92 50.00 Weighted Average Ceiling 56.33 57.93 57.76 58.80 61.04 61.04 66.82 WTI Swaps2 Volume (Bbl/d) 13,000 14,000 14,000 9,000 6,000 6,000 1,000 Weighted Average Differential3 (0.72) (0.72) (0.72) (0.59) (0.51) (0.51) (0.70) GAS PEPL Collars4 Volume (MMBtu/d) 130,000 120,000 90,000 60,000 50,000 50,000 20,000 Weighted Average Floor 2.57 2.39 2.33 2.28 2.23 2.23 1.98 Weighted Average Ceiling 2.93 2.70 2.56 2.49 2.46 2.46 2.16 El Paso Perm Collars5 Volume (MMBtu/d) 90,000 90,000 70,000 50,000 40,000 40,000 20,000 Weighted Average Floor 2.52 2.22 2.14 2.06 1.98 1.98 1.65 Weighted Average Ceiling 2.84 2.48 2.32 2.23 2.14 2.14 1.80 Total Natural Gas Collars Volume (MMBtu/d) 220,000 210,000 160,000 110,000 90,000 90,000 40,000

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 FERC 3 Index price on basis swaps is WTI NYMEX less weighted average differential shown in table

33

Permian Region Production

Daily Production (MBOE)

68 74 81 99 94 87 80 85 86 85 96 107 105 112 25 50 75 100 Q3 14 Q4 14 Q1 15 Q2 15 Q3 15 Q4 15 Q1 16 Q2 16 Q3 16 Q4 16 Q1 17 Q2 17 Q3 17 Q4 17 Oil NGL Natural Gas

34

Mid-Continent Region Production

Daily Production (MBOE)

68 64 58 56 54 64 70 65 59 63 70 85 85 88 25 50 75 Q3 14 Q4 14 Q1 15 Q2 15 Q3 15 Q4 15 Q1 16 Q2 16 Q3 16 Q4 16 Q1 17 Q2 17 Q3 17 Q4 17 Oil NGL Natural Gas

35

Efficiency Gains Continue in LOE

$0.81 $0.62 $0.49 $0.44 $1.63 $1.49 $1.30 $1.17 $0.83 $0.61 $0.28 $0.37 $1.97 $1.45 $1.15 $1.11 $1.25 $0.83 $0.73 $0.68 $6.48 $5.00 $3.95 $3.77 2014 2015 2016 2017 Compressor Rental & Repair Labor/Other Water Disposal Repairs, Maintenance, Chemicals & Rentals Workovers

$/BOE

36

Non-GAAP Reconciliation

Reconciliation of Net Income to EBITDA and Adjusted EBITDA1

($ in Millions) 2014 2015 2016 2017 Net income (loss) $ 526 $(2,580) $ (409) $ 494 Income tax expense (benefit) 310 (1,472) (214) 188 Interest expense, net of capitalized 37 55 62 52 DD&A and ARO accretion 786 741 400 462 EBITDA 1,659 (3,256) (161) 1,196 Impairment of oil and gas

• 4,033

758

• Adjusted EBITDA

1,659 778 597 1,196

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 2017 Basic shares outstanding (in 000s) 95,124 95,437 Debt adjusted shares outstanding YE Debt, net TTM stock price 847,124 115.07 1,099,466 114.00 Equivalent shares issued using TTM stock price 7,362 9,644 Debt adjusted shares using TTM stock price 102,485 105,082

37

Non-GAAP Reconciliation

Reconciliation of cash flow from operations1

Three months Ended Dec 31 ($ in Millions) 2017 2016 Net cash provided by operating activities $ 341 $ 185 Change in operating assets and liabilities 16 34 Adjusted cash flow from operations $ 357 $ 219

Finding & development (F&D) cost

2017 Additions to proved reserves (MMBOE) Revisions of previous estimates (10.0) Extensions & discoveries 156.8 Purchase of reserves 0.2 Total Additions (all sources) 147.0 Total Capital ($MM) $ 1,281 F&D Costs (all sources) ($/BOE) $ 8.71 Drilling F&D cost (extensions & discoveries) ($/BOE) $ 8.17

Debt/Cap calculation

($ in Millions) Dec 31, 2017 Long-term debt (principal) $ 1,500 Stockholders equity 2,568 Total capitalization 4,068 Long-term debt/total capitalization 37%

Debt/Adjusted EBITDA calculation

Twelve months Ended Dec 31 ($ in Millions) 2015 2016 2017 Long-term debt (principal) $1,500 $1,500 $1,500 Adjusted EBITDA 778 597 1,196 Debt/Adjusted EBITDA 1.9x 2.5x 1.3x

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.

38

• Culberson Lower Wolfcamp Animal

Kingdom development

– Eight wells testing 14 wells per section – Currently drilling

• Reeves Upper Wolfcamp Snowshoe

development

– Eight wells testing 18 wells per section – Currently drilling

• Red Hills Upper Wolfcamp Hallertau

development

– Five wells testing 12 wells per section – Waiting on completion

• Red Tank Avalon Triste Draw

development

– Six wells testing 20 wells per section – Currently drilling

Permian Basin Pilot Details

1,216’ 1,216’ 225’

Lower Wolfcamp

Animal Kingdom spacing

225’

Snowshoe spacing

880’ 880’ 375’ Upper Wolfcamp 190’

500’ 380’

Avalon

Triste Draw spacing Hallertau spacing

880’ Upper Wolfcamp 50’