CORPORATE PRESENTATION May 2018 Forward-looking Statements This - - PowerPoint PPT Presentation

CORPORATE PRESENTATION

May 2018

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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

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XEC – Statistical Summary

1 As of May 7, 2018 2 As of and for the twelve months ended 3/31/18. See Appendix for non-GAAP definitions and reconciliations to nearest comparable GAAP

measure.

Market Cap1 $ 9 billion Debt/Adj. EBITDA2 1.2x

Daily Production (1Q 18)

206 MBOE Proved Reserves (YE 17) 559 MMBOE

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

Quarterly Dividend $0.16/share

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• Returns driven E&P company
• 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 – $464 million in cash at March 31, 2018

Who is Cimarex?

5

• Improved well performance

– Enhanced completion design – Allows tighter development well spacing

• Six successful spacing pilots announced in 2017

– Additional spacing tests underway

• Result: infill development that preserves returns while adding

locations (NPV)

2017 Achievements

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• High return projects expected to

generate 2018 production growth

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

– Oil growth estimated at 30–35% 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

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• 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 ~30%

• Additional $80 – 90 million

budgeted for midstream/other

• Operating 13 drilling rigs

– Ten in Permian – Three in Mid-Continent

• Five completion crews

– Three in Permian – Two in Mid-Continent

2018 Capital Investment Program

Wolfcamp Bone Spring Avalon Woodford Meramec Other

D&C Capital $1.3 – 1.4 billion

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190 206 200-209 211-221 2017A 1QA 2QE 3QE 4QE 2018E Oil 15 23 49 34 50 1QA 2QE 3QE 4QE Wells Drilling or WOC at 12/31/18 Permian Mid-Continent

2018 Production Growth

Daily Production (MBOE) Net Wells Online

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2018 Delaware Basin Plans

Wolfcamp Avalon Bone Spring $885 – 935mm

Total D&C Capital

Reeves Culberson Lea Eddy Ward

Economies of Scale

Multi-well Single well 80 Net Wells

Activity by Area

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• ~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
• 195 total Wolfcamp wells

drilled

– 109 long laterals (>7,000’)

Delaware Basin Wolfcamp Overview

2017/18 wells Lower Wolfcamp Upper Wolfcamp Bone Spring

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• 100,000+ net acres; JDA with

Chevron in Culberson County

• 72 long lateral wells
• Seattle Slew spacing pilot

producing

• Animal Kingdom infill – drilling
• Positive results from Western

Culberson Upper Wolfcamp delineation

– Five wells with average 30-day peak initial production of 2,724 BOE/d (56% oil)

Culberson / White City Wolfcamp Details

Lower Wolfcamp Upper Wolfcamp Operated SWD

Owl Draw 12 2,521 BOE/d (1,393 b/d) Charismatic 5 3,271 BOE/d (1,882 b/d)

12 500 1,000 1,500 2,000 Gen 1 Gen 2 Gen 3 Gen 4 Infill Oil (b/d)

• 52 –10,000-ft. lateral Upper

Wolfcamp wells drilled 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

• 10,000-ft. infill wells have

IP180s that are 90% of parent wells

Well Productivity Improvements

Long Lateral Upper Wolfcamp Wells

Completion Generation IP180 (BOE/d)

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Resilient Long Lateral Returns

Culberson Long Lateral Wolfcamp

0% 100% 200% 300% $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

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• 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 currently 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’

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• 34 long lateral wells

– Targeting Upper Wolfcamp

• 28 – 10,000-ft. laterals producing

– Average 30-day peak IP of 1,809 BOE/d (49% oil)

• Two downspacing pilots producing

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

• Snowshoe development waiting on

completion

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

Reeves County Focus Area

Wood State Snowshoe Pagoda State

Upper Wolfcamp Operated SWD

Dixieland State 55-6 2,505 BOE/d (1,464 b/d)

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• 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 16% 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

Cumulative Production (MBOE)

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• Exciting multi-pay area
• $225 million capital spend in 2018
• Two Avalon wells brought online in

1Q 18

– Coriander AOC 1-12 State 1H with average 30-day peak IP of 3,333 BOE/d (67% oil) – Thyme APY Fed 9H with average 30-day peak IP of 2,059 BOE/d (69% oil)

• Avalon activity

– 24,000 net prospective acres – Triste Draw infill spacing pilot waiting on completion

• Wolfcamp activity

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

Lea County

Red Hills Red Tank Triste Draw Hallertau

Upper Wolfcamp Avalon Bone Spring

Coriander AOC 1-12 3,333 BOE/d (2,248 b/d) Thyme APY 2,059 BOE/d (1,416 b/d)

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• Sales agreements in place

– >98% of forecasted production through October 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

• utlets

– Long-term sales agreements in place for NGL volumes

Permian Basin – Residue Gas Takeaway

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• Sales agreements in place for oil

volumes through 2018 & 2019

• Strategic partnerships in core

areas

– Pipelines in place – Purchase obligations – Midland index pricing

• ~70% oil production on pipe

Permian Basin – Oil Takeaway

Oil NGL Gas Q1 18 Permian Revenue

Plains pipeline Plains pipeline (under construction) Energy Transfer pipeline Offloading Site

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• 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

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Mid-Continent Basin 2018 Outlook

Meramec Woodford $375 – 425 million

Total D&C Capital

Meramec Lone Rock Other Woodford

Economies of Scale

Multi-well Single well 41 Net Wells

Activity by Area

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• 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

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• Improving well results driving

activity

• Thirteen – 10,000-ft. lateral wells

brought online in 2017

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

• Four Meramec developments

planned in 2018

• Formulating development plans in

the 14N-10W area

• 40 industry downspacing pilots
• nline or underway in the play

– XEC has interest or data on all but nine

Meramec – The Big Picture

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

Tillman BIA 1H 2,389 BOE/d (1,069 b/d) Dupree BIA 1H 2,877 BOE/d (1,597 b/d) Rocky 1-17H 1,912 BOE/d (1,282 b/d) 14N10W Mike Com 1H 4,353 BOE/d (433 b/d)

20 40 60 80 100 120 500 1,000 1,500 2,000 2,500 2014 2015 2016 2017 Oil BOE Oil per 1000' lateral Average 30-day Peak IP (b/d) Oil Rate (b/d)

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• 2018 developments

– Steve O – 6 wells with 8 wells/section spacing (currently

completing)

– Lehman – 6 wells with 8 wells/section spacing – Miss Mary – 3 wells with 8 wells/section spacing (waiting on

completion)

• Future 14N-10W development

– Stacked Meramec/Woodford – Operate almost all of the 24,000 gross acres – Average 62% working interest – 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

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• 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

Woodford Activity

Operated well

Non-operated well

Clyde Copeland Lone Rock 14N10W

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• 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 completing) – JD Hoppinscotch testing 8 wells per section in Woodford (currently

drilling)

Lone Rock Activity

Shelly Hines Federal 1H 17.2 MMcfed (1,016 b/d) Meyers 1H 13.4 MMcfed (535 b/d) Jimmie Com 10.2 MMcfed (368 b/d) Woodford

100 200 300 400 500 60 120 180 240 300 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

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• Solid returns from large portfolio
• Strong financial position

– $464 million of cash on the balance sheet at March 31, 2018

• 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

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Appendix

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2018 Guidance

Second Quarter Full Year Daily Production (MBOE) 200 – 209 211 – 221 % Oil 33% Capital Expenditures ($billion) E & D $1.6 – 1.7 D & C $1.3 – 1.4 Midstream/Other $0.08 – 0.09 Expenses ($/BOE) Production $3.80 – 4.30 Transportation, processing & other $2.40 – 3.00 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) 5.75 – 6.25%

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Hedges as of May 7, 2018

2018 2019 Second Quarter Third Quarter Fourth Quarter First Quarter Second Quarter Third Quarter OIL WTI Oil Collars1 Volume (Bbl/d) 31,000 27,000 21,000 15,000 15,000 8,000 Weighted Average Floor 47.97 47.67 48.76 49.07 49.07 50.00 Weighted Average Ceiling 58.35 58.25 59.33 61.49 61.49 66.21 WTI Swaps2 Volume (Bbl/d) 15,000 21,000 16,000 13,000 13,000 8,000 Weighted Average Differential3 (0.78) (1.94) (2.25) (2.60) (2.60) (3.93) GAS PEPL Collars4 Volume (MMBtu/d) 130,000 100,000 70,000 60,000 60,000 30,000 Weighted Average Floor 2.35 2.28 2.21 2.17 2.17 1.93 Weighted Average Ceiling 2.66 2.52 2.46 2.42 2.42 2.18 El Paso Perm Collars5 Volume (MMBtu/d) 100,000 80,000 60,000 50,000 50,000 30,000 Weighted Average Floor 2.15 2.06 1.97 1.88 1.88 1.60 Weighted Average Ceiling 2.43 2.28 2.19 2.12 2.12 1.87 Total Natural Gas Collars Volume (MMBtu/d) 230,000 180,000 130,000 110,000 110,000 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 FERC 3 Index price on basis swaps is WTI NYMEX less weighted average differential shown in table

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Permian Region Production

Daily Production (MBOE)

74 81 99 94 87 80 85 86 85 96 107 105 112 114 25 50 75 100 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 Q1 18 Oil NGL Natural Gas

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Mid-Continent Region Production

Daily Production (MBOE)

81 74 70 68 77 82 77 71 74 81 85 85 88 91 25 50 75 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 Q1 18 Oil NGL Natural Gas

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Non-GAAP Reconciliation

Reconciliation of Net Income to EBITDA and Adjusted EBITDA1

($ in Millions) 2015 2016 2017 LTM 3/31/18 Net income (loss) $(2,580) $ (409) $ 494 $ 550 Income tax expense (benefit) (1,472) (214) 188 166 Interest expense, net of capitalized 55 62 52 49 DD&A and ARO accretion 741 400 462 498 EBITDA (3,256) (161) 1,196 1,264 Impairment of oil and gas 4,033 758

• Adjusted EBITDA

778 597 1,196 1,264

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 LTM 3/31/18 Basic shares outstanding (in 000s) 95,124 95,437 95,433 Debt adjusted shares outstanding YE Debt, net TTM stock price 847,124 115.07 1,099,466 114.00 1,036,190 108.33 Equivalent shares issued using TTM stock price 7,362 9,644 9,565 Debt adjusted shares using TTM stock price 102,485 105,082 104,998

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Non-GAAP Reconciliation

Reconciliation of cash flow from operations1

Three months Ended Mar 31, ($ in Millions) 2017 2018 Net cash provided by operating activities $ 250 $ 383 Change in operating assets and liabilities 16 (16) Adjusted cash flow from operations $ 266 $ 367

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) Mar 31, 2018 Long-term debt (principal) $ 1,500 Stockholders equity 2,752 Total capitalization 4,252 Long-term debt/total capitalization 35%

Debt/Adjusted EBITDA calculation

Twelve months Ended Mar 31, LTM ($ in Millions) 2016 2017 2018 Long-term debt (principal) $1,500 $1,500 $1,500 Adjusted EBITDA 597 1,196 1,264 Debt/Adjusted EBITDA 2.5x 1.3x 1.2x

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.

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• 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 – Waiting on completion

• Red Hills Upper Wolfcamp Hallertau

development

– Five wells testing 12 wells per section – Producing

• Red Tank Avalon Triste Draw

development

– Six wells testing 20 wells per section – Waiting on completion

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’

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• 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

100 200 300 400 60 120 180 240 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)

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• 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

50 100 150 200 250 300 350 60 120 180 240 300 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