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February 2017
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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 [email protected]‐285‐4957
Cimarex Energy Co.1700 Lincoln Street, Suite 3700Denver, CO 80203303‐295‐3995
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Market cap……………………...…….....….$12.6B
Debt/Adj. EBITDA1……………...…………...………..2.5x
Production (4Q16)………………...……..960 MMcfe/d
Proved reserves………………...…….. 2.9 Tcfe
% Natural gas………………...……..51%
% Proved developed………………...……..79%
R/P Ratio………………...…….. 8.2x
Quarterly dividend of $0.08/share
Who is Cimarex?
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1 December 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 — $653mm in cash at December 31, 2016
What’s Important
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5
2.32.5
3.12.9 2.9
$6.90$7.72 $7.48
$3.94$3.46
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
2012 2013 2014 2015 2016
Oil NGL Gas Realized price ($/Mcfe)
5
Reserves Through Commodity CyclesProved Reserves(Tcfe)
6
6
Production Growth
Daily Production(MMcfe)
2.56
3.28
3.553.44
0
1
2
3
4
2013 2014 2015 2016
Net Debt Adjusted Production/Share(MMcfe)
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$0.13 $0.10 $0.10 $0.08 $0.09 $0.07
$0.25$0.23 $0.21 $0.19 $0.19 $0.19
$0.14$0.10
$0.06$0.04 $0.05 $0.04
$0.56
$0.40$0.43
$0.33 $0.28 $0.28
$1.08
$0.83 $0.80
$0.64$0.61 $0.58
2014 2015 1Q16 2Q16 3Q16 4Q16
Compressor Rental & Repair Labor/Other
Water Disposal Repairs, Maintenance, Chemicals & Rentals
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Record Per‐Unit LOE Highlights Continued Efficiency Gains
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• 2017 E&D Capital estimated to be $1.1 – 1.2 billion
• Includes D&C capital of $850‐900mm — Up 56% from 2016 level— 76% of E&D capital— Generates 10‐15% production
growth
• Flexibility to right size capital— Minimum capital = cash flow— Cash on the balance sheet
2017 Capital Plans
11%
25%
13%
‐2%
13%
$1,251
$1,531
$730
$552
$875
2013 2014 2015 2016 2017E
D&C capital (mm) Production Growth
Drilling & Completion Capital(millions)
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• $850‐900 million• 2/3 Permian; 1/3 Mid‐Con• Includes $330mm of drilling
to hold acreage• Multiple projects & zones• Delaware Basin — Wolfcamp delineation & infill— Bone Spring & Avalon
development— Acreage obligations met
• Mid‐Continent region— Meramec delineation and acreage
retention— Woodford spacing tests and infill
• Currently running 11 rigs; 18 by fourth quarter
2017 Drilling & Completion CapitalDrilling & Completion Capital
$850‐$900 million
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10
2017 Well Completions by Quarter
19
27
31
20
47
1Q 2Q 3Q 4Q Drilling &WOC at12/31/17
Permian Basin Mid‐Continent
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Completion Evolution ContinuesPounds of Sand per Lateral Foot
Jan. '15 July '15 Jan. '16 July '16 Jan. '17
Culberson Upper Wolfcamp 1,250 1,650 1,650 2,500 2,500
Culberson Lower Wolfcamp 1,250 1,250 1,250 2,400 2,500
Reeves Upper Wolfcamp 1,300 1,700 1,700 2,500 2,500
Meramec 1,250 1,800 2,700 2,800 2,800
Woodford 2,000 2,500 3,000 3,500 3,500
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• ~190,000 net acres in the fairway
• Multiple Wolfcamp Targets— Culberson/White City Area
• 100,000+ net acres• Upper & Lower Wolfcamp• JDA with Chevron
— Reeves County • 62,000 net acres• Upper Wolfcamp
— Ward County • 16,000 net acres• Re‐evaluating
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 in Culberson County
• 21 Lower Wolfcamp long laterals producing
• 21 Upper Wolfcamp long laterals producing
• Another successful Upper Wolfcamp step out — Lord Murphy 2H has average
30‐day peak IP of 2,207 BOE/d (1,315 bo/d) from 10,000‐ft. lateral
• Encouraging results from Upper Wolfcamp (Sunny’s/Gato) spacing pilot
• Lower Wolfcamp (Tim Tam) infill flowing back
Culberson Area Wolfcamp Details
Upper WolfcampOperated SWD
Kingman2,057 BOE/d
(58% oil) Lower Wolfcamp
Lord Murphy2,207 BOE/d
(60% oil)
Flying Ebony3,127 BOE/d
(23% oil)
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• Sixteen 10,000‐foot laterals
— Average 30‐day peak IP of 2,316 BOE/d (25% oil; 45% gas; 30% NGL)
• Flying Ebony
— Average 30‐day peak IP of 3,127 BOE/d (23% oil; 47% gas; 30% NGL)
— Completed using 2,400 lb/ft; 48 stages
Long Lateral Performance
Cumulative Production (MBOE)
Culberson Lower Wolfcamp
0
100
200
300
400
500
600
700
0 60 120 180 240 300 360Days
Flying Ebony
10,000‐ft. lateral*
5,000‐ft. lateral
68% Increase
*Flying Ebony well excluded from average.
115% Increase
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• Seven 10,000‐ft. laterals completed to date
• Wells with new frac have >1,650+ lb/ft of sand— 30‐day peak IP of 2,097 BOE/d
(55% oil; 28% gas; 17% NGL)
Improving Upper Wolfcamp Completion Design
0
100
200
300
400
500
600
0 60 120 180 240 300 360
Days
New frac
Old frac
Cumulative Production (MBOE)
Culberson County
18% Increase
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Resilient Long Lateral Returns
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Culberson County Wolfcamp – 10,000‐ft. lateral
*Assumes natural gas price of $3.00/Mcf, 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
‐ ‐ ‐ Lower WolfcampFlying Ebony completion
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• Similar per‐well results with 6 or 8 wells per section
• Next step: tighter spacing— 12 wells per section— Stack/Stagger pattern— Six‐well pilot (Seattle Slew)— Spud in first quarter
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0
50
100
150
200
250
0 30 60 90 120 150Days
Gato (6 wells)Sunnys (8 wells)
Extrapolated Average Cumulative Production per well(MBOE)
Extrapolated 180‐day Cumulative Production Per Section (MBOE)
Upp
er W
olfc
amp
Sunny’s Halo8 wells/section
125’
675’ 900’
Parent Well
Gato del Sol6 wells/section
45%45%
Culberson County –Upper Wolfcamp Pilot
0
600
1,200
1,800
Sunny's Halo Gato del Sol
Oil NGL Gas
45% 45%
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• Targeting Upper Wolfcamp • 14 long laterals producing— Average 30‐day peak IP of 1,645
BOE/d (50% oil; 28% gas; 22% NGL)
• Best wells to date— 10k‐ft: Big Timber has avg. 30‐day
peak IP of 3,309 BOE/d (49% oil; 27% gas; 24% NGL)
— 5k‐ft: Cabinet State has avg. 30‐day peak IP of 2,170 BOE/d (60% oil; 22% gas; 18% NGL)
• Wood State infill development— Three of six wells producing
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Reeves County Focus Area
Big Timber
Cabinet State
Wood State
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• 13,700 net acres
• Current inventory of 250 locations— Includes Avalon and Leonard— Assumes 8 wells per section
• Plans to test 12 and 20 wells per section in 2017
Cumulative Production (MBOE)
Lea County
119% Increase
0
50
100
150
200
250
0 60 120 180
Days
Triste Draw 25 7H Old frac
Triste Draw 25 #7H
Recent spacing pilot
Bigger Completion Improves Avalon Results
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• Meramec and Woodford Stacked Targets
• Meramec: 116,500 net prospective acres — 90,000 derisked
• Woodford: 136,500 net undeveloped acres (88% HBP)
Cana core
Meramec play outline
Mid‐Continent Overview
Woodford play outline
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• 24‐5,000‐ft laterals have avg. 30‐day peak IP of 1,417 BOE/d— 34% oil; 43% gas; 23% NGL
• Nine 10,000‐ft laterals have avg. 30‐day peak IP of 2,057 BOE/d— 43% oil; 37% gas; 20% NGL
• Oil yield range: 11‐523 bbl per MMcf
• Delineation continues• Downspacing pilot producing
Meramec play outline
5,000‐ft. Meramec well
10,000‐ft. Meramec well
Meramec: The Big Picture
Peterson
Sims
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• 47% uplift after 180 days• Nine 10,000‐ft laterals have 30‐
day peak IP of 2,057 BOE/d — 43% oil; 37% gas; 20% NGL— Oil yields range from 37 to 523
Bbl/MMcf
• 24‐ 5,000‐ft laterals have 30‐day peak IP of 1,417 BOE/d
— 34% oil; 43% gas; 23% NGL
— Oil yields range from 11 to 486 Bbl/MMcf
Meramec Long Lateral Performance
0
50
100
150
200
250
300
0 60 120 180
Days
Average 10,000‐ft lateral (9 wells)
Average 5,000‐ft lateral (24 wells)
Cumulative Production (MBOE)
47% Increase
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• Stacked/Staggered Pilot— Eight total wells— Four Meramec wells
• Stacked/staggered spacing• Testing 10 wells per section
— Four Woodford wells• Testing nine wells per section
— Flowing back
• 16 additional downspacingpilots underway— XEC has interest or data on all
but three
Meramec Spacing Pilots
Osage
Woodford
Meramec
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• Long history of activity— Participated in 880 gross wells
since 2007• Eastern core infill underway— Six sections; two operated— 47 gross (22 net) wells
• 19 gross (14 net) producing— All wells online by 2Q17
• Increased density spacing pilot underway— 8 wells testing 16 & 20 wells per
section• Leota‐Jacobs infill to begin
drilling in late 2017— Long lateral Woodford
development
Woodford Shale Activity
Operated WellNon‐operated Well
Cana‐Woodford Activity Map
Eastern Core Infill
Leota-Jacobs Infill
Increased DensityPilot
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• Testing 16 & 20 wells per section
• Eight well test— 4 wells tests 16 wells/section— 5 wells testing 20 wells/section
• Two rigs drilling— First production expected 2H17
Woodford Increased Density Spacing PilotsW
oodf
ord
Eastern Core Infill
Increased DensityPilot
330’
264’
80’
16 wells/section 20 wells/section
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0
400
800
1,200
1,600
2,000
2,400
0 60 120 180 240 300 360
Days
Armacost (9 infill wells)
Haley (8 infill wells)
Hartz (8 infill wells)
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Woodford: Completion Evolution Continues• Armacost section developed
using larger completion— Per well production in‐line with
earlier sections
• Tighter spacing means more production per section:
365‐Day Section Cumulative(Bcfe)
Cumulative Production
Per Well Average (MMcfe)
18.917.3 17.1
Armacost Haley Hartz
Gas NGL Oil
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• Diverse asset portfolio with solid returns
• Strong financial position
— Debt to total cap of 39%— $653 million of cash on the balance sheet at 12/31/16— Investment grade rating with stable outlook at both S&P and
Moody’s
• Flexibility to adapt to commodity environment
• Emphasis on idea generation
Well‐positioned for 2017 and Beyond
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Appendix
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2017 Guidance
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2017 Production, Unit Expense and Capital Guidance
First Quarter Full‐YearProductionTotal Equivalent (Bcfe/d) 1.01 ‐ 1.05 1.06 ‐ 1.110
% Gas 47% 45%
Capital Expenditures $1.1 ‐ 1.2 billion
Expenses ($/Mcfe):Production $0.60 ‐ 0.70Transportation, processing & other 0.50 ‐ 0.60DD&A and ARO accretion* 1.25 ‐ 1.35General and administrative 0.20 ‐ 0.25Taxes other than income (% of oil and gas revenue) 5.0% ‐ 6.0%
*Excludes the potential impact of any future ceiling test write‐downs
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Hedges
(1) WTI refers to West Texas Intermediate oil prices as quoted on the New York Mercantile Exchange.(2) PEPL refers to Panhandle Eastern Pipe Line Tex/OK Mid‐Continent. Perm EP is El Paso Permian Basin index; both as quoted in Platt’s
Inside FERC.
2017 2018 Average
First Second Third Fourth First
Oil: Quarter Quarter Quarter Quarter Quarter
WTI Oil Collars (1)
Volume (Bbl/d) 20,000 20,000 16,000 11,000 6,000 14,602 Wtd Avg Floor Purchased (put) 43.08$ 43.08$ 45.09$ 46.27$ 47.33$ 44.36$ Wtd Avg Ceiling Sold (call) 52.90$ 52.90$ 55.50$ 56.98$ 59.11$ 54.60$
Total WTI Oil CollarsVolume (Bbl/d) 20,000 20,000 16,000 11,000 6,000 14,602
2017 2018 Average
First Second Third Fourth First
Gas: Quarter Quarter Quarter Quarter Quarter
PEPL Collars (2)
Volume (MMBtu/d) 110,000 110,000 90,000 60,000 30,000 80,022 Wtd Avg Floor 2.52$ 2.52$ 2.61$ 2.79$ 2.90$ 2.61$ Wtd Avg Ceiling 3.04$ 3.04$ 3.12$ 3.22$ 3.32$ 3.11$
El Paso Perm Collars (2)
Volume (MMBtu/d) 90,000 90,000 60,000 40,000 20,000 59,978 Wtd Avg Floor 2.59$ 2.59$ 2.68$ 2.86$ 3.00$ 2.67$ Wtd Avg Ceiling 3.10$ 3.10$ 3.16$ 3.28$ 3.41$ 3.15$
Total Natural Gas CollarsVolume (MMBtu/d) 200,000 200,000 150,000 100,000 50,000 140,000
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• Target volume is ~50% of oil and ~50% of gas production
— Methodical approach— Five quarter duration
• Bias toward costless collars
— Downside protection— Some upside price exposure
• Average commodity prices of current collars:
— Crude oil: $44.36 X $54.60— PEPL gas: $2.61 X $3.11— Perm EP gas: $2.67 X $3.15
Hedged Volumes as of 12/31/16MMcfe/d
Hedge Strategy
0
50
100
150
200
250
300
350
1Q17 2Q17 3Q17 4Q17 1Q18 Average
Gas Oil
32
255
310
406
384
350 333
322
385
419
390
353
375
‐
50
100
150
200
250
300
350
400
450
Q1 14 Q2 14 Q3 14 Q4 14 Q1 15 Q2 15 Q3 15 Q4 15 Q1 16 Q2 16 Q3 16 Q4 16
Gas NGL Oil
32
MMcfe/day
Cana Area Production
Row 4 drilling commenced
Row 4 completions beganEastern Core completions began
33
33
Permian Basin Production
58
6568
74
81
9994
87
80
85 86 85
‐
10
20
30
40
50
60
70
80
90
100
Q1 14 Q2 14 Q3 14 Q4 14 Q1 15 Q2 15 Q3 15 Q4 15 Q1 16 Q2 16 Q3 16 Q4 16
Oil NGL Gas
MBOE/day
34
• Multiple projects/multiple zones— Wolfcamp shale (oil & gas)— Bone Spring sands (oil)— Avalon Shale (oil window)
• 2016 Focus— Wolfcamp Long Laterals— Meeting acreage obligations
Permian Region Provides Multiple Opportunities
35
• First Lower Wolfcamp Infill• Five 10,000‐foot laterals— Testing six wells per two‐section unit— Staggered well pattern
• Flowing back
Culberson County – Tim Tam Infill Development
35
Barbaro
Prewit‐Omaha
Parent Well
Tim Tam
Forward Pass
878’878’200’
Low
er W
olfc
amp
D
36
($ in Millions) 2013 2014 2015 2016
Net income (loss) 565$ 507$ (2,409)$ (431)$
Income tax expense (benefit) 329 299 (1,373) (227)
Interest expense, net of capitalized 23 37 55 62
DD&A and ARO accretion 624 816 788 474
EBITDA 1,541 1,659 (2,939) (122)
Impairment of oil and gas properties - - 3,717 719
Adjusted EBITDA 1,541 1,659 778 597
Non‐GAAP Reconciliation
36
Reconciliation of Net Income to EBITDA and Adjusted EBITDA1
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
37
Non‐GAAP Reconciliation
37
2016 2015
Net cash provided by operating activities $ 170 $ 115 Change in operating assets
and liabilities 49 11
Adjusted cash flow from operations $ 219 $ 126
(in millions)
Three months
Ended Dec. 31,
Debt/Cap Calculation2
2016
Additions to Proved Reserves (Bcfe)
Revisions of previous estimates 19.7 Extensions & discoveries 324.0 Purchase of reserves 1
Total Additions (All sources) 344.7
Total Capital $MM 735$
F&D Costs (All sources) ($/Mcfe) 2.13$
Drilling F&D cost (extensions & discoveries) ($/Mcfe) 2.27$
Reconciliation of cash flow from operations1
Finding & development (F&D) cost
2016
Long‐term debt (principal) $ 1,500
Stockholders' Equity 2,360
Total capitalization $ 3,860
Long‐term debt/total capitalization 39%
Dec. 31,
(in millions)
Debt/Adj. EBITDA CalculationTwelve months
Ended December 31,2014 2015 2016
Long‐term debt (principal) 1,500 1,500 1,500
Adj. EBITDA 1,659 778 597Debt/Adj. EBITDA 0.9x 1.9x 2.5x
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.
2Management believes this non‐GAAP measure is useful information as it is a common statistic used in the investment community to assist with analysis of the financial condition of an entity.
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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
