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J.P. Morgan Inaugural Energy Equity ConferenceJune 27‐29, 2016
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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……………………...…….....….$11.0B
Debt/Adj. EBITDA1……………...…………...………..2.2x
Production (1Q16)………………...……..973 MMcfe/d
Proved reserves………………...…….. 2.9 Tcfe
% Natural gas………………...……..52%
% Proved developed………………...……..75%
R/P Ratio………………...…….. 8.1x
Quarterly dividend of $0.08/share
Who is Cimarex?
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1 March 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 — $677mm in cash at March 31, 2016
What’s Important
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5
2.32.5
3.12.9
3.3
0.4
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
2012 2013 2014 2015 2015*
Oil NGL Gas
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Reserves GrowthProved Reserves(Tcfe)
*Adjusted for negative price revisions.
6
6
Production Growth
Daily Production(MMcfe)
48%51%
51%53% 53%
627693
869
985 940‐970
0
250
500
750
1,000
2012 2013 2014 2015 2016E
Oil & NGL Natural Gas
2.342.56
3.28
3.55
0
1
2
3
4
2012 2013 2014 2015
Net Debt Adjusted Production/Share(MMcfe)
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• Quarterly hedging program targets 10% of expected oil and gas volumes over next five quarters— Methodical approach
• Bias toward costless collars
—Provides downside protection
—Maintains some upside price exposure
Daily Hedged Volumes
0
30
60
90
120
0
5,000
10,000
15,000
20,000
2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17
Oil (Bbl/d)
Gas (MMcf/d)
Oil (Bbl/d) Gas (MMcf/d)
14 24 24 21 21 11 0% of 1Q16 Oil & Gas Volumes
Hedge Strategy Targets 50% of Oil & Gas Volumes
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• $650‐700mm (up $50mm from previous guidance)
• Multiple projects/multiple zones
• Delaware Basin— Acreage obligations— Upper & Lower Wolfcamp in Culberson
County— Reeves infill development
• Mid‐Continent region— Meramec delineation and acreage
retention— Continue Woodford infill
• Flexibility to right size capital
2016 E&D InvestmentDrilling & Completion Capital
$475‐$500mm
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• ~230,000 net acres in the fairway
• Multiple Wolfcamp Targets— Culberson/White City Area
• 100,000+ net acres• Upper & Lower Wolfcamp• JDA with Chevron
— Reeves County • 80,000 net acres• Upper Wolfcamp
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
• 19 long‐lateral Lower Wolfcamp wells producing
• Ten Upper Wolfcamp long laterals producing— Downspacing pilot underway
• New oil gathering in place
Culberson Area Wolfcamp Details
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• Fourteen 10,000‐foot laterals
— Average 30‐day peak IP of 2,306 BOE/d (25% oil; 46% gas; 29% NGL)
Long Lateral Performance
Cumulative Production (MBOE)
Culberson Lower Wolfcamp
0
100
200
300
400
500
600
0 60 120 180 240 300 360
Days
10,000‐ft. lateral Tim Tam
69% Increase
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Resilient Long Lateral Returns
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Culberson County Wolfcamp – 10,000‐ft. lateral
*Assumes $2.00/Mcf natural gas, 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
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• Seven 7,500‐ft. laterals
— Two with larger completion• Larger completions have 34%
production uplift (125 days)
— Avg. 30‐day peak IP of 1,879 BOE/d (51% oil; 30% gas; 19% NGL)
Improving Upper Wolfcamp Completion Design
Cumulative Production (MBOE)
Culberson County
34% Increase
0
50
100
150
200
250
0 30 60 90 120 150 180
Days
New frac (2 wells) Old frac (5 wells)
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• Three 10,000‐ft. laterals
— One with larger completion• Larger completion has 23%
production uplift (120 days)
— 30‐day peak IP of 2,139 BOE/d (52% oil; 29% gas; 19% NGL)
Improving Upper Wolfcamp Completion Design
Cumulative Production (MBOE)
Culberson County
0
50
100
150
200
250
0 30 60 90 120
Days
New frac (1 well) Old frac (2 wells)
23% Increase
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• Six‐well downspacing pilot— 7,500‐foot laterals— Stacked/staggered well
pattern• Sunny’s Halo section testing
eight wells/section• Gato del Sol testing six
wells/section• Completions begin in May• First production expected
midyear • $8.8mm well cost
Culberson County – Upper Wolfcamp Pilot
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Gato del Sol
Upp
er W
olfc
amp
Sunny’s Halo
125’
675’ 900’
Parent Well
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• First Lower Wolfcamp Infill• Five 10,000‐foot laterals— 107‐acre spacing (6 wells/section)— Staggered well pattern
• Currently drilling— Completion in 4Q
Culberson County – Tim Tam Infill Development
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Barbaro
Prewit‐Omaha
Tim Tam
Forward Pass
Parent Well
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• Targeting Upper Wolfcamp • Nine long laterals producing— Average 30‐day peak IP of 1,577
BOE/d (51% oil; 28% gas; 21% NGL)
• Best well to date— Big Timber has avg. 30‐day peak IP
of 3,309 BOE/d (49% oil; 27% gas; 24% NGL)
• First infill development now drilling— Six 10k‐ft. laterals— Stack/Stagger pattern— Meets acreage obligations
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Reeves County Activity
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• Meramec and Woodford Stacked Targets
• Meramec: 115,000 net prospective acres — 60% downdip; 40% updip— 70,000 de‐risked— Downspacing pilots underway
• Woodford: 128,000 net prospective acres (86% HBP)
Cana core
Meramec play outline
Mid‐Continent Overview
Woodford play outline
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• Long history of activity— Participated in 817 gross wells
since 2007
• Eastern core infill underway— 6 sections; 2 operated— 47 gross (22 net) wells— Currently drilling— Completions begin in October
Woodford Shale Activity
Operated WellNon‐operated Well
Cana‐Woodford Activity Map
Row 4 Infill
Eastern Core Infill
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Woodford: Consistent Results Across Acreage
0
400
800
1,200
1,600
2,000
2,400
0 60 120 180 240 300 360
Days
Golden (8 infill wells)Hartz (8 infill wells)Haley (8 infill wells)Phillips/Armacost (11/9 infill wells)
Cumulative Production (MMcfe)
2.1 2.1 2.2
Golden Hartz Haley
Gas NGL Oil
First Year Cumulative Production (Bcfe)
Row 4 Infill
Eastern Core Infill
Golden Haley
Hartz
Phillips, Armacost
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• 18 5,000‐ft laterals have avg. 30‐day peak IP of 8.3 MMcfe/d
• Three10,000‐ft laterals with avg. 30‐day peak IP of 13.6 MMcfe/d— Product mix averages 44% gas;
33% oil; 23% NGL— Oil yield ranges from 11‐486 bbl/
MMcfe
• Downspacing pilots underway
Cana core
Meramec play outline
5,000‐ft. Meramec well
10,000‐ft. Meramec well
Meramec: The Big Picture
Woodford play outline
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• 62% uplift after 120 days• Three 10,000‐ft laterals have
30‐day peak IP of 13.6 MMcfe/d — 45% gas, 32% oil, 23% NGL — Oil yields range from 37 to 278
Bbl/MMcf
• 18‐ 5,000‐ft laterals have 30‐day peak IP of 8.3 MMcfe/d
— 43% gas, 23% NGL, 34% oil
— Oil yields range from 11‐486 Bbl/MMcf
Meramec Long Lateral Performance
Cumulative Production (MMCFE)
0
200
400
600
800
1,000
1,200
1,400
0 60 120
Days
Average 10,000‐ft lateral (3 wells)
Average 5,000‐ft lateral (18 wells)
62% Increase
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• Stacked/Staggered Pilot— Eight total wells; two rigs working— Four Meramec wells
• Stacked/staggered spacing• Testing 10 wells per section
— Four Woodford wells• Testing 9 wells per section
— Completions in 2H16
• Partner‐operated downspacing pilot— Testing 5 wells per section— Wells are flowing
Meramec Spacing Pilots
Osage
Woodford
Meramec
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• Diverse asset portfolio with solid returns
• Strong financial position
— Investment grade rating with stable outlook at both S&P and Moody’s
• Flexibility to adapt to commodity environment
• Emphasis on improved productivity
• Focus on retaining our attractive acreage position
Well‐positioned for 2016 and Beyond
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Appendix
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2016 Guidance
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2016 Production, Unit Expense and Capital Guidance
Second Quarter Full‐YearProductionTotal Equivalent (Mmcfe/d) 935‐965 940‐970
% Liquids 52% 53%
Capital Expenditures $650‐$700 million
Expenses ($/Mcfe): Remainder of '16Production $0.80 ‐ $0.90Transportation, processing & other 0.45 ‐ 0.55DD&A and ARO accretion* 1.30 ‐ 1.50General and administrative 0.19 ‐ 0.23Taxes other than income (% of oil and gas revenue) 5.5 ‐ 6.0%
*Excludes the potential impact of any future ceiling test write‐downs
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Hedges
(1) WTI refers to West Texas Intermediate oil prices as quoted on the New York Mercantile Exchange.(2) PEPL refers to Panhandle Eastern Pipe Line Tex/OK Mid‐Continent. El Paso Perm is El Paso Permian Basin index; both as quoted in
Platt’s Inside FERC.
2016 2017
Second Third Fourth First Second Third Fourth
Oil: Quarter Quarter Quarter Total Quarter Quarter Quarter Quarter Total
WTI Oil Collars (1)
Volume (Bbl/d) 4,000 9,000 9,000 5,519 9,000 9,000 5,000 ‐ 5,723 Wtd Avg Floor Purchased (put) 35.00$ 39.17$ 39.17$ 38.42$ 39.17$ 39.17$ 42.50$ ‐$ 39.90$ Wtd Avg Ceiling Sold (call) 42.50$ 47.92$ 47.92$ 46.94$ 47.92$ 47.92$ 52.26$ ‐$ 48.88$
WTI Oil Three‐Way Collars (1)
Volume (Bbl/d) 3,000 3,000 3,000 3,000 ‐ ‐ ‐ ‐ ‐ Wtd Avg Floor Sold (put) 40.00$ 40.00$ 40.00$ 40.00$ ‐$ ‐$ ‐$ ‐$ ‐$ Wtd Avg Floor Purchased (put) 50.00$ 50.00$ 50.00$ 50.00$ ‐$ ‐$ ‐$ ‐$ ‐$ Wtd Avg Ceiling Sold (call) 60.00$ 60.00$ 60.00$ 60.00$ ‐$ ‐$ ‐$ ‐$ ‐$
2016 2017
Second Third Fourth First Second Third Fourth
Gas: Quarter Quarter Quarter Total Quarter Quarter Quarter Quarter Total
PEPL Collars (2)
Volume (MMBtu/d) 30,000 60,000 60,000 40,109 50,000 50,000 30,000 ‐ 32,356 Wtd Avg Floor 2.32$ 2.28$ 2.28$ 2.32$ 2.20$ 2.20$ 2.25$ ‐$ 2.21$ Wtd Avg Ceiling 2.75$ 2.82$ 2.82$ 2.81$ 2.82$ 2.82$ 2.90$ ‐$ 2.84$
El Paso Perm Collars (2)
Volume (MMBtu/d) 33,297 50,000 50,000 38,388 50,000 50,000 20,000 ‐ 29,836 Wtd Avg Floor 2.45$ 2.37$ 2.37$ 2.44$ 2.37$ 2.37$ 2.30$ ‐$ 2.36$ Wtd Avg Ceiling 2.90$ 2.89$ 2.89$ 2.92$ 2.95$ 2.95$ 2.93$ ‐$ 2.95$
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229 216 217
226
255
310
406
384
350 333
322
385
419
‐
50
100
150
200
250
300
350
400
450
Q1 13 Q2 13 Q3 13 Q4 13 Q1 14 Q2 14 Q3 14 Q4 14 Q1 15 Q2 15 Q3 15 Q4 15 Q1 16
Gas NGL Oil
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MMcfe/day
Cana Area Production
Row 4 Drilling Commenced
Row 4 Completions Began
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29
Permian Basin Production
46
53
59 55
58
6568
74
81
9994
87
80
‐
10
20
30
40
50
60
70
80
90
100
Q1 13 Q2 13 Q3 13 Q4 13 Q1 14 Q2 14 Q3 14 Q4 14 Q1 15 Q2 15 Q3 15 Q4 15 Q1 16
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)
• 2016 Focus— Wolfcamp Long Laterals— Meeting acreage obligations
Permian Region Provides Multiple Opportunities
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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
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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 Lower Wolfcamp 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
1,500
2,500
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 average1,250 1,095
‐
400
800
1,200
1,600
Lower Wolfcamp Upper Wolfcamp
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
35
Non‐GAAP Reconciliation
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($ in Millions) 2013 2014 2015 LTM
Net income (loss) 565$ 507$ (2,409)$ (2,180)$
Income tax expense (benefit) 329 299 (1,373) (1,251)
Interest expense, net of capitalized 23 37 55 59
DD&A and ARO accretion 624 816 788 700
EBITDA 1,541 1,659 (2,939) (2,672)
Impairment of oil and gas properties - - 3,717 3,343
Adjusted EBITDA 1,541 1,659 778 671
Reconciliation of Net Income to EBITDA and Adjusted EBITDA
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Non‐GAAP Reconciliation
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2016 2015
Net cash provided by operating activities $ 85 $ 113
Change in operating assets
and liabilities (3) 74
Adjusted cash flow from operations $ 82 $ 187
(in millions)
Three months
Ended March 31,
Debt/Cap Calculation
2015
Proved Reserves adds (Bcfe)
Revisions of previous estimates (276.2)
Extensions & discoveries [C] 428.7
Purchase of reserves -
Total adds [A] 152.5
Total capital $MM [B] 877$
All-sources F&D ($/Mcfe) [B]/[A] 5.75$
Drilling (excl. revisions) F&D ($/Mcfe) [B]/[C] 2.05$
Reconciliation of cash flow from operations
Finding & development (F&D) cost
2016
Long-term debt (principal) $ 1,500
Stockholders' Equity 2,614
Total capitalization $ 4,114
Long-term debt/total capitalization 36%
March 31,
(in millions)
Debt/Adj. EBITDA Calculation
Twelve months
Ended December 31, LTM
2014 2015 3/31/2016
Long-term debt (principal) 1,500 1,500 1,500
Adj. EBITDA 1,659 778 671
Debt/Adj. EBITDA 0.9x 1.9x 2.2x