35
CORPORATE PRESENTATION Barclays 2018 CEO Energy-Power Conference
CORPORATEPRESENTATION
Barclays
2018 CEO Energy-Power Conference
2
Forward-looking Statements
This presentation contains projections andother forward-looking statements within themeaning of Section 27A of the U.S.Securities Act of 1933 and Section 21E of theU.S. Securities Exchange Act of 1934.These projections and statements reflect theCompany’s current views with respect tofuture events and financial performance. Noassurances can be given, however, thatthese events will occur or that theseprojections will be achieved, and actualresults could differ materially from thoseprojected as a result of certain factors. Adiscussion of these factors is included in theCompany’s periodic reports filed with theU.S. Securities and Exchange Commission.
Contact:
Karen AciernoDirector – Investor [email protected]
Cimarex Energy Co.1700 Lincoln Street, Suite 3700Denver, CO 80203303-295-3995
3
Cimarex Energy SnapshotNYSE symbol: XEC
Market Cap1: $8.1 billion
Enterprise Value1: $9.6 billion
Debt/EBITDA2: 1.1x
Annual Dividend3: $0.72 (0.8% yield)
Daily Production: 211 MBOE
‒ 61,651 barrels of oil per day
2018E Capex: $1.6-$1.7 billion
2018E Production Growth: 14%-18%
Ward County Sale Closed 8/31/18 for $544.5 million
1 As of August 30, 20182 As of and for the twelve months ended 6/30/18. See Appendix for non-GAAP definitions and reconciliations to nearest comparable GAAP measure.3 Annualized yield of announced 3Q18 dividend
4
Cimarex Energy Overview
• Maximizing full-cycle return on invested capitalEnduring Culture
• Creating value, generating top-tier returnsProven Track Record
• Core positions in the Permian and Anadarko BasinsPremier Portfolio
• Trailing 10-year average CROCE: 30%• 10-year production growth CAGR: 11%
Profitable Growth
• Low leverage and liquidity provides opportunitiesStrong
Financial Position
5
The Culture of Cimarex
Maximize Full-Cycle Returns
Idea GenerationDriven by Rigorous
Technical Evaluation
Acreage Concentration
Creating Economies of Scale, Economic Gains
Inventory Expansion
Product of Innovation, and ExplorationFocused
ExecutionDelineation and
Development Focused on Maximizing NPV, IRR
Financial Discipline
Strong Returns Result in Cash Flow Growth, Liquidity, Optionality
Lookback Evaluation
Improves Economic Returns, Operational
Efficiencies
6
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
Drilling &Completion
Midstream SWD Overhead Land -$1,500/acre
% of Fully-Burdened Investment ATAX IRR
Maximizing Fully-Burdened Returns
2017 XEC project, includes 36 gross wells.
Flat oil & natural gas realized prices of $55.00/$2.00
Half-Cycle Fully-Burdened
Cimarex culture built on maximizing fully burdened after-tax rate of return on investment
Rigorous technical evaluation of all aspects of E&D to improve economic return
Pre-drill and post-drill lookback evaluation of expected to actual results
+ + + +
7
History of Outsized Returns
Cash Return on Capital Employed (CROCE)XEC vs S&P 500 E&P Peers
0%
10%
20%
30%
40%
50%
2008 2009 2010 2011 2012 2013 2014 2015 2016 2017
XEC Peer Avg.***
8
XEC Generating Top-Tier Returns
Source: Stifel estimatesE&P estimates based on Stifel estimates, S&P 500 estimates based on consensusCROCE = (CFFO + Interest (1-tax))/ (Avg Capital Employed)
2018 Cash Return on Capital Employed (CROCE)XEC vs S&P 500
0%
5%
10%
15%
20%
25%
30%
CRO
CE (
%) Average
9
Delaware Basin – Overview
259,000 total net acres
70% of 2018 D&C Budget
Stacked pay opportunities provides multi-zone development opportunities– Upper and Lower Wolfcamp
– Second and Third Bone Spring
– Avalon
WolfcampBonesprinAvalon
WolfcampBone SpringAvalon
10
0
500
1,000
1,500
2,000
Gen 1 Gen 2 Gen 3 Gen 4
Oil (b/d)
49 –10,000-ft. lateral Upper Wolfcamp wells drilled in Permian Basin 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
Well Productivity ImprovementsLong Lateral Upper Wolfcamp Wells(Culberson and Reeves Counties)
Completion GenerationIP180 (BOE/d)
11
Sales agreements in place for oil volumes through 2019
Strategic partnerships in core areas– Pipelines in place– Purchase obligations– Midland index pricing
~70% of oil production on pipe; increasing to >80% by YE18
Permian Basin – Oil Takeaway
Plains pipelinePlains pipeline (under construction)Energy Transfer pipelineOffloading Site
12
Sales agreements in place– 98% of forecasted production through December 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 outlets– Long-term sales agreements in place for NGL volumes
Permian Basin – Residue Gas Takeaway
13
Delaware Basin – Culberson/White City
Low er WolfcampUpper WolfcampOperated SWD
Owl Draw 122,521 BOE/d (1,393 b/d)
Charismatic 53,271 BOE/d(1,882 b/d)
Carry Back 6 State A 1H
Currently Flowing Back
100,000+ net acres, JDA with Chevron in Culberson 30% of 2018 D&C capital Targeting Upper and Lower
Wolfcamp, Bone Spring Western delineation
continues to unlock value– Five well average: 30-day
IP of 2,724 Boe/d (56% oil) Animal Kingdom: (WOC)
Lower Wolfcamp– 8 wells testing 14
wells/section
1,216’
1,216’225’
Low
er W
olfc
amp
Animal Kingdom spacing
225’
14
Resilient Long Lateral ReturnsCulberson Long Lateral Wolfcamp
0%
100%
200%
300%
400%
$30 $40 $50 $60 $70Realized 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
15
Delaware Basin – Reeves County
59,400 net acres 20% of 2018 D&C capital Targeting Upper Wolfcamp Wood State: 12 well/section
– Development wells 28% above parent wells
Pagoda State: 16 wells/section– Development wells 16% above
parent wells
Snowshoe: 18 wells/section– 8 wells test flowing back
Wood StateSnowshoe
Pagoda State
Upper WolfcampOperated SWD
Dixieland State 55-62,505 BOE/d (1,464 b/d)
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Delaware Basin – Lea County
31,400 net acres 12% of 2018 D&C capital Targeting Upper Wolfcamp,
Avalon, Bone Spring Hallertau (Upper Wolfcamp)
– Confirms 12 wells/section Tristie Draw (Avalon)
– 6 wells testing 20 wells/section, completing
Red Hills
Red Tank
Triste Draw
Upper WolfcampAvalonBone Spring
Hallertau Infill4,200’ Avg Lateral
6 Well Avg1,295 BOE/d (783 b/d)
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Mid-Continent – Overview
326,000 net acres 30% of 2018 D&C capital Woodford: 136,500 net
undeveloped acres– Participated in >950 wells
(>325 operated) since 2007 Meramec: 116,500 net acres
– Improving results driving activity
14N-10W area: formulating Woodford-Meramec co-development plans– Operate 90% of ~24,000
gross acres, 60% WI– Successfully tested 19
wells/section (Leon Gundy)
Cana Core
14N10W
Lone Rock
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Mid-Continent – Meramec
116,500 net acres, – 100% HBP
15% of 2018 D&C capital 40 industry development
pilots active, XEC has interest or data in 31 2018 Developments
– Steve O: 6 wells on 8 well spacing (flowing back)
– Lehman: 4 wells on 6 well spacing
– Miss Mary: 3 wells on 8 well spacing
5,000 ft Meramec10,000 ft MeramecMeramec play outline
Dupree BIA 1H1 Mile
2,877 BOE/d (1,597 b/d)
Rocky 1-17H1 Mile
1,912 BOE/d (1,282 b/d)
14N-10W
Mike Com 1H2 Mile
4,353 BOE/d (433 b/d)
Gresham Com 1H 2 Mile
5,813 BOE/d (484 b/d)
Steve OLehman
Miss Mary
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Mid-Continent – Woodford
136,500 net undeveloped acres 16% of 2018 D&C capital Lone Rock (16,000 net acres)
yielding best Woodford results to date, completion optimization driving results– Shelly: 5 wells testing 8 and 12
wells per section (flowing back)– JD Hoppinscotch: 4 wells on 8
well spacing (flowing back)
14N-10W area: formulating development plans
Lone Rock
14N 10W
Shelly JD Hoppinscotch
Operated wellNon-operated well
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Cash Operating Margin ExpansionDeclining LOE and Increasing Realized Prices Driving Margin Expansion
Cash operating costs include: LOE, Transportation, Production Tax, G&A
Realized prices exclude hedge gain/loss
$0
$5
$10
$15
$20
$25
$30
$35
0%
10%
20%
30%
40%
50%
60%
70%
1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18
$/Bo
e O
PEX
& M
argi
n
Mar
gin
%
Cash Operating Costs Margin Margin %
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2018 Program Overview
Production - MBOE/d
Net Wells Online – 2018E
*Pro forma excludes Ward County volumes
Capital Program ($mm)E&D Capital $1,600 - $1,700D&C Capital $1,300 - $1,400Midstream/Other $80 - $90
D&C as % of E&D
PermianMid-Continent
2018E
70%30%
82%
Produciton GuidanceTotal Production (MBOE/d) 214 - 221Oil Production (MBO/d) 66.0 - 68.0
2018E
Pro Forma* Y/Y GrowthTotal Production 14% - 18%Oil Production 20% - 25%
2018E
206 211 211242
190218
1QA 2QA 3QE 4QE 2017A 2018EOil
206-215 214-221
1QA 2QA 3QE 4QE Drilling orWOC at
YE18Mid-Continent Permian
49
1523
37 38
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Disciplined Financial Positioning• $1.4 billion of liquidity, including $411mm of cash (2Q18)Significant
Liquidity
• 1.1x Debt/TTM EBITDA (2Q18)Conservative Leverage
• $750 million 3.900% senior unsecured notes due in 2027• $750 million 4.375% senior unsecured notes due in 2024
Investment Grade Debt
0.0x
0.5x
1.0x
1.5x
2.0x
2.5x
3.0x
3.5x
4.0x
2010 2011 2012 2013 2014 2015 2016 2017 2Q18
Deb
t/TTM
EB
ITDA
Debt/EBTIDA Average Debt/TTM EBITDA
XEC Debt/EBITDA
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Positioned for Success
• Maximizing full-cycle return on invested capital• Idea driven, technical emphasis
Enduring Culture
• Generating strong returns• Decades of top-tier inventory
Premier Portfolio
• 2018 Oil Production Growth: 20%-25%Profitable Growth
• Low leverage and liquidity provides opportunitiesStrong
Financial Position
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Appendix
25
2018 Guidance
3Q18E FY18E
Production (MBOE/d) 206 - 215 214-221
Oil Production (Bbls/d) 61,500 – 64,500 66,000 – 68,000
Capital Expenditures ($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 $1.15 – 1.45
Taxes other than income (% of oil and gas revenue) 5.75 – 6.25%
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Hedges as of August 3, 20182018 2019
ThirdQuarter
Fourth Quarter
First Quarter
Second Quarter
ThirdQuarter
Fourth Quarter
OILWTI Oil Collars1
Volume (Bbl/d) 35,000 29,000 23,000 23,000 16,000 8,000Weighted Average Floor 49.80 51.03 51.83 51.83 53.50 57.00Weighted Average Ceiling 60.49 61.74 63.77 63.77 67.13 68.04
WTI Midland Swaps2
Volume (Bbl/d) 27,000 22,000 19,000 19,000 14,000 6,000Weighted Average Differential (3.89) (4.56) (5.17) (5.17) (6.84) (10.73)
GASPEPL Collars3
Volume (MMBtu/d) 130,000 100,000 90,000 90,000 60,000 30,000Weighted Average Floor 2.19 2.12 2.08 2.08 1.92 1.90Weighted Average Ceiling 2.48 2.42 2.39 2.39 2.26 2.33
El Paso Perm Collars3
Volume (MMBtu/d) 100,000 80,000 70,000 70,000 50,000 20,000Weighted Average Floor 1.92 1.81 1.73 1.73 1.50 1.35Weighted Average Ceiling 2.14 2.03 1.95 1.95 1.74 1.55
Waha Collars3
Volume (MMBtu/d) 10,000 10,000 10,000 10,000 10,000 10,000Weighted Average Floor 1.35 1.35 1.35 1.35 1.35 1.35Weighted Average Ceiling 1.56 1.56 1.56 1.56 1.56 1.56
Total Natural Gas CollarsVolume (MMBtu/d) 240,000 190,000 170,000 170,000 120,000 60,000
1 WTI refers to West Texas Intermediate oil prices as quoted on the New York Mercantile Exchange.2 Index price on basis swaps is WTI NYMEX less the weighted average WTI Midland differential, as quoted by Argus Americas Crude. 3 PEPL refers to Panhandle Eastern Pipe Line Tex/OK Mid-Continent Index, El Paso Perm refers to El Paso Permian Basin Index, and Waha refers to West Texas (Waha) Index, all as quoted on Platt’s Inside FERC.
27
190206
211 206-215214-221
2017A 1QA 2QA 3QE 4QE 2018E
Oil
15
23
49
3738
1QA 2QA 3QE 4QE WellsDrilling orWOC at12/31/18
Permian Mid-Continent
2018 Production GrowthDaily Production(MBOE)
Net Wells Online
28
Permian Region ProductionDaily Production(MBOE)
81
9994
8780
85 86 85
96
107 105
112 114
122
0
25
50
75
100
125
1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18
Oil NGL Natural Gas
29
Mid-Continent Region ProductionDaily Production(MBOE)
7470
68
7782
77
7174
8185 85
8891
89
0
25
50
75
1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18
Oil NGL Natural Gas
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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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Growth Sensitivities Highlight Asset Quality and Depth
From 2019-2021 (at $55/$2.00 realized), XEC can grow production 10% per year and generate $500-600mm of cumulative free cash flow**
**Free cash flow is defined as cash provided by operating activities less D&C capital, capitalized overhead, production and midstream capital and dividends. It excludes proceeds from announced asset sale.
2019-2021Cumulative Free Cash
Sensitivities BOE Oil Flow ($mm) CROCEMaintenance Case 700 Flat FlatGrowth Sensitivity 1,200 10% 13% $500-$600 30%
Production Growth (3-Yr CAGR)Capex
($mm)
32
Culberson Lower Wolfcamp - Animal Kingdom– Eight wells testing 14 wells per section– Waiting on completion
Red Hills (Lea) Upper Wolfcamp - Hallertau– Six wells testing 12 wells per section– Producing
Reeves Upper Wolfcamp - Snowshoe– Eight wells testing 18 wells per section– Currently completing
Red Tank (Lea) Avalon - Triste Draw– Six wells testing 20 wells per section– Waiting on completion
Permian Basin Development Pilot Details
1,216’
1,216’225’
Low
er W
olfc
amp
Animal Kingdom spacing
225’
Snowshoe spacing880’
880’
375’
Upp
er W
olfc
amp
190’
500’
380’
Ava
lon
Triste Draw spacing
Hallertau spacing880’
Upp
er W
olfc
amp
50’
225’
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Non-GAAP ReconciliationReconciliation of Net Income to EBITDA and Adjusted EBITDA1
($ in Millions) 2015 2016 2017LTM
6/30/18
Net income (loss) $ (2,580) $ (409) $ 494 $ 593
Income tax expense (benefit) (1,472) (214) 188 150
Interest expense, net of capitalized 55 62 52 47
DD&A and ARO accretion 741 400 462 535
EBITDA (3,256) (161) 1,196 1,325
Impairment of oil and gas 4,033 758 — —
Adjusted EBITDA 778 597 1,196 1,325
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 2017LTM
6/30/18
Basic shares outstanding (in 000s) 95,124 95,437 95,393Debt adjusted shares outstanding
YE Debt, net 847,124 1,099,466 1,089,177TTM stock price 115.07 114.00 104.42
Equivalent shares issued using TTM stock price 7,362 9,644 10,431
Debt adjusted shares using TTM stock price 102,485 105,082 105,824
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Non-GAAP ReconciliationReconciliation of cash flow from operations1 Debt/Cap calculation
Six Months Ended June 30, ($ in Millions)
Jun 30, 2018
($ in Millions) 2017 2018Long-term debt (principal) 1,500
Net cash provided by operating activities $ 505 $ 704 Stockholders equity 2,886
Change in operating assets and liabilities 40 12 Total capitalization 4,386
Adjusted cash flow from operations $ 545 $ 717 Long-term debt/total capitalization 34%
Finding & development (F&D) cost2017
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
Total Capital ($MM) $ 1,281
F&D Costs (all sources) ($/BOE) $ 8.71
Drilling F&D cost (extensions & discoveries) ($/BOE) $ 8.17
Debt/Adjusted EBITDA calculationTwelve months Ended Dec 31 LTM
($ in Millions) 2016 2017 6/30/18
Long-term debt (principal) $1,500 $1,500 $1,500
Adjusted EBITDA 597 1,196 1,325
Debt/Adjusted EBITDA 2.5x 1.3x 1.1x
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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Non-GAAP ReconciliationCash Return on Capital Employed (CROCE)
Cash Flow from Operating Activities+ After-tax Interest ExpenseAverage Book Equity + Average Debt
2008 2009 2010 2011 2012 2013 2014 2015 2016 2017
Cash flow from operating activities 1,367 675 1,130 1,292 1,193 1,324 1,619 726 626 1,097Effective Tax Rate 37% 36% 37% 37% 37% 37% 37% 36% 34% 28%
Stockholder's equity 2,349 2,038 2,610 3,131 3,390 3,834 4,332 2,458 2,043 2,568Debt 591 393 350 405 750 924 1,500 1,500 1,500 1,500Capitalization 2,941 2,431 2,960 3,536 4,140 4,758 5,832 3,958 3,543 4,068
Interest expense 33 40 37 36 49 55 73 86 83 75Capitalized int (22) (23) (29) (29) (35) (32) (36) (31) (21) (23)Net interest exp 11 17 8 7 14 23 37 55 62 52
CROCE 41% 26% 42% 40% 31% 30% 31% 16% 18% 30%
