enercom’s the oil and gas conference...actual results may differ materially from company...
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ENERCOM’S THE OIL AND GAS CONFERENCEAugust 2020
2FORWARD-LOOKING STATEMENTS
Forward-looking Statements
Contact:
Karen AciernoVice President – Investor Relations
This 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. SecuritiesExchange 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 factorsis included in the Company’s periodic reports filed with the U.S. Securities and Exchange Commission.
Actual results may differ materially from company projections and other forward-looking statements and can be affected by a variety of factors outside the control of the company includingamong other things: oil, NGL and natural gas price levels and volatility, including those resulting from demand destruction from the COVID-19 pandemic; disruptions to the availability ofworkers and contractors due to illness and stay at home orders related to the COVID-19 pandemic; disruptions to gathering, pipeline, refining, transportation and other midstream anddownstream activities due to the COVID-19 pandemic; disruptions to supply chains and availability of critical equipment and supplies, including as a result of the COVID-19 pandemic; theeffectiveness of controls over financial reporting; declines in the values of our oil and gas properties resulting in impairments; impairments of goodwill; higher than expected costs andexpenses, including the availability and cost of services and materials, which may be negatively impacted by the COVID-19 pandemic; our ability to successfully integrate the March 2019acquisition of Resolute Energy Corporation; compliance with environmental and other regulations; costs and availability of third party facilities for gathering, processing, refining andtransportation; risks associated with concentration of operations in one major geographic area; environmental liabilities; the ability to receive drilling and other permits and rights-of-way in atimely manner, which may be negatively impacted by COVID-19 restrictions on regulatory personnel who process and approve those matters; development drilling and testing results; thepotential for production decline rates to be greater than expected; performance of acquired properties and newly drilled wells; regulatory approvals, including regulatory restrictions onfederal lands which may be negatively impacted by a change in administration; legislative or regulatory changes, including initiatives related to hydraulic fracturing, emissions and disposal ofproduced water, which may be negatively impacted by a change in administration; unexpected future capital expenditures; economic and competitive conditions; the availability and cost ofcapital; the ability to obtain industry partners to jointly explore certain prospects, and the willingness and ability of those partners to meet capital obligations when requested; changes inestimates of proved reserves; derivative and hedging activities; the success of the company's risk management activities; title to properties; litigation; the ability to complete property sales orother transactions; and other factors discussed in the company's reports filed with the SEC. Cimarex Energy Co. encourages readers to consider the risks and uncertainties associated withprojections and other forward-looking statements. In addition, the company assumes no obligation to publicly revise or update any forward-looking statements based on future events orcircumstances.
3CIMAREX ENERGY: PILLARS OF SUCCESSFUL STRATEGY
Cimarex Energy: Pillars of Successful Strategy
PLANNING
EXPLORATION
ENVIRONMENT
COST CONTROL
DIGITAL INNOVATION
4OPERATIONAL HIGHLIGHTS
Operational Highlights
FLARING UPDATE
GENERATED CASH FROM OPERATING ACTIVITIES OF $145MM
$26MM OF FREE CASH FLOW AFTER DIVIDEND
OIL PRODUCTION OF 78.0 MBBLS/D
TOTAL PRODUCTION OF 254.7 MBOE/D
12 NET WELLS BROUGHTON PRODUCTION IN 2Q, 11 IN THE PERMIAN BASIN
GO FORWARD AVERAGE PERMIAN WELL COSTS OF $800–900 PER FOOT
8.08 7.89 6.92$6.00
$7.00
$8.00
$9.00
2Q19A 3Q19A 4Q19A 1Q20A 2Q20A
TOTAL COMPANY CASH OPERATING COSTS DOWN 14% FROM 2Q19 AND DOWN 12% SEQUENTIALLY
Cash operating costs include: LOE, Workover, Transportation, Production Tax, G&A
PE
R B
OE
2020 PERMIANFLARING INTENSITY
TARGET: 1.44%STRETCH: 0.96%
YTD: 1.08%
2Q UPDATES
Flaring Intensity = Flared Gas Volumes (Mcf)/Gross Permian Gas Production (Mcf)
5ADJUSTING TO THE CHANGING ENVIRONMENT
Adjusting to the Changing Environment
EMPLOYEE HEALTH & SAFETY
• Multi-disciplinary approach to COVID-19 pandemic
COVID-19 Task Force
Return to Office Task Force
• Field protocols in place
• 50% of office staff continue to work from home
• Following CDC guidelines to implement phased return to office
RESPONSE
• Focused on Free Cash Flow
• Reduced capital investment
• Curtailed May production; brought back on line in June
• Measured return to activity
Adding three rigs in 3Q and restarting completions in September
• Improved efficiencies
Lower well costs and LOE
OIL PRICES HAVE IMPROVED, HEADWINDS REMAIN
6RESUMING ACTIVITY IN 3Q
Resuming Activity in 3Q
ADDING ONE DRILLING RIG PER MONTH AND TWO COMPLETION CREWS IN SEPTEMBER
Jul
Aug
Sep
20
10
46
1Q20A 2Q20A 3Q20E 4Q20E IN PROGRESS AT12/31/20
NE
T W
EL
L C
OU
NT
PERMIAN BASIN ANADARKO BASIN
BROUGHT 12.5 NET WELLS ON PRODUCTION IN 2Q
EXPECT TO BRING 43 NET WELLS ON PRODUCTION IN 2020
• 46 wells in progress at year end 2020
NET WELLS ON PRODUCTION
12.5
$ MILLION 1QA 2QA YTDUPDATED 2020E
GUIDANCE
DRILLING & COMPLETION (D&C)1 $ 214 $ 49 $ 263 $ ~ 430
MIDSTREAM/SWD 27 - 27 ~ 40
OTHER2 33 35 68 ~ 130
TOTAL CAPITAL INVESTMENT $ 274 $ 84 $ 358 $ ~ 600
7CAPITAL INVESTMENT UPDATE
Capital Investment Update
1 Includes well facilities, flow back and outside operated wells2 Capitalized overhead, production capital, land and technology
Updated 2020 Delaware Basin Plans
0
2,000
4,000
6,000
8,000
10,000
CU
LB
ER
SO
N
ED
DY
RE
EV
ES
LE
A
8UPDATED 2020 DELAWARE BASIN PLANS
REEVES
CULBERSON
LEA
EDDY
WELLS ON LINE BY COUNTY
40NET WELLS
WOLFCAMP
BONE SPRING
$415 MM
D&CCAPITAL
AVERAGE LATERAL LENGTH BY COUNTY
BASIN AVERAGE: 9,000
2020 DEVELOPMENTS ON LINE
PROJECT NAME WELLS % WI ON LINE
1 ELECTRIC STATE 5 100 1Q
2 CARRY BACK 2 80 1Q
3 RIVERBEND 5 86 1Q
4 VACA DRAW 6 50 1Q
5 GOAT 7 96 2Q
6 HIS EMINENCE 5 50 2Q
7 DIXIELAND 7 97 4Q20E
DEVELOPMENTS IN PROGRESS 12/31/20
8 RED HILLS 6 57 1Q21E
9 CRAWFORD 4 100 1Q21E
10 BIG SKY STATE 6 100 1Q21E
11 BURGOO KING 7 50 2Q21E
12 TIM TAM 6 50 2Q21E
13 NORTH TABLE 4 100 2Q21E
14 COUNT FLEET 7 50 2Q21E
15 DOS EQUIS 4 59 2Q21E
16 CAPPLETON 7 93 3Q21E
17 SNOWSHOE 5 100 3Q21E
18 SPECTACULAR BID 8 50 3Q21E
19 TAR HEEL 8 100 4Q21E
9DELAWARE BASIN 2020 – DEVELOPMENT UPDATE
Delaware Basin 2020 – Development Update
34
2
5
6
1
NEW MEXICO
TEXAS
CURRENTLY OPERATING THREE DRILLINGS RIGS
12
9
8
11
7
14
CIMAREX ACREAGE
WOLFCAMP
BONE SPRING
AVALON
FEDERAL ACREAGE
16
19
13
17 10
15
18
10DELAWARE BASIN ACREAGE
Delaware Basin AcreageNEW MEXICO
TEXAS
FEDERAL ACREAGE
238,000 NET ACRES WITH THREE MAJOR PLAYS• 33% federal acreage, all in New Mexico
DEVELOPMENT PLANS INCLUDE ~5,000 FEDERAL ACRES THROUGH 2023• 46 wells planned through 2023
~28% OF 2020 D&C CAPITAL INVESTMENT ON FEDERAL ACREAGE
CIMAREX ACREAGE
WOLFCAMP
BONE SPRING
AVALON
FEDERAL ACREAGE
FEDERAL PERMITS FOR WELLS ON RIG SCHEDULE
PERMIT STATUS THROUGH 2023
APPROVED 32
IN PROGRESS 14
*Includes 16 wells which require extension before spud date
*
11PERMIAN REGION WELL COST IMPROVEMENTS
Permian Region Well Cost ImprovementsWELL COST PER COMPLETED LATERAL FOOT (OPERATED)
$1,479
$1,106
$-
$200
$400
$600
$800
$1,000
$1,200
$1,400
$1,600
2018A 2019A 2020E
$/C
OM
PL
ET
ED
LA
TE
RA
L F
EE
T
$900 – 1,000
515,000 FEET 708,000 FEET 426,000 FEET
67 NET WELLSCOMPLETED
76 NET WELLSCOMPLETED
49 NET WELLS1
LATERAL FEET COMPLETED
TOTAL CAPITAL ASSOCIATED WITH COMPLETED WELLS2
=WELL COST PER LATERAL FOOT
2020 WELL COSTS TRENDING BELOW EXPECTATIONS
GO FORWARD WELL COSTS:
• Culberson: $750-800 per foot
• Reeves: $800-850 per foot
• Lea: $900-1,000 per foot
PERMIAN PROGRAM AVERAGE OF $800-900 PER FOOT
1Wells completed, but not necessarily on line in 20202Total capital includes D&C, facilities and flow back associated with wells completed in the period
$ PER COMPLETED LATERAL FOOT
55 W
EL
LS
81 56 451 17 254 9 247 34 51 36 360 11 188 9 176 22 43 28 272 9 119 8 114 17 23 19 177 3 74 5 64 0
50
100
150
200
250
300
350
400
450
XEC OTHER XEC OTHER XEC OTHER XEC OTHER
6 MONTHS 12 MONTHS 18 MONTHS 24 MONTHS
12DELAWARE BASIN WELL PERFORMANCE – XEC VS OTHER OPERATORS
Delaware Basin Well Performance – XEC vs Other Operators
DELAWARE BASIN CUMULATIVE OIL PRODUCTION BY COUNTY(>8,500 LL, First Prod >2016, Upper Wolfcamp & Bone Spring Formations)
CU
MU
LA
TIV
E O
IL (
MB
BL
S)
CULBERSON REEVES LEA EDDY
13CULBERSON COUNTY STANDS OUT
Culberson County Stands Out
$750-800 PER LATERAL FOOT – OUR LOWEST DRILLING COST IN THE DELAWARE BASIN
LOW PRODUCTION EXPENSE• Culberson: $1.85 per Boe • Total Permian: $3.10 per Boe
OWN AND OPERATE SALTWATER DISPOSAL (SWD)• Allows water reuse through XEC engineered risers• Avoids surface storage of produced water• Reduces need for fresh water
RISER: XEC-ENGINEERED ACCESS FOR WATER REUSE
XEC ACREAGE
INFRASTRUCTURE
OPERATED SWD
SWD INFRASTRUCTURE WOLFCAMP FRAC WATER
32%
87%
97%
94%
100%
2016 2017 2018 2019 1H20
RECYCLED PURCHASED
WA
TE
R S
OU
RC
ED
(M
BB
LS
)
14MID-CONTINENT
Mid-Continent
326,000 NET ACRES
WOODFORD: 135,625 NET UNDEVELOPED ACRES (HBP)
MERAMEC: 116,500 NET ACRES (>98% HBP)
FOCUSING ON HIGH QUALITY INVENTORY SUBSET, LOWERING COSTS AND A RISING COMMODITY ENVIRONMENT TRANSLATES INTO STRONG ECONOMICS
OKLAHOMA
CIMAREX ACREAGE
MERAMEC OUTLINE
WOODFORD OUTLINE
LONEROCK
13-8 AREA
15LONG-TERM STRATEGY, NEAR-TERM PRIORITIES
Long-Term Strategy, Near-Term Priorities
Return on and of capital
Capital discipline andasset optimization
Focused execution
STRATEGY PRIORITIES
Employee health and safety
Free cash flow generation and balance sheet strength
Returning capital to shareholdersthrough our dividend
Financial strength
16FREE CASH FLOW OUTLOOK STRONG
Free Cash Flow Outlook Strong
1Assuming current strip prices for the balance of the year2$35 WTI, $2.50 Henry Hub, 45% NGL of WTI
2020
PROJECTING $150-200MM1 OF FCF AFTER THE DIVIDEND
• Production expected to decline into 4Q20, before modest growth in December
• 2H20 activity ramp will drive meaningful 1H21 oil growth
2021-20242021
ASSUMING SIMILAR CAPITAL YEAR-OVER-YEAR:
• Excess FCF after the dividend at $35 WTI2
• Oil volumes flat to slightly up year-over-year
• Grow dividend
• Strengthen balance sheet
• 2021 capital plans to be determined
TARGETS INCLUDE:
• Excess FCF after the dividend at $35 WTI2; flat to single digit oil production growth
• Annual dividend increase
• Generate FCF to retire notes in 2024
• Debt/EBITDA <1.0x
17STRONG BALANCE SHEET, CONSERVATIVE FINANCIAL POSITION
Strong Balance Sheet, Conservative Financial Position
INVESTMENT GRADE RATED
NO NEAR-TERM DEBT MATURITIES
$1.3 BILLION OF LIQUIDITY, INCLUDING $44 MILLION OF CASH (6/30/2020)
EXPECT NO ADDITIONAL BORROWINGS IN 2020
AMPLE LIQUIDITY, NO NEAR-TERM DEBT MATURITIES
CASH CREDIT FACILITY DEBT
XEC DEBT/TTM EBITDA
$0
$200
$400
$600
$800
$1,000
$1,200
$1,400
LIQUIDITY6/30/20
2024 2027 2029
$ M
ILL
ION
S
DEBT MATURITIES
0.0x
0.5x
1.0x
1.5x
2.0x
2017A 2018A 2019A 1Q20A 2Q20A
CREATING VALUEAND GENERATINGTOP-TIER RETURNS
PROVENTRACK
RECORD
18CIMAREX ENERGY OVERVIEW
Cimarex Energy Overview
PREMIER PORTFOLIO
CORE POSITIONS INTHE PERMIAN ANDANADARKO BASINS
ENDURINGCULTURE
MAXIMIZING FULL-CYCLE RETURN ON INVESTED CAPITAL
STRONGFINANCIALPOSITION
LIQUIDITY PROVIDES FLEXIBILITY
19APPENDIX
APPENDIX
20RESUMING 2020 GUIDANCE
Resuming 2020 Guidance3Q20E 2020E
Production (MBOE/d) 230 – 250 240 – 250
Oil Production (MBbls/d) 69 – 74 75 – 78
Capital Expenditures ($ Million)
D&C ~ $430
Midstream & Saltwater Disposal (SWD) ~ 40
Other ~ 130
Total Capital ~ $600
Expenses ($/BOE)
Production $2.90 – 3.30
Transportation, processing & other $2.10 – 2.40
DD&A and ARO accretion $7.40 – 7.90
General and administrative $0.95 – 1.15
Taxes other than income (% of oil and gas revenue) 6.0% – 8.0%
21HEDGES AS OF AUGUST 5, 2020
Hedges as of August 5, 2020
Notes:1 WTI refers to West Texas Intermediate oil prices as quoted on the New York Mercantile Exchange2 Index price on basis swaps is WTI Midland as quoted by Argus Americas Crude 3 Index price on basis swaps is WTI NYMEX less weighted average differential shown in table
4 PEPL refers to Panhandle Eastern Pipe Line Tex/OK Mid-Continent as quoted on Platt’s Inside FERC5 El Paso Perm refers to El Paso Permian Basin index as quoted on Platt’s Inside FERC6 Waha refers to West Texas Natural Gas Index (“Waha”) as quoted in Platt’s Inside FERC
2020 2021 2022OIL 3Q 4Q 1Q 2Q 3Q 4Q 1Q
WTI OIL COLLARS1
Volume (Bbl/d) 41,000 41,000 40,000 30,000 21,000 21,000 7,000
Weighted Average Floor 40.91 40.91 38.06 34.23 31.48 31.48 35.00
Weighted Average Ceiling 49.84 49.84 46.45 42.25 39.67 39.67 45.28
WTI OIL BASIS SWAPS2
Volume (Bbl/d) 32,000 32,000 31,000 25,000 20,000 20,000 7,000Weighted Average Differential3 0.18 0.18 0.03 (0.10) (0.38) (0.38) 0.11
WTI OIL ROLL DIFFERENTIAL SWAPS1
Volume (Bbl/d) - - 7,000 7,000 7,000 7,000 7,000Weighted Average Price - - (0.24) (0.24) (0.24) (0.24) (0.24)
GAS 3Q 4Q 1Q 2Q 3Q 4Q 1Q
PEPL GAS COLLARS4
Volume (MMBtu/d) 100,000 100,000 100,000 90,000 70,000 70,000 40,000
Weighted Average Floor 1.78 1.78 1.83 1.83 1.88 1.88 2.00
Weighted Average Ceiling 2.21 2.21 2.23 2.22 2.29 2.29 2.40
EL PASO PERM GAS COLLARS5
Volume (MMBtu/d) 70,000 70,000 70,000 70,000 50,000 50,000 20,000
Weighted Average Floor 1.36 1.36 1.50 1.50 1.64 1.64 1.85
Weighted Average Ceiling 1.64 1.64 1.79 1.79 1.95 1.95 2.18
WAHA GAS COLLARS6
Volume (MMBtu/d) 70,000 70,000 90,000 90,000 70,000 70,000 40,000
Weighted Average Floor 1.43 1.43 1.52 1.52 1.65 1.65 1.77
Weighted Average Ceiling 1.73 1.73 1.83 1.83 1.98 1.98 2.15
22PERMIAN BASIN TAKEAWAY
Permian Basin Takeaway
OIL TRANSPORT AND SALES AGREEMENTS IN PLACE• ~89% of oil production on pipe• Strategic partnerships in core producing areas provide
strong flow assurance• Oil sales arrangements with credit worthy counterparties
GAS SALES AGREEMENTS IN PLACE• 97% of remaining 2020 production has been sold forward• Local pricing• Committed 125,000 MMBtu per day to Whistler Pipeline
Project; 10 year firm commitment, provides access to Gulf Coast pricing, expected online 3Q21
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
CIMAREX ACREAGE
ENERGY TRANSFER PIPELINE
EAGLECLAW
OFFLOADING SITE
PLAINS PIPELINE
23PERMIAN BASIN WATER MANAGEMENT
Permian Basin Water Management
OWN AND OPERATE SALT WATER DISPOSAL (SWD) SYSTEMS IN CULBERSON, EDDY AND REEVES • Improves operating costs
RECYCLING PRODUCED WATER FOR COMPLETION OPERATIONS• 63% of total water procured in 2019 was recycled• Cost savings of ~$0.65/bbl of water
IN 2019 – CULBERSON WOLFCAMP WELLS USED 94% RECYCLED WATER FOR COMPLETIONS; REEVES WOLFCAMP WELLS USED 25%
SECURED SWD AGREEMENTS IN LEA COUNTY
24NON-GAAP RECONCILIATION
Non-GAAP Reconciliation($ MILLIONS) 2017 2018 2019 LTM
6/30/20
Net income (loss) $ 494 $ 792 $ (125) $ (1,960)
Income tax expense (benefit) 188 231 (26) (357)
Interest expense, net of capitalized 52 47 37 38
DD&A and ARO accretion 462 598 891 899
EBITDA 1,196 1,668 777 (1,380)
Impairment of oil and gas — — 619 1,894
Impairment of goodwill — — — 714
ADJUSTED EBITDA1 1,196 1,668 1,396 1,228
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
THREE MONTHS ENDEDJUNE 30,
($ MILLIONS) 2020 2019
Net cash provided by operating activities $ 145 $ 414
Change in operating assets and liabilities - (78)
Adjusted cash flow from operations2 145 336
Oil and gas expenditures (153) (379)
Other capital expenditures (12) (22)
Change in capital accruals 69 61
Free cash flow 49 (4)
Dividends paid (24) (21)
Free cash flow after dividend $ 26 $ (25)
TWELVE MONTHS ENDEDDECEMBER 31, LTM
($ MILLIONS) 2017 2018 2019 6/30/20
Long-term debt (principal) $1,500 $1,500 $2,000 $2,000
Adjusted EBITDA 1,196 1,668 1,396 1,228
Debt/Adjusted EBITDA 1.3x 0.9x 1.4x 1.6x
2019
ADDITIONS TO PROVED RESERVES (MMBOE)
Revisions of previous estimates (50.7)
Extensions & discoveries 119.3
Purchase of reserves 63.0
TOTAL ADDITIONS (ALL SOURCES) 131.6
2Management uses the non-GAAP financial measures of adjusted cash flow from operations, free cash flow and free cash flow after dividend as means of measuring our ability to fund our capital program and dividends, without fluctuations caused by changes in current assets and liabilities, which are included in the GAAP measure of net cash provided by operating activities. Management believes these non-GAAP financial measures provide useful information to investors for the same reason, and that they are also used by professional research analysts in providing investment recommendations pertaining to companies in the oil and gas exploration and production industry.