new november 2017 · 2017. 11. 8. · • balanced portfolio of assets —premier position in the...

1

November 2017

2

Forward-looking Statements

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. 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]

Cimarex Energy Co.1700 Lincoln Street, Suite 3700Denver, CO 80203303-295-3995

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Who is Cimarex?

1 As of November 6, 20172 As of and for the twelve months ended 9/30/17. See Appendix for non-GAAP definitions and reconciliations to nearest comparable GAAP measure.

Market Cap1 $ 12 billion

Debt/Adj. EBITDA2 1.4x

Production (3Q 17) 1,143 MMcfe/d

Proved Reserves 2.9 Tcfe

— % Natural gas 51%

— % Proved Developed 79%

— R/P Ratio 8.2x

Quarterly Dividend $0.08/share

4

• 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

— $423 million in cash at September 30, 2017

What’s Important

4

5

• Enhanced completion design

— Improved well performance

— Allows tighter development well spacing

• Five successful spacing pilots announced in 2017

— Now prosecuting even tighter spacing tests

• 12-wells/section Upper Wolfcamp on production in Culberson

• 14-wells/section Lower Wolfcamp in Culberson drilling

• 18-wells/section Upper Wolfcamp in Reeves County drilling

• Result: infill development that preserves returns while adding locations (NPV)

Recent Achievements

5

6

Production Growth

6

Daily Production(MMcfe)

50%51%

53% 52%

55%

693

869

985 963

+18-19%1,134-1,147

0

250

500

750

1000

1250

2013 2014 2015 2016 2017E

Oil & NGL Natural Gas

• Strong returns lead to production growth

• Oil to lead 2017 volume growth

• 4Q 17 oil volume up 32 – 37% vs 4Q 16

7

D&C Capital vs. Production Growth(millions)

$1,251

$1,531

$730

$552

$900-925

11%

25%

13%

-2%

17%

2013 2014 2015 2016 2017E

D&C Capital Production Growth

2017 Capital Plans

• Estimated 2017 E&D capital ~$1.2 billion

— Up 63% from 2016 level

• Includes D&C capital of $900-925 million

— D&C is 76% of E&D capital

— Generates 18-19% production growth

• Flexibility to right size capital

— Cash on the balance sheet provides flexibility

8

Drilling & Completion Capital

2017 Drilling & Completion Capital

• $900‐925 million

• Multiple projects and zones

• Delaware Basin

— Wolfcamp delineation and infill

— Bone Spring & Avalon development

— Test of new concepts

• Mid-Continent region

— Meramec delineation and acreage retention

— Woodford spacing tests and infill

• Currently operating 14 rigs

— Nine in Permian

— Five in Mid-Continent

Woodford

Meramec

Bone Spring

Wolfcamp

Avalon

9

180 day Average Daily Production per Well (BOE/d)

638

890

1,142

1,317

1,612

-

500

1,000

1,500

2013 2014 2015 2016 2017

Productivity Improvement in the Wolfcamp

4,671 5,869 7,094 8,910 9,789Average Lateral

Length (ft)

Delaware Basin Wolfcamp wells

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BTAX IRR*

Improvement in Well Level Returns

67%

44%

130%

147%

0%

50%

100%

150%

Lower Wolfcamp Upper Wolfcamp

*Assumes flat realized oil price of $50/bbl, gas price of $2.50/mcfand NGL price of $16.67/bbl

3Q17 3Q173Q143Q14

• Focused on ways to improve returns

— Radically changed completion design

— Improved water management

— Decreased drilling days

— Significantly better well productivity

• Result: Solid returns at flat prices

• Higher well level returns equal higher fully burdened returns

Culberson Long-Lateral Wolfcamp

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Biggest Opportunity - Delaware Basin Wolfcamp

• ~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

• ~61,000 net acres

• Upper Wolfcamp

— Lea County


— Ward County


• Two wells drilled

– One well completing

2017 wells

Lower Wolfcamp

Upper Wolfcamp

Bone Spring

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Culberson/White City Area Wolfcamp Details

• 100,000+ net acres; JDA with Chevron in Culberson County

• 59 long lateral Wolfcamp

wells producing

• Seattle Slew spacing pilot

producing

• Animal Kingdom infill drilling

• Eddy County lower Wolfcamp

latest completion design

— Marquardt 12-13 Fed Com

11H has average 30-day peak

IP of 2,766 BOE/d (19% oil;

47% gas; 34% NGL)

Lower Wolfcamp

Upper Wolfcamp

Operated SWD

Marquardt2,766 BOE/d

(19% oil)

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Improving Upper Wolfcamp Completion Design

• Ten wells with new frac design

have average 30-day peak IP of

2,330 BOE/d (53% oil; 28% gas;

19% NGL)

— Five wells brought on-line in 2017 have average 30-day peak IP of 2,584 BOE/d (51% oil; 28% gas; 21% NGL)

Cumulative Production (MBOE)

0

100

200

300

400

500

600

700

0 60 120 180 240 300 360

Days

Old Completion New Completion

27% Increase

Culberson Long Lateral Upper Wolfcamp

>1,650 lb/ft

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Resilient Long Lateral Returns

14

Culberson County Wolfcamp – 10,000 ft lateral

BTAX IRR*

*Assumes full NGL recovery, NGL price is 30% of oil price

0%

50%

100%

150%

200%

250%

300%

$30 $40 $50 $60 $70

Realized Oil Price

Upper Wolfcamp - $3/Mcf Lower Wolfcamp - $3/Mcf

Upper Wolfcamp - $2/Mcf Lower Wolfcamp - $2/Mcf

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Culberson County – Tim Tam Infill Development

• Five –10,000 ft wells testing six wells per section

• Infills have surpassed parent wells in both landing zones

• Animal Kingdom infill testing 14 wells per section

— Currently drilling

— 8 wells; 3 landings


Parent Well (lower landing) Parent Well (upper landing)

Infill well (lower landing) Infill well (upper landing)

1,756’

1,756’200’

Low

er

Wolfca

mp

Tim Tam spacing

-

100

200

300

400

500

600

0 60 120 180 240 300

Days

1,216’

1,216’225’

Low

er

Wolfca

mp

Animal Kingdom spacing

225’

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Culberson County – Upper Wolfcamp Pilots

• Similar per-well results with 6, 8 or 12 wells per section

• Seattle Slew testing 12 wells per section

— Six wells

— Stack/Stagger pattern

— Early results encouraging

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Extrapolated Average Cumulative Production per 7,500-ft well (MBOE)

45%45%45% 45%

904’ 125’

Upper

Wolfca

mp

Seattle Slew spacing

0

100

200

0 60 120 180

Days

Gato average well

Sunny's average well

Seattle Slew average well

40% 42%

0

600

1,200

1,800

2,400

3,000

3,600

Sunny's Halo(8 wells/section)

Gato del Sol(6 wells/section)

Oil NGL Gas

Extrapolated 365-day Cumulative Production per 960 Acre Section (MBOE)

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Reeves County Focus Area

• Targeting Upper Wolfcamp

• 24 – 10,000 ft laterals producing

— Average 30-day peak IP of 1,728 BOE/d (49% oil; 29% gas; 22% NGL)

• Two downspacing pilots producing

— Wood State (12 wells per section)

— Pagoda State (16 wells per section)

• Snowshoe development testing 18 wells per section

— 8 wells; 3 landings

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Wood State

Snowshoe

Pagoda State

Upper Wolfcamp

Operated SWD

Snowshoe spacing880’

880’

375’

Uppe

r W

olfca

mp

190’

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Reeves County – Infill Well Results

• Upper Wolfcamp

— 10,000 ft laterals

• Wood State: 6 wells testing 12 wells per section

— Best long lateral to date sits right next door (Big Timber)

• Pagoda State: 4 wells testing 16 wells per section


0

100

200

300

400

500

600

0 30 60 90 120 150 180 210 240 270 300 330

Days

Big Timber well

Wood State parent well

Average Wood State well

Average Pagoda State well

Pagoda spacing

680’

680’

340’

Upp

er

Wolfc

am

pWood State spacing

880’

880’

340’

Uppe

r W

olfc

am

p

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Mid-Continent Overview

• Meramec and Woodford Stacked Targets

• Meramec: 116,500 net prospective acres

— 90,000 derisked

— 100% HBP by YE17

• Woodford: 136,500 net undeveloped acres (88% HBP)

Cana core

Meramec play outline

Woodford play outline

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Meramec: The Big Picture

• 45 wells producing with average lateral length of ~6,800 ft— Average 30-day IP of 1,591

BOE/d (40% oil; 40% gas; 20% NGL)

• Seven – 10,000 ft lateral wells brought on-line in 2017 YTD — Average 30-day IP of 1,996

BOE/d (46% oil, 36% gas, 18% NGL)

• Oil yield range: 11-523 bbl per MMcf

• Delineation continues

• 24 downspacing pilots on-line or underway in the play— XEC has interest or data on all

but four

5,000 ft Meramec

10,000 ft Meramec

Meramec play outline

Leon Gundy

3Q 17 Wells

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Leon Gundy Pilot Results

• Stacked/Staggered Pilot

— Four Meramec wells

• Stacked/staggered spacing

• Testing ten wells per section

— Four Woodford wells

• Testing nine wells per section

• Next step: confirm zone completion sequence

— Two tests planned

Cumulative Production MMcfe

0

500

1,000

1,500

2,000

0 90 180 270 360

Days

Average Middle Meramec well

Average Lower Meramec well

Average Parent Well

1,065’

1,065’200’

Woodford

Meramec

Osage

300’578’

Leon Gundy spacing

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Woodford Shale Activity

• Long history of activity

— Participated in 882 gross wells since 2007

• Eastern core infill wells completed

• Long lateral Leota Jacobs infill planned following results of pilots in area

• Clyde Copeland high density spacing pilot producing

• Emerging Lone Rock play yielding best results to date

Operated well

Non-operated well

Leota Jacobs

Eastern CoreClyde Copeland

Lone Rock

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Clyde Copeland Results

• Increased density pilot

— 8 wells testing 16 and 20 wells per section

• Completion design optimized for tighter well spacing

• Results positive for future well spacing

Cumulative Production MMcfe

0

100

200

300

400

500

600

700

800

0 30 60 90

Days

Average well (20 well spacing)

Average well (16 well spacing)

Average parent well (9 well spacing)

Woodford

Osage

330’

16 well spacing

80’

528’

20 well spacing

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Lone Rock Activity

• ~16,000 net contiguous acres in over-pressured Woodford

• Best Woodford returns in portfolio

• Shelly infill drilling underway

—Nine wells testing 8 and 11 well per section

Woodford

Osage

448’

8 well spacing

637’

11 well spacing

0

400

800

1,200

0 30 60 90 120 150 180

Days

1st Gen (~1,440 lb/ft)

2nd Gen (~2,800 lb/ft)

3rd Gen (~2,800 lb/ft)

Average Cumulative Production MMcfe

Shelly

Hines Federal 1H15.2 MMcfed (40% oil)

Meyers 1H13.4 MMcfed (24% oil)

Meiwes 1-25H10.4 MMcfed (15% oil)

Woodford

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• Diverse portfolio with solid returns

• Strong financial position

— $423 million of cash on the balance sheet at 9/30/17

• Technical emphasis on idea generation

— Enhancements to completion design

— Testing even tighter infill well spacing

• Ultimate field optimization that preserves returns while adding

locations (NPV)

Well-positioned for 2017 and Beyond

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Appendix

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27

2017 Guidance

Fourth Quarter Full Year

Production

Total Equivalent (MMcfe/d)Total Equivalent (BOE/D)

1,175 – 1,225195.8 – 204.2

1,134 – 1,147189.0 – 191.2

% Oil 30%

Capital Expenditures (billion) ~$1.2

Expenses $/Mcfe $/BOE

Production $0.60 – 0.70 $3.60 – 4.20

Transportation, processing & other $0.50 – 0.60 $3.00 – 3.60

DD&A and ARO accretion $1.05 – 1.15 $6.30 – 6.90

General and administrative $0.20 – 0.25 $1.20 – 1.50

Taxes other than income (% of oil and gas revenue) 5.0 – 5.5% 5.0 – 5.5%

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Hedges as of November 2, 20172017 2018 2019

Fourth Quarter

First Quarter

Second Quarter

Third Quarter

Fourth Quarter

First Quarter

Second Quarter

OIL

WTI Oil Collars1

Volume (Bbl/d) 21,000 28,000 22,000 18,000 12,000 6,000 6,000

Weighted Average Floor 46.29 47.25 47.23 46.61 48.00 48.00 48.00

Weighted Average Ceiling 56.64 56.15 55.35 54.55 54.58 55.21 55.21

WTI Swaps2

Volume (Bbl/d) 5,000 13,000 13,000 13,000 8,000 5,000 5,000

Weighted Average Differential3 0.94 0.72 0.72 0.72 0.58 0.47 0.47

GAS

PEPL Collars4

Volume (MMBtu/d) 120,000 120,000 90,000 60,000 30,000 20,000 20,000



El Paso Perm Collars5

Volume (MMBtu/d) 80,000 80,000 60,000 40,000 20,000 10,000 10,000



Total Natural Gas Collars

Volume (MMBtu/d) 200,000 200,000 150,000 100,000 50,000 30,000 30,000

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 FERC3 Index price on basis swaps is WTI NYMEX less weighted average differential shown in table

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2017 Net Wells Completed

29

26

18

30

24

43

1QA 2QA 3QA 4QE Wells Drilling &WOC at12/31/17Permian Basin Mid-Continent

30

Mid-Continent Region Production

30

Daily Production(MMcfe)

406384

350333

322

385

419

390

353375

417

509 513

0

100

200

300

400

500

Q3 14 Q4 14 Q1 15 Q2 15 Q3 15 Q4 15 Q1 16 Q2 16 Q3 16 Q4 16 Q1 17 Q2 17 Q3 17

Gas NGL Oil

31

Permian Region Production

31

Daily Production(MBOE)

68

74

81

99

94

87

80

85 86 85

96

107105

0

25

50

75

100

Q3 14 Q4 14 Q1 15 Q2 15 Q3 15 Q4 15 Q1 16 Q2 16 Q3 16 Q4 16 Q1 17 Q2 17 Q3 17

Oil NGL Gas

32

Efficiency Gains Continue in LOE

32

$0.13 $0.10 $0.08 $0.07

$0.27 $0.25

$0.22 $0.20

$0.14

$0.10

$0.05 $0.06

$0.33

$0.24

$0.19 $0.18

$0.21

$0.14

$0.12 $0.11

$1.08

$0.83

$0.66 $0.62

2014 2015 2016 2017 YTD

Compressor Rental & Repair Labor/OtherWater Disposal Repairs, Maintenance, Chemicals & RentalsWorkovers

($/Mcfe)

33

Non-GAAP Reconciliation

Reconciliation of Net Income to EBITDA and Adjusted EBITDA1

($ in Millions) 2014 2015 2016LTM

9/30/17

Net income (loss) $ 526 $(2,580) $ (409) $ 368

Income tax expense (benefit) 310 (1,472) (214) 233

Interest expense, net of 37 55 62 56

DD&A and ARO accretion 786 741 400 410

EBITDA 1,659 (3,256) (161) 1,067

Impairment of oil and gas - 4,033 758 -

Adjusted EBITDA 1,659 778 597 1,067

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

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Non-GAAP ReconciliationReconciliation of cash flow from operations1

Three months Ended Sept 30

($ in Millions) 2017 2016

Net cash provided by operating activities $ 251 $ 223

Change in operating assets and liabilities

33 (41)

Adjusted cash flow from operations $ 284 $ 182

Finding & development (F&D) cost

2016

Additions to proved reserves (Bcfe)

Revisions of previous estimates 19.8

Extensions & discoveries 324.0

Purchase of reserves 0.9

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

Debt/Cap calculation

($ in Millions)Sept 30,

2017

Long-term debt (principal) $ 1,500

Stockholders equity 2,402

Total capitalization 3,902

Long-term debt/total capitalization 38%

Debt/Adjusted EBITDA calculation

Twelve monthsEnded Dec 31, LTM

($ in Millions) 2015 2016 9/30/17

Long-term debt (principal)

$1,500 $1,500 $1,500

Adjusted EBITDA 778 597 1,067

Debt/Adjusted EBITDA

1.9x 2.5x 1.4x

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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• Sand volumes have leveled

• Focus on perf placement, number of stages, pump time, etc.

Completion Evolution

Pounds of Sand per Lateral Foot

Jul 2015

Jan 2016

Jul 2016

Jan2017

Jul2017

Culberson Upper Wolfcamp 1,650 1,650 2,500 2,500 2,500

Culberson Lower Wolfcamp 1,250 1,250 2,500 2,500 2,500

Reeves Upper Wolfcamp 1,700 1,700 2,500 2,500 2,500

Meramec 1,800 2,700 2,800 2,800 2,800

Woodford 2,500 3,000 3,500 3,500 3,200

new november 2017 · 2017. 11. 8. · • balanced portfolio of assets —premier position in the...

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