jack stark- president · 2018. 6. 1. · • optimized completions • drilling efficiencies •...

PROPERTY OF CONTINENTAL RESOURCES, INC. REPRODUCTION ONLY WITH WRITTEN PERMISSIONPROPERTY OF CONTINENTAL RESOURCES, INC. REPRODUCTION ONLY WITH WRITTEN PERMISSION

The Bakken… America’s Quality Oil Play!

2018 WBPC | Bismarck, ND - May 22-24

Jack Stark- President


Forward-Looking Information

2

Cautionary Statement for the Purpose of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995 This presentation includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements included in this presentation other than statements of historical fact, including, but not limited to, forecasts or expectations regarding the Company’s business and statements or information concerning the Company’s future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, rates of return, budgets, costs, business strategy, objectives, and cash flows, are forward-looking statements. When used in this presentation, the words “could,” “may,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “budget,” “plan,” “continue,” “potential,” “guidance,” “strategy,” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.

Forward-looking statements are based on the Company’s current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company’s control. No assurance can be given that such expectations will be correct or achieved or the assumptions are accurate. The risks and uncertainties include, but are not limited to, commodity price volatility; the geographic concentration of our operations; financial, market and economic volatility; the inability to access needed capital; the risks and potential liabilities inherent in crude oil and natural gas exploration, drilling and production and the availability of insurance to cover any losses resulting therefrom; difficulties in estimating proved reserves and other revenue-based measures; declines in the values of our crude oil and natural gas properties resulting in impairment charges; our ability to replace proved reserves and sustain production; the availability or cost of equipment and oilfield services; leasehold terms expiring on undeveloped acreage before production can be established; our ability to project future production, achieve targeted results in drilling and well operations and predict the amount and timing of development expenditures; the availability and cost of transportation, processing and refining facilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing; increased market and industry competition, including from alternative fuels and other energy sources; and the other risks described under Part I, Item 1A Risk Factors and elsewhere in the Company’s Annual Report on Form 10-K for the year ended December 31, 2016, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time.

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this presentation occur, or should underlying assumptions prove incorrect, the Company’s actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. Except as expressly stated above or otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this presentation, or otherwise.

Readers are cautioned that initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels. In particular, production from horizontal drilling in shale oil and natural gas resource plays and tight natural gas plays that are stimulated with extensive pressure fracturing are typically characterized by significant early declines in production rates.

We use the term "EUR" or "estimated ultimate recovery" to describe potentially recoverable oil and natural gas hydrocarbon quantities. We include these estimates to demonstrate what we believe to be the potential for future drilling and production on our properties. These estimates are by their nature much more speculative than estimates of proved reserves and require substantial capital spending to implement recovery. Actual locations drilled and quantities that may be ultimately recovered from our properties will differ substantially. EUR data included herein remain subject to change as more well data is analyzed.

PROPERTY OF CONTINENTAL RESOURCES, INC. REPRODUCTION ONLY WITH WRITTEN PERMISSIONPROPERTY OF CONTINENTAL RESOURCES, INC. REPRODUCTION ONLY WITH WRITTEN PERMISSION 3

CLR: #1 Producer and #1 Leasehold Owner in the Bakken

Source: NDIC/ Select peers include WLL, HES, COP, EOG, OAS, XOM, WPX, STL, MRO.

• 1,650 Bakken well Completed to Date• 4,000+ Bakken wells in Inventory• 800,000 net acres• 6 Drilling Rigs • 8 Stim Crews• ~ 56% of CLR Production Q1 2018

0

0.5

1

1.5

2

2.5

3

3.5

4

4.5

5

MM

Bo

CLR

Gross Monthly Production(January 2018)

CLR 2018 D&C Budget: $2.0 Billion

Bakken$1.2 Billion60%

40%

CLR Partner with North Dakota

~ 13% of ND Production


0%

20%

40%

60%

80%

100%

120%

140%

160%

180%

200%

$50 $60 $70 $80

RO

R

WTI Oil Price, $/BBL

430 MBOE Model

603 MBOE Model

800 MBOE Model

980 MBOE Model

1,100 MBOE Model (2018 $7.9MM)

CLR Bakken Returns Have Never Been Better

4

165% ROR(1) from 1.1 MMboe Type Curve • 7 month Payout

• $15MM+ PV10 per well

• 80% oil

• $26/BO PV-10 Break even

Driven By Ingenuity and Technology• Optimized completions

• Drilling Efficiencies

• Infrastructure Improvements

Rocks Did Not Change!

1. ROR, PV-10 & payout are based on $70 WTI and $3.00 gas

Evolution of EUR and ROR for CLR Bakken Wells

2018 165% ROR

20112014

2015

2017


0

200

400

600

800

1,000

1,200

0

10

20

30

40

50

60

2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

LBS/FT

# STAGES

EUR MBOE TC

It’s All About Connecting with the Rock!

5

Based on 2 mile lateral

# ST

AGES

LBS/FT &

EUR

Mboe

1.1MMboe

800 Mboe

603 Mboe

430 Mboe

279 Mboe

PERF SPACING

FLUID X-LINK GEL HYBRID / SLICKWATER

3%-5% 15%-20%More Stimulated Rock VolumeRECOVERY FACTOR

CLR’s Growing EUR and Recoveries

180’ 30’

980 Mboe


CLR Drilling Efficiencies Drive Cycle Times Down

6

33.0 21.7 18.6 17.4 16.4 14.3 11.3

7

11

1415

1921

24

0

5

10

15

20

25

30

0

5

10

15

20

25

30

35

2011 2012 2013 2014 2015 2016 2017

WELL C

OU

NT

DAY

S

SPUD to TD WELLS per RIG YEAR

832 1,150 1,333 1,495 1,903 2,402 3,154

$506

$438$390

$367

$293

$223$193

0

100

200

300

400

500

600

0

500

1000

1500

2000

2500

3000

3500

2011 2012 2013 2014 2015 2016 2017

CO

STFT

LATERAL FT per DAY COST per LATERAL FT

Driven by technology: Multi-well pads │ Super “Spec” rigs │ Motor technology │ Bit advancements │ Rotary steerable systems │ Geo-steering technology │ Improved geologic targeting

Spud to TD 3X Faster vs 2011 4X Feet per Day in Lateral vs 2011


$4.8$4.2

$3.6 $3.4 $3.0$2.5 $2.0 $2.2

$5.3$5.4

$4.9

$6.6

$6.4

$4.2$4.7

$4.8

$0.8$0.8

$10.1$9.6

$8.5

$10.1$9.4

$6.7

$7.5$7.9

$0

$2

$4

$6

$8

$10

$12

2011 2012 2013 2014 2015 2016 2017 2018

Bak

ken

CW

C ($

MM

)

LIFT CMP DRL

CLR Bakken Well Costs Decrease as Performance Increases

7

ACCELERATED LIFT


1524

39

5057

66

117

136

0

20

40

60

80

100

120

140

160

16Q3 16Q4 17Q1 17Q2 17Q3 17Q4 18Q1 18Q2

Wel

ls

Accelerated Lift – Bringing Bakken Value Forward

8

CLR Bakken Wells on ESP by Quarter

0

100,000

200,000

300,000

400,000

0 1 2 3 4 5 6 7 8 9 10 11 12

Cum

. Flu

id (B

bls)

Months Producing

~3X Total Fluid in 1st Year(1)

0

50,000

100,000

150,000

200,000

0 1 2 3 4 5 6 7 8 9 10 11 12

Cum

. Oil

(Bbl

s)

Months Producing

~3X Oil in 1st Year(1)

2017 2014

2017 2014

+ 122 MBO / 1 YR

+ 239 MBbls / 1 YR

(1) CLR Operated Wells


Source: IHS and Internal Reporting

9

Step Change in Well Performance Rapidly Expanding Across the Bakken Field- Industry Wide

2000 - 2014 15 Years

2015 - 20173 Years

Wells or units with wells >100Mboe in 90 DaysApproximate Bakken Field Outline

Industry-Wide Bakken Wells or Units that Produced Over 100,000 Boe in 90 Days

100 mi


CLR Crude Differentials Improved 65% since 2014

10

No Longer “Disadvantage Crude”

• Netbacks increased $7.52/bbl since 2014

• Growing Infrastructure brings better pricing• DAPL• Renegotiated Contracts

• Catalyst for exporting Bakken Crude• CLR has exported almost 2MM barrels of Bakken

Crude to Asia and UK• Other opportunities being evaluated• Bakken quality ideal for European and Asian

refineries

RAI

LPI

PE

($11.83)

($9.21)

($8.26)

($6.14)

($4.31)

($14)

($12)

($10)

($8)

($6)

($4)

($2)

$02014 2015 2016 2017 1Q'18

$ /B

arre

l

Bakken Oil Differential to WTI


Bakken Quality Shines Through

11

Bakken100% of Reservoir in Oil Window

80% Oil

Low Water Cut (Avg. <50%)

Consistent API Crude

Permian Multi-Phase Reservoir (Oil/Condensate/Gas)

~65% Oil (Avg.)

High Water Cut (Avg. ~70%)

Variable API Crude


Bakken 100% in Oil Window

12

Oil Window

Oil WindowCondensate WindowGas Window

MMBOPD & BCFD

MMBOPD & BCFDPermian

Horizontal wells

Bakken

Permian

Bakken

1.2 MMBOPD 2.0 BCFD (YE 2017)

2.0 MMBOPD 6.1 BCFD(YE 2017)

Source: IHS


Bakken Low Water Cut

13

Bakken HZ Production52% Oil Cut

Permian HZ Production32% Oil Cut

MMBbls / Daily MMBbls / Daily

WATER

WATER

1.2 MMBOPD 1.1 MMBWPD

(YE 2017)

2.0 MMBOPD 4.3 MMBWPD

(YE 2017)

Source: IHS


Superior Production from The Bakken

14

Source: JRCO Research, Drilling Info and CLR

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

Reeves Midland CLR Bakken

Cum

ulat

ive

Oil

Prod

uctio

n

2 Most Active Counties in Permian

First 6 Months Cumulative Oil Production 2017

Source: JRCO Research May 2018


Bakken Consistent High Quality Crude

15

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

90,000

100,000

20 30 40 50 60

Peak

Mon

thly

Oil

Prod

uctio

n Pe

r Wel

l (bb

l)

API Gravity

Permian Bakken

Wells reported over last 2 years (DrillingInfo)

Source: DrillingInfo


Early Stage Demands on Bakken Infrastructure Behind Us

16

Permian – 15,000 mi2463 Active Rigs

Bakken – 14,000 mi257 Active Rigs

Max Rig Count – 229 (June 2012)

150

Mile

s150 Miles

Delaware Basin6,700 mi2

Midland Basin8,300 mi2

Bakken Play

Active Rigs

Source: NDIC, IHS, Baker Hughes

150 Miles


0

100

200

300

400

500

600

0

300

600

900

1,200

1,500

1,800

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

70 Rigs

17

North Dakota Actual and Projected Crude Oil Growth

ND Production (Mbopd)

Monthly Completions

ND Rigs

Source: NDIC, IHS, and CLR estimates

Projected Growth

600

Rig

s / M

onth

ly C

ompl

etio

ns

500

400

300

200

100

0

1,800

ND

Production(M

bopd)

1,500

1,200

900

600

300

0


Bakken Infrastructure Expanding to Keep up with Growth

18

-

500

1,000

1,500

2,000

2,500

3,000

3,500

2009 2011 2013 2015 2017 2019E

Local Refining PipelineRail Bakken ProductionForecasted Production (50 Rigs) Forecasted Production (60 Rigs)

Thou

sand

Bop

d

RAI

LPI

PECrude Oil Takeaway Capacity

BPD

NDIC NGL Takeaway Projection

Source: North Dakota Pipeline Authority and CLR estimates


Bakken800,000 net acres

SCOOP/STACK1,100,000 net acres

1.9 Million Net Reservoir Acres (~70% HBP

(1))

1. Acreage numbers and HBP numbers are approximate as of 1Q18.

19

2018: Breakout Year For CLRDelivering Sustainable, Cash-Flow Positive Growth

0

50,000

100,000

150,000

200,000

250,000

300,000

350,000

2010 2011 2012 2013 2014 2015 2016 2017 2018E

STACK

SCOOP

Bakken

Legacy

242,637

Annu

al P

rodu

ctio

n B

oe p

er D

ay

285,000-300,000

2018 Breakout year for CLR

• $2.3 Billion CAPEX

• 17-24% Production Growth

• ~$1Billion free cash flow

• Investment grade status

jack stark- president · 2018. 6. 1. · • optimized completions • drilling efficiencies •...

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