chesapeake 2018 dug conference dug conference.pdf · 2018 dug haynesville conference 4 (1) net...

CHESAPEAKE – 2018 DUG CONFERENCE

Shreveport, Louisiana

February 21, 2018

FORWARD-LOOKING STATEMENTS

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. Forward-looking statements are statements other than statements of historical fact. They include statements that give our current expectations, guidance or forecasts of

future events, production and well connection forecasts, estimates of operating costs, anticipated capital and operational efficiencies, planned development drilling and expected

drilling cost reductions, general and administrative expenses, capital expenditures, the timing of anticipated asset sales and proceeds to be received therefrom, projected cash

flow and liquidity, our ability to enhance our cash flow and financial flexibility, plans and objectives for future operations, and the assumptions on which such statements are

based. Although we believe the expectations and forecasts reflected in the forward-looking statements are reasonable, we can give no assurance they will prove to have been

correct. They can be affected by inaccurate or changed assumptions or by known or unknown risks and uncertainties.

Factors that could cause actual results to differ materially from expected results include those described under “Risk Factors” in Item 1A of our annual report on Form 10-K and

any updates to those factors set forth in Chesapeake’s subsequent quarterly reports on Form 10-Q or current reports on Form 8-K (available at http://www.chk.com/investors/

sec-filings). These risk factors include: the volatility of oil, natural gas and NGL prices; the limitations our level of indebtedness may have on our financial flexibility; our inability

to access the capital markets on favorable terms; the availability of cash flows from operations and other funds to finance reserve replacement costs or satisfy our debt

obligations; our credit rating requiring us to post more collateral under certain commercial arrangements; write-downs of our oil and natural gas asset carrying values due to low

commodity prices; our ability to replace reserves and sustain production; uncertainties inherent in estimating quantities of oil, natural gas and NGL reserves and projecting

future rates of production and the amount and timing of development expenditures; our ability to generate profits or achieve targeted results in drilling and well operations;

leasehold terms expiring before production can be established; commodity derivative activities resulting in lower prices real ized on oil, natural gas and NGL sales; the need to

secure derivative liabilities and the inability of counterparties to satisfy their obligations; adverse developments or losses from pending or future litigation and regulatory

proceedings, including royalty claims; charges incurred in response to market conditions and in connection with our ongoing actions to reduce financial leverage and complexity;

drilling and operating risks and resulting liabilities; effects of environmental protection laws and regulation on our business; legislative and regulatory initiatives further regulating

hydraulic fracturing; our need to secure adequate supplies of water for our drilling operations and to dispose of or recycle the water used; impacts of potential legislative and

regulatory actions addressing climate change; federal and state tax proposals affecting our industry; potential OTC derivatives regulation limiting our ability to hedge against

commodity price fluctuations; competition in the oil and gas exploration and production industry; a deterioration in general economic, business or industry conditions; negative

public perceptions of our industry; limited control over properties we do not operate; pipeline and gathering system capacity constraints and transportation interruptions; terrorist

activities and/or cyber-attacks adversely impacting our operations; potential challenges by SSE’s former creditors of our spin-off of in connection with SSE’s recently completed

bankruptcy under Chapter 11 of the U.S. Bankruptcy Code; an interruption in operations at our headquarters due to a catastrophic event; the continuation of suspended

dividend payments on our common stock; the effectiveness of our remediation plan for a material weakness; certain anti-takeover provisions that affect shareholder rights; and

our inability to increase or maintain our liquidity through debt repurchases, capital exchanges, asset sales, joint ventures, farmouts or other means.

In addition, disclosures concerning the estimated contribution of derivative contracts to our future results of operations are based upon market information as of a specific date.

These market prices are subject to significant volatility. Our production forecasts are also dependent upon many assumptions, including estimates of production decline rates

from existing wells and the outcome of future drilling activity. Expected asset sales may not be completed in the time frame anticipated or at all. We caution you not to place

undue reliance on our forward-looking statements, which speak only as of the date of this presentation, and we undertake no obligation to update any of the information

provided in this presentation, except as required by applicable law. In addition, this presentation contains time-sensitive information that reflects management’s best judgment

only as of the date of this presentation.

We use certain terms in this presentation such as “Resource Potential,” “Net Reserves” and similar terms that the SEC’s guide lines strictly prohibit us from including in filings

with the SEC. These terms include reserves with substantially less certainty, and no discount or other adjustment is included in the presentation of such reserve numbers. U.S.

investors are urged to consider closely the disclosure in our Form 10-K for the year ended December 31, 2016, File No. 1-13726 and in our other filings with the SEC, available

from us at 6100 North Western Avenue, Oklahoma City, Oklahoma 73118. These forms can also be obtained from the SEC by calling 1-800-SEC-0330.

22018 DUG HAYNESVILLE CONFERENCE

STRATEGIC GOALS

Debt reduction

of $2 – $3 billionultimate goal of net debt

to EBITDA of 2X

Free cash flow neutrality

Margin enhancement

2

3

1

OUR STRATEGY AND GOALS

Our strategy remains unchanged –

resilient to commodity price volatility

> Financial discipline

> Profitable and efficient growth

from captured resources

> Exploration

> Business development

2018 DUG HAYNESVILLE CONFERENCE 3


(1) Net acreage estimates as of December 31, 2017 and proforma for announced Mid-Continent asset divestitures; 2018 estimated average rig count; PV10 breakeven with oil held flat at $55/bbl and gas held flat at $3/mcf

APPALACHIA NORTH

1 rig

~$1.60 – 2.20/mcf Breakeven

Acreage ~577,000 (86% Held)

MID-CONTINENT

~1 rig

~$30 – 40/bbl Breakeven


SOUTH TEXAS

~4 rigs



GULF COAST

3 rigs



ROCKIES

~3 rigs


Acreage ~369,000 (55% Held) APPALACHIA SOUTH

2 rigs


Acreage ~2,275,000 (87% Held)

~4.7 millionNet acres

~13,300Undrilled locations

PREMIER, DIVERSIFIED ASSET BASE(1)

Recompleted SRLT as first

Haynesville horizontal

3/2007

PXP JV for $1.6 billion in cash

and $1.6 billion in carries

2008

Revamp engineering design

Prop-a-geddon – 50mm pounds of sand

8/2016


HAYNESVILLE TIMELINE

Discovery

SRLT 29-1 in Caddo Parish, LA

9/2006

Large scale land acquisition started

2008

10,000' lateral execution

becoming standard

2017

Activity reduces to three rigs

from high of 38 rigs

2012 – 2014

Bossier, refrac, 15,000' lateral

appraisal programs

2017 – 2018

LA

HAYNESVILLE: WHAT’S EVERYONE SAYING?

• “The Haynesville – It’s better than you think” – Heikkinen, Feb. 2017

• “Is Haynesville About to Make a Comeback?” – Oilprice.com, March 2017

• “IT’S BACK – The Haynesville is back!” – IHS, June 2017

• “An Old Fracking Hot Spot Makes a Comeback” – WSJ, October 2017

˃ “The Haynesville Shale in Louisiana is being reborn, with the number of active drilling rigs tripling in the past year.”

• “While still somewhat of an unknown in the outlook for natural gas supply,

the Haynesville Shale has come back to life over the past 18 months.”

– Wolfe Research Jan 2018


THE HAYNESVILLE HEATS UP INDUSTRY DRILLING ACTIVITY

• Drilling activity has increased

over three-fold

˃ 9/9/2016: 14

˃ 2/9/2018: 49

• De Soto and Red River

parishes lead the activity

Source: Baker Hughes


0

10

20

30

40

50

60

Baker Hughes Weekly Rig Count

LA

GULF COAST – HAYNESVILLEASSET OVERVIEW

• Acreage position is 100% HBP, 25%

developed – ideal for long lateral

development

• Completions breakthrough is scalable

across entire acreage position

• Unlocking the Bossier

• Ample takeaway capacity to markets

with favorable pricing


LA

A HAYNESVILLE RENAISSANCEGROSS PRODUCTION AND RIG COUNT


0

5

10

15

20

25

30

35

40

0

500,000

1,000,000

1,500,000

2,000,000

2,500,000

01/2008 01/2009 01/2010 01/2011 01/2012 01/2013 01/2014 01/2015 01/2016 01/2017

Rig

Co

un

t

Gro

ss

Op

era

ted

Pro

du

cti

on

(M

cf/

d)

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 Rig Count

Appraisal

Program

HBP

Acreage

Decreased

Activity

Core

Development

Technological

Breakthrough

LA

CHESAPEAKE OWNS THE HAYNESVILLETECHNOLOGY AND INNOVATION CREATE DIFFERENTIAL PERFORMANCE


0

2

4

6

8

10

12

14

16

18

20

0

200,000

400,000

600,000

800,000

1,000,000

1,200,000

1,400,000

01/2014 01/2015 01/2016 01/2017

Rig

Co

un

t

Gro

ss O

pera

ted

Pro

du

cti

on

(m

cf/

d)

Core Development

Technological BreakthroughReservoir modeling, longer laterals, enhanced completions

Rig Count

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

~30% growth – three-rig program over two years

Decreased

Activity

0

5

10

15

20

25

30

Ave

rag

e I

P3

0

(MM

CF

/D)

02468

101214161820

2Q

201

7

1Q

201

7

4Q

201

6

3Q

201

6

2Q

201

6

1Q

201

6

4Q

201

5

3Q

201

5

2Q

201

5

1Q

201

5

4Q

201

4

3Q

201

4

2Q

201

4

1Q

201

4

4Q

201

3

3Q

201

3

2Q

201

3

1Q

201

3

4Q

201

2

3Q

201

2

2Q

201

2

1Q

201

2

4Q

201

1

3Q

201

1

2Q

201

1

1Q

201

1

4Q

201

0

3Q

201

0

2Q

201

0

1Q

201

0

4Q

200

9

3Q

200

9

2Q

200

9

1Q

200

9

4Q

200

8

3Q

200

8

2Q

200

8

1Q

200

8

Ave

rag

e E

UR

(B

CF

)

0

1

2

3

4

5

6

7

8

Ave

rag

e 1

-Ye

ar

Pro

du

cti

on

(B

CF

)WELL PERFORMANCE EVOLUTION KICKS OFF REVOLUTION


Appraisal HBP AcreageCore

Development

• 2014 – 2017 continuous

improvement

˃ Core area focus

˃ Longer laterals

˃ Completion enhancements

˃ Optimized initial flow rates

• IP30s increased by ~75%

• First year production

increased by ~100%

• EURs increased by ~140%

• Contacting more rock volume

Technological

Breakthrough

LA

Present Day

OLD CORE VS. NEW CORE


Chesapeake retained acreage after planned divestitures

Pre-2016

PKY 1H25 mmcf/d; 10,000' lateral; 4,000 lbs./ft.

CA 1H38 mmcf/d; 10,000' lateral;

3,000 lbs./ft. proppant

PCK 1H31 mmcf/d; 7,000' lateral;

2,700 lbs./ft. proppant

NABORS 2H & 3HQ4 5,200' lateral;

3,000 & 5,000 lbs./ ft.

Completion designs increase field-wide productivity to unprecedented levels

LA

6 712

21 24

42

29

44

132 136

'08 '09 '10 '11 '12 '13 '14 '15 '16 '17E

Annualized Gas Rate per Rig (mmcf/d/rig)

~200% improvementIn production delivered per rig line

from 2015 to 2017

Continued executionProductivity projected to increase due

to faster drilling, longer laterals and

next-generation completions

D&C PERFORMANCE & COST


(1) Drilling cost is based off wells rig release date

(2) Completion cost based off wells that were completed in the given year

LA

$0

$600

$1,200

2013 2014 2015 2016 2017

Drilling Cost per Lateral Foot (1)

$0

$500

$1,000

2013 2014 2015 2016 2017

Completions Cost per Lateral Foot (2)

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

0 2 4 6 8 10 12 14

Av

era

ge C

um

ula

tiv

e G

as p

er

Well (

bcf)

Month

Average Cumulative Gas per Well

‘08 – ‘09

‘10 – ‘13

‘14 – ‘15

‘16

‘17

HAYNESVILLECOMPETITIVE ADVANTAGE


2008 – 2013

HBP Position

2014 – 2015

Develop Core Position2016

Longer Laterals,

Enhanced Completions,

Increased IP’s

2017

Area Specific Completions,

Improved Capital Efficiency,

Optimized Drawdown

14

LA

Gulf Coast Acreage 401,000 (90% Held)

HAYNESVILLEPARADIGM SHIFT


Two pads, 134 mmcf/dBSNR 1H – 37 mmcf/d w/ 9,800' LL

BSNR 2H – 32 mmcf/d w/ 9,800' LL

BSNR 3H – 35 mmcf/d, w/ 9,800' LL

BSNR 4H – 30 mmcf/d, w/ 9,800' LL

Strong across the field26 wells with IP 30 greater than 30 mmcf/d

15

LA

BOSSIER UNLOCKED POTENTIAL


Nabors 13&12-10-13 1HCTIL 11/17/2017 ~10,000' lateral

Peak rate – 35,800 mcf/d

47-day cumulative – 1.39 bcf

• Longest horizontal and largest completion

˃ First 10,000' lateral drilled and completed

˃ Reduced cluster spacing with 4,500 lb./ft.

• Exceptional reservoir quality and pressure

LA

Cumulative Production – Normalized for LL

Producing Days

Cu

mu

lati

ve P

rod

ucti

on

(m

mcf/

ft)

Nabors 13&12-10-13 1HC

Other Bossier Wells

WHAT IS THE FUTURE OF THE GULF COAST?


• Extending lateral lengths across the play

• Continuing to optimize completion design

• Testing enhanced completions in the Bossier

• Testing different refrac methods

˃ Plug and perf with new production liner

˃ All diverter method

LA

Continuing to push the envelope

15,000' Laterals Bossier

Development

Unlocking

Refrac Potential

More to do…

chesapeake 2018 dug conference dug conference.pdf · 2018 dug haynesville conference 4 (1) net...

Documents