INVESTOR RELATIONS UPDATE - Chesapeake Energy Update_January 2017.pdf · INVESTOR RELATIONS UPDATE...

INVESTOR RELATIONS UPDATE

January 2017

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 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 noncore 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 (including our ability to optimize base production and execute gas gathering agreements), the

ability of our employees, portfolio strength and operational leadership to create long-term value, 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 or at all; the availability of cash flows from operations and other funds to finance reserve replacement costs or satisfy our debt obligations; a further

downgrade in 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 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 realized 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 cyber-attacks adversely impacting our operations; potential

challenges of our spin-off of Seventy Seven Energy Inc. (SSE) 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 and preferred stock; 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 release or the

accompanying Outlook, except as required by applicable law.

INVESTOR RELATIONS UPDATE – JANUARY 2017 2

HAYNESVILLE DIVESTITURESACCELERATING VALUE

• Signed PSA to divest multiple Haynesville

assets for total of $915mm

˃ Both sales expected to close in 1Q 2017

˃ Proceeds continue progress towards

strategic target of $2 – $3 billion in debt

reduction

• Gross proceeds from asset divestitures

signed or closed of $2.5 billion in 2016


Play Statistics

Current Post Divestitures

Undrilled 2,070 1,425

Acreage ~385,000 ~255,000

Production 1.2 bcf/d 1.1 bcf/d

8 – 10 Development program years of

extended lateral drilling remaining

after planned divestitures

OUR STRATEGYRELEVANT THROUGH COMMODITY PRICE CYCLES


Profitable and Efficient Growth

From Captured Resources

> Develop world-class inventory

> Target top-quartile operating and

financial metrics

> Pursue continuous improvement

> Drive value leakage out of operations

Explore

> Leverage innovative technology

and expertise

> Explore and exploit new growth

opportunities

Business Development

> Optimize portfolio through strategic

divestitures

> Target strategic acquisitions

> Enhance and expand the portfolio

Financial Discipline

> Balance capital expenditures

with cash flow from operations

> Increase financial and operational

flexibility

> Achieve investment grade metrics

Strategic Targets In 2017 And Beyond

Operational Focus In 2017

Differential Business Improvement

CHK IS POSITIONED TO OUTPERFORM


(1) From 12/31/2012 through 6/30/2016

(2) Includes production expenses and general and administrative expenses, including stock-based compensation

(3) Assumes strip pricing through 2017 and $3/mcf and $60/bbl thereafter

Where we are going2016 – 2020

Strengthened the balance sheet,

reduced complexity and legacy

commitments

Leverage portfolio strength and

depth to drive efficient growth

and further improve debt metrics (3)

2xNet debt/EBITDA

5% – 15%Annual production growth

Where we have been2012 – 2016

~50% reductionIn total leverage (1)

= $10.9 billion

~50% reductionIn cash costs per boe (2)

= $4.10/boe in 2016E

Cash flow neutrality achievable in 2018Based on 2017 investment

UNRECOGNIZED VALUE, UNLOCKED POTENTIALPOWER OF THE PORTFOLIO


(1) Economics run at $3/mcf and $60/bbl oil flat

11.3 BBOETotal net recoverable resources

5,600locationsAbove 40% ROR (1)

> Risked locations

> Downspacing upside

> Proven reservoirs

> Tremendous exploration

and technology upside

SOUTH TEXAS ASSET OVERVIEWUNDRILLED ACREAGE, POSITIONED FOR GROWTH

• Secure acreage position

• Best-in-class operations

• Extended laterals are working

(1) Net processed production mix


~270,000 Net Acres in Eagle Ford – 99% HBP/ HBO

56%19%

25%

Production Mix (1)

Oil NGL Natural Gas

Locations

Remaining

Development

75%

Drilled

25%

Upper Eagle Ford

1,000

Austin Chalk

1,000

Lower Eagle Ford

3,260

3 – 4 rigsActive in 2017

ACCELERATING VALUE USING EXTENDED LATERALSCURRENT EAGLE FORD RESULTS BEATING TYPE CURVE EXPECTATIONS


Extended Lateral Wells (>9,000')

Avg. Extended Lateral Performance

10,000' Lateral Type Curve

5,000' Lateral Type Curve

-$5.0

-$4.0

-$3.0

-$2.0

-$1.0

$0.0

$1.0

$2.0

0 1 2 3 4 5

Cumulative 10% Discounted Cash Flow, $(mm)

Two 5,000' Laterals Single 10,000' Lateral

Beating the type curve11 of 13 extended lateral wells are

outperforming the type curve

Expected payout in

< 2 yearsDue to XL strategy execution

0

40

80

120

160

0 40 80 120 160 200

Cu

mu

lative

Oil

Pro

du

ctio

n (

mb

o)

Production Days

West Four Corners Performance

Value accelerationExtended laterals provide 2-for-1 NPV

Years

TRANSFORMING THE LOWER EAGLE FORDEXTENDED LATERALS UNLOCK VALUE IN LOW PRICE ENVIRONMENT


(1) Assumes $3/mcf gas price flat

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

$2.0 $3.0 $4.0 $5.0 $6.0 $7.0

Pro

du

ction

IP

(b

oe

/d)

Well Cost ($mm)

Well Cost vs. Production IP (1)

Lazy A Cotulla G 4H

LL: 10,547' Lazy A Cotulla G 5H

LL: 10,563'

Lazy A Cotulla G 3H

LL: 10,523' Valley Wells C 6H

LL: 9,180'

Valley Wells C 4H

LL: 9,778'

2016: 6,500' TC laterals




SOUTH TEXASWELL POSITIONED TO GROW


0

5

10

15

20

25

30

35

0

50

100

150

200

250

300

2011 2012 2013 2014 2015 2016 2017 2018

Gro

ss R

ig C

oun

t

Gro

ss O

pera

ted

Pro

du

ction

, m

boe

/d

2011 2012 2013 2014 2015 2016E 2017E 2018E

2016ERig Count 2011 2012 2013 2014 2015 2016E 2018E2017E

MID-CONTINENTBRIDGE TO OIL GROWTH

• Shift from historical plays to new

concepts and formations

• Legacy acreage position offers

extensive opportunity

• Oswego – a bridge to oil

production growth

• Actively exploiting

“The Wedge” opportunity


~1.5mm Net Acres in Mid-Continent


OSWEGO DELIVERING IMPRESSIVE RESULTS


71%

12% 17%

Oil NGL Natural Gas

40 MILES

Lightle 4-18-6 1H

IP 30 = 1,098 bo/dIP 30 = 1,235 boe/d

Hasty 3-18-6 1H

IP 30 = 897 bo/dIP 30 = 1,033 boe/d

Caldwell 22-18-6 1H

IP 30 = 1,447 bo/dIP 30 = 1,813 boe/d

Themer 6-17-6 1H

IP 30 = 717 bo/dIP 30 = 832 boe/d

Hughes Trust 33-18-7 1H

IP 30 = 1,257 bo/dIP 30 = 1,326 boe/d

40 M

ILE

S

Farrar 11-18-6 1H

IP 30 = 727 bo/dIP 30 = 852 boe/d

$3.0mm/wellDevelopment cost

~400 mboe EUR83% liquid, average WI 53%

THE WEDGE PLAYCHESAPEAKE’S FUTURE MID-CONTINENT GROWTH ASSET

• ~870,000 net acres

˃ 94% HBP

• Robust economics

˃ ~500 locations at 50% ROR (1,2)

• Significant running room

˃ ~1,400 additional upside locations

• Efficient capital spend

˃ Industry actively de-risking plays

(1) Location counts exclude Miss Lime locations

(2) Price deck: $3/mcf for gas and $60/bbl oil flat


Sharon 31-27-11 1H

IP: 2,062 boe/d

Anderson 1206 1-33WH

IP: 745 boe/d

Governor James B. Edwards

IP 30: 1,684 boe/d

Whistle Pig 10-4AH

IP 30: 719 boe/d

Ward 21-1H

IP: 596 boe/d

McCray 2414 1-10H/15H

IP: 1,267 boe/d

Howard 5-19-17 1H

IP: 2,454 boe/d

School Land 1-36H

IP 30: 1,353 boe/d

Strong economics – large land position

TWO New Wedge step-out tests

1,000 – 1,500 boe/d

(50 – 70% oil)One mile laterals with opportunity

for two mile development

MID-CON GROWTH ENGINESCALABLE GROWTH FROM OSWEGO AND THE WEDGE


Development model only reflects the first 100 Oswego locations

0

20

40

60

80

100

120

140

06/2016 06/2017 06/2018 06/2019 06/2020

Gro

ss O

pe

rate

d P

rod

uctio

n, m

bo

e/d

Oswego Oswego Gen 3 Completion Miss Lime Development Wedge Development

1 – 4 Rigs 4 – 8 Rigs

2Q '16 10,000' Laterals w/Modern Completion

10,000'+ Lateral w/3,000'+ lbs./ft.

Completion

Future Returns of the Gulf Coast (1)

27%

50%

~70%

GULF COAST WORLD-CLASS RESOURCE

• CHK Haynesville position is 100% HBP

and only 25% developed

• Unique opportunity to develop field with

newest technology

(1) Assumes $3 mcf gas price


2016E 2017+


HAYNESVILLE GAME-CHANGING PERFORMANCELONGER LATERALS AND BIGGER COMPLETIONS


3.0

1.6

1.2

0.8

0

0.5

1

1.5

2

2.5

3

3.5

0 20 40 60 80 100 120 140

Cu

mu

lative

Pro

du

ction

(b

cf)

Producing Days

New CHK wells delivering monster IPsCA 1H – 38 mmcf/d, 10,000' lateral

PCK 1H – 31 mmcf/d, 7,000' lateral

WILL 1H – 34 mmcf/d, 8,350' lateral

>250% increaseIn 90-day production with extended

laterals, increased proppant loading

and reduced cluster spacing

RETURNING TO POWDER RIVER BASINONE MILE OF OPPORTUNITY


-

20

40

60

80

100

120

2017E 2018E 2019E 2020E 2021E 2022E

mb

oe

/d

Net Production Potential

Oil NGL Natural Gas

4+ Rigs1–2 Rigs

2016E CHK Eagle Ford Equivalent

Teapot

ParkmanE, A, B/C & Deep

Surrey

Sussex

Niobrara

Turner

Frontier

Mowry

• ~2.7 bboe gross recoverable resource potential

• ~2,600 risked locations

• Renegotiated midstream unlocks value

• The next oil growth asset

˃ CHK rig returned to the basin in November

SUSSEX SANDSTONEHIGHLY ECONOMIC OIL PLAY

• Moving to development

• Dominant position in the play

• ~200 undrilled locations

˃ Assumes 1,320' spacing

˃ Overpressured – high deliverability

• Targeted development

˃ EUR: 825 – 1,350 mboe

˃ ROR: 50 – 70% (1)

˃ 2017 focused drilling program

(1) Assumes $3 gas and $60 oil prices flat

(2) PV10 positive breakeven price assuming $3 gas price


53%

12%

35%

Production Mix

Oil NGL Natual Gas

Teapot

ParkmanE, A, B/C & Deep

Surrey

Sussex

Niobrara

Turner

Frontier

Mowry

Oil breakeven price (2)

<$40

TURNER SANDSTONEPROVEN RESERVOIR – UNREALIZED VALUE

• Same play as northern hotspot with similar

rock properties and anticipated higher

pressure

• Offset activity proves potential, but not

optimized for drilling and completion


Turner North CHK Turner

Depth ~10,000' ~11,000'

Reservoir Pressure (Est.) ~4,800 psi ~6,800 psi

Avg. Porosity 7% 7%

Avg. Water Saturation 45 – 60% 35 – 60%

Oil breakeven price (1)

~$40

48%

14%

38%

Production Mix

Oil NGL Natural Gas

(1) PV10 positive breakeven price assuming $3 gas price

RETURNING TO GROWTHPORTFOLIO STRENGTH AND OIL GROWTH WILL DRIVE MARGIN EXPANSION


(1) Production forecast subject to final capital allocation decisions for 2017 and 2018 and market conditions

450

500

550

600

650

700

750

4Q'16E 4Q'17E 4Q'18E

Total Production (mboe/d) (1)

60

80

100

120

140

4Q'16E 4Q'17E 4Q'18E

Oil Production (mbo/d) (1)

~10% oil production growth projected from 4Q’16 to 4Q’17

~20% oil production growth projected from 4Q’17 to 4Q’18

CASH FLOW NEUTRAL IN 2018


(1) Excluding judgment for BONY litigation and debt maturities

CHK turns

FCF neutralIn 2018 due to production

growth from 2017 investment

2017 vs. 2016 Adjusted

Production Decline of

(5%) – 0%

2018 vs. 2017 Adjusted

Production Growth of

10% – 15%

2017 cash flow outspend

of $400mm – $600mm (1)

Da

ily E

qu

iva

lent

Ra

te, m

boe

/d


2020

Strategic targetsSubstantial progress on every front

Reduced total leverage by

~50% ($10.9 billion)

Improved cash costs by

~50% per boe

Reduced financial and balance

sheet complexity

High-graded portfolio —

10,500+ locations above 20% ROR

Grow production 5% – 15%

annually

Expand margin through

10% - 20% annual oil growth

Retire $2 – $3 billion of debt

Achieve 2x net debt/EBITDA

2016

Appendix


GROWTH POTENTIAL AND FUTURE DEVELOPMENTMARCELLUS SHALE

• Longer laterals

• Optimal completion designs

• Substantial Upper Marcellus

fairway

• Additional upside in Utica

development

(1) Optimizing future Marcellus locations to >10,000' lateral length where possible


Lateral Length Locations Remaining

Lower Marcellus Core (1) 6,000' 780

Lower Marcellus Core Expansion (1) 6,000' 620

Upper Marcellus 5,000' 1,500

Upper Marcellus Optimized (1) 10,000' ~750

~ 3

00'

Not to Scale

Upper Marcellus

Lower Marcellus

Lateral Well

~1,200'

~1,200'

Spacing Assumptions

~1,200'

MARCELLUS PRODUCTION STRENGTH SUSTAINABLE PRODUCTION WITH MINIMAL CAPITAL

• DUC focus in 2017 and 2018

> Exceptional point forward

economics

• Minimal obligations

> 11 obligatory spuds through 2018


Remarkable productivityMinimal capital required G

ross D

aily

Pro

du

ctio

n (

mm

cf/

d)

Base Producing Wells Includes curtailed volumes

No D&C capital spend required

FLEXIBLE INVESTMENT OPPORTUNITIESSTRENGTH IN OPTIONALITY – UTICA

• High-quality and diverse position

• Market advantages

• 1 – 2 rigs planned in 2017

(1) Assumes $3 / $48 for 2017 and $3 / $60 in 2018, excluding hedges


~$200mmProjected free cash flow

through 2018 (1)

Drilled 30%

Location Count

Remaining

Development

70%$40

$50

$60

$70

$80

$2.00

$2.50

$3.00

$3.50

$4.00

0% 50% 100% 150%

Oil

Price $

/bbl

Gas P

rice (

$/m

cf)

Rate of Return

DRY TYPE CURVE WET TYPE CURVE

DRY GAS GROWTHUTICA SHALE


(1) Assumes $3/mcf gas flat

Utica Dry Locations

Drilled

10%

Remaining

Development

90%

>350% Production growth

>40% RORAverage CHK WI ~ 90% (1)

~93% of dry gas is sent to Gulf market

$2.14Per mcf Utica Dry PV10

breakeven

Utica Dry Production

(mmcf/d)

Ga

s P

rod

uctio

n m

mcf/

d

ADJUSTED PRODUCTION RECONCILIATIONCUMULATIVE IMPACT OF MULTIPLE SALES TRANSACTIONS IN 2016


(1) 3Q’16 divestiture production impact of 8,200 bo/d, 102mmcf/d and 5,900 bbl/d of NGL. 4Q’16 projected divestiture production impact of 8,300 bo/d, 310 mmcf/d and 7,200 bbl/d of NGL.

1Q’17 projected divestiture production impact of 8,500 bo/d, 495 mmcf/d and 8,100 bbl/d of NGL.

(2) Projected total production volumes represent the mid-point of guidance provided on page 5.

0

100

200

300

400

500

600

700

800

3Q'16 4Q'16 1Q'17

Total Production Divested Liquids Volume Divested Gas Volume

Production with Divestiture Adjustments (1)

Mid-Continent

divestitures close

Partial quarter

impact of Barnett

Shale exit

Full impact of

Barnett and

planned Devonian

and Haynesville

divestitures

(mb

oe

/d)

(2) (2)

DEBT MATURITY PROFILE


• Pro forma tender results, OMRs, 6.25% Euro note maturity and 6.50% 2017

redemption

HEDGING POSITION


(1) As of 1/15/17, using midpoints of total production from 11/3/2016 Outlook

Oil2017 (1)

68%

Swaps $50.19/bbl

Natural Gas2017 (1)

71%

68%Swaps

3%Collars

$3.00/$3.48/mcfNYMEX

$3.07/mcfNYMEX

~120 bcf hedged in 2018 with swaps at an average price of $3.13

~47 bcf hedged in 2018 with collars at an average price of $3.00/$3.25

CORPORATE INFORMATION


HEADQUARTERS

6100 N. Western Avenue

Oklahoma City, OK 73118

WEBSITE: www.chk.com

CORPORATE CONTACTS

BRAD SYLVESTER, CFA

Vice President – Investor Relations

and Communications

DOMENIC J. DELL’OSSO, JR.

Executive Vice President and

Chief Financial Officer

Investor Relations department

can be reached at [email protected]

PUBLICLY TRADED SECURITIES CUSIP TICKER

6.50% Senior Notes due 2017 #165167BS5 CHK17

7.25% Senior Notes due 2018 #165167CC9 CHK18A

3mL + 3.25% Senior Notes due 2019 #165167CM7 CHK19

6.625% Senior Notes due 2020 #165167CF2 CHK20A

6.875% Senior Notes due 2020 #165167BU0 CHK20

6.125% Senior Notes due 2021 #165167CG0 CHK21

5.375% Senior Notes due 2021 #165167CK21 CHK21A

8.00% Senior Secured Second Lien Notes due 2022#165167CQ8 N/A

#U16450AT2 N/A

4.875% Senior Notes due 2022 #165167CN5 CHK22

5.75% Senior Notes due 2023 #165167CL9 CHK23

8.00% Senior Notes due 2025#165167CT2 N/A

#U16450AU99 N/A

5.50% Contingent Convertible Senior Notes due 2026 #165167CR6 N/A

2.75% Contingent Convertible Senior Notes due 2035 #165167BW6 CHK35

2.50% Contingent Convertible Senior Notes due 2037#165167BZ9/

#165167CA3CHK37/ CHK37A

2.25% Contingent Convertible Senior Notes due 2038 #165167CB1 CHK38

4.5% Cumulative Convertible Preferred Stock #165167842 CHK PrD

5.0% Cumulative Convertible Preferred Stock (Series 2005B)#165167834/

N/A#165167826

5.75% Cumulative Convertible Preferred Stock

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5.75% Cumulative Convertible Preferred Stock (Series A)

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Chesapeake Common Stock #165167107 CHK

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INVESTOR RELATIONS UPDATE - Chesapeake Energy Update_January 2017.pdf · INVESTOR RELATIONS UPDATE...

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