IR Update Jan 2017

INVESTOR RELATIONS UPDATEJanuary 2017

INVESTOR RELATIONS UPDATE – JANUARY 2017 2

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.

3

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

INVESTOR RELATIONS UPDATE – JANUARY 2017

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

4

OUR STRATEGYRELEVANT THROUGH COMMODITY PRICE CYCLES


Profitable and Efficient GrowthFrom 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

6

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

7

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

9

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%

Drilled25%

Upper Eagle Ford1,000

Austin Chalk1,000

Lower Eagle Ford3,260

3 – 4 rigsActive in 2017

10

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


Extended Lateral Wells (>9,000')Avg. Extended Lateral Performance10,000' Lateral Type Curve5,000' Lateral Type Curve

0 1 2 3 4 5

-$3,000.0-$2,500.0-$2,000.0-$1,500.0-$1,000.0

-$500.0$0.0

$500.0$1,000.0$1,500.0$2,000.0

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 80 120 160 200 240 280 320 360 400 440 4800

40

80

120

160

West Four Corners Performance

Production Days

Cum

ulat

ive

Oil

Prod

uctio

n (m

bo)

Value accelerationExtended laterals provide 2-for-1 NPV

Years

11

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


(1) Assumes $3/mcf gas price flat

$2.0 $3.0 $4.0 $5.0 $6.0 $7.0 0

200

400

600

800

1,000

1,200

1,400

1,600

1,800Well Cost vs. Production IP (1)

Well Cost ($mm)

Pro

duct

ion

IP (b

oe/d

)

20% ROR @ $50 Oil40% ROR @ $50 Oil

Lazy A Cotulla G 4HLL: 10,547' Lazy A Cotulla G 5H

LL: 10,563'

Lazy A Cotulla G 3HLL: 10,523' Valley Wells C 6H

LL: 9,180'

Valley Wells C 4HLL: 9,778'

2016: 6,500' TC laterals

2016: 10,000' TC laterals

2014: 5,000' TC laterals2015: 6,500' TC laterals

12

SOUTH TEXASWELL POSITIONED TO GROW


2011 2012 2013 2014 2015 2016 2017 20180

50

100

150

200

250

300

0

5

10

15

20

25

30

35

Gro

ss O

pera

ted

Pro

duct

ion,

mbo

e/d

Gro

ss R

ig C

ount

2011 2012 2013 2014 2015 2016E 2017E 2018E

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

13

MID-CONTINENT BRIDGE 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


14

OSWEGO DELIVERING IMPRESSIVE RESULTS


71%

12% 17%

Oil NGL Natural Gas

40 MILES

Lightle 4-18-6 1HIP 30 = 1,098 bo/dIP 30 = 1,235 boe/d

Hasty 3-18-6 1HIP 30 = 897 bo/dIP 30 = 1,033 boe/d

Caldwell 22-18-6 1HIP 30 = 1,447 bo/dIP 30 = 1,813 boe/d

Themer 6-17-6 1HIP 30 = 717 bo/dIP 30 = 832 boe/d

Hughes Trust 33-18-7 1HIP 30 = 1,257 bo/dIP 30 = 1,326 boe/d

40 MILE

S

Farrar 11-18-6 1HIP 30 = 727 bo/dIP 30 = 852 boe/d

$3.0mm/wellDevelopment cost

~400 mboe EUR83% liquid, average WI 53%

15

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 1HIP: 2,062 boe/d

Anderson 1206 1-33WHIP: 745 boe/d

Governor James B. EdwardsIP 30: 1,684 boe/d

Whistle Pig 10-4AHIP 30: 719 boe/d

Ward 21-1HIP: 596 boe/d

McCray 2414 1-10H/15HIP: 1,267 boe/d

Howard 5-19-17 1HIP: 2,454 boe/d

School Land 1-36HIP 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

16

MID-CON GROWTH ENGINESCALABLE GROWTH FROM OSWEGO AND THE WEDGE


Development model only reflects the first 100 Oswego locations

06/2016 06/2017 06/2018 06/2019 06/20200

20000

40000

60000

80000

100000

120000

140000

Oswego Oswego Gen 3 CompletionMiss Lime Development Wedge Development

Gro

ss O

pera

ted

Pro

duct

ion,

mbo

e/d

1 – 4 Rigs 4 – 8 Rigs

17

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+


18

HAYNESVILLE GAME-CHANGING PERFORMANCELONGER LATERALS AND BIGGER COMPLETIONS


0 20 40 60 80 100 120 1400

0.5

1

1.5

2

2.5

3

3.5

0.8

1.2

1.6

3.0

Producing Days

Cum

ulat

ive

Prod

uctio

n (b

cf)

New CHK wells delivering monster IPsCA 1H – 38 mmcf/d, 10,000' lateralPCK 1H – 31 mmcf/d, 7,000' lateralWILL 1H – 34 mmcf/d, 8,350' lateral

Vintage Completion

Improved Completion10K w/ Improved Completion

10K +

3,000

lbs./

ft.+

reduce

d cluste

r spac

ing

>250% increaseIn 90-day production with extended laterals, increased proppant loading and reduced cluster spacing

19

RETURNING TO POWDER RIVER BASINONE MILE OF OPPORTUNITY


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

20

40

60

80

100

120 Net Production Potential

Oil NGL Natural Gas

mbo

e/d

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

20

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

MowryOil breakeven price (2)

<$40

21

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 TurnerDepth ~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)

~$4048%

14%

38%

Production Mix

Oil NGL Natural Gas

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

23

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

4Q'16E 4Q'17E 4Q'18E450,000

500,000

550,000

600,000

650,000

700,000

750,000

Total Production (mboe/d) (1)

4Q'16E 4Q'17E 4Q'18E60,000

80,000

100,000

120,000

140,000

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

24

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)

Dai

ly E

quiv

alen

t Rat

e, m

boe/

d

25INVESTOR RELATIONS UPDATE – JANUARY 2017

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

26

Appendix


27

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

~ 30

0'

Not to Scale

Upper Marcellus

Lower Marcellus

Lateral Well

~1,200'

~1,200'

Spacing Assumptions

~1,200'

28

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

Dai

ly P

rodu

ctio

n (m

mcf

/d)

Base Producing Wells Includes curtailed volumesNo D&C capital spend required

29

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%

0% 20% 40% 60% 80% 100% 120% 140%$2.00

$2.50

$3.00

$3.50

$4.00

$40

$50

$60

$70

$80

DRY TYPE CURVE WET TYPE CURVE

Rate of Return

Gas

Pric

e ($

/mcf

)

Oil

Pric

e $/

bbl

30

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)

Gas

Pro

duct

ion

mm

cf/d

31

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.

3Q'16 4Q'16 1Q'170

100

200

300

400

500

600

700

800

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

(mbo

e/d)

(2) (2)

32

DEBT MATURITY PROFILE


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

33

HEDGING POSITION


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

Oil 2017 (1)

68%

Swaps $50.19/bbl

Natural Gas 2017 (1)

71%

68%Swaps

3%Collars $3.00/$3.48/mcf

NYMEX

$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

34

CORPORATE INFORMATION


HEADQUARTERS

6100 N. Western AvenueOklahoma City, OK 73118WEBSITE: www.chk.com

CORPORATE CONTACTS

BRAD SYLVESTER, CFAVice 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 CHK177.25% Senior Notes due 2018 #165167CC9 CHK18A3mL + 3.25% Senior Notes due 2019 #165167CM7 CHK196.625% Senior Notes due 2020 #165167CF2 CHK20A6.875% Senior Notes due 2020 #165167BU0 CHK206.125% Senior Notes due 2021 #165167CG0 CHK215.375% 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 CHK225.75% Senior Notes due 2023 #165167CL9 CHK23

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#U16450AU99 N/A5.50% Contingent Convertible Senior Notes due 2026 #165167CR6 N/A2.75% Contingent Convertible Senior Notes due 2035 #165167BW6 CHK35

2.50% Contingent Convertible Senior Notes due 2037 #165167BZ9/ #165167CA3 CHK37/ CHK37A

2.25% Contingent Convertible Senior Notes due 2038 #165167CB1 CHK384.5% Cumulative Convertible Preferred Stock #165167842 CHK PrD

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

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5.75% Cumulative Convertible Preferred Stock#U16450204/

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5.75% Cumulative Convertible Preferred Stock (Series A)#U16450113/

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Chesapeake Common Stock #165167107 CHK

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IR Update Jan 2017

Investor Relations

Transcript of IR Update Jan 2017