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

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HAYNESVILLE DIVESTITURES ACCELERATING 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

8 – 10 Development program years of extended lateral drilling remaining after planned divestitures

Play Statistics Current

Post Divestitures

Undrilled

2,070

1,425

Acreage

~385,000

~255,000

Production

1.2 bcf/d

1.1 bcf/d

INVESTOR RELATIONS UPDATE – JANUARY 2017

3

OUR STRATEGY RELEVANT THROUGH COMMODITY PRICE CYCLES

Financial Discipline > Balance capital expenditures with cash flow from operations

Profitable and Efficient Growth From Captured Resources > Develop world-class inventory

> Increase financial and operational flexibility

> Target top-quartile operating and financial metrics

> Achieve investment grade metrics

> Pursue continuous improvement > Drive value leakage out of operations

Business Development

Explore

> Optimize portfolio through strategic divestitures

> Leverage innovative technology and expertise

> Target strategic acquisitions

> Explore and exploit new growth opportunities

> Enhance and expand the portfolio

INVESTOR RELATIONS UPDATE – JANUARY 2017

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Differential Business Improvement

Operational Focus In 2017

Strategic Targets In 2017 And Beyond

CHK IS POSITIONED TO OUTPERFORM

Where we have been 2012 – 2016

Where we are going

Strengthened the balance sheet, reduced complexity and legacy commitments

Leverage portfolio strength and depth to drive efficient growth and further improve debt metrics (3)

2016 – 2020

~50% reduction

~50% reduction

2x

In total leverage (1)

In cash costs per boe (2)

= $10.9 billion

= $4.10/boe in 2016E

5% – 15%

Net debt/EBITDA

Annual production growth

Cash flow neutrality achievable in 2018 Based on 2017 investment (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

INVESTOR RELATIONS UPDATE – JANUARY 2017

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UNRECOGNIZED VALUE, UNLOCKED POTENTIAL POWER OF THE PORTFOLIO

11.3 BBOE Total net recoverable resources

5,600 locations Above 40% ROR (1)

> Risked locations > Downspacing upside

> Proven reservoirs > Tremendous exploration and technology upside

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

INVESTOR RELATIONS UPDATE – JANUARY 2017

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Differential Business Improvement

Operational Focus In 2017

Strategic Targets In 2017 And Beyond

SOUTH TEXAS ASSET OVERVIEW UNDRILLED ACREAGE, POSITIONED FOR GROWTH

• Secure acreage position

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

• Best-in-class operations • Extended laterals are working

3 – 4 rigs Active in 2017 Austin Chalk 1,000

Locations

Production Mix (1)

Upper Eagle Ford 1,000 Drilled 25%

Lower Eagle Ford 3,260

Remaining Development 75%

25% 56% 19%

Oil

NGL

Natural Gas

(1) Net processed production mix

INVESTOR RELATIONS UPDATE – JANUARY 2017

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ACCELERATING VALUE USING EXTENDED LATERALS CURRENT EAGLE FORD RESULTS BEATING TYPE CURVE EXPECTATIONS

West Four Corners Performance

Beating the type curve

160

11 of 13 extended lateral wells are outperforming the type curve

Cumulative Oil Production (mbo)

Extended Lateral Wells (>9,000') Avg. Extended Lateral Performance 10,000' Lateral Type Curve 5,000' Lateral Type Curve

120

Value acceleration Extended laterals provide 2-for-1 NPV

80

Cumulative 10% Discounted Cash Flow, $(mm) Two 5,000' Laterals

Single 10,000' Lateral

$2.0 $1.0

40

$0.0 0

1

2

3

4

-$1.0

5

Years

-$2.0

0 0

40

80

120

Production Days

160

200

-$3.0

Expected payout in

-$4.0

< 2 years

-$5.0

Due to XL strategy execution

INVESTOR RELATIONS UPDATE – JANUARY 2017

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TRANSFORMING THE LOWER EAGLE FORD EXTENDED LATERALS UNLOCK VALUE IN LOW PRICE ENVIRONMENT

Well Cost vs. Production IP (1) 1,800 Lazy A Cotulla G 4H LL: 10,547'

1,600

Lazy A Cotulla G 5H LL: 10,563'

Production IP (boe/d)

1,400 Lazy A Cotulla G 3H LL: 10,523'

1,200

1,000

Valley Wells C 4H LL: 9,778'

Valley Wells C 6H LL: 9,180'

2016: 10,000' TC laterals

800

2016: 6,500' TC laterals 2015: 6,500' TC laterals 2014: 5,000' TC laterals

600

400

200

0 $2.0

$3.0

$4.0

$5.0

$6.0

$7.0

Well Cost ($mm) (1) Assumes $3/mcf gas price flat

INVESTOR RELATIONS UPDATE – JANUARY 2017

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SOUTH TEXAS WELL POSITIONED TO GROW 300

35

30

25 200 20 150 15

Gross Rig Count

Gross Operated Production, mboe/d

250

100 10

50

5

0 2011 Rig Count

0 2012 2011

2013 20122016E

2014 2013

2015 2015 2014

2016 2016E 2015

2017 2017E 2016E

2018 2018E 2017E

INVESTOR RELATIONS UPDATE – JANUARY 2017

2018E

12

MID-CONTINENT BRIDGE TO OIL GROWTH

• Shift from historical plays to new concepts and formations

~1.5mm Net Acres in Mid-Continent

• Legacy acreage position offers extensive opportunity

• Oswego – a bridge to oil production growth • Actively exploiting “The Wedge” opportunity

3 – 4 rigs Active in 2017

INVESTOR RELATIONS UPDATE – JANUARY 2017

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OSWEGO DELIVERING IMPRESSIVE RESULTS 40 MILES Lightle 4-18-6 1H IP 30 = 1,098 bo/d IP 30 = 1,235 boe/d

Hasty 3-18-6 1H IP 30 = 897 bo/d

$3.0mm/well

IP 30 = 1,033 boe/d

Development cost

~400 mboe EUR

Farrar 11-18-6 1H IP 30 = 727 bo/d

83% liquid, average WI 53%

IP 30 = 852 boe/d

40 MILES

Hughes Trust 33-18-7 1H IP 30 = 1,257 bo/d

Caldwell 22-18-6 1H IP 30 = 1,447 bo/d

IP 30 = 1,326 boe/d

12%

IP 30 = 1,813 boe/d

17%

Themer 6-17-6 1H IP 30 = 717 bo/d IP 30 = 832 boe/d

71% Oil

NGL

Natural Gas

INVESTOR RELATIONS UPDATE – JANUARY 2017

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THE WEDGE PLAY

CHESAPEAKE’S FUTURE MID-CONTINENT GROWTH ASSET Strong economics – large land position • ~870,000 net acres Sharon 31-27-11 1H IP: 2,062 boe/d

˃ 94% HBP

• Robust economics ˃ ~500 locations at 50% ROR (1,2)

• Significant running room ˃ ~1,400 additional upside locations

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

Ward 21-1H IP: 596 boe/d School Land 1-36H IP 30: 1,353 boe/d

• Efficient capital spend ˃ Industry actively de-risking plays

Howard 5-19-17 1H IP: 2,454 boe/d Whistle Pig 10-4AH IP 30: 719 boe/d

TWO New Wedge step-out tests

1,000 – 1,500 boe/d (50 – 70% oil) One mile laterals with opportunity for two mile development

Anderson 1206 1-33WH IP: 745 boe/d

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

(1) Location counts exclude Miss Lime locations (2) Price deck: $3/mcf for gas and $60/bbl oil flat

INVESTOR RELATIONS UPDATE – JANUARY 2017

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MID-CON GROWTH ENGINE SCALABLE GROWTH FROM OSWEGO AND THE WEDGE

140

Gross Operated Production, mboe/d

120

100

80

60

40

20

0 06/2016

06/2017 1 – 4 Rigs

Oswego

Oswego Gen 3 Completion

06/2018

06/2019

06/2020

4 – 8 Rigs

Miss Lime Development

Wedge Development

Development model only reflects the first 100 Oswego locations

INVESTOR RELATIONS UPDATE – JANUARY 2017

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GULF COAST WORLD-CLASS RESOURCE • CHK Haynesville position is 100% HBP and only 25% developed • Unique opportunity to develop field with newest technology

Future Returns of the Gulf Coast (1) ~70%

50% 27%

2Q '16

10,000' Laterals w/ Modern Completion

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

2016E

2017+

2 – 3 rigs Active in 2017

(1) Assumes $3 mcf gas price

INVESTOR RELATIONS UPDATE – JANUARY 2017

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HAYNESVILLE GAME-CHANGING PERFORMANCE LONGER LATERALS AND BIGGER COMPLETIONS

New CHK wells delivering monster IPs

3.5

Cumulative Production (bcf)

3

CA 1H – 38 mmcf/d, 10,000' lateral PCK 1H – 31 mmcf/d, 7,000' lateral WILL 1H – 34 mmcf/d, 8,350' lateral

3.0

2.5

2

1.6 1.5

1.2 1

>250% increase

0.8

In 90-day production with extended laterals, increased proppant loading and reduced cluster spacing

0.5

0 0

20

40

60

80

100

120

140

Producing Days

INVESTOR RELATIONS UPDATE – JANUARY 2017

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RETURNING TO POWDER RIVER BASIN ONE MILE OF OPPORTUNITY • ~2.7 bboe gross recoverable resource potential • ~2,600 risked locations • Renegotiated midstream unlocks value

Teapot

• The next oil growth asset

Parkman E, A, B/C & Deep

˃ CHK rig returned to the basin in November

Surrey

Net Production Potential 120

Sussex

100 2016E CHK Eagle Ford Equivalent

Niobrara mboe/d

80

Oil

NGL

Natural Gas

Turner 60

Frontier Mowry

40 20 2017E

2018E

2019E

1–2 Rigs

2020E

2021E

2022E

4+ Rigs INVESTOR RELATIONS UPDATE – JANUARY 2017

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SUSSEX SANDSTONE HIGHLY ECONOMIC OIL PLAY • Moving to development • Dominant position in the play

Teapot

• ~200 undrilled locations

Parkman E, A, B/C & Deep

˃ Assumes 1,320' spacing

˃ Overpressured – high deliverability

Surrey

• Targeted development Sussex

˃ EUR: 825 – 1,350 mboe ˃ ROR: 50 – 70% (1)

Niobrara

˃ 2017 focused drilling program

Production Mix

Turner Frontier

Oil breakeven price

Mowry

35%

(2)

53%

10,000' lateral length where possible

INVESTOR RELATIONS UPDATE – JANUARY 2017

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MARCELLUS PRODUCTION STRENGTH SUSTAINABLE PRODUCTION WITH MINIMAL CAPITAL

• DUC focus in 2017 and 2018 > Exceptional point forward economics

> 11 obligatory spuds through 2018

Remarkable productivity Minimal capital required

Gross Daily Production (mmcf/d)

• Minimal obligations

Base Producing Wells Includes curtailed volumes No D&C capital spend required

INVESTOR RELATIONS UPDATE – JANUARY 2017

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FLEXIBLE INVESTMENT OPPORTUNITIES STRENGTH IN OPTIONALITY – UTICA

• High-quality and diverse position • Market advantages

$4.00

$80

$3.50

$70

$3.00

$60

$2.50

$50

Drilled 30% Remaining Development 70%

$2.00 0%

~$200mm

$40 150%

50% 100% Rate of Return DRY TYPE CURVE

WET TYPE CURVE

Projected free cash flow through 2018 (1) (1) Assumes $3 / $48 for 2017 and $3 / $60 in 2018, excluding hedges

INVESTOR RELATIONS UPDATE – JANUARY 2017

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Oil Price $/bbl

Location Count

Gas Price ($/mcf)

• 1 – 2 rigs planned in 2017

DRY GAS GROWTH UTICA SHALE

Utica Dry Locations

Remaining Development 90%

>40% ROR Average CHK WI ~ 90% (1)

Gas Production mmcf/d

Drilled 10%

Utica Dry Production (mmcf/d)

>350% Production growth

$2.14 Per mcf Utica Dry PV10 breakeven

~93% of dry gas is sent to Gulf market

(1) Assumes $3/mcf gas flat

INVESTOR RELATIONS UPDATE – JANUARY 2017

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ADJUSTED PRODUCTION RECONCILIATION CUMULATIVE IMPACT OF MULTIPLE SALES TRANSACTIONS IN 2016 Production with Divestiture Adjustments (1) Full impact of Barnett and planned Devonian and Haynesville divestitures

800 700

Mid-Continent divestitures close

Partial quarter impact of Barnett Shale exit

600

(mboe/d)

500 400 300 200 100 0 3Q'16

Total Production

4Q'16

(2)

Divested Liquids Volume

1Q'17

Divested Gas Volume

(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.

INVESTOR RELATIONS UPDATE – JANUARY 2017

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(2)

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

INVESTOR RELATIONS UPDATE – JANUARY 2017

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HEDGING POSITION

Natural Gas

Oil

2017

2017 (1)

(1)

3% Collars

$3.00/$3.48/mcf NYMEX

71% 68% Swaps

68% $3.07/mcf NYMEX Swaps $50.19/bbl

~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

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

INVESTOR RELATIONS UPDATE – JANUARY 2017

33

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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]

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