1q 2019 earnings

1Q 2019 EARNINGSMay 8, 2019

FORWARD-LOOKING STATEMENT

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, management's outlook 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, anticipated timing of wells to be placed into production, general and administrative expenses, capital expenditures, the timing of anticipated asset

sales and proceeds to be received therefrom, the expected use of proceeds of anticipated asset sales, projected cash flow and liquidity, our ability to enhance our cash flow and

financial flexibility, plans and objectives for future operations, 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/secfilings).

These risk factors include the volatility of oil, natural gas and NGL prices; 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 replace reserves and sustain production; drilling and operating risks and resulting liabilities; our

ability to generate profits or achieve targeted results in drilling and well operations; 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; adverse

developments or losses from pending or future litigation and regulatory proceedings, including royalty claims; effects of environmental protection laws and regulation on our business;

terrorist activities and/or cyber-attacks adversely impacting our operations; effects of acquisitions and dispositions, including our acquisition of WildHorse and our ability to realize

related synergies; effects of purchase price adjustments and indemnity obligations; a potential 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 to low commodity prices; our ability to replace reserves and sustain production; 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; 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; 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; an interruption in operations at our headquarters due to a catastrophic event; 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 Resource,” “Net Reserves” and similar terms that the SEC’s guidelines 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, 2018, 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.

1Q 2019 Earnings 2

http://www.chk.com/investors/secfilings

BUSINESS STRATEGIES

Our strategy remains unchanged –

resilient to commodity price volatility

Financial discipline

Profitable and efficient growth

from captured resources

Exploration

Business development

STRATEGIC GOALS

Margin enhancement

Free cash flow

Net debt to EBITDAX of 2X

Excellence in HSER

1Q 2019 Earnings 3

(1) Adjusted for asset purchases and sales

(2) Cash costs defined as production, general and administrative and gathering, processing and transportation expenses

(3) Cash flow positive defined as net revenue less all operating costs and capital expenditures, excluding general and administrative and interest expenses

1Q 2019 Earnings 4

Reduced cash costs(2) by

~$81 million14% lower than in the 2018 first quarter

DELIVERING ON OUR STRATEGY1Q’19 HIGHLIGHTS

On track to deliver transformational oil growth

and materially improved cash flow

$15.50 / boe EBITDAX margin

Highest in four years

Brazos Valley projected to be

cash flow positiveat the asset level in 2019

(3)

Year-over-year adjusted

oil productionincreased 13%

(1)

310

320

330

340

350

360

370

380

390

400

4Q'18 1Q'19 2Q'19E 3Q'19E 4Q'19E

40

50

60

70

80

90

100

110

120

130

140

4Q'18 1Q'19 2Q'19E 3Q'19E 4Q'19E

INVESTING IN OUR HIGHEST-MARGIN OPPORTUNITIES

1Q 2019 Earnings 5

(1) 2019 EBITDAX/boe projection is based on 5/8/19 Outlook

(2) Subject to capital reallocation

$10.83

$12.81

$14.80(1)

17 18 19E

Adj. EBITDAX/boe

'17 '18 '19E

0

20

40

60

80

100

120

1Q'19 2Q'19E 3Q'19E 4Q'19E

2019 TIL Schedule(2)

High-margin

Oil-growth Assets

Cash-generating

Gas Assets

Growth Optionality

19% oil mix 4Q'18

Total Oil Volume (mbo/d) Total Gas + NGL Volume (mboe/d)

26% oil mix 4Q'19

BRAZOS VALLEY STRATEGIC PORTFOLIO ADDITION

Asset projected to be free cash flow positive in 2019(1)

Capturing expected capital improvements

and base optimization

Reservoir characterization underway

1Q 2019 Earnings 6

(1) Free cash flow defined as net revenue less all operating costs and capital expenditure, excluding general and administrative and interest expense; Based on 5/8/19 Outlook

(2) Represents average net production volumes for 1Q’19; Brazos Valley net sales volumes began on 2/1/19

(3) 2019 Activity reflects 5/8/19 Outlook

2019 Activity(3)

Wells to Turn in Line 85

Rigs 4

Frac Crews 2

Total Capex (millions) $665 – $685

Overview

1Q’19 Production 47 mboe/d(2)

Net Acres ~470,000

Production Mix(2)

GasOil NGL

14%75% 11%


13

28

2123

0

5

10

15

20

25

30

1Q'19 2Q'19E 3Q'19E 4Q'19E

ACCELERATING VALUEBRAZOS VALLEY’S 90-DAY UPDATE

(1) Cash flow positive defined as net revenue less all operating costs and capital expenditures, excluding general and administrative and interest expenses; Based on 5/8/19 Outlook

(2) Improved year-over-year drilling cycle time from March 2018 to March 2019

(3) Set a completion stage record with 11 stages per day on the Bell Pad, which is a 57% improvement over WildHorse's record

1Q 2019 Earnings 7

In 2019, asset projected to be

cash flow positive(1)

Base production management

~300 mbo gained4% monthly improvement

$500k per well savings

Achieved >$1mm on individual wells

Drilled first extended lateral

~9,800' LLPlan to average ~9,000' in 2019

SETTING RECORDS:

Drilling cycle time(2)

decreased ~40% Max completed stages per day(3)

increased ~55%

0

2

4

6

8

10

2017 2018 2019E

Stages per Day by Frac Start Date

~60%increase

DELIVERING ON EXPECTATIONS

1Q 2019 Earnings 8

$0

$200

$400

$600

$800

$1,000

$1,200

2017 2018 2019E

Well Cost per Lateral Foot

by Spud Date

~20%decrease

0

2,000

4,000

6,000

8,000

10,000

2017 2018 2019E

Lateral Length by Spud Date (ft)

~25%increase

WRD CHK

0

200

400

600

800

1,000

2017 2018 2019E

IP90 of Oil Wells by TIL Date (boe/d)

~35%increase

OPERATIONAL EXCELLENCE DRIVING PRODUCTION IMPROVEMENTS

Early wins

• Two-well pad with new flowback procedure

• Average lateral length of 7,500'

• ~35% IP30 uplift based on type well

estimate

Continued focus

• Optimized choke settings and gas lift

injection rates to manage drawdown

• Accelerating gas lift start up to maximize

early time volumes

• Automation upgrades for production

management

1Q 2019 Earnings 9

Outperforming type well estimate by ~35% ~12,000 incremental barrels of oil in first 30 days

0

5,000

10,000

15,000

20,000

25,000

30,000

0 10 20 30 40

Gro

ss O

il (b

bls

)

Producing Days

Easy Rider Production

~35%increase

Easy Rider Pad

7,500' Type Two-Well Pad

0

60,000

50,000

40,000

30,000

20,000

10,000

Bell Pad

Eagle Ford Focus Area

Eagle Ford Play Extent

OPTIMIZED COMPLETIONS YIELDING RESULTS

Driving significant efficiencies

• 45% reduction in average stage pump time

• 30% reduction in pumped water while maintaining

sand volume

• ~190% improvement, 6.7 mbo,(1) over historic

performance in traditionally weaker-performing

portion of the play

1Q 2019 Earnings 10

(1) Improvement is over a normalized offset analog

(2) Offset WRD pad normalized to four wells per pad and lateral length of 7,000'

0

500

1,000

1,500

2,000

2,500

3,000

0 3 6 9 12 15 18

Oil

Pro

duction (

bo/d

)

Days on Production

~190%increase

CHK Bell Pad Production

Offset WRD Pad(2)

Bell Pad Oil Production(Avg. Lateral Length of 7,000')

Miles50250

WE ARE JUST GETTING STARTED

Continuing to accelerate value through:

• Driving additional cost savings

• Shifting focus to high-margin oil window

• Leveraging CHK technology to optimize field development

• Improving choke management on flowbacks

• Aggressively addressing repair and maintenance

needs to drive long-term value

• Adopting our top-quartile safety and

environmental practices

1Q 2019 Earnings 11

Rex Tyson Jr. 1H Pad in Burleson County

…more to do…

SOUTH TEXAS FREE CASH FLOW MACHINE

Projected to generate ~$450mm in free cash flow(1)

Optimized spacing and completions driving value

Multi-zone high-margin oil growth potential

1Q 2019 Earnings


(2) Represents average net production volumes for 1Q’19



Overview


Net Acres ~235,000

2019 Activity(3)


Rigs 4

Frac Crews ~2

Total Capex (millions) $510 – $540Production Mix

(2)

GasOil NGL

22%56% 22%

12

29 16

39

49

0

10

20

30

40

50

60

1Q'19 2Q'19E 3Q'19E 4Q'19E

Jun-11 Nov-11 May-12 Nov-12 May-13 Nov-13 May-14 Nov-14 May-15 Nov-15 May-16 Nov-16 Apr-17 Oct-17 Apr-18 Oct-18

EU

R b

o/f

t

Well Productivity Progression – West Four Corners Region

Percent of the Parent EUR Range of production outcomes

73% at 500' spacing

50% at 330' spacing

95% at 660' spacing

Parent EUR

EAGLE FORD WELL SPACING ENHANCING PRODUCTION

Significantly reduced parent-child EUR

degradation with 660' spacing

Increased spacing and larger completions

contribute to lower decline rates

Lowest well cost per foot operator on the

western portion of the play(1)

1Q 2019 Earnings 13

(1) Source: RS Energy Group

West Four Corners

Lower Eagle Ford

Maturity Windows

Oil

Volatile Oil

Condensate/Wet Gas

Dry Gas

Miles50250

Maturity Windows

Oil

Volatile Oil

Condensate/Wet Gas

Dry Gas

First Co-Development Location

Producing Austin Chalk

Austin Chalk

Upper Eagle Ford

Lower Eagle Ford

Austin Chalk

Upper Eagle Ford

EXPANDING INTO DIFFERENT HORIZONS

1Q 2019 Earnings 14

Maximizing multi-bench recovery

• Drilled first CHK Lower Eagle Ford, Upper Eagle Ford

and Austin Chalk co-development location

Promising Austin Chalk results

• Will be developed over existing Lower Eagle Ford

Advancing Upper Eagle Ford

• Will be co-developed with Lower Eagle Ford drilling program

0

50,000

100,000

150,000

200,000

250,000

300,000

350,000

1 101 201 301 401 501

Cum

ula

tive

Pro

du

ctio

n (

bo

e)

Days

Austin Chalk Well Performance

2019 Austin Chalk

2018 Upper Eagle Ford

2017 Austin Chalk

0 100 200 300 400 500

Miles20100

POWDER RIVER BASIN OIL GROWTH ENGINE

Averaged 39 mboe/d (46% oil) in April

Project 100% YOY oil growth in 2019

Turner in full development

1Q 2019 Earnings 15


Overview


Net Acres ~213,000

2019 Activity(2)


Rigs 6

Frac Crews ~1


(1)

GasOil NGL

38%45% 17%

13

15

24

20

0

5

10

15

20

25

30

1Q'19 2Q'19E 3Q'19E 4Q'19E



DRIVING RECORD RESULTS IN THE TURNER

1Q 2019 Earnings 16

BB2 PAD

SWD Wells

Producing Turner Well

Planned TIL

CPF/SWD

Turner Oil Window

High GOR

Delineated

Turner

Miles1050

Single well production record – RRC 5 well

• >4,000 boe/d

• >3,000 bo/d

Pad production record – BB2 pad

• >9,000 boe/d

• >7,800 bo/d

• >7,200 mcf/d

Field production record

• Net 42 mboe (48% oil) on May 1st

$11.18 $11.54$12.89

$20.50

FY 2016 FY 2017 FY 2018 FY 2019E

EXPANDING POWDER RIVER MARGINS

1Q 2019 Earnings 17

(1) Based on 5/8/19 Outlook

(1)

Powder River Basin EBITDAX/boe

3%increase

12%increase

~60% increase

Oil sales line began flowing 5/3/19

• >15% field volumes currently being piped

GP&T/boe expected to be reduced by more than 25% in 2019

• Gathering agreements eliminate >$2/bbl for trucking

Water pipeline system eliminates >$1/bbl trucking cost

30 mbo/d Central Production Facility coming online in 2Q’19

KEY DRIVERS

40% oil 40% oil 44% oil 47% oil

MARCELLUS FOUNDATIONAL ASSET


Field optimized for spacing and lateral length

January 2019 gross production record

of 2.5 bcf/d

1Q 2019 Earnings 18


Overview


Net Acres ~540,000

2019 Activity(2)


Rigs ~2.5

Frac Crews ~1


(3)

Gas

100%

9

14

8

13

0

2

4

6

8

10

12

14

16

1Q'19 2Q'19E 3Q'19E 4Q'19E




LONGER LATERALS MAXIMIZING VALUE

Longer laterals driving down F&D costs and

delivering strong recovery per foot

Acreage position provides significant

long-lateral runway

• In 1Q’19, drilled the 1st 15k lateral in App North

• 15 wells >8,000' lateral length TIL’d in 2018

55% of the 2019 program will have >8,000'

lateral lengths

1Q 2019 Earnings 19

(1) Source: RS Energy Group

2

2.2

2.4

2.6

2.8

3

3.2

3.4

3.6

3.8

4

4,000' to 8,000' >8,000'

EUR (mmcf/ft) by Lateral Length(1)

Achieving same EUR/ft with longer laterals

$0.00

$0.05

$0.10

$0.15

$0.20

$0.25

$0.30

$0.35

4,000' to 8,000' >8,000'

F&D ($/mcf) by Lateral Length(1)

NICKOLYN 6HCAvg 30 days: 37 mmcfd*

NICKOLYN 7HCAvg 30 days: 36 mmcfd*

JOEGUSWA 4HCAvg 30 days: 51 mmcfd*

JOEGUSWA 5HCAvg 30 days: 40 mmcfd*

BOREK 104HAvg 30 days: 37 mmcfd*



CANNELLA 24HCAvg 30 days: 26 mmcfd*

CANNELLA 25HCAvg 30 days: 20 mmcfd*

Lower Marcellus Well

Upper Marcellus Well

Lower Marcellus Core

Upper Marcellus Core

Lower Marcellus Core Expansion

*Average 30 days for non-zero production

Miles20100

GULF COAST CONSISTENT PERFORMANCE


Access to premium markets

Base optimization yielding significant results

1Q 2019 Earnings


Overview


Net Acres ~301,000

2019 Activity(3)


Rigs ~2

Frac Crews ~1


(2)

Gas

100%

20

109

5

0

2

4

6

8

10

12

1Q'19 2Q'19E 3Q'19E 4Q'19E




ADVANCING THE HAYNESVILLE FIELD DEVELOPMENT PROGRAM

1Q 2019 Earnings 21

(1) JPIL wells TIL’d on 4/12/19

Lateral length designed for acreage footprint

and drilling risk mitigation

Completion, drill out and flowback optimized

for reservoir

Recent highlights

• Initial flowback results exceeding 80 mmcfd

for the two-well pad(1)

JPIL 1HC

Peak Rate: 47 mmcfd

Lateral Length: 12,500'

JPIL 2HC

Peak Rate: 34 mmcfd

Lateral Length: 10,000'

JPIL Wells

Springridge

Mansfield

Miles20100

MID-CONTINENT GROWTH OPTIONALITY

Redeployed capital to Powder River

Integrating new 3D data and recent appraisal

program results

High-grading 2020 and 2021 program

1Q 2019 Earnings


Overview


Net Acres ~764,000

2019 Activity(2)


Rigs 0

Frac Crews ~1


(1)

GasOil NGL

42%33% 25%

22

9

5

0

2

4

6

8

10

1Q'19 2Q'19E 3Q'19E 4Q'19E



DIVERSE & STRONG PORTFOLIOCORE POSITIONS ACROSS MULTIPLE BASINS

(1) As of 1Q’19

Marcellus: Foundational Asset

Mid-Continent: Growth Optionality

Powder River Basin: Oil Growth Engine

South Texas: Free Cash Flow Machine

Brazos Valley: Strategic Portfolio Addition

DAILY PRODUCTION AVERAGE(1)

~484 mboe

1Q 2019 Earnings 23

Gulf Coast: Consistent Performance

TOTAL 2019 PRODUCTION MIX(1)

Gas 70%

Oil 22%

NGL 8%

HEDGING POSITIONAS OF 5/3/19

(1)

(1) Does not reflect April or May 2019 settlements

241Q 2019 Earnings

W E I G H T E D A V E R A G E P R I C E

OIL Volume (mmbbl) Fixed Call ($ per bbl) Put

Swaps:

2019 17.4 $59.39

2020 11.4 $59.32

Collars:

2019 4.4 $67.75 $58.00

2020 1.8 $83.25 $65.00

Swaptions:

2020 4.4 $62.45

Puts:

2019 1.6 $54.08

Total 2019 23.4

Total 2020 17.6

NATURAL GAS Volume (bcf) Fixed Call ($ per mcf) Put

Swaps:

2019 344.0 $2.84

2020 250.1 $2.75

Three-way collars:

2019 66.0 $3.10 $2.50/$2.80

Collars:

2019 27.5 $2.91 $2.75

Swaptions:

2020 106.1 $2.77

Total 2019 437.5

Total 2020 356.2

BASIS HEDGESAS OF 5/3/19

(1)

1Q 2019 Earnings

(1) Does not reflect April or May 2019 settlements

25

CIG2019: 8 bcf @ ($0.89) / mcf

HSC2019: 19.3 bcf @ $0.03 / mcf

Argus Houston vs Argus WTI2019: 3.4 mmbbls @ $5.16 / bbl

Argus LLS vs Argus WTI2019: 2.7 mmbbls @ $6.20 / bbl

$302 $293$451

$338

$850

$1,300 $1,319 $1,300

$1,250

$688BVL

$1,222CHK

$700

$0

$500

$1,000

$1,500

$2,000

$2,500

$3,000

2019 2020 2021 2022 2023 2024 2025 2026 2027

Unsecured

Convertibles

Revolving Credit Facility

BVL Unsecured

$ m

illio

ns

DEBT MATURITY PROFILE(1)

1Q 2019 Earnings 26

(1) As of 3/31/19 pro forma for settlement of the exchange transaction on 4/3/19 and maturity of the 2019 FRNs on 4/15/19 ($380mm FRN balance added to CHK’s 3/31/19 revolver balance of $842mm)

$1.9 billion$1.2 billion CHK RCF

$688 million WRD RCF

$8.1 billionSenior Notes

7.0%WACD

CORPORATE INFORMATION

1Q 2019 Earnings 27

As of 5/1/19

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]

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1q 2019 earnings

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