1Q 2019 Earnings

1. 1Q 2019 EARNINGS
May 8, 2019

2. 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

3. 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

4. (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 million
14% lower than in the 2018 first quarter
DELIVERING ON OUR STRATEGY
1Q’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 positive
at the asset level in 2019
(3)
Year-over-year adjusted
oil production
increased 13%
(1)

5. 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

6. 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%
2019 TIL Schedule(3)
13
28
21
23
0
5
10
15
20
25
30
1Q'19 2Q'19E 3Q'19E 4Q'19E

7. ACCELERATING VALUE
BRAZOS 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 gained
4% monthly improvement
$500k per
well savings
Achieved >$1mm on individual wells
Drilled first extended lateral
~9,800' LL
Plan to average ~9,000' in 2019
SETTING RECORDS:
Drilling cycle time(2)
decreased ~40%
Max completed stages per day(3)
increased ~55%

8. 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

9. 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
GrossOil(bbls)
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

10. 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
OilProduction(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')
Miles
50250

11. 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…

12. 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
(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
(3) 2019 Activity reflects 5/8/19 Outlook
2019 TIL Schedule(3)
Overview
1Q’19 Production 110 mboe/d(2)
Net Acres ~235,000
2019 Activity(3)
Wells to Turn in Line 133
Rigs 4
Frac Crews ~2
Total Capex (millions) $510 – $540
Production 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

13. 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
EURbo/ft
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
Miles
50250

14. 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
CumulativeProduction(boe)
Days
Austin Chalk Well Performance
2019 Austin Chalk
2018 Upper Eagle Ford
2017 Austin Chalk
0 100 200 300 400 500
Miles
20100

15. 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
2019 TIL Schedule(2)
Overview
1Q’19 Production 36 mboe/d(1)
Net Acres ~213,000
2019 Activity(2)
Wells to Turn in Line 72
Rigs 6
Frac Crews ~1
Total Capex (millions) $505 – $525
Production Mix(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
(1) Represents average net production volumes for 1Q’19
(2) 2019 Activity reflects 5/8/19 Outlook

16. 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
Miles
1050
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

17. $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

18. MARCELLUS
FOUNDATIONAL ASSET
Projected to generate ~$400mm in free cash flow(1)
Field optimized for spacing and lateral length
January 2019 gross production record
of 2.5 bcf/d
1Q 2019 Earnings 18
2019 TIL Schedule(2)
Overview
1Q’19 Production 158 mboe/d(3)
Net Acres ~540,000
2019 Activity(2)
Wells to Turn in Line 44
Rigs ~2.5
Frac Crews ~1
Total Capex (millions) $190 – $210
Production Mix(3)
Gas
100%
9
14
8
13
0
2
4
6
8
10
12
14
16
1Q'19 2Q'19E 3Q'19E 4Q'19E
(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) 2019 Activity reflects 5/8/19 Outlook
(3) Represents average net production volumes for 1Q’19

19. 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 6HC
Avg 30 days: 37 mmcfd*
NICKOLYN 7HC
Avg 30 days: 36 mmcfd*
JOEGUSWA 4HC
Avg 30 days: 51 mmcfd*
JOEGUSWA 5HC
Avg 30 days: 40 mmcfd*
BOREK 104H
Avg 30 days: 37 mmcfd*
BOREK 2H
Avg 30 days: 38 mmcfd*
BOREK 4H
Avg 30 days: 40 mmcfd*
CANNELLA 24HC
Avg 30 days: 26 mmcfd*
CANNELLA 25HC
Avg 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
Miles
20100

20. GULF COAST
CONSISTENT PERFORMANCE
Projected to generate ~$200mm in free cash flow(1)
Access to premium markets
Base optimization yielding significant results
1Q 2019 Earnings
2019 TIL Schedule(3)
Overview
1Q’19 Production 127 mboe/d(2)
Net Acres ~301,000
2019 Activity(3)
Wells to Turn in Line 24
Rigs ~2
Frac Crews ~1
Total Capex (millions) $130 – $150
Production Mix(2)
Gas
100%
20
10
9
5
0
2
4
6
8
10
12
1Q'19 2Q'19E 3Q'19E 4Q'19E
(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
(3) 2019 Activity reflects 5/8/19 Outlook

21. 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
Miles
20100

22. 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
2019 TIL Schedule(2)
Overview
1Q’19 Production 24 mboe/d(1)
Net Acres ~764,000
2019 Activity(2)
Wells to Turn in Line 14
Rigs 0
Frac Crews ~1
Total Capex (millions) $75 – $95
Production Mix(1)
GasOil NGL
42%33% 25%
22
9
5
0
2
4
6
8
10
1Q'19 2Q'19E 3Q'19E 4Q'19E
(1) Represents average net production volumes for 1Q’19
(2) 2019 Activity reflects 5/8/19 Outlook

23. DIVERSE & STRONG PORTFOLIO
CORE 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%

24. HEDGING POSITION
AS 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

25. BASIS HEDGES
AS OF 5/3/19(1)
1Q 2019 Earnings
(1) Does not reflect April or May 2019 settlements
25
CIG
2019: 8 bcf @ ($0.89) / mcf
HSC
2019: 19.3 bcf @ $0.03 / mcf
Argus Houston vs Argus WTI
2019: 3.4 mmbbls @ $5.16 / bbl
Argus LLS vs Argus WTI
2019: 2.7 mmbbls @ $6.20 / bbl

26. $302 $293
$451
$338
$850
$1,300 $1,319 $1,300
$1,250
$688
BVL
$1,222
CHK
$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
$millions
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 billion
Senior Notes
7.0%
WACD

27. 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 ir@chk.com
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