2Q 2019 Earnings

2Q 2019 EARNINGS
August 6, 2019

FORWARD-LOOKING STATEMENT
2Q 2019 Earnings 2
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, expected lateral lengths of wells, anticipated timing of wells to be placed into production, anticipated timing of wells to
be placed into production, anticipated timing of the Brazos Valley business unit becoming cash flow positive, general and administrative expenses, capital expenditures,
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/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; the availability of cash flows from operations and other funds to finance reserve replacement costs or satisfy our debt
obligations; 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; 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; 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.

BUSINESS STRATEGY
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
2Q 2019 Earnings 3

$22.88
$27.27
$25.50
20
21
22
23
24
25
26
27
28
2017 2018 2019E
$2.2 $2.2 $2.2
1.5
1.7
1.9
2.1
2.3
2.5
2.7
2.9
3.1
2017 2018 2019E
0
5
10
15
20
2017 2018 2019E
$10.48 $12.53 $14.11
$2.4
$2.3
$2.1
9
10
11
12
13
14
15
16
1.95
2
2.05
2.1
2.15
2.2
2.25
2.3
2.35
2.4
2.45
2017 2018 2019E
EXECUTING OUR STRATEGY
2Q 2019 Earnings
Eliminated
$300mm
in cash costs
(1) Based on 8/6/19 Outlook
(2) Cash costs include production expenses, gathering, processing & transportation, and general & administrative expenses
4
Increased oil mix
~50%
2019 exit rate >130,000 bo/d
16%
Avg Sales Price per boe (excluding hedges)
Capex (billions)
Adj EBITDAX (billions)
$2.5
$2.1
Improved margins
~35%
Generating more cash with better margins
EBITDAX and Capex(1)
Enhancing Margins(1,2)
Cash Costs (billions)
Adj EBITDAX ($/boe)
Annual Oil Production Mix (%)
24%
$2.4
17%

0
20
40
60
80
100
120
1Q'19 2Q'19 3Q'19E 4Q'19E
2019 TIL Schedule
(1,2)
60
80
100
120
140
4Q'18 1Q'19 2Q'19 3Q'19E 4Q'19E
Total Oil Volume (mbo/d)(2)
INVESTING IN OUR HIGHEST-MARGIN
OPPORTUNITIES
2Q 2019 Earnings
(1) Subject to capital reallocation
320
340
360
380
400
4Q'18 1Q'19 2Q'19 3Q'19E 4Q'19E
Total Gas + NGL Volume (mboe/d)(2)
26%
4Q’19E
Oil
Gas
5
19%
4Q‘18

$396 $500
$2,287
$1,015
$1,500
$1,800 $1,700
$1,500
$1,100
2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027
TRANSFORMING OUR DEBT
MATURITY OUTLOOK
2Q 2019 Earnings 6
SEPT. 30, 2015
JUNE 30, 2019
Unsecured Senior Notes (millions)
$302 $294 $451 $338
$850
$2,000
$2,569
$1,300
$686
BVL
$1,372
CHK
2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027
Revolving Credit Facility (millions)
6

COMMITTED TO SAFETY AND
ENVIRONMENTAL LEADERSHIP
HSER excellence and
environmental stewardship
central to our core values
A culture of continuous
improvement to reduce our
environmental footprint
• Voluntary commitment in
The Environmental Partnership
sharing best practices and
technologies to reduce emissions
• Enhanced Leak Detection and
Repair (LDAR) program
2Q 2019 Earnings 7
(1) American Exploration & Production Council (AXPC) annual benchmarking survey results
(2) Based upon Subpart W reported values for tonne methane and tonne gas produced
(3) Peer companies include: APC, PXD, DVN, EQT, XEC, NFX, AR, APA, NBL, ECA, RRC
0.51
0.38
0.05
0.23
0.52
0.48
0.43
0.39
2015 2016 2017 2018
Total Recordable Incident Rate
= AXPC
Average(1)
0.26%
0.24%
0.19%
0.14%
0.26%
0.31%
0.28%
2015 2016 2017 2018
Methane Loss Rate(2)
= Peer Group
Average(3)

BRAZOS VALLEY
STRATEGIC PORTFOLIO ADDITION
Asset projected to be free cash flow positive in 2019(1)
Lowered projected break-even to ~$39/bbl
since merger
Initial reservoir characterization
expands oil window
2Q 2019 Earnings
(1) Free cash flow defined as net revenue less all operating costs and capital expenditures, excluding general and administrative and interest expenses; Based on 8/6/19 Outlook
(2) Represents average net production volumes for 2Q’19
(3) Projected 2019 mix
2019 Activity(4)
Wells to Turn in Line 82
Rigs 4
Frac Crews 2
Total Capex (millions) $665 – $685
Overview
2Q’19 Production 49 mboe/d(2)
Net Acres ~470,000
2019 Production Mix(3)
GasOil NGL
21%67% 12%
2019 TIL Schedule(4)
8
20
26
19
5
4
1Q'19 2Q'19 3Q'19E 4Q'19E
Gas
Oil
8

DELIVERING COST SAVINGS TARGETS
BRAZOS VALLEY’S 180-DAY UPDATE
PROJECTED ANNUAL SAVINGS(1)
2019E SAVINGS(2)
Operational Efficiencies $50 – $80 million $90 – $100 million
Capital Efficiencies $150 – $200 million $160 – $180 million
Total $200 – $280 million $250 – $280 million
(1) Savings projection made when the deal was announced on 10/30/18
(2) Does not include the capex savings recognized from the reduction in rig activity compared to 2018
2Q 2019 Earnings 9
Operational efficiencies include savings from reduced cash costs and downtime
Capital efficiencies include savings from longer laterals and improved well design
Averaged $600k per well savings; Recognized >$2.0mm savings on certain wells

REDEFINING THE ECONOMICS OF THE PLAY
2Q 2019 Earnings
(2) Type well break-even is $39; Price deck: $55/bo and $2.50/mcf
(3) Source: RS Energy Group
773
682
~930
0
100
200
300
400
500
600
700
800
900
1,000
2017 2018 2019E
~35%
increase
Peak Rate of Oil Wells by TIL Date (boe/d)(1)
$1,109
$1,057
~$880
$0
$200
$400
$600
$800
$1,000
$1,200
2017 2018 2019E
~17%
decrease
Well Cost per Lateral Foot by Spud Date(1)
Estimated 2019 savings of $250 – $280 million WRD
CHK
10
18
34
~37
44 – 46
0
5
10
15
20
25
30
35
40
45
50
2017 2018 2019E 2020E
>30%
increase
Oil Production (mbo/d)(1)
$47
$53
~$39
$0
$10
$20
$30
$40
$50
$60
2017 2018 2019E
~25%
decrease
Break-even per Barrel(1,2)
(3)
(3)

TERRY EF UNIT 1H
Peak Rate: 1,119 bo/d, 329 mcf/d
7,612' Lateral
BARWISE EF UNIT 1H
7,623' Lateral
SCARPINATO 3H
7,037' Lateral
ODSTRCIL B 1H
Peak Rate: 897 bo/d, 315 mcf/d
7,010' LateralSHAW EF 2H
7,168' Lateral
RAGER 1H (A. Chalk)
Peak Rate: 731 bo/d, 5,418 mcf/d
6,229' Lateral
EASY RIDER 1H
7,778' Lateral
EASY RIDER 3H
6,824' Lateral
SCHOENEMAN C 1H
9,362' Lateral
SCHOENEMAN C 3H
8,654' Lateral
COLLINS EF UNIT 1H
6,590' Lateral
WELLS OUTPERFORMING PAST RESULTS
2Q 2019 Earnings 11
(1) 24-hour peak rate
(2) Normalized at 7,000' laterals Miles
1050 20
2019 Eagle Ford TIL Wells
2019 Austin Chalk TIL Wells
1H ’19
Placed seven wells to sales
with peak rates >1,000 bo/d(1)
compared to:
2018
Three wells reached a
peak rate of >1,000 bo/d(1)
0
20,000
40,000
60,000
80,000
100,000
120,000
0 60 120 180 240 300 360
Producing Days
Well Performance by TIL Year
Accelerated production
>30% faster
2018 Average(2)
2019 YTD Average(2)
CumulativeProduction(bo)
SEILHEIMER 1H (A. Chalk)
Peak Rate: 53 bo/d, 14,627 mcf/d
6,936' Lateral

2019 Eagle Ford TIL Wells
2019 Drill Schedule
Near-term Core Expansion Wells
Miles
1050 20
MOSES/COLLINS 2 WELL PROJECT
Project Max IP = 1,716 bo/d, 613 mcf/d
BELL 4 WELL PROJECT
Project Max IP = 2,712 bo/d, 3,641 mcf/d
BATISTA 2 WELL PROJECT
Project Max IP = 1,397 bo/d, 316 mcf/d
EXPANDING THE OIL OPPORTUNITY
~230 locations shifted to improved
performance and higher-margin
black oil window
• Average GOR: 50 – 2,000 scf/bbl
Expanded black oil area
• Leveraged lab and PVT data
to increase understanding of
oil window
Remaining 2019 and 2020
drill schedule is 100% oil
development focused
2Q 2019 Earnings 12

SIGNIFICANT PROGRESS
2Q 2019 Earnings 13
Cost savings ahead of schedule
• Projected 2019 total savings of $250 – $280 million
• Averaged $600k per well savings; recognized >$2 million
savings on certain wells
Redefining economics
• Eagle Ford projected break-even lowered to ~$39/bbl
High-margin oil
• Projected to increase oil production >30% 2020 vs. 2018
• Shifted ~230 locations to higher-margin black
oil window
…more to come…
Rex Tyson Jr. 1H Pad in Burleson County

POWDER RIVER BASIN
OIL GROWTH ENGINE
Projected 100% oil growth in 2019(1)
GP&T/boe expected to be reduced by
~25% in 2019(1)
Drilled first Niobrara well since 2014
2Q 2019 Earnings
Overview
Net Acres ~213,000
2019 Activity(1)
Rigs ~5
Frac Crews ~2
GasOil NGL
37%48% 15%
13
16
26
13
1Q'19 2Q'19 3Q'19E 4Q'19E
14
Oil

5.9
10.5
21.8
FY 2017 FY 2018 FY 2019E
0
5
10
15
20
25
Powder River Basin Net Oil Production vs GOR
(1)
7,200
7,000
5,100
0
1000
2000
3000
4000
5000
6000
7000
8000
GOR (scf/bbl)
Net Oil Production
(mbo/d)
$9.34
$16.17 $17.30
$32.57
$38.20
$34.00
0
5
10
15
20
25
30
35
40
45
FY 2017 FY 2018 FY 2019E
ELIMINATING COSTS, GROWING MARGINS
2Q 2019 Earnings
(1)
Powder River Basin EBITDAX/boe
48% oil
~85%
increase
~45%
decrease
$10.47 $9.83
$8.53 $8.45
$-
$2.00
$4.00
$6.00
$8.00
$10.00
$12.00
$14.00
$16.00
$18.00
1Q'19 2Q'19 3Q'19E 4Q'19E(1) (1)
$15.67
$12.29
$-
$2.00
$4.00
$6.00
$8.00
$10.00
$12.00
$14.00
$16.00
$18.00
FY 2017 FY 2018
Powder River Basin GP&T/boe
116
85
2018 2019E
>25%
decrease
Turner Avg Spud-TIL Cycle Time
(1)
15
Avg Sales Price per boe (excluding hedges)
EBITDAX ($/boe)
Driven by 100% year-over-year oil growth in 2019
42% oil40% oil

Miles
1050
RRC 5-34-70 USA B TR 23H
Avg 30 days: 2,000 bo/d*
BB 2-35-71 USA A TR 16H
Avg 30 days: 1,825 bo/d*
PREMIER TURNER PERFORMANCE
Basin comparison
• Average oil well performance is greater than peers
• Single well production record – RRC 5 well
- >4,000 boe/d, >3,000 bo/d
• BB2 16H peak rate
- 3,200 boe/d, 2,800 bo/d
2Q 2019 Earnings 16
(1) Source: RS Energy Group; Powder River Basin Turner wells with a lateral length in excess of ~2,000’ and GOR less than 3,500 scf/bbl.
SWD Wells
Producing Turner Well
Planned TIL
CPF/SWD
Turner Oil Window
High GOR
Delineated
Turner
*Average 30 days for non-zero production
0 1 2 3 4 5 6
Turner Cumulative Production
(1)
Cumulativembls
180
160
140
120
100
80
60
40
20
RRC 5-34-70 USA B TR 23H
BB 2-35-71 USA A TR 16H
CHK average
14 Peer company averages
Months
0

SOUTH TEXAS
FREE CASH FLOW MACHINE
Projected to generate >$350mm in free cash flow(1)
Optimized spacing and completions driving value
Multi-zone high-margin oil growth potential
2Q 2019 Earnings
Overview
Net Acres ~235,000
2019 Activity(4)
Rigs 4
Frac Crews ~2
GasOil NGL
24%55% 21%
29
17
42
47
1Q'19 2Q'19 3Q'19E 4Q'19E
17
Oil

MARCELLUS
FOUNDATIONAL ASSET
Projected to generate ~$320mm in free cash flow(1)
Ten years of drilling inventory at
$1.50 – $1.75/mcf break-even(2)
1,150+ Marcellus locations remaining
(assuming ~1,350' average spacing)(3)
2Q 2019 Earnings
(2) Assumes current drilling activity level
(3) Upper and lower Marcellus locations, excludes Utica
Overview
2Q’19 Production 929 mmcf/d(4)
Net Acres ~540,000
2019 Activity(6)
Rigs 2
Frac Crews 1
Gas
100%
18
9
14
12
9
1Q'19 2Q'19 3Q'19E 4Q'19E
Gas

$291 $430 $320
0
100
200
300
400
500
600
700
800
0
100
200
300
400
500
600
700
2017 2018 2019E
Marcellus FCF vs EBITDAX
(1)
$2.76
$2.99
$2.44
2017 2018 2019E
2
2.1
2.2
2.3
2.4
2.5
2.6
2.7
2.8
2.9
3
Free Cash Flow (millions)
EBITDAX (millions)
CHK Average Gas Price (excluding hedges)
$520
$401
MAXIMIZING VALUE,
DEFINING CAPITAL EFFICIENCY
Capital efficiency drivers:
• Proper spacing (1,200' – 1,500')
• Longer laterals
• Optimized completions
• Base production management
2Q 2019 Earnings
19
$582
VANDEMARK 2H
Avg 30 days: 35 mmcf/d*
SHUMHURST 3H
SLUMBER VALLEY 3H
MCGAVIN 21H
MCGAVIN 2H
Lower Marcellus Well
Upper Marcellus Well
Lower Marcellus Core
Upper Marcellus Core
Lower Marcellus Core Expansion
*Average 30 days for non-zero production
NICKOLYN 6HC
NICKOLYN 7HC
JOEGUSWA 4HC
JOEGUSWA 5HC
BOREK 104H
BOREK 2H
BOREK 4H
CANNELLA 24HC (Upper)
CANNELLA 25HC (Upper)
Miles
20100

GULF COAST
CONSISTENT PERFORMANCE
Projected to generate ~$150mm in free cash flow(1)
Access to premium markets
Base optimization yielding significant results
2Q 2019 Earnings
Overview
2Q’19 Production 751 mmcf/d(2)
Net Acres ~301,000
2019 Activity(4)
Rigs ~1
Frac Crews ~1
Gas
100%
20
10
9
5
1Q'19 2Q'19 3Q'19E 4Q'19E
Gas

MID-CONTINENT
GROWTH OPTIONALITY
Redeployed capital to Powder River
Integrating new 3D data and recent appraisal
program results
High-grading 2020 and 2021 program
2Q 2019 Earnings
Overview
Net Acres ~764,000
2019 Activity(3)
Rigs 0
Frac Crews ~1
GasOil NGL
41%35% 24%
9
5
1Q'19 2Q'19 3Q'19E 4Q'19E
21
Oil

HEDGE POSITION – CHK + BVL
AS OF 7/31/19
Includes July and August 2019 derivative contracts that have settled
W E I G H T E D A V E R A G E P R I C E
OIL Volume (mmbbl) Hedge % Fixed Call ($ per bbl) Put
Swaps:
2019 13.7 60% $60.20
2020 12.9 $59.21
Collars:
2019 2.9 13% $67.75 $58.00
2020 1.8 $83.25 $65.00
Swaptions:
2020 2.2 $63.15
Puts:
2019 1.4 6% $54.31
Total 2019 18.1 79%
Total 2020 16.9
NATURAL GAS Volume (bcf) Fixed Call ($ per mcf) Put
Swaps:
2019 254.9 67% $2.84
2020 264.7 $2.76
Three-way collars:
2019 14.6 4% $3.10 $2.50/$2.80
Collars:
2019 18.4 5% $2.91 $2.75
Swaptions:
2020 106.1 $2.77
2021 14.6 $2.80
2022 14.6 $2.80
Total 2019 288.0 76%
Total 2020 370.8
2Q 2019 Earnings 22

CORPORATE INFORMATION
2Q 2019 Earnings
As of 6/30/19
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
Publicly Traded Securities Cusip Ticker
6.625% Senior Notes due 2020 #165167CF2 CHK20A
6.875% Senior Notes due 2020
#165167BU0
#165167BT3
#U16450AQ8
CHK20
6.125% Senior Notes Due 2021 #165167CG0 CHK21
5.375% Senior Notes Due 2021 #165167CK1 CHK21A
4.875% Senior Notes Due 2022 #165167CN5 CHK22
5.75% Senior Notes Due 2023 #165167CL9 CHK23
7.00% Senior Notes due 2024 #165167DA2 N/A
#165167CT2
#165167CU9
#U16450AU9
N/A
7.50% Senior Notes due 2026 #165167DB0 N/A
#165167DC8
#U16450AY1
N/A
#165167CV7
#U16450AV7
N/A
5.50% Contingent Convertible Senior Notes due 2026 #165167CY1 N/A
4.5% Cumulative Convertible Preferred Stock #165167842 CHK PrD
5.0% Cumulative Convertible Preferred Stock (Series 2005B)
#165167834
#165167826
N/A
5.75% Cumulative Convertible Preferred Stock
#U16450204
#165167776
#165167768
N/A
5.75% Cumulative Convertible Preferred Stock (Series A)
#U16450113
#165167784
#165167750
N/A
Chesapeake Common Stock #165167107 CHK
23

2Q 2019 Earnings

Recommended

Recommended

More Related Content

What's hot

What's hot (20)

Similar to 2Q 2019 Earnings

Similar to 2Q 2019 Earnings (20)

More from Chesapeake Energy Corporation

More from Chesapeake Energy Corporation (11)

Recently uploaded

Recently uploaded (20)

2Q 2019 Earnings