2Q 2019 EARNINGS - filecache.investorroom.comfilecache.investorroom.com/mr5ir_chk/504/download... · 2Q 2019 Earnings 2 This presentation includes “forward-looking statements”

2Q 2019 EARNINGSAugust 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 $2.21.5

1.7

1.9

2.1

2.3

2.5

2.7

2.9

3.1

2017 2018 2019E0

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

$300mmin 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$686BVL

$1,372CHK

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

0.520.48

0.430.39

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 TARGETSBRAZOS 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 Miles1050 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)

Cum

ula

tive P

roduction (

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 WellsMiles

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

2019 TIL Schedule(1)Overview


Net Acres ~213,000

2019 Activity(1)


Rigs ~5

Frac Crews ~2

Total Capex (millions) $505 – $5252019 Production Mix(3)

GasOil NGL

37%48% 15%

1316

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 23HAvg 30 days: 2,000 bo/d*

BB 2-35-71 USA A TR 16HAvg 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)

Cum

ula

tive m

bls

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







Net Acres ~235,000

2019 Activity(4)


Rigs 4

Frac Crews ~2


GasOil NGL

24%55% 21%

29

17

4247

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





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 $3200

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 2019E2

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 2HAvg 30 days: 35 mmcf/d*

SHUMHURST 3HAvg 30 days: 33 mmcf/d*

SLUMBER VALLEY 3HAvg 30 days: 30 mmcf/d*

MCGAVIN 21HAvg 30 days: 34 mmcf/d*

MCGAVIN 2HAvg 30 days: 46 mmcf/d*

Lower Marcellus Well

Upper Marcellus Well

Lower Marcellus Core

Upper Marcellus Core

Lower Marcellus Core Expansion

*Average 30 days for non-zero production

NICKOLYN 6HCAvg 30 days: 37 mmcf/d*

NICKOLYN 7HCAvg 30 days: 36 mmcf/d*

JOEGUSWA 4HCAvg 30 days: 51 mmcf/d*

JOEGUSWA 5HCAvg 30 days: 40 mmcf/d*

BOREK 104HAvg 30 days: 37 mmcf/d*



CANNELLA 24HC (Upper)Avg 30 days: 26 mmcf/d*

CANNELLA 25HC (Upper)Avg 30 days: 20 mmcf/d*

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


2Q’19 Production 751 mmcf/d(2)

Net Acres ~301,000

2019 Activity(4)


Rigs ~1

Frac Crews ~1


Gas

100%





20

109

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



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 + BVLAS 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 [email protected]

Publicly Traded Securities Cusip Ticker

6.625% Senior Notes due 2020 #165167CF2 CHK20A

6.875% Senior Notes due 2020

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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

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8.00% Senior Notes due 2025

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23

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2Q 2019 EARNINGS - filecache.investorroom.comfilecache.investorroom.com/mr5ir_chk/504/download... · 2Q 2019 Earnings 2 This presentation includes “forward-looking statements”