Howard weil march 2017 final

2017 SCOTIA HOWARD WEIL ENERGY CONFERENCE

March 28, 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.

HOWARD WEIL ENERGY CONFERENCE 2

OUR STRATEGYRELEVANT THROUGH COMMODITY PRICE CYCLES

Profitable and Efficient Growth

from Captured Resources

ExplorationBusiness Development

Financial Discipline


Near term focus – What we are doing now

Increased return on capital – shorter cycle times

Margin growth – cost leadership

Base optimization improvement – 11,000+ producing wells

Portfolio management – divestitures, smart additions, reducing debt

Safety and environmental stewardship

30%

15%

10%5%

5%

15%

20%

2017 D&C Asset Funding

Eagle Ford

Utica

Haynesville

Marcellus

OtherPowder

River

Mid-Continent

2017 CAPITAL ALLOCATIONFLEXIBLE PROGRAM – VALUE FOCUSED


Eagle Ford Shale

< $40/bbl breakeven

6 Rigs / 3 Frac Crews

Haynesville Shale

< $2.35/mcf breakeven


Mid-Continent

< $40/bbl breakeven


Powder River Basin

$35 – $45/bbl breakeven

2 Rigs / 1 Frac Crew

Utica Shale

$2.15/mcf breakeven


Marcellus Shale

$2.00/mcf breakeven

1 Rig / 1 Frac Crew

Price Deck: $3/mcf and $60/bbl oil flat

Capital allocation drivers • High margin production growth

• Cash generating capability

• Available infrastructure and operational efficiency

POWDER RIVER BASIN – TURNER SANDSTONEEXCEPTIONAL FIRST WELL

• What we have confirmed

˃ Great rock quality,

higher pressure

˃ Control of thickest pay zone

in southern area

˃ ~300+ undrilled locations

˃ 2,640' spacing assumed

˃ 140,000 net acres prospective

• What does it mean

˃ EUR: ~1,350 mboe (1)

˃ Single well ROR: ~75% (2)

(1) Reflects Turner Oil Phase appraisal type curve

(2) Assumes $3 gas and $60 oil flat

(3) PV10 positive breakeven price assuming $3 gas price and $60 oil price

2,325 boe/d (78% oil)TIL 3/16/2017

7,100' lateral


Teapot

ParkmanE, A, B/C & Deep

Surrey

Sussex

Niobrara

Turner

Frontier

Mowry~$35/bbl(3)

Breakeven

POWDER RIVER BASIN – SUSSEXPRODUCTION ACCELERATION

(1) IHS data



Moving to developmentActive in 2017 drilling 15 – 25 wells

with 15 – 25 TILs including 3 DUCs

8,100'Extended lateral program

Average length in 2017

150+ locationsAssumes 1,320' spacing

<$40/bbl(2)

Breakeven

Best Sussex in the PRBTeapot


Surrey

Sussex

Niobrara

Turner

Frontier

Mowry

3Q 2017 1st production from multi-well pads

POWDER RIVER BASIN2 RIGS AND OPTION TO ACCELERATE

• More Turner results coming

˃ Second Turner completion

underway

• First Parkman result in May

˃ Completion underway

• Mowry results late Q2 – early Q3

˃ Drilling operations in progress

• First Sussex pad results in Q3


Teapot


Surrey

Sussex

Niobrara

Turner

Frontier

Mowry

Upcoming

POWDER RIVER BASINOFF TO A GREAT START

90% undevelopedAverage 80% working interest


307,000 acres80% HBP/HBU/HBO

48% Federal acreage

~2.7 bboe Of resource potential

~2,600 risked locations Teapot


Surrey

Sussex

Niobrara

Turner

Frontier

Mowry

150 mmboe resource base

150+ undrilled locations

1,450 mmboe resource base








35%

16%

49%

Resource Mix

Oil NGL Natural Gas

OSWEGO UPDATELOW-COST, HIGH RETURN OIL GROWTH

(1) Price Deck: $3/mcf and $50/bbl oil flat


40 MILES

40 M

ILE

S

Lightle 4-18-6 1HIP 30 = 1,462 boe/d, 88% oil

Hasty 3-18-6 1HIP 30 = 1,033 boe/d, 87% oil

Caldwell 22-18-6 1HIP 30 = 1,813 boe/d, 80% oil

Themer 6-17-6 1HIP 30 = 832 boe/d, 86% oil

Hughes Trust 33-18-7 1HIP 30 = 1,326 boe/d, 95% oil

Farrar 11-18-6 1HIP 30 = 1,059 boe/d, 87% oil

Hill 2-18-6 1HIP 30 = 1,223 boe/d, 86% oil

Eugene 29-18-6 1HIP 30 = 824 boe/d, 79% oil

Morris 31-18-6 2HIP 30 = 938 boe/d, 91% oil Morris 31-18-6 1H

IP 30 = 881 boe/d, 92% oil

~80% ROR at $50 oil (1)

> $3.2MM/well development cost

delivering 400 mboe EUR

(83% liquids)

Rapid and reliable oil growth

> 10 wells averaging IP30 of

1,140 boe/d with 2 rigs drilling

core inventory in 2017

Quick return on investment

> Cycle time 38 days spud to TIL

MID-CONTINENT PORTFOLIO UPDATEOPTIMIZING OUR POSITION FOR MAXIMUM VALUE

Develop

˃ TIL 40 – 50 Wedge wells in 2017

˃ Drill spacing tests

˃ Drill extended laterals

˃ Optimize completion design

Grow

˃ Test new horizons

˃ Bolted-on 19,300 acres in Major County

for $26 million

˃ Farmed-in 6,700 acres in Major County

Divest

˃ Multiple divestment packages currently

in progress south and east of focus area

(1) PR* – Peak Daily rate shown due to well not having 30 days of production


Schoeppel 1HMeramec (St. Genevieve)

IP 30 = 977 boe/d, 50% oil

Hoskins 1HMeramec (St. Genevieve)

IP 30 = 1,185 boe/d, 60% oil

Hunt 1HMeramec (Stack)

IP 30 = 1,050 boe/d, 45% oil

Johnston 1HMeramec (Stack)

IP 30 = 1,360 boe/d, 31% oil

Stephen 1HOsage (Pipeline Constrained)

PR* = 891 boe/d, FTP = 1,804 PSI

Hoskins 2HMeramec (St. Genevieve)

PR* = 1,357 boe/d, 65% oil(1)

GULF COASTTECHNOLOGY DRIVING RENAISSANCE

Continuing to deliver monster IPsGLD 1H – 42 mmcf/d, 8,200' lateral, 1Q 2017 TIL

Six J 1H – 35 mmcf/d, 10,000' lateral, 1Q 2017 TIL

ROTC 1H – 40 mmcf/d, 10,000' lateral, 4Q 2016 TIL

CA 1H – 38 mmcf/d, 10,000' lateral , 2Q 2016 TIL

(1) PV10 positive breakeven price

ROTC 1H

CA 1H

Six J 1H, GLD 1H


1,200+ locationsPost-divestiture and optimized for

longer lateral development

<$2.35/mcf(1)

Breakeven

EAGLE FORDUNDRILLED ACREAGE, POSITIONED FOR GROWTH

(1) Net processed production mix


~260,000 Net Acres in Eagle Ford – 99% HBP/HBO

56%19%

25%

Production Mix (1)

Oil NGL Natural Gas

<$40(2)

Breakeven


3,200+ locationsLower Eagle Ford standard spacing

5 – 6 rigsActive in 2017 drilling 175 – 195

wells with 155 – 175 TILs

EAGLE FORD LONG LATERAL DEVELOPMENT REDUCES PAYOUT ~45% COMPARED TO STANDARD LATERALS

13HOWARD WEIL ENERGY CONFERENCE

Long laterals improve

capital efficiency

and create shorter

reinvestment cycles0

5

10

15

20

25

30

35

0 50 100 150 200 250 300 350

NO

RM

ALIZ

ED

AV

G.

CU

M O

IL

(MB

O/$

MM

)

DAYS

2 - East

21

EastAvg LL: 12,600’

IP30: 1,346 BOE/D

94% Oil

CentralAvg LL: 12,950’

IP30: 977 BOE/D

92% Oil

0

5

10

15

20

25

30

35

0 50 100 150 200 250 300 350

NO

RM

ALIZ

ED

AV

G.

CU

M O

IL

(MB

O/$

MM

)

DAYS

1 - Central

2017

2016

2013 - 2015

2017

2016

2013 - 2015

APPALACHIA: ONE BASIN, TWO OUTSTANDING ASSETSMARCELLUS & UTICA SHALES – FREE CASH FLOW GROWTH

>$800mm In projected FCF generation

from 2017 – 2018


Maximizing valueYTD performance exceeding plan by optimizing production during favorable pricing

Improving LOE>20% / BOE reduction from Q1 2016 – YTD

97 88100

0

50

100

150

200

250

300

350

400

$-

$100

$200

$300

$400

$500

$600

2016 2017E 2018E

Ne

t p

rod

uctio

n (

mm

bo

e)

($m

m)

2016 – 2018 Projected Free Cash Flow(1)

and Production(Excluding Hedges)

2017 Budget Actual Production (mmboe)

Jan – Feb

Actuals

(1) Assumes $3.15 / $52 for 2017 and $3 / $60 in 2018

Free cash flow defined as net revenue less all operating, gathering, processing and transportation expenses, production taxes and capital expenditures

CHESAPEAKE OPERATING PERFORMANCERELENTLESS FOCUS ON COST MANAGEMENT


$0.00

$5.00

$10.00

$15.00

$20.00

$25.00

CHK A B C D E F G H I J K

$/b

oe

2016 Production Expense (1)

$3.05/boe2016 production expense

Base production optimization

Supply chain synergies

Maintaining EHS excellence

(1) Production expense defined as the total of lease operating expenses, ad valorem taxes and other production expenses

Peer Group includes: APC, APA, COP, DVN, ECA, EOG, HES, MRO, MUR, NBL and OXY

CHESAPEAKE CAPITAL EFFICIENCYRELENTLESS FOCUS ON CAPITAL DEPLOYED


$-

$10.00

$20.00

$30.00

$40.00

$50.00

$60.00

$70.00


$/b

oe

2016 Proved F&D Costs (1)

15 mcf to 1 boe

$-

$10.00

$20.00

$30.00

$40.00

$50.00

$60.00


$/b

oe

2016 Proved F&D Costs (1)

6 mcf to 1 boe

(1) Source: 2016 10-K filings. Proved reserve F&D costs defined as the sum of the development and exploration costs divided by proved reserves added by extensions, additions and discoveries.

Peer Group includes: APC, APA, COP, DVN, ECA, EOG, HES, MRO, MUR, NBL and OXY

Operational leadership and technical capabilities

provide peer-leading cost management

~$2.35/boe ~$3.40/boe


Resilient, strong, diverse portfolio

Balance sheet and liquidity improvement

Oil growth on track from PRB, Mid-Con and Eagle Ford

Industry-leading operating performance and capital efficiency

Investment Thesis

OPTIMIZING DOWNSTREAM COMMITMENTS

Assumes Seaway and MEP buy down

~$560mm additional commitment reductions

with Seaway and MEP buy down

($mm) 2017 2018 2019 2020 2021 Thereafter

Haynesville 355 149 147 125 114 419

Northeast 373 401 401 401 399 3,580

Eagle Ford 363 334 332 335 255 1,085

Other 248 222 187 127 125 122

Total (1) 1,339 1,107 1,067 989 894 5,205

GP&T Commitments ($ billion)

YE’14 YE’15 YE’16 YE’17

$16.0 $14.0 $11.1 $9.3E

~$7 billion reduction In midstream and marketing

commitments since 2014

Commitment being fully utilized; CHK projects overall estimate of ~90% utilization company-wide

Reducing commitments


Optimizing commitments to further increase EBITDA

DEBT MATURITY PROFILE

Pro forma tender results, OMRs, 6.25% Euro note maturity and 6.50% 2017 redemption


HEDGING POSITION

(1) As of 2/6/16, using midpoints of total production from 2/14/2017 Outlook

Oil2017 (1)

68%

Swaps $50.19/bbl

Natural Gas2017 (1)

71%

68%Swaps

3%Collars

$3.00/$3.48/mcfNYMEX

$3.07/mcfNYMEX

NGL2017 (1)

7%

Ethane Swaps $0.28/gal


~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

CORPORATE INFORMATION

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

7.25% Senior Notes due 2018 #165167CC9 CHK18A

3mL + 3.25% Senior Notes due 2019 #165167CM7 CHK19

6.625% Senior Notes due 2020 #165167CF2 CHK20A

6.875% Senior Notes due 2020 #165167BU0 CHK20

6.125% Senior Notes due 2021 #165167CG0 CHK21

5.375% Senior Notes due 2021 #165167CK21 CHK21A

8.00% Senior Secured Second Lien Notes due 2022#165167CQ8 N/A

#U16450AT2 N/A

4.875% Senior Notes due 2022 #165167CN5 CHK22

5.75% Senior Notes due 2023 #165167CL9 CHK23

8.00% Senior Notes due 2025#165167CT2 N/A

#U16450AU99 N/A

5.50% Contingent Convertible Senior Notes due 2026 #165167CR6 N/A

2.75% Contingent Convertible Senior Notes due 2035 #165167BW6 CHK35

2.50% Contingent Convertible Senior Notes due 2037#165167BZ9/

#165167CA3CHK37/ CHK37A

2.25% Contingent Convertible Senior Notes due 2038 #165167CB1 CHK38

4.5% Cumulative Convertible Preferred Stock #165167842 CHK PrD

5.0% Cumulative Convertible Preferred Stock (Series 2005B)#165167834/

N/A#165167826

5.75% Cumulative Convertible Preferred Stock

#U16450204/

N/A#165167776/

#165167768

5.75% Cumulative Convertible Preferred Stock (Series A)

#U16450113/

N/A#165167784/

#165167750

Chesapeake Common Stock #165167107 CHK


http://www.chk.com/

mailto:[email protected]

Howard weil march 2017 final

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