Chesapeake Presentation at 2016 Heikkinen Energy Conference

2016 HEIKKINEN ENERGY CONFERENCE August 24, 2016

FORWARD-LOOKING STATEMENTS

This news release and the accompanying Outlook include "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 news release, 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.

2016 Heikkinen Energy Conference 2

2016 KEY ACHIEVEMENTS TO DATE

• Barnett Shale exit and elimination of Barnett midstream commitments

˃ EBITDA uplift of $200mm - $300mm for the remainder of 2016 and 2017, respectively

˃ Reduced Mid-Con gathering expense by 36% and moved to a fixed-fee gathering agreement

• Portfolio strength and operational efficiencies continue to deliver

˃ Raised production guidance while reiterating capex guidance range despite YTD asset divestitures

of ~35,000 boe/d

• Transformational change in Haynesville Shale economics and well

productivity

˃ Extended laterals and optimized completions significantly enhance economics across the field

˃ Purchased ~70,000 net acres in the Haynesville for $87mm; primarily in existing operating units,

increasing WI to 83%; internal reserve value of ~$200mm at 7/1 strip pricing

• ~$1.0 billion in proceeds from asset divestitures YTD

> Year-end gross divestiture proceeds expected to be in excess of $2 billion


CHESAPEAKE’S FOCUS IN 2016WHAT WE PLAN TO DO

(1) Includes general and administrative expenses, including stock based compensation.

(2) Includes production expenses and general and administrative expenses, including stock based compensation.

2016 Heikkinen Energy Conference

2016 Plan 2016 Progress to Date

Maximize

Liquidity

□ Reduce capital budget by >50%

□ 10% reduction in LOE/boe

□ 15% reduction in G&A/boe (1)

■ Raised 2016 production guidance and reiterated

capex guidance

■ Reduced cash costs by 25% second quarter YOY (2)

Optimize

Portfolio

□ Close on $700mm in signed asset divestitures

□ $500 – $1,000mm in additional asset divestitures

□ Fund short-cycle cash-generating projects

■ Exited the Barnett Shale

■ $1.0 billion in asset divestitures YTD

■ Year-end gross divestiture proceeds expected to be

in excess of $2 billion

■ Acquired ~70,000 net acres in the Haynesville

Increase

EBITDA

□ Improve gathering and transportation agreements

□ 2016 capital program focusing on TILS

□ Reduce base decline rate by 10%

■ EBITDA uplift of $200mm - $300mm in 2016 and

2017, respectively

■ Reduced gathering costs by 36% in the Mid-

Continent

Debt

Management/

Elimination

□ Proactive liability management

□ Open market repurchases of debt

□ Focus on 2017 and 2018 maturity management

■ $1.5 billion term loan secured

■ Reduced 2017 maturing/puttable debt by ~$830mm

since 9/30/15

■ ~$730mm in incremental liquidity since 9/30/2015

due to proactive liability management

4

BARNETT EXIT AND WILLIAMS RENEGOTIATIONSTRENGTHENING THE FOUNDATION OF THE BUSINESS

• Chesapeake conveyed Barnett interests to a private company

˃ Eliminated current gathering agreement, minimum volume

commitments, and fees pertaining to Barnett Shale assets

˃ Williams will receive ~$334mm from CHK and an additional

sum from the private company


~$1.9 Billion Midstream Commitments Eliminated

Transaction Highlights

Net Acres ~215,000

Operated Well Count 2,855

Avg. Q2 2016 Production 65 mboe/d

Proved Reserves (12/31/15) 81 mmboe

36% Reduction in Mid-Continent Gathering Costs

• Renegotiated Mid-Continent gathering agreement in exchange for

a payment of $66 million

~$715mm Reduction in total GP&T

expenses in 2016 and 2017 (2)

$200 - $300mmIncrease in annual operating

income from 2016 through 2019 (1)

~$550mm Uplift to total company PV10 (3)

Barnett

Mid-Con

Together, these transactions provide:

(1) Before charges and other termination costs associated to this transaction.

(2) Gathering, processing, and transportation expenses, inclusive of projected MVC shortfall payments.

(3) At December 31, 2015. See “Non-GAAP financial measures” on page 2.

$8.43

$8.55 $8.58

$7.60 – $8.10

2014 2015 2016E 2016E New 2017E New

GP&T $/boe (incl. MVC shortfall) (1)

$7.15 - $7.65

GATHERING, PROCESSING & TRANSPORTSUBSTANTIAL COST STRUCTURE IMPROVEMENT GOING FORWARD


(1) Includes all actual and projected MVC payments; 2016E represents guidance midpoint.

2017 GP&T expenses expected to improve by ~14% after

midstream transactions

GP&T expense

expected to be

reduced by

~9% in 2016

6

2Q’16 RESERVE VALUE WALKSEC VS. NYMEX PRICING

~$8.0 billionUplift in reserve value at NYMEX

pricing vs. 6/30/16 SEC valuation


$3.1

$5.8

$2.2 $11.1

$0

$2

$4

$6

$8

$10

$12

PV10 @ SEC 12-monthtrailing price deck

NYMEX PriceDeck Uplift

Previously ExcludedVolume Uplift

PV10 @ NYMEX

Pre

sent

Valu

e (

$B

)

(1) (2)

80% PDP

20% PUD

61% PDP

39% PUD

• Significant leverage to

natural gas pricing

• PV-9 at 6/30 NYMEX strip

pricing of $11.9 billion

> Used for bank collateral

determination

(1) Uplift in value attributable to properties that run at SEC pricing ($43/$2.24), but valued at 6/30/16 NYMEX pricing (2016: $49/$3.02, 2017: $52/$3.18, 2018: $54/$3.02).

(2) Uplift in value attributable to properties that run only at NYMEX pricing.

$382 $336

$660

$315

$1,168

$730

$0

$500

$1,000

$1,500

$2,000

$2,500

$3,000

$3,500

9/30/15 Outstanding 6/30/16 Outstanding

2.50% 2037 6.5% 2017 6.25% 2017


$2,210

$1,381 (1)

~$730mm Total incremental liquidity since 9/30/2015

through proactive liability management (3)

Financial Transaction Liquidity Savings

Debt Exchange$305mm of new

2nd lien$291mm

Open Market

Repurchases$99mm of cash $86mm

Equity for Debt

Exchanges

68.6mm shares

(valued at $295mm)$354mm

From 9/30/2015 through 6/30/2016, reduced

2017 maturing/puttable debt obligations by

~$830mm

38% REDUCTION IN 2017 MATURING/PUTTABLE DEBT

$3,091 (2)

Available

Liquidity

(1) 6.25% 2017's converted to USD for entire period using exchange rate of $1.1106 to €1.00 as of 6/30/16

(2) $4.0B credit facility plus cash, less outstanding borrowings and letters of credit as of 6/30/16

(3) Incremental liquidity savings includes principal savings and net interest impact

CONTINUOUS IMPROVEMENT OF CASH COSTS

• Plan to reduce G&A by 15%

and LOE by 10% in 2016

• Progress being made on both fronts

in early 2016

> 25% reduction in $/boe cash

costs in second quarter YOY (1)

> ~$102mm reduction in cash

costs YOY in 2Q (1)

• History of continuous cash cost

improvement


$7.76

$6.60$5.93

$5.17

2012 2013 2014 2015 2016 E

Annual Cash Costs ($/boe)

$3.90 – $4.30 (2)

(1)

(1)

$5.75$5.40

$4.87 $4.64$4.14 $4.07

1Q'15 2Q'15 3Q'15 4Q'15 1Q'16 2Q'16

Quarterly Cash Costs ($/boe)

(1) Includes production expenses and general and administrative expenses, including stock based compensation.

(2) Guidance as of August 4, 2016.

9

Marcellus Shale134 mboe/d net (1)

Spud: 0-5 / TIL: 20

Utica Shale (2)

146 mboe/d net (1)

Spud: 20-25 / TIL: 45-55

Eagle Ford Shale92 mboe/d net (1)

Spud: 95-105 / TIL: 195-205

Powder River Basin16 mboe/d net (1)

Spud: 0 / TIL: 5

Mid-Continent78 mboe/d net (1)

Spud: 50-60 / TIL: 85-95

Haynesville Shale126 mboe/d net (1)

Spud: 25-35 / TIL: 45-55

SUBSTANTIAL ASSET PORTFOLIOSIGNIFICANT VALUE IN DEVELOPED AND UNDEVELOPED ACREAGE


(1) Average daily production 2Q’16.

(2) Includes production volumes from legacy Devonian wells in West Virginia and Kentucky.

10

Barnett Shale65 mboe/d net (1)

Spud: 0 / TIL: 0

UNRECOGNIZED VALUE, UNLOCKED POTENTIALDEPTH AND BREADTH OF PORTFOLIO


(1) Economics run at $3/mcf and $60/bbl oil flat.

(2) Operated gross locations.

(3) Includes upper Eagleford and Austin Chalk locations.

Tremendous resource optionality provides Chesapeake a competitive

advantage for years to come

10,500+ locations>20% ROR remaining

in the portfolio (1)(2)

(3)

1,110

2,400

600

1,900

200

650

2,500+

2,400

275

50

350

1,350 425

1,750

550

2,250

350

275

500

Eagle Ford Mid-Continent Marcellus Powder River Haynesville Utica Exploration andTechnology

Opportunities

0% - 20% ROR20% - 40% ROR>40% ROR

(1) Economics run at $3/mcf flat.

3%

18%

25%

37%

47%

5,000'Springridge

Lateral

7,500'Springridge

Lateral

10k SpringridgeLateral

10k CA 12&13-15-15 2H

10k CA 12&13-15-15 1H

Rate of Return (1)

Longer Laterals

Reduced

D&C Costs

Enhanced

Completion &

High IP

2014 20162015


HAYNESVILLE SHALEGAME CHANGING SHIFT IN ECONOMICS

• Completions optimization and extended laterals

significantly increases ROR and NPV in all areas

• CA 1H confirms the ability to flow at higher sustained

rates in Haynesville utilizing larger stim design

CA 1H38 MMcfd & 7,450 psi;

25 psi/day drawdown

3,000 lbs/ft proppant

CA 2H23 MMcfd & 7,400 psi;


PCK 2H23 MMcfd & 7,640 psi;


PCK 1H31 MMcfd & 7,680 psi;


CHK Operated Rigs

CHK Leasehold

10,000’ Wells

Completion Tests

Nabors 2H & 3HDrilled X-Unit laterals;

Q3 3,000 and 5,000

lbs/ft completion test

Bossier ParishQ4 10,000’ lateral;

5,000 lbs/ft completion test

PKY 1HQ3 10,000’ lateral;

4,000 lbs/ft completion test


HAYNESVILLE SHALEGAME CHANGING WELL PERFORMANCE

Extended laterals with modern completions delivering exceptional returns

(1) All well costs add 6.5% to field estimates.

(2) Economics are run at $3/mcf flat.

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

0 5 10 15 20 25 30 35

Casin

g P

ressure

(psi)

Gas R

ate

(M

cfd

)

Producing Days

CA 1H Gas Rate PCK 1H Gas Rate CA 1H Csg Pressure PCK 1H Csg Pressure

CA 1H (3,000 lbs/ft) - 38 MMcfd

PCK 1H (2,700 lbs/ft) - 31 MMcfd

Lateral Length Well Cost (1) IP EUR ROR (2)

CA 1H (3,000 lbs/ft) 10,000’ $9.8MM 38 MMcfd 22 - 24 Bcf 47%

PCK 1H (2,700 lbs/ft) 7,500’ $8.4MM 31 MMcfd 15 - 17 Bcf 31%


• Leading edge well design increases

field-wide productivity

˃ Majority of the play now performs as

well as the historical core

Significant high-quality inventory offers value acceleration

through select divestment opportunities

Increasing EUR/Lateral Ft.

1 Bcf/Mft 2.5 Bcf/Mft

• World-class gas asset with access

to gulf markets with existing

infrastructure

˃ 8 – 10 development program years of

extended lateral drilling remaining after

planned divestitures

• Purchased ~70K net acres for $87mm

˃ Acquisition primarily within existing CHK

operated units; increases WI to 83%

Historical

Core

Economics

CA & PCK

1.4 Bcf/Mft

1.3 Bcf/Mft

2.1 Bcf/Mft

1.5 Bcf/Mft

Historical Haynesville

EUR/Lateral Ft.

Current Core Economics

CA & PCK

2.3 Bcf/Mft

2.0 Bcf/Mft

2.3 Bcf/Mft

2.5 Bcf/Mft

Go-Forward Haynesville

EUR/Lateral Ft.

HAYNESVILLE SHALEFULL-FIELD TRANSFORMATION

EAGLE FORD SHALECAPITAL EFFICIENCY DRIVING COMPETITIVE RETURNS

• Outstanding well performance to

date for extended lateral program

• Per-foot development costs

reduced by ~50%

• Current returns on development

program at $45/bbl oil

outcompete 2014 program at

$80/bbl oil (1)


25 – 65%Expected ROR for 2016 development program (1) (2)

15

0

25

50

75

100

125

0

10

20

30

40

50

60

70

80

90

100

110

120

130

Cum

ula

tive

Oil

Mb

o

Cumulative Oil Production

Test Avg. LL 9,900'

Control Avg. LL 4,983'

(1) 2016 economics @ July 11, 2016 strip pricing.

(2) Based on spud date.

(3) Average cost per foot of wells drilled and/or completed within the time period.

5,6006,500

9,000 9,300

10,500

4,000

6,000

8,000

10,000

12,000

2014 YE 2015 Avg. 2016 1Q 2016 2Q YE Goal

La

tera

l L

en

gth

(ft

.)

Lateral Length (2)

$1,000$923

$488 $430 $405

$0

$200

$400

$600

$800

$1,000

$1,200

2014 YE 2015 Avg. 2016 1Q 2016 2QE YE Goal

To

tal W

ell

Cost p

er

La

tera

l F

oo

t

Cost per Foot (3)

MID-CONTINENTTREMENDOUS GROWTH INVENTORY

16

(1) Price Deck: $3/$60 flat.

850Inventory locations above

20% ROR (1)

15+ Different formations

currently being appraised


CHK Acreage

~1,500,000Net acres in the Mid-Continent

Recent exploration success provides additional inventory

CONTINUE TO DELIVER IN 2016

$1.5 billion term loan secured; ~$730mm incremental liquidity

generated through proactive liability management (1)


(1) Since 9/30/2015, as of 6/30/16.

17

~$1.0 billion in proceeds from asset divestitures YTD; Year-

end gross proceeds expected to be in excess of $2 billion

Recent transactions enhance EBITDA by ~$500mm through

2017; Reduced cash costs by 25% in second quarter YOY

Reduced 2017 maturing/puttable debt by ~$830 million (1)

APPENDIX


$1,381

$846

$949

$1,126

$861

$607

$384

$2,425

$830

$169

$551

$1,070

$839

$893

$716

2017 2018 2019 2020 2021 2022 2023

$1,381

$846

$949$861

$607

$384

$1,126

MATURITY PROFILEPROACTIVE LIABILITY MANAGEMENT


(1) Debt principal removed from books in 2015 and 2016, as of 6/30/16.(2) Recognizes earliest investor put option as maturity for the 2.50% 2037 and 2.25% 2038 Contingent Convertible Senior Notes.(3) Bid prices as of 6/30/16. Euro-notes are converted to USD using exchange rate of $1.1106 to €1.00 (6/30/16).

Debt

Reduction (1)

Unsecured

Notes (2)

2nd Lien

Notes

Market

Value (3)

(2)

$79.2mm Annual interest payment reduction from

all liability management transactions

$3.1 billion Debt principal removed from books

in 2015 and 2016 as of 6/30/16

HEDGING POSITION (1)


32%

71%74%

(1) For July - December 2016 production as of August 1, 2016

Swaps $46.60/bbl Ethane Swaps $0.17/gal

Propane Swaps $0.46/gal

Natural Gas2016

Oil2016

NGL2016

267 bcf of 2017 gas volumes hedged with swaps @ $3.02/mcf

23 bcf of 2017 gas volumes hedged with $3.00/$3.48 collars

7.7 mmbbl of 2017 oil volumes hedged with swaps @ $47.49/bbl

$3.00 / $3.48/mcf

NYMEX $2.76/mcf

NYMEX

71%

Swaps

3%

Collars

RECONCILIATION OF PV-9 AND PV-10 TO STANDARDIZED MEASURE($ IN MILLIONS; UNAUDITED)


PV-9 is a non-GAAP metric used to determine the value of collateral under our credit facility. PV-10 is a non-GAAP metric used

by the industry, investors and analysts to estimate present value, discounted at 10% per annum, of estimated future cash flows

of our estimated proved reserves before income tax and asset retirement obligations. The following table shows the

reconciliation of PV-9 and PV-10 to our standardized measure of discounted future net cash flows, the most directly

comparable GAAP measure, for the year ended December 31, 2015 and for the interim period ended June 30, 2016.

Management believes that PV-9 provides useful information to investors regarding our collateral position and that PV-10

provides useful information to investors because it is widely used by professional analysts and sophisticated investors in

evaluating oil and natural gas companies. Because there are many unique factors that can impact an individual company when

estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable for evaluating our

company. Neither PV-9 nor PV-10 should be considered as an alternative to the standardized measure of discounted future net

cash flows as computed under GAAP. With respect to PV-9 and PV-10 calculated as of an interim date, it is not practical to

calculate taxes for the related interim period because GAAP does not provide for disclosure of standardized measure on an

interim basis.

CORPORATE INFORMATION

PUBLICLY TRADED SECURITIES CUSIP TICKER

6.25% Senior Notes due 2017 #027393390 N/A

6.50% Senior Notes due 2017 #165167BS5 CHK17

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

#U16450AT2

N/A

N/A

4.875% Senior Notes Due 2022 #165167CN5 CHK22

5.75% Senior Notes Due 2023 #165167CL9 CHK23

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

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

#165167CA3

CHK37/

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/

#165167826N/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

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]


http://www.chk.com/

mailto:[email protected]

Date post:	23-Jan-2017
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Chesapeake Presentation at 2016 Heikkinen Energy Conference

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