2Q’16 EARNINGSAugust 4, 2016

2Q'16 Earnings 2

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.

2Q'16 Earnings 3

2016 KEY ACHIEVEMENTS TO DATE

• Portfolio strength and operational efficiencies continue to deliver˃ Raised production guidance while reiterating capex guidance range despite asset

divestitures of ~35,000 boe/d; portfolio continues to outperform˃ Cost structure continues to improve with 2Q’16 cash costs decreasing 25% YOY (1)

• 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 CHK operated units, increasing WI to 83%; internal reserve value of ~$200mm at 6/30 strip pricing

• ~$1.0 billion in proceeds from asset divestitures YTD> Year-end gross divestiture proceeds expected to be in excess of $2 billion> Any future A&D transactions will seek to further strengthen the portfolio(1) Includes production expenses and general and administrative expenses, including stock based

compensation.

2Q'16 Earnings 4

CHESAPEAKE’S FOCUS IN 2016WHAT WE PLAN TO DO

2016 Plan 2016 Progress to Date

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

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

■ $1.0 billion in asset divestitures proceeds 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%

■ Continued positive discussion around gathering and transportation agreements

■ Further reduced operating expense guidance

Debt Management/Elimination

□ Proactive liability management□ Open market repurchases of debt□ Focus on 2017 and 2018 maturity

management

■ Reduced 2017 maturing/puttable debt by ~$830mm since 9/30/15

■ ~$730mm in incremental liquidity since 9/30/2015 due to proactive liability management

5

2Q’16 RESERVE VALUE WALKSEC VS. NYMEX PRICING

~$8.0 billionUplift in reserve value at NYMEX pricing vs. 6/30/16 SEC valuation

2Q'16 Earnings

PV10 @ SEC 12-month trailing price deck

NYMEX Price

Deck Uplift

Previously Excluded Volume Uplift

PV10 @ NYMEX$0

$2,000,000

$4,000,000

$6,000,000

$8,000,000

$10,000,000

$12,000,000

$3,055,306.0

$5,776,104.0

$2,219,178.0 $11,050,588.0

Pres

ent V

alue

($B)

(1) (2)

80% PDP20% PUD

61% PDP39% 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.

2Q'16 Earnings 6

9/30/15 Outstanding 6/30/16 Outstanding$0

$500

$1,000

$1,500

$2,000

$2,500

$3,000

$3,500

$382 $336

$660$315

$1,168

$730

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

2Q'16 Earnings 7

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

2012 2013 2014 2015 2016 E

$7.76$6.60

$5.93$5.17

Annual Cash Costs ($/boe)

$3.90 – $4.30 (2)

(1)

(1)

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

$5.75 $5.40$4.87 $4.64 $4.14 $4.07

Quarterly Cash Costs ($/boe)

(1) Includes production expenses and general and administrative expenses, including stock based compensation.(2) Guidance as of August 4, 2016.

82Q'16 Earnings

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.

Barnett Shale65 mboe/d net (1)

Spud: 0 / TIL: 0

2Q'16 Earnings 9(1) Economics run at $3/mcf flat.

5,000' Springridge

Lateral

7,500' Springridge

Lateral

10k Springridge

Lateral

10k CA 12&13-15-15

2H

10k CA 12&13-15-15

1H

3%

18%25%

37%

47%

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; 1,600 lbs/ft proppant

PCK 2H23 MMcfd & 7,640

psi; 1,600 lbs/ft proppant

PCK 1H31 MMcfd & 7,680

psi; 2,700 lbs/ft proppant

CHK Operated RigsCHK Leasehold10,000’ WellsCompletion Tests

Nabors 2H & 3H

Drilled 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

2Q'16 Earnings 10

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 5 10 15 20 25 30 350

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

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

Producing Days

Gas R

ate

(Mcf

d)

Casin

g Pr

essu

re (p

si)

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%

2Q'16 Earnings 11

• 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

EconomicsCA & 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 & PCK2.3

Bcf/Mft

2.0 Bcf/Mft

2.3 Bcf/Mft

2.5 Bcf/Mft

Go-Forward Haynesville

EUR/Lateral Ft.

HAYNESVILLE SHALEFULL-FIELD TRANSFORMATION

2Q'16 Earnings 12

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)

0 10 20 30 40 50 60 70 80 90 100

110

120

130

0

25

50

75

100

125 Cumulative Oil ProductionTest Avg. LL 9,900'

Cum

ulat

ive O

il Mbo

(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.

2014 YE

2015 Avg.

2016 1Q 2016 2Q YE Goal

4,000

6,000

8,000

10,000

12,000

5,6006,500

9,000 9,30010,500

Lateral Length (2)

Late

ral L

engt

h (ft

.) 2014

YE 2015 Avg.

2016 1Q 2016 2QE YE Goal

$0$200$400$600$800

$1,000$1,200 $1,000 $923

$488 $430 $405

Cost per Foot (3)

Tota

l Well

Cos

t per

La

tera

l Foo

t

13

MID-CONTINENTTREMENDOUS GROWTH INVENTORY

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

850Inventory locations above 20% ROR (1)

15+ Different formations currently being appraised

2Q'16 Earnings

CHK Acreage

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

Recent exploration success provides additional inventory

14

CONTINUE TO DELIVER IN 2016

~$730mm incremental liquidity generated through proactive liability management (1)

2Q'16 Earnings

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

~$1.0 billion in proceeds from asset divestitures YTD; Year-end gross proceeds expected to be in excess of $2 billion

Reduced cash costs by 25% in second quarter YOY; further reduced operating expense guidance

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

15

APPENDIX

2Q'16 Earnings

2Q'16 Earnings 16

$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

2Q'16 Earnings 17

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/galPropane Swaps $0.46/gal

Natural Gas2016

Oil2016

NGL2016

267 bcf of 2017 gas volumes hedged with swaps @ $3.02/mcf23 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/mcfNYMEX $2.76/mcf

NYMEX

71% Swaps

3% Collar

s

2Q'16 Earnings 18

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.

192Q'16 Earnings

CORPORATE INFORMATION

PUBLICLY TRADED SECURITIES CUSIP TICKER6.25% Senior Notes due 2017 #027393390 N/A6.50% Senior Notes due 2017 #165167BS5 CHK177.25% Senior Notes due 2018 #165167CC9 CHK18A3mL + 3.25% Senior Notes due 2019 #165167CM7 CHK196.625% Senior Notes due 2020 #165167CF2 CHK20A6.875% Senior Notes due 2020 #165167BU0 CHK206.125% Senior Notes Due 2021 #165167CG0 CHK215.375% Senior Notes Due 2021 #165167CK21 CHK21A8.00% Senior Secured Second Lien Notes due 2022 #165167CQ8

#U16450AT2N/AN/A

4.875% Senior Notes Due 2022 #165167CN5 CHK225.75% Senior Notes Due 2023 #165167CL9 CHK232.75% Contingent Convertible Senior Notes due 2035 #165167BW6 CHK352.50% Contingent Convertible Senior Notes due 2037 #165167BZ9/

#165167CA3CHK37/ CHK37A

2.25% Contingent Convertible Senior Notes due 2038 #165167CB1 CHK384.5% 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

HEADQUARTERS

6100 N. Western AvenueOklahoma City, OK 73118WEBSITE: www.chk.com

CORPORATE CONTACTS

BRAD SYLVESTER, CFAVice 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