A copy of Chesapeake Energy's PowerPoint presentation at the Heikkinen Energy Conference in August 2016. Several slides show Chesapeake's shale drilling strategy, which will focus on the Eagle Ford and Haynesville Shale plays in the near-term.

1. 2016 HEIKKINEN ENERGY CONFERENCE
August 24, 2016

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.
2016 Heikkinen Energy Conference 2

3. 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
2016 Heikkinen Energy Conference 3

4. CHESAPEAKE’S FOCUS IN 2016
WHAT 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

5. BARNETT EXIT AND WILLIAMS RENEGOTIATION
STRENGTHENING 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
2016 Heikkinen Energy Conference 5
~$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 - $300mm
Increase 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.

6. $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 & TRANSPORT
SUBSTANTIAL COST STRUCTURE IMPROVEMENT GOING FORWARD
2016 Heikkinen Energy Conference
(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

7. 2Q’16 RESERVE VALUE WALK
SEC VS. NYMEX PRICING
~$8.0 billion
Uplift in reserve value at NYMEX
pricing vs. 6/30/16 SEC valuation
2016 Heikkinen Energy Conference 7
$3.1
$5.8
$2.2 $11.1
$0
$2
$4
$6
$8
$10
$12
PV10 @ SEC 12-month
trailing price deck
NYMEX Price
Deck Uplift
Previously Excluded
Volume Uplift
PV10 @ NYMEX
PresentValue($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.

8. $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
2016 Heikkinen Energy Conference 8
$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

9. 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
2016 Heikkinen Energy Conference
$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

10. Marcellus Shale
134 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 Shale
92 mboe/d net (1)
Spud: 95-105 / TIL: 195-205
Powder River Basin
16 mboe/d net (1)
Spud: 0 / TIL: 5
Mid-Continent
78 mboe/d net (1)
Spud: 50-60 / TIL: 85-95
Haynesville Shale
126 mboe/d net (1)
Spud: 25-35 / TIL: 45-55
SUBSTANTIAL ASSET PORTFOLIO
SIGNIFICANT VALUE IN DEVELOPED AND UNDEVELOPED ACREAGE
2016 Heikkinen Energy Conference
(1) Average daily production 2Q’16.
(2) Includes production volumes from legacy Devonian wells in West Virginia and Kentucky.
10
Barnett Shale
65 mboe/d net (1)
Spud: 0 / TIL: 0

11. UNRECOGNIZED VALUE, UNLOCKED POTENTIAL
DEPTH AND BREADTH OF PORTFOLIO
112016 Heikkinen Energy Conference
(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 and
Technology
Opportunities
0% - 20% ROR20% - 40% ROR>40% ROR

12. (1) Economics run at $3/mcf flat.
3%
18%
25%
37%
47%
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
Rate of Return (1)
Longer Laterals
Reduced
D&C Costs
Enhanced
Completion &
High IP
2014 20162015
2016 Heikkinen Energy Conference 12
HAYNESVILLE SHALE
GAME 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 1H
38 MMcfd & 7,450 psi;
25 psi/day drawdown
3,000 lbs/ft proppant
CA 2H
23 MMcfd & 7,400 psi;
1,600 lbs/ft proppant
PCK 2H
23 MMcfd & 7,640 psi;
1,600 lbs/ft proppant
PCK 1H
31 MMcfd & 7,680 psi;
2,700 lbs/ft proppant
CHK Operated Rigs
CHK Leasehold
10,000’ Wells
Completion Tests
Nabors 2H & 3H
Drilled X-Unit laterals;
Q3 3,000 and 5,000
lbs/ft completion test
Bossier Parish
Q4 10,000’ lateral;
5,000 lbs/ft completion test
PKY 1H
Q3 10,000’ lateral;
4,000 lbs/ft completion test

13. 2016 Heikkinen Energy Conference 13
HAYNESVILLE SHALE
GAME 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
CasingPressure(psi)
GasRate(Mcfd)
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%

14. 2016 Heikkinen Energy Conference 14
• 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 SHALE
FULL-FIELD TRANSFORMATION

15. EAGLE FORD SHALE
CAPITAL 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)
2016 Heikkinen Energy Conference
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
CumulativeOilMbo
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.
5,600
6,500
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
LateralLength(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
TotalWellCostper
LateralFoot
Cost per Foot (3)

16. MID-CONTINENT
TREMENDOUS GROWTH INVENTORY
16
(1) Price Deck: $3/$60 flat.
850
Inventory locations above
20% ROR (1)
15+
Different formations
currently being appraised
2016 Heikkinen Energy Conference
CHK Acreage
~1,500,000
Net acres in the Mid-Continent
Recent exploration success provides additional inventory

17. CONTINUE TO DELIVER IN 2016
$1.5 billion term loan secured; ~$730mm incremental liquidity
generated through proactive liability management (1)
2016 Heikkinen Energy Conference
(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)

18. APPENDIX
2016 Heikkinen Energy Conference 18

19. $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 PROFILE
PROACTIVE LIABILITY MANAGEMENT
2016 Heikkinen Energy Conference 19
(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

20. HEDGING POSITION (1)
2016 Heikkinen Energy Conference 20
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 Gas
2016
Oil
2016
NGL
2016
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

21. RECONCILIATION OF PV-9 AND PV-10 TO STANDARDIZED MEASURE
($ IN MILLIONS; UNAUDITED)
2016 Heikkinen Energy Conference 21
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.

22. 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/
#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 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
2016 Heikkinen Energy Conference 22