CHK 2016 Barclays

BARCLAYS CEO ENERGY-POWER CONFERENCESeptember 8, 2016

2

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 presentation, and we undertake no obligation to update any of the information provided in this presentation, except as required by applicable law.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. Management believes 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. PV-10 should not be considered as an alternative to the standardized measure of discounted future net cash flows as computed under GAAP. With respect to pro forma changes in PV-10, it is not practical to calculate taxes on a pro forma basis because GAAP does not provide for disclosure of standardized measure on such basis.

Barclays CEO Energy-Power Conference

3

OUR STRATEGYRELEVANT THROUGH COMMODITY PRICE CYCLES


Profitable and Efficient GrowthFrom Captured Resources

> Develop world-class inventory> Target top-quartile operating and

financial metrics> Pursue continuous improvement> Drive value leakage out of

operationsExplore

> Leverage innovative technology and expertise

> Explore and exploit new growth opportunities

Business Development> Optimize portfolio through strategic

divestitures> Target strategic acquisitions> Enhance and expand the portfolio

Financial Discipline> Balance capital expenditures

with cash flow from operations> Increase financial and operational

flexibility> Achieve investment grade metrics

Strength and Depth of Portfolio

Operational Leadership

Differential Business Improvement

5

Where we are going2016 – 2020

CHK IS POSITIONED TO OUTPERFORM


Strengthened the balance sheet, reduced complexity and legacy commitments

Leverage portfolio strength and depth to drive efficient growth and further improve debt metrics (3)

2xNet debt/EBITDA

5% – 15%Annual production growth

Where we have been2012 – 2016

(1) From 12/31/2012 through 6/30/2016(2) Includes production expenses and general and administrative expenses, including stock-based compensation(3) Assumes strip pricing through 2017 and $3/mcf and $60/bbl thereafter

~50% reductionIn total leverage (1)

= $10.6 billion

~50% reductionIn cash costs per boe (2)

= $4.10/boe in 2016E

Cash flow neutrality achievable in 2018Based on 2017 investment

Barclays CEO Energy-Power Conference 6

2012 Q2-'16E(1)$0

$5,000

$10,000

$15,000

$20,000

$25,000

REDUCED TOTAL LEVERAGE AND COMPLEXITY

Chesapeake continues to simplify the business:> Eliminated finance leases, subsidiary

preferred equity and seven VPPs> Optimizing the capital structure

$mm

$21,537

$10,894

2012 (1) 2Q’16 (1)

Credit FacilitySecured Loans & Notes

VPPsSubsidiary Preferred Equity

Unsecured NotesOperating & Finance Leases

Preferred Stock

(1) Assumes euro-denominated notes are converted to USD at the relevant 12/31 exchange rate for each calendar year; for 2Q’16, exchange rate and credit facility balance are as of 6/30/16

~50% reductionIn total leverage

= $10.6 billion

7Barclays CEO Energy-Power Conference

($4,000)

($3,000)

($2,000)

($1,000)

$0

$1,000

$2,000

$3,000

$4,000

$5,000

$6,000

Debt

Incr

ease

/Red

uctio

n ($

mm

)PROACTIVE LIABILITY MANAGEMENT INDUSTRY-LEADING DEBT REDUCTION SINCE 1/1/2013

Source: Company filings as of 12/31/2012 and 6/30/2016. CHK data represents principal reduction of long-term debt, while peer company data represents carrying value reduction of long-term debt, as principal balances are not always disclosed.

% Debt Increase/Reduction

34% reduction = $4.4 billion In debt principal reduction

CHK APA ECA HES MUR MRO EOG OXY DVN APC NBL COP

-34% -29% -26% -19% 9% 9% 11% 9% 9% 18% 93% 32%


REDUCTION IN 2017 MATURITIES

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

$500

$1,000

$1,500

$2,000

$2,500

$3,000

$3,500

$382 $337 $297

$660$315 $233

$1,168

$730

$130

6.5% 2017 6.25% 2017 Series1

$2,210

$1,382 (2) Financial Transaction Liquidity Savings

(4)

Debt Exchange

$305mm of2nd lien notes $291mm

Open Market Repurchases $99mm of cash $86mm

Equity for Debt

Exchanges

68.6mm shares (valued at $295mm)

$354mm

Tender Offer $722mm of 1.5 lien Term Loan $695mm

~$1.4 billion

$3,091 (1)

Available

Liquidity

$660 (3)

Sources: Company management and disclosures. Note: $ in millions.(1) $4.0 billion credit facility plus cash, less outstanding borrowings and letters of credit as of 6/30/2016(2) 6.25% 2017’s converted to USD for entire period using exchange rate of $1.1106 to €1.00 as of 6/30/2016(3) Assumes non-convertible tender participation as of early tender deadline in addition to full convertible tender participation up to sub-cap(4) Incremental liquidity savings includes principal savings and net interest impact

37% reductionIn maturities from 9/30/15 to 6/30/1670% reductionPro forma from current tender offer


BARNETT EXIT AND WILLIAMS RENEGOTIATIONSTRENGTHENING THE FOUNDATION OF THE BUSINESS

~$1.9 billion of midstream commitments expected to be eliminated• Chesapeake agreed to convey Barnett interests

to a private company ˃ Expected to eliminate current gathering

agreement, minimum volume commitments and fees pertaining to Barnett assets

˃ Williams will receive ~$334mm from CHK and an additional sum from the private company

$200 – $300mm increaseIn annual operating income from 2016 through 2019 (1)

Barnett

Expected 36% reduction in Mid-Continent gathering costs • Renegotiated Mid-Continent gathering agreement

in exchange for a payment of $66mm

Mid-Con

Together, these transactions are expected to provide:

~$550mm uplift To total company PV10 (3)

~$715mm reduction In total GP&T expenses in 2016 and 2017 (2)

(1) Before charges and other termination costs associated to this transaction(2) Gathering, processing & transportation expenses, inclusive of projected MVC shortfall payments(3) As of 12/31/2015





CAPITAL EFFICIENCY HOLDS PRODUCTION FLATDESPITE ASSET DIVESTITURES OF $16+ BILLION

• Spending 10% of 2012 capex program while producing equivalent volumes

• $16+ billion in divestitures led to 50% reduction in total leverage• Relatively flat absolute production through growth of retained assets

Sources: Company management and disclosures(1) Production range and total capital expenditure guidance from 8/9/2016 Outlook; includes capitalized interest(2) Historical capital spend and operating costs contain Seventy Seven Energy data

2012 2013 2014 2015 2016 E

648 670 706 679611 – 638 (1)

$14.7

$7.8 $6.7

$3.6$1.3 – $1.8 (1)

Production (mboe/d)Capex ($B) (2)

2012 2013 2014 2015 2016 E

648 670 706 679611 – 638 (1)

$14.7

$7.8 $6.7

$3.6$1.3 – $1.8 (1)

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(1) Includes production expenses and general and administrative expenses, including stock based compensation(2) 2016E represents 8/9/2016 guidance midpoint

SIGNIFICANT REDUCTIONS IN CASH COSTS

Industry-leading cash cost structure:> Relentless focus on cost management> Operational leadership and technical

capabilities provide industry-leading production expense


~50% reductionIn production and G&A expenses per boe since 2012

2012 2016E

$2.28$0.80

$5.52

$3.30

Cash Costs ($/boe) (1)(2)

G&A LOE

$7.80

$4.10

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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


PCK 1H31 MMcfd & 7,680


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

(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%

Longer Laterals

Reduced D&C Costs

Enhanced Completion

& High IP

2014 20162015

Rate of Return (1)

14

EAGLE FORD SHALEEXTENDED LATERALS KEY TO REDUCING DEVELOPMENT COST

(1) Based on spud date(2) Average cost per foot of wells drilled and/or completed within the time period


• Strategic shift to longer laterals has reduced development cost per foot by 60%

• ~65% of cost reductions are attributable to sustainable operational efficiency gains

5,600'6,500'

9,000' 9,300'10,500'

5,300'

Lateral Length (1)

$1,000 $923

$488 $430 $405

$962Total Well Cost per Lateral Foot (2)

YE Goal'14 YE '15 Avg. 1Q'16 2Q'16

~25%At 5,300'

~65%At 10,500'

Rate of Return for 2016 Development

Program

$5.3 $4.9

$2.6 $2.3 $2.1

$5.1Total Well Cost, Normalized to 5,300' LL

($mm)

'14 YE





UNRECOGNIZED VALUE, UNLOCKED POTENTIALSTRENGTH AND DEPTH OF PORTFOLIO

(1) Economics run at $3/mcf and $60/bbl oil flat(2) Operated gross, risked locations(3) Includes Upper Eagle Ford and Austin Chalk locations

Tremendous resource optionality provides Chesapeake with a competitive advantage for years to come

Eagle Ford Mid-Continent Marcellus Powder River Haynesville Utica Exploration and Technology

Opportunities

1,110

2,400

600

1,900

200650

2,400275

50

350

1,350 425

1,750

550

2,250

350

275500

10,500+ locations>20% ROR (1)(2)

(3)

5,600+ locations>40% ROR (1)(2)

5,260

3,2252,900

2,600

1,8251,575

2,500+

>40% ROR

20% – 40% ROR <20% ROR


• CHK has the opportunity to develop the field with current technology> Longer laterals> Optimized completions> Significantly enhanced returns

• Opportunity for exceptional value realization from captured resources for years to come

HAYNESVILLE SHALETHE CHESAPEAKE ADVANTAGE

Chesapeake has this opportunity across all of its assets

Heavily developed competitor position

Substantial development opportunities remain for

CHK

CHK Haynesville Locations

Drilled; 25%

Remaining Development

; 75%

EAGLE FORD MULTIZONE RESOURCE POTENTIALAREAS OF INTEREST AND COMPETITOR ACTIVITY


Austin Chalk

Lower Eagle Ford

Upper Eagle Ford

Staggered Wellbores

Competitor offset information was derived from public data

CHK South Texas Locations

Drilled; 25%

Remaining Development

; 75%

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UTICA SHALEDRY GAS 2016 PROGRAM

• 2016 dry gas drilling program˃ ~11,500' average lateral

length˃ ~$6.8mm D&C per well ˃ Average CHK WI of 99%


• Substantial growth planned for 2017

• Favorable gas differentials> ~93% of dry gas is sent to Gulf markets

~45% ROR2016 drilling program

>350% Production growthJuly 2016 – July 2017

Utica Dry Gas ProductionCHK Utica Dry LocationsDrilled; 10%

Remaining Development;

90%

20

2020

Strategic targets


Substantial progress on every front

Reduced total leverage by ~50% ($10.6 billion)

Improved cash costs by ~50% per boe

Reduced financial and balance sheet complexity

High-graded portfolio – 10,500+ locations above 20% ROR

ANALYST DAYOctober 20, 2016 Oklahoma City

Grow production 5% – 15% annually

Retire $2 – $3 billion of debt through asset divestitures

Achieve 2x net debt/EBITDA

2016


22

2014 2015 2016E 2016E New 2017E New

$8.43 $8.55 $8.58

$7.60 – $8.10

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

$7.15 – $7.65

GATHERING, PROCESSING & TRANSPORTSUBSTANTIAL COST STRUCTURE IMPROVEMENT GOING FORWARD

Barclays CEO Energy-Power 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

2016 GP&T expense reduced by ~9%

23

HEDGING POSITION


(1) For July – December 2016 production as of August 4, 2016.(2) Using midpoints for projected 2017 total production guidance as of August 9, 2016.

Oil 2017 (2)

23%

Swaps $47.49/bbl

Natural Gas 2017 (2)

33%30%

Swaps

3%Collars $3.00 /

$3.48/mcfNYMEX

$3.02/mcfNYMEX

Natural Gas2016

74%71%

Swaps

3%Collars

$3.00 / $3.48/mcf

NYMEX

$2.76/mcfNYMEX

Oil2016

71%

Swaps $46.60/bbl

NGL2016

32%

Ethane Swaps $0.17/galPropane Swaps $0.46/gal


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 [email protected]

http://www.chk.com/

mailto:[email protected]

Presentations & Public Speaking

CHK 2016 Barclays