INVESTOR PRESENTATION February 2015

1 I INVESTOR PRESENTATION

2/25/2015

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 that give our current expectations or forecasts of future events. They include production forecasts, estimates of operating costs, assumptions regarding future natural gas and liquids prices, planned drilling activity, anticipated asset sales and related adjustments, reductions in leverage, estimates of future capital expenditures, estimates of recoverable resources, projected rates of return and expected efficiency gains, as well as projected cash flow, inventory levels and capital efficiency, business strategy and other plans and objectives for future operations. 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; write-downs of our oil and natural gas carrying values due to declines in prices; the availability of operating cash flow and other funds to finance reserve replacement costs; 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; the limitations our level of indebtedness may have on our financial flexibility; charges incurred in response to market conditions and in connection with 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; federal and state tax proposals affecting our industry; potential OTC derivatives regulation limiting our ability to hedge against commodity price fluctuations; impacts of potential legislative and regulatory actions addressing climate change; 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; cyber attacks adversely impacting our operations; and interruption in operations at our headquarters due to a catastrophic event. 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 estimates and underlying market prices are subject to significant volatility. Our production forecasts are 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. References to “EUR” (estimated ultimate recovery) and “resources” include estimates of quantities of natural gas, oil and NGL we believe will ultimately be produced, but that are not yet classified as “proved reserves,” as defined in SEC regulations. Estimates of unproved resources are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of actually being realized by Chesapeake. We believe our estimates of unproved resources are reasonable, but our estimates have not been reviewed by independent engineers. Estimates of unproved resources may change significantly as development provides additional data, and actual quantities that are ultimately recovered may differ substantially from prior estimates. 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 presentation, except as required by applicable law.

2 I INVESTOR PRESENTATION

2/25/2015

WHERE WE ARE TODAY

CORPORATE PROGRESSION

2013

2014

2015+

TRANSFORMATION FOUNDATION E&P LEADERSHIP

3 I INVESTOR PRESENTATION

2/25/2015

2014 ACCOMPLISHMENTS OPERATIONAL > > > > >

Best safety performance in our history, 35% improvement YOY Reduced cumulative reportable spill volume by 40% Lowest production and G&A costs per BOE in a decade 30 - 60% capital efficiency improvement by play Highest production in company history achieved with less than half the operating rigs in 2012

STRATEGIC > > >

Successful spin-off of Seventy Seven Energy $450 million property exchange in oil-rich PRB (RKI) Southern Marcellus divestiture – largest transaction in company history

FINANCIAL > > >

$4.2 billion reduction in total leverage New unsecured, undrawn $4 billion credit facility with investment grade-like terms Two-notch upgrade from credit rating agencies

4 I INVESTOR PRESENTATION

2/25/2015

APPLYING OUR BUSINESS STRATEGIES FINANCIAL DISCIPLINE

EXPLORATION

> Balance capital expenditure with cash flow from operations

> Leverage innovative technology and expertise

> Increase financial and operational flexibility through value-driven spending and lower business costs

> Explore and exploit domestic resources > Pursue international growth opportunities

> Achieve investment grade metrics

PROFITABLE AND EFFICIENT GROWTH FROM CAPTURED RESOURCES > Develop world-class inventory

BUSINESS DEVELOPMENT > Target strategic acquisitions > Enhance and expand the portfolio

> Target top-quartile operating and financial metrics > Pursue continuous improvement > Drive value leakage out of our operations

5 I INVESTOR PRESENTATION

2/25/2015

2015E OUTLOOK SUMMARY 2015E Adjusted Production Growth Absolute Production: Liquids – mmbbls Oil – mmbbls NGL(1) – mmbbls Natural gas - bcf Total absolute production – mmboe Absolute daily rate – mboe

3 – 5% 62 – 64 39 – 40 23 – 24 1,035 – 1,055 235 – 240 645 – 655

Operating Costs per Boe of Projected Production: Production expenses, production taxes and G&A(2) Capital Expenditures($mm) (3) Capitalized Interest ($mm) Total capital expenditures ($mm)

$6.40 – $7.10 $3,500 – $4,000 $500 $4,000 – $4,500

(1) Assumes ethane recovery in Utica to fulfill CHK’s pipeline commitments, no ethane recovery in Powder River Basin, and partial ethane recovery in Mid-Continent and Eagle Ford (2) Excludes stock-based compensation and restructuring and other termination costs (3) Includes capital expenditures for drilling and completion, acquisition of unproved properties, geological and geophysical costs and other property and plant and equipment

6 I INVESTOR PRESENTATION

2/25/2015

MEASURED GROWTH Adjusted Production (mboe/d) 586

2013(1)

2015E Asset Sale

640 – 650

640 18 622

640 – 652

2015E

2014(1)

Absolute Production (mboe/d) 670

2013 (1)

706 645 – 655

2015E

2014

Adjusted to reflect production, net of 2013 and 2014 asset sales

7 I INVESTOR PRESENTATION

2/25/2015

1Q’15 PRODUCTION 4Q’14 – 1Q’15 Production Walk (mboe/d) 770 729

(57) (15) Divestitures(1)

December ‘14 Peak Rate

Curtailments

(7)

645 - 655

Downtime

1Q’15E

4Q’14

(1) Includes Marcellus South and Other

8 I INVESTOR PRESENTATION

2/25/2015

2014 FINANCIAL RESULTS

ADJ. EARNINGS/FDS

ADJ. EBITDA

PROD. and G&A EXP.

$ 4.94 billion

$ 1.49

9% YOY $6.84/boe(1)

LIQUIDITY

2014 ASSET SALES

$ 8.1 billion

(2)

$ 7.0 billion

TOTAL CAPEX

14% YOY $6.7 billion(3)

(1) Includes stock-based compensation and production taxes (2) Includes unrestricted cash and borrowing availability under unsecured revolving credit facility as of 12/31/2014 (3) Includes D&C costs, other explorations and development costs, PP&E, PRB property exchange, sale leasebacks and capitalized interest Note: Reconciliation of non-GAAP measures to comparable GAAP measures appear on pages 32-33

9 I INVESTOR PRESENTATION

2/25/2015

2014 OPERATIONAL RESULTS

ADJUSTED PRODUCTION

9% YOY

LIQUIDS MIX(2)

29%

ADJ. OIL PRODUCTION

7% YOY

of Total Production

640 mboe/d(1)

ADJ. NGL PRODUCTION

42% YOY

110 mbbls/d

PROVED RESERVES

PROVED DEVELOPED

2.47 Billion BOE

68% in 2013

70 mbbls/d

(1) (2)

75%

to

Adjusted for asset sales Oil and NGL collectively referred to as “liquids”

10 I INVESTOR PRESENTATION

2/25/2015

of Total Proved Reserves

OPERATIONS UPDATE •

Delivered 2014 adjusted production growth of 9% >

•

12% growth if Marcellus South divestiture excluded

2.47 billion boe of proved reserves at YE’14 >

•

4Q’14 Daily Avg. Net Production (mboe/d)

Proved developed portion increased to 75% of total

(2)

2015E total Capex of $4.0 - $4.5 billion(1) >

YOY decrease of ~25% (before acquisitions and sale leasebacks), or ~35% decrease from total capex

>

CHK’s 2015 planned rig count lowest since 2004

(3)

Operated Rig Count

% of 2015E D&C Capex by Play

(2)

(3)

(1) (2) (3)

Includes capital expenditures for drilling and completion, acquisition of unproved properties, geological and geophysical costs and other PP&E and capitalized interest Includes Cleveland, Tonkawa, Colony and Texas Panhandle Granite Washes and Other Anadarko plays Includes Barnett, Marcellus South (sold Dec’14) and all other producing properties not listed

11 I INVESTOR PRESENTATION

2/25/2015

CAPTURING MORE FOR LESS NORTHERN DIVISION Utica: 53% Improvement

Marcellus North: 39% Improvement

(1)

(1)

Powder River Basin: 46% Improvement

(1)

Note: Capex / EUR is defined as net drilling and completion (D&C) costs per well divided by net estimated ultimate reserves booked per well (1) 2014 estimated D&C costs per well and net reserves booked per well are as of 12/31/2014

12 I INVESTOR PRESENTATION

2/25/2015

CAPTURING MORE FOR LESS SOUTHERN DIVISION Haynesville: 67% Improvement

Eagle Ford: 38% Improvement

(1)

(1)

Mississippian Lime: 47% Improvement

(1)

Note: Capex / EUR is defined as net drilling and completion (D&C) costs per well divided by net estimated ultimate reserves booked per well (1) 2014 estimated D&C costs per well and net reserves booked per well are as of 12/31/2014

13 I INVESTOR PRESENTATION

2/25/2015

UTICA ASSET OVERVIEW •

Largest producer, leasehold owner and most active driller >

•

•

>1 million net acres 61% avg WI

Operate >55% of wells in the play

4Q’14 avg. net production of 100 mboe/d >

Up 17% sequentially

>

180 mboe/d gross operated

Plan to avg. 3 - 5 rigs, four frac crews in ’15 >

~45% HBP drilling, ~80% pad drilling

CHK/TOT JV Outline CHK Operated Rigs CHK Leasehold Oil Window Wet Gas Window Dry Gas Window

•

~165 wells WOC/WOP at YE’14, anticipate >20% reduction in 2015

•

3 - 5 oil window completions planned in 2015 Production mix

14 I INVESTOR PRESENTATION

2/25/2015

UTICA CONTINUOUS IMPROVEMENT 6,000

(1)

(1)

(1)

As measured from Jan.-Oct.

15 I INVESTOR PRESENTATION

2/25/2015

EAGLE FORD ASSET OVERVIEW •

•

>

Up 4% sequentially

>

230 mboe/d gross operated

Plan to avg. 12 - 14 rigs, four frac crews in ’15 >

• •

449,000 net acres 61% avg WI

4Q’14 avg net production of ~106 mboe/d

95% pad drilling

123 wells brought online in 4Q’14 had an avg. peak rate of 850 boe/d CHK Operated Rigs CHK Leasehold Oil Window Wet Gas Window Dry Gas Window

~160 wells WOC/WOP at YE’14

Production mix

16 I INVESTOR PRESENTATION

2/25/2015

EAGLE FORD CONTINUOUS IMPROVEMENT 5,900

(1) (1)

(1)

(1)

As measured from Jan.-Oct.

17 I INVESTOR PRESENTATION

2/25/2015

HAYNESVILLE ASSET OVERVIEW • •

Largest producer, leasehold owner and most active driller 4Q’14 avg. net production of 592 mmcfe/d > >

•

Plan to avg. 7 - 8 rigs, 1 frac crew in ’15 >

• •

387,000 net acres 71% avg WI

Up 5% sequentially 910 mmcfe/d gross operated 100% pad drilling

18 wells brought online in 4Q’14 had an avg. peak rate of 13.4 mmcfe/d ~20 wells WOC/WOP at YE’14

CHK Operated Rigs CHK Leasehold

Production mix

18 I INVESTOR PRESENTATION

2/25/2015

HAYNESVILLE CONTINUOUS IMPROVEMENT

(1)

(1)

(1)

As measured from Jan.-Oct.

19 I INVESTOR PRESENTATION

2/25/2015

POWDER RIVER BASIN ASSET OVERVIEW •

Closed transaction with RKI in August ’14 >

•

4Q’14 avg net production of ~18 mboe/d > >

•

•

Up 29% sequentially 27 mboe/d gross operated

Plan to avg. 3 - 4 rigs, one frac crew in ’15 >

• •

Exchanged nonoperated northern acreage and $450 mm cash for RKI’s southern acreage

100% pad drilling

~40 wells WOC/WOP at YE’14 50:50 development plan of Niobrara / Sussex wells in 2015 Stacked formation tests in 2015: > > > >

388,000 net acres 79% avg WI

CHK Operated Rigs CHK Leasehold

Production mix

1 Sussex Northern boundary test 1 in Teapot 1 in Shannon 1 in Parkman

20 I INVESTOR PRESENTATION

2/25/2015

POWDER RIVER BASIN CONTINUOUS IMPROVEMENT

(1)

(1)

(1)

As measured from Jan.-Oct.

21 I INVESTOR PRESENTATION

2/25/2015

MISSISSIPPIAN LIME ASSET OVERVIEW •

> >

•

•

Up 4% sequentially 72 mboe/d gross operated

CHK Operated Rigs CHK Leasehold

Plan to avg. 7 - 8 rigs, two frac crews in ’15 >

•

164,000 net acres 44% avg WI

4Q’14 avg. net production of 28 mboe/d

85% pad drilling

42 wells brought online in 4Q’14 had an avg. peak rate of 730 boe/d ~55 wells WOC/WOP at YE’14

Production mix

22 I INVESTOR PRESENTATION

2/25/2015

MISSISSIPPIAN LIME CONTINUOUS IMPROVEMENT

(1)

(1)

(1)

(1)

As measured from Jan.-Oct.

23 I INVESTOR PRESENTATION

2/25/2015

MARCELLUS ASSET OVERVIEW •

4Q’14 avg net production of ~817 mmcfe/d >

•

2.07 bcfe/d gross operated

Plan to avg. 1-2 rigs in 2015 >

100% pad drilling

Franclaire 8H 30.6 mmcf/d

•

~115 wells WOC/WOP at YE’14

•

25 wells brought online in 4Q’14 had an avg. peak rate of 15.2 mmcfe/d

•

Upper Marcellus test wells planned in 2015

•

Projecting to hold total production relatively flat in 2015 with 70% less capex

Franclaire 7H 30.2 mmcf/d Franclaire 9H 22.4 mmcf/d

230,000+ net acres 39% avg WI

CHK Operated Rigs CHK Leasehold

Production mix

24 I INVESTOR PRESENTATION

2/25/2015

MARCELLUS CONTINUOUS IMPROVEMENT 5,900

(1)

(1)

(1)

As measured from Jan.-Oct.

25 I INVESTOR PRESENTATION

2/25/2015

APPENDIX

26 I INVESTOR PRESENTATION

2/25/2015

REDUCING LEVERAGE ($mm)

2012

2014

Term Loan

$2,000

--

Long-Term Bonds

$10,666

$11,766

$418

--

$13,084

$11,766

VPPs

$3,187

$1,720

Operating & Finance Leases

$1,255

--

Subsidiary Preferred

$2,500

$1,250

Corporate Preferred

$1,531

$1,531

Adjusted Leverage

$21,558

$16,267

$287

$4,108

$21,271

$12,159

Credit Facility GAAP Debt

Cash Total Adjusted Leverage (net of cash)

27 I INVESTOR PRESENTATION

2/25/2015

10%

25% 43%

UPSIDE POTENTIAL

CHK

28 I INVESTOR PRESENTATION

2/25/2015

2015 HEDGING POSITIONS

Natural Gas 20% 3-Way Collars

Oil 32% Swaps

$4.51/$4.29/$3.37 /mcf NYMEX

43%

$94.58/bbl NYMEX

43% 23% Swaps

$4.14/mcf NYMEX

11% 3-Way Collars

$98.94/$90/$80 /bbl NYMEX

Note: Hedged positions as of 1/31/2015 based on production estimates provided in 2/25/2015 Outlook

29 I INVESTOR PRESENTATION

2/25/2015

UTICA DOWNSTREAM MARKETING ADVANTAGE •

Average transportation rates of $0.24mcf per day for 2015

•

•

Dawn

Gulf Coast Market Access >

440 MMcf/d to the Gulf Coast for 2015

>

732 MMcf/d to the Gulf Coast beginning in 2016

Utica

Upper Midwest/Canadian Market Access >

•

200 MMcf/d of capacity to Dawn market in 2017

Local Market Access >

96 MMcf/d to local markets

Gulf Coast

30 I INVESTOR PRESENTATION

2/25/2015

SENIOR NOTE MATURITY PROFILE Sr. Notes: $11.8 billion 12/31/2014 WACD – 5.1% Avg. Maturity: 4.9 years

Convertibles(1)

Other Senior Notes

$2,245 $1,800

$1,700 $1,500

$1,500

$1,100

$1,015

$396

(1) (2) (3)

$500

2015

2016

2017

2018

2.75%(1)

3.25%

2.5%(1) 6.5% 6.25%(2)

2.25%(1) 7.25%

2019 3mL+3.25%(3)

2020 6.875% 6.625%

2021

2022

2023

5.375% 6.125%

4.875%

5.75%

Recognizes earliest investor put option as maturity for the 2.75% 2035, 2.5% 2037 and 2.25% 2038 Contingent Convertible Senior Notes Euro-denominated notes with a principal amount based on the exchange rate of $1.2098 to €1.00 at 12/31/2014 All-in yield composed of 3.25% spread and 3mL

31 I INVESTOR PRESENTATION

2/25/2015

RECONCILIATION OF ADJUSTED EARNINGS PER SHARE ($ in mm)

Twelve Months Ended: Net income available to common stockholders Adjustments, net of tax:

Unrealized gains on derivatives Restructuring and other termination costs Impairments of fixed assets and other Net gains on sales of fixed assets Impairments of investments Net (gain) loss on sales of investments Losses on purchases of debt and extinguishment of other financing Losses on investments Provision for legal contingencies Other Redemption of preferred shares of a subsidiary(1)

Adjusted net income available to common stockholders(2) Preferred stock dividends Earnings allocated to participating securities

Total adjusted net income attributable to CHK Weighted average fully diluted shares outstanding(3) Adjusted earnings per share assuming dilution(2)

12/31/2014

12/31/2013

$1,273

$474

(941) 4 57 (128) 3 (43) 126 150 9 447

(100) 154 341 (187) 6 5 120 84 (1) 69

$957

$965

$1,154 776 $1.49

$1,146 765 $1.50

171 26

171 10

(1)

All adjustments to net income available to common stockholders reflected net of tax other than the redemption of preferred shares of a subsidiary.

(2)

Adjusted net income available to common stockholders and adjusted earnings per share assuming dilution exclude certain items that management believes affect the comparability of operating results. The company believes these adjusted financial measures are a useful adjunct to earnings calculated in accordance with accounting principles generally accepted in the United States (GAAP) because: (i) Management uses adjusted net income available to common stockholders to evaluate the company's operational trends and performance relative to other natural gas and oil producing companies. (ii) Adjusted net income available to common stockholders is more comparable to earnings estimates provided by securities analysts. (iii) Items excluded generally are one-time items or items whose timing or amounts cannot be reasonably estimated. Accordingly, any guidance provided by the company generally excludes information regarding these types of items. Management believes that “adjusted net income attributable to common stockholders” represents a useful corollary to net income attributable to common stockholders because it provides useful information regarding our ongoing operations and is widely used by investors, analysts and rating agencies in the valuation, rating and investment recommendations of companies. In millions. Weighted average fully diluted shares outstanding include shares that were considered antidilutive for calculating earnings per share in accordance with GAAP

(3)

32 I INVESTOR PRESENTATION

2/25/2015

RECONCILIATION OF ADJUSTED EBITDA ($ in mm)

Twelve Months Ended: Cash provided by operating activities Changes in assets and liabilities

Operating cash flow Net income

(1)

Interest expense Income tax expense Depreciation and amortization of other assets Oil, natural gas and NGL depreciation, depletion and amortization

EBITDA(2)

Adjustments:

Unrealized gains on oil, natural gas and NGL derivatives Restructuring and other termination costs Impairments of fixed assets and other Net gains on sales of fixed assets Losses on investments Net (gain) loss on sales of investments Losses on purchases of debt and extinguishment of other financing Provision for legal contingencies Net income attributable to noncontrolling interests Other

Adjusted EBITDA(3)

12/31/2014

12/31/2013

$4,634

$4,614

392

344

$5,026 $2,056

$4,958 $894

$6,204

$4,572

(1,394) 7 88 (199) 5

(228) 248 550 (302) 146

(67) 197 234 (139) 9

7 193 _ (170) --

$4,945

$5,016

89 1,144 232 2,683

227 548 314 2,589

(1) Operating cash flow represents net cash provided by operating activities before changes in assets and liabilities. Operating cash flow is presented because management believes it is a useful adjunct to net cash provided by operating activities under GAAP. Operating cash flow is widely accepted as a financial indicator of a natural gas and oil company's ability to generate cash which is used to internally fund exploration and development activities and to service debt. This measure is widely used by investors and rating agencies in the valuation, comparison, rating and investment recommendations of companies within the natural gas and oil exploration and production industry. Operating cash flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating, investing or financing activities as an indicator of cash flows, or as a measure of liquidity. (2) Ebitda represents net income (loss) before interest expense, income taxes, and depreciation, depletion and amortization expense. Ebitda is presented as a supplemental financial measurement in the evaluation of our business. We believe that it provides additional information regarding our ability to meet our future debt service, capital expenditures and working capital requirements. This measure is widely used by investors and rating agencies in the valuation, comparison, rating and investment recommendations of companies. Ebitda is also a financial measurement that, with certain negotiated adjustments, is reported to our lenders pursuant to our bank credit agreements and is used in the financial covenants in our bank credit agreements. Ebitda is not a measure of financial performance under GAAP. Accordingly, it should not be considered as a substitute for net income, income from operations or cash flow provided by operating activities prepared in accordance with GAAP. (3) Adjusted ebitda excludes certain items that management believes affect the comparability of operating results. The company believes these non-GAAP financial measures are a useful adjunct to net income because: (i) Management uses adjusted ebitda to evaluate the company's operational trends and performance relative to other natural gas and oil producing companies. (ii) Adjusted ebitda is more comparable to estimates provided by securities analysts. (iii) Items excluded generally are one-time items or items whose timing or amount cannot be reasonably estimated. Accordingly, any guidance provided by the company generally excludes information regarding these types of items.

33 I INVESTOR PRESENTATION

2/25/2015

CORPORATE INFORMATION CHESAPEAKE 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 by phone at (405) 935-8870 or by email at [email protected]

PUBLICLY TRADED SECURITIES

CUSIP

TICKER

3.25% Senior Notes due 2016

#165167CJ4

CHK16

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

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 #165167834/ #165167826 #U16450204/ #165167776/ #165167768 #U16450113/ #165167784/ #165167750 #165167107

CHK PrD

5.0% Cumulative Convertible Preferred Stock (Series 2005B) 5.75% Cumulative Convertible Preferred Stock 5.75% Cumulative Convertible Preferred Stock (Series A) Chesapeake Common Stock

34 I INVESTOR PRESENTATION

2/25/2015

N/A N/A N/A CHK