Investor Presentation November 5, 2014

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Peregrine Cecil Tucker
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1 Investor Presentation November 5, 2014

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 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, planned 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. Further, pending divestiture transactions are subject to closing conditions and may not be completed in the time frame anticipated or at all. In particular, we caution you that our October 2014 purchase and sale agreement with Southwestern Energy Company, in which we agreed to sell certain assets in the Marcellus Shale and Utica Shale for approximately $5.375 billion, is subject to closing conditions, including third-party consents and waiver of participation rights. These closing conditions may not be completed in the time frame anticipated or at all. 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 2013 annual report on Form 10-K filed with the U.S. Securities and Exchange Commission on February 27, These risk factors include the volatility of natural gas, oil and NGL prices; the limitations our level of indebtedness may have on our financial flexibility; declines in the prices of natural gas and oil potentially resulting in a write-down of our asset carrying values; the availability of capital on an economic basis, including through planned asset sales, to fund reserve replacement costs; our ability to replace reserves and sustain production; uncertainties inherent in estimating quantities of natural gas, oil 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; hedging activities resulting in lower prices realized on natural gas, oil and NGL sales; the need to secure hedging liabilities and the inability of hedging counterparties to satisfy their obligations; drilling and operating risks, including potential environmental liabilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing, air emissions and endangered species; uncertainties regarding legal claims and governmental proceedings, including royalty claims, and the adequacy of our provision for legal contingencies; a deterioration in general economic, business or industry conditions having a material adverse effect on our results of operations, liquidity and financial condition; oilfield services shortages, gathering system and transportation capacity constraints and various transportation interruptions that could adversely affect our revenues and cash flow; adverse developments and losses in connection with pending or future litigation and regulatory investigations; cyber attacks adversely impacting our operations; and an interruption at our headquarters that adversely affects our business. 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 dependent upon many assumptions, including estimates of production decline rates from existing wells and the outcome of future drilling activity. 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 release, except as required by applicable law. 2 I INVESTOR PRESENTATION 11/5/2014

WHERE WE ARE TODAY CORPORATE PROGRESSION 2013 2014 2015 +

3 WHERE WE ARE TODAY CORPORATE PROGRESSION TRANSFORMATION FOUNDATION E&P LEADERSHIP 3 I INVESTOR PRESENTATION 11/5/2014

investment grade metrics Develop world-class inventory Target top-quartile operating and financial

4 APPLYING OUR BUSINESS STRATEGIES Balance capital expenditures with cash flow from operations Divest noncore assets and noncore affiliates Reduce financial and operational risk and complexity Achieve investment grade metrics Develop world-class inventory Target top-quartile operating and financial metrics Pursue continuous improvement Drive value leakage out of operations 4 I INVESTOR PRESENTATION 11/5/2014

5 3Q 14 OPERATIONAL AND FINANCIAL RESULTS TOTAL ADJ. PROD. LIQUIDS MIX ADJ. OIL PROD. 11% YOY (1) 726 mboe/d to 29% 28% in 2Q 14 of Total Production (2) 5% Q/Q (1) mbbls/d ADJ. EARNINGS/FDS ADJ. EBITDA CAPEX 12% YOY $0.38 (3) 7% YOY $1.24 billion (3) 8% YOY $1.35 billion (1) Adjusted for asset sales (2) Oil and NGL collectively referred to as liquids (3) Adjusted earnings per fully diluted share and adjusted EBITDA are non-gaap financial measures. A reconciliation of non-gaap financial measures to comparable GAAP financial measures appears on pages I INVESTOR PRESENTATION 11/5/2014

changes in assets and liabilities (2) 2014 based on midpoint of company Outlook issued on 11/5/2014; capex

6 $ in billions CAPITAL DISCIPLINE $14.2 (1) $7.6 ~$5.7 (2) 60% Decrease in Capital Investment 36% Increase in Operating Cash Flow (1) Operating Cash Flow before changes in assets and liabilities (2) 2014 based on midpoint of company Outlook issued on 11/5/2014; capex includes capitalized interest, but excludes the exchange of properties with RKI Exploration and Production, LLC for ~$450 million in August I INVESTOR PRESENTATION 11/5/2014

7 Inventory Count mmboe GROWING PRODUCTION WHILE MANAGING INVENTORY 7 I INVESTOR PRESENTATION 11/5/2014

OPERATIONS UPDATE Operating cash flow (1) for first nine months of 2014 of approximately $4.2 billion, compared to capital expenditures of $3.

Net Production (mboe/d) Adjusted production (3) for first nine months was 12% higher than year-ago levels Achieved year-end estimated exit rate of

Operated Rig Count <5% <5% 17-20 ~ ~ ~ ~ ~ (5) 42-49 Liquids Focused Rigs 13-16 Natural Gas Focused Rigs 55-65 Total Operated Rigs 5-6 ~ ~ ~ (1)

the company in conjunction with the august 2014 exchange of properties with RKI Exploration and Production, LLC.

8 OPERATIONS UPDATE Operating cash flow (1) for first nine months of 2014 of approximately $4.2 billion, compared to capital expenditures of $3.5 billion (2) 3Q 14 Daily Avg. Net Production (mboe/d) Adjusted production (3) for first nine months was 12% higher than year-ago levels Achieved year-end estimated exit rate of 730 mboe/d in September, 2014 (5) 2014E % of E&P Capex by Play (2)(4) 2014E Avg. Operated Rig Count <5% <5% ~ ~ ~ ~ ~ (5) Liquids Focused Rigs Natural Gas Focused Rigs Total Operated Rigs 5-6 ~ ~ ~ (1) Operating Cash Flow before changes in assets and liabilities (2) (3) Excludes capitalized interest and approximately $450 million of cash paid by the company in conjunction with the august 2014 exchange of properties with RKI Exploration and Production, LLC. Adjusted for asset sales in 2013 and 2014 (4) (5) Net of Utica and PRB drilling carries; includes drilling, completion, leasehold, geological and geophysical costs and capitalized G&A; excludes capitalized interest Includes: Mississippian Lime, Cleveland, Tonkawa, Colony and Texas Panhandle Granite Washes and Other Anadarko plays 8 I INVESTOR PRESENTATION 11/5/2014

89 gross wells in 3Q 14 449,000 net acres 61% avg WI, 46% avg NRI ~40% of 2014 estimated E&P capex CHK Operated Rigs CHK

9 EAGLE FORD ASSET OVERVIEW 3Q 14 avg. net production of ~102 mboe/d > Up 12% sequentially Averaged 21 operated rigs (3 of which were spudder rigs) and connected 89 gross wells in 3Q ,000 net acres 61% avg WI, 46% avg NRI ~40% of 2014 estimated E&P capex CHK Operated Rigs CHK Leasehold Oil Window Wet Gas Window Dry Gas Window Avg. completed well cost of ~$6.0 million (2) Production mix (1) (1) 3Q 14 avg. daily production (2) As measured from Jan-July 9 I INVESTOR PRESENTATION 11/5/2014

window > 300,000 net acres in oil > 540,000 net acres in dry gas (1) CHK/TOT JV Outline CHK Operated Rigs CHK Leasehold Oil Window Wet Gas Window Dry Gas Window > 71% avg.

10 UTICA ASSET OVERVIEW 3Q 14 avg. net production of ~86 mboe/d > Up 27% sequentially Averaged 7 operated rigs and connected 77 gross wells in 3Q 14 Over 1 million net acres > 250,000 net acres in wet gas window > 300,000 net acres in oil > 540,000 net acres in dry gas (1) CHK/TOT JV Outline CHK Operated Rigs CHK Leasehold Oil Window Wet Gas Window Dry Gas Window > 71% avg. WI, 57% avg. NRI Avg. completed well cost of ~$6.5 million (3) Production mix (2) (1) Utica dry gas acreage includes 165,000+ acres that overlap in Southern Marcellus, the proposed sale of which was announced in October 2014 (2) 3Q 14 daily average net production (3) As measured from Jan-July 10 I INVESTOR PRESENTATION 11/5/2014

POWDER RIVER BASIN NIOBRARA ASSET OVERVIEW Net production of ~14 mboe/d (1) Three operated rigs in 3Q 14 and connected 17 gross wells in 3Q 14 388,000+ net acres 79% avg.

11 POWDER RIVER BASIN NIOBRARA ASSET OVERVIEW Net production of ~14 mboe/d (1) Three operated rigs in 3Q 14 and connected 17 gross wells in 3Q ,000+ net acres 79% avg. WI Buckinghorse Plant (4Q'14) expected to add 120 mmcf/d processing capacity Avg. completed well cost of ~$9.2 million CHK Operated Rigs CHK Leasehold Production mix (1) (1) 3Q 14 daily average net production (2) As measured from Jan-July 11 I INVESTOR PRESENTATION 11/5/2014

12 EXECUTING OUR PLAN Production growth (1) 9 12% Cash flow $5,250 $5,450 MM Capital $5,000 $5,400 MM (2) Cash costs LOE, G&A and interest expense Leverage Reduce adjusted leverage by 30% YE 2014 (1) Growth range based on 2013 production of 604mboe/day adjusted for asset sales in 2013 and 2014 (2) Excludes capitalized interest and approximately $450 million of cash paid by the company in conjunction with the August 2014 exchange of properties with RKI Exploration and Production, LLC. 12 I INVESTOR PRESENTATION 11/5/2014

13 APPENDIX 13 I INVESTOR PRESENTATION 11/5/2014

14 TRANSFORMING OUR BUSINESS Organizational structure Decision rights Focus on capital efficiency Cash cost reduction Portfolio management and capital allocation process Corporate budget process and plan Performance measurement and compensation program 14 I INVESTOR PRESENTATION 11/5/2014

15 FOUNDATIONAL ELEMENTS FOR VALUE CREATION Growing production while de-levering Industry-leading capital efficiency Differential future growth CHK 15 I INVESTOR PRESENTATION 11/5/2014

NORTHERN MARCELLUS ASSET OVERVIEW 3Q 14 avg. net production of ~882 mmcfe/d > Up 1% sequentially Averaged 3 operated rigs and connected 23 gross wells in 3Q 14 230,000+ net acres (1) 39% avg.

16 NORTHERN MARCELLUS ASSET OVERVIEW 3Q 14 avg. net production of ~882 mmcfe/d > Up 1% sequentially Averaged 3 operated rigs and connected 23 gross wells in 3Q ,000+ net acres (1) 39% avg. WI, 34% avg. NRI Avg. completed well cost of ~$7.0 million (3) CHK Operated Rigs CHK Leasehold Production mix (2) (1) Excludes acreage off main development fairway (2) 3Q 14 daily average net production (3) As measured from Jan-July 16 I INVESTOR PRESENTATION 11/5/2014

17 MID-CONTINENT ASSET OVERVIEW 3Q 14 avg. net production of ~96 mboe/d Averaged 18 operated rigs and connected 63 gross wells in 3Q ,000 net acres actively being developed in aggregate Mississippian Lime 164,000 net acres 44% avg WI, 36% avg NRI Granite Wash plays (1) 85,000 net acres Production mix (2) Miss. Lime Granite Washes CHK Leasehold CHK Operated Rigs 83% avg WI, 67% avg NRI ~1.9 mm net acres of legacy leasehold ~20% of 2014 estimated E&P capex Avg. completed well cost of $3.1 million in the Mississippian Lime (3) (1) Granite Wash plays include Colony Granite Wash, TX Panhandle Granite Wash and Missourian Granite Wash (2) 3Q 14 daily avg. net production (3) As measured from Jan-July 17 I INVESTOR PRESENTATION 11/5/2014

18 HAYNESVILLE ASSET OVERVIEW 3Q 14 avg. net production of ~562 mmcfe/d > Up 11% sequentially Averaged 9 operated rigs and connected 14 gross wells in 3Q ,000 net acres 71% avg WI, 57% avg NRI Avg. completed well cost of ~$8.2 million (2) CHK Operated Rigs CHK Leasehold Production mix (1) (1) 3Q 14 daily avg. net production (2) As measured from Jan-July 18 I INVESTOR PRESENTATION 11/5/2014

2014 estimated E&P capex Field maturity now entering period of low base decline rate Avg.

19 BARNETT SHALE ASSET OVERVIEW 3Q 14 avg. net production of ~410 mmcfe/d 1-2 operated rigs in ,000 net acres 68% avg WI, 52% avg NRI <5% of 2014 estimated E&P capex Field maturity now entering period of low base decline rate Avg. completed well cost of ~$2.9 million (2) Production mix (1) CHK Operated Rigs CHK Leasehold (1) 3Q 14 daily average net production (2) As measured from Jan-July 19 I INVESTOR PRESENTATION 11/5/2014

CURRENT HEDGE POSITION Natural Gas Oil 72% 64% $4.50-$5.24/mcf NYMEX 26% Three-Way Collars 42% Swaps $4.11 - $4.37/mcf NYMEX $4.09/mcf NYMEX $94.

20 CURRENT HEDGE POSITION Natural Gas Oil 72% 64% $4.50-$5.24/mcf NYMEX 26% Three-Way Collars 42% Swaps $ $4.37/mcf NYMEX $4.09/mcf NYMEX $94.22/bbl NYMEX Q Total 2015 Natural Gas Hedges Crude Oil Hedges Volume (bcf) Price ($/mcf) $4.12 $4.31 Volume (mmbls) 7,197 16,837 Price ($/bbl) $94.22 $93.39 Note: Hedged positions as of 11/1/2014 based on production estimates provided in 11/5/2014 Outlook; 26% of 2014 gas production is hedged under collar arrangements with upside to average NYMEX price of $4.37/mcf and exposure below average NYMEX price of $3.49/mcf 20 I INVESTOR PRESENTATION 11/5/2014

21 UTICA DOWNSTREAM MARKETING ADVANTAGE Average transportation rates of $0.22 per mcf per day for balance of 2014 and $0.24 per mcf per day for 2015 Dawn Gulf Coast Market Access > 440 MMcfd to the Gulf Coast for 2015 Utica > 732 MMcfd to the Gulf Coast beginning in 2016 Upper Midwest/Canadian Market Access > 200 MMcfd of capacity to Dawn market in 2017 Local Market Access Gulf Coast > 96 MMcfd to local markets 21 I INVESTOR PRESENTATION 11/5/2014

22 REDUCING LEVERAGE ($mm) E (1)(2) Term Loan $2, Long-Term Bonds $10,666 $11,821 Credit Facility $ GAAP Debt $13,084 $11,821 ~10% VPPs $3,187 $1,720 Operating & Finance Leases $1, Subsidiary Preferred $2, Corporate Preferred $1,531 $1,531 Total Adjusted Leverage $21,558 $15,061 ~30% ~$6.5B Reduction in Leverage During the Past 2 Years (1) Assumes takeout of Cleveland-Tonkawa, sale of South and East Texas conventional assets (VPP 6) in 2H 2014 (2) Excludes approximately $5.4 billion in potential proceeds from the proposed Southern Marcellus asset sale, subject to close in December I INVESTOR PRESENTATION 11/5/2014

23 SENIOR NOTE PROFILE Convertibles Other Senior Notes $2,263 Sr. Notes: $11.8 billion 9/30/2014 WACD 5.0% Avg. Maturity: 5.2 years $1,500 $1,800 $1,700 $1,500 $1,015 $1,100 $396 $500 $ % (1) 3.25% 2.5% (1) 2.25% (1) 3mL+3.25% (3) 6.875% 5.375% 4.875% 5.75% 6.5% 7.25% 6.625% 6.125% 6.25% (2) (1) Recognizes earliest investor put option as maturity for the 2.75% 2035, 2.5% 2037 and 2.25% 2038 Contingent Convertible Senior Notes (2) Euro-denominated notes with a principal amount based on the exchange rate of $ to 1.00 at 9/30/2014 (3) All-in yield composed of 3.25% spread and 3mL 23 I INVESTOR PRESENTATION 11/5/2014

24 RECONCILIATION OF ADJUSTED EARNINGS PER SHARE ($ in mm, except per share data) Three Months Ended: 9/30/2014 9/30/2013 Net income available to common stockholders $169 $156 Adjustments, net of tax: Unrealized losses on derivatives (384) 118 Restructuring and other termination costs (9) 39 Impairments of fixed assets and other 9 55 Net gains on sales of fixed assets (54) (82) Net gains on sales of investments - (2) Provision for legal contingencies 62 - Other 11 (2) Redemption of preferred shares of a subsidiary (1) Adjusted net income available to common stockholders (2) $251 $282 Preferred stock dividends Earnings allocated to participating securities 3 3 Total adjusted net income attributable to CHK $297 $328 Weighted average fully diluted shares outstanding (3) Adjusted earnings per share assuming dilution (2) $0.38 $0.43 (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 amount 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. (3) In millions. Weighted average fully diluted shares outstanding include shares that were considered antidilutive for calculating earnings per share in accordance with GAAP 24 I INVESTOR PRESENTATION 11/5/2014

25 RECONCILIATION OF ADJUSTED EBITDA ($ in mm) Three Months Ended: 9/30/2014 9/30/2013 Cash provided by operating activities $1,184 $1,381 Changes in assets and liabilities Operating cash flow (1) $1,293 $1,412 Net income $692 $240 Interest expense Income tax expense Depreciation and amortization of other assets Natural gas, oil and NGL depreciation, depletion and amortization EBITDA (2) $1,871 $1,158 Adjustments: Unrealized losses on natural gas, oil and NGL derivatives (622) 191 Restructuring and other termination costs (14) 63 Impairments of fixed assets and other Net gains on sales of fixed assets (86) (132) Net gains on sales of investments -- (3) Net income attributable to noncontrolling interests (30) (38) Provision for legal contingencies Other 2 (3) Adjusted EBITDA (3) $1,236 $1,325 (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. 25 I INVESTOR PRESENTATION 11/5/2014

CORPORATE INFORMATION CHESAPEAKE HEADQUARTERS 6100 N. Western Avenue Oklahoma City, OK 73118 WEBSITE: www.chk.

Executive Vice President and Chief Financial Officer Investor Relations department can be reached by phone at (405) 935-8870 or by email at ir@chk.com PUBLICLY TRADED SECURITIES CUSIP TICKER 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.

26 CORPORATE INFORMATION CHESAPEAKE HEADQUARTERS 6100 N. Western Avenue Oklahoma City, OK WEBSITE: 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) or by at PUBLICLY TRADED SECURITIES CUSIP TICKER 3.25% Senior Notes due 2016 #165167CJ4 CHK % Senior Notes due 2017 # N/A 6.50% Senior Notes due 2017 #165167BS5 CHK % Senior Notes due 2018 #165167CC9 CHK18A 3mL % Senior Notes due 2019 #165167CM7 CHK % Senior Notes due 2020 #165167CF2 CHK20A 6.875% Senior Notes due 2020 #165167BU0 CHK % Senior Notes Due 2021 #165167CG0 CHK % Senior Notes Due 2021 #165167CK21 CHK21A 4.875% Senior Notes Due 2022 #165167CN5 CHK % Senior Notes Due 2023 #165167CL9 CHK % Contingent Convertible Senior Notes due 2035 #165167BW6 CHK % 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 # CHK PrD 5.0% Cumulative Convertible Preferred Stock (Series 2005B) # / # N/A 5.75% Cumulative Convertible Preferred Stock #U / # / N/A # % Cumulative Convertible Preferred Stock (Series A) #U / # / N/A # Chesapeake Common Stock # CHK 26 I INVESTOR PRESENTATION 11/5/2014

February 22, 2018 CHESAPEAKE ENERGY 2017 Q4 EARNINGS

February 22, 2018 CHESAPEAKE ENERGY 2017 Q4 EARNINGS FORWARD-LOOKING STATEMENTS This presentation includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and