Filed by Chesapeake Energy Corporation (Commission File No. 001-13726) Pursuant to Rule 425 under the Securities Act of 1933 and deemed filed pursuant to rule 14a-12 under the Securities Exchange Act of 1934 Subject Company: WildHorse Resource Development Corporation (Commission File No. 001-37964) The following is a presentation to be given by Chesapeake Energy Corporation to investors and securities analysts beginning November 12, 2018.

NOVEMBER 2018 UPDATE

FORWARD-LOOKING STATEMENT Cautionary Statement Regarding Forward-Looking Information This communication may contain certain forward-looking statements, including certain plans, expectations, goals, projections, and statements about the benefits of the proposed transaction, WildHorse’s and Chesapeake’s plans, objectives, expectations and intentions, the expected timing of completion of the transaction, and other statements that are not historical facts. Such statements are subject to numerous assumptions, risks, and uncertainties. Statements that do not describe historical or current facts, including statements about beliefs and expectations, are forward-looking statements. Forward-looking statements may be identified by words such as expect, anticipate, believe, intend, estimate, plan, target, goal, or similar expressions, or future or conditional verbs such as will, may, might, should, would, could, or similar variations. The forward-looking statements are intended to be subject to the safe harbor provided by Section 27A of the Securities Act of 1933, Section 21E of the Securities Exchange Act of 1934, and the Private Securities Litigation Reform Act of 1995. While there is no assurance that any list of risks and uncertainties or risk factors is complete, below are certain factors which could cause actual results to differ materially from those contained or implied in the forward-looking statements: the possibility that the proposed transaction does not close when expected or at all because required regulatory, shareholder or other approvals are not received or other conditions to the closing are not satisfied on a timely basis or at all; the risk that regulatory approvals required for the proposed merger are not obtained or are obtained subject to conditions that are not anticipated; potential adverse reactions or changes to business or employee relationships, including those resulting from the announcement or completion of the transaction; uncertainties as to the timing of the transaction; competitive responses to the transaction; the possibility that the anticipated benefits of the transaction are not realized when expected or at all, including as a result of the impact of, or problems arising from, the integration of the two companies; the possibility that the transaction may be more expensive to complete than anticipated, including as a result of unexpected factors or events; diversion of management’s attention from ongoing business operations and opportunities; the ability of Chesapeake to complete the acquisition and integration of WildHorse successfully; litigation relating to the transaction; and other factors that may affect future results of WildHorse and Chesapeake. Additional factors that could cause results to differ materially from those described above can be found in WildHorse’s Annual Report on Form 10-K for the year ended December 31, 2017 and in its subsequent Quarterly Reports on Form 10-Q for the quarters ended March 31, 2018, June 30, 2018, and September 30, 2018, each of which is on file with the SEC and available in the “Investor Relations” section of WildHorse’s website, http://www.wildhorserd.com/, under the subsection “SEC Filings” and in other documents WildHorse files with the SEC, and in Chesapeake’s Annual Report on Form 10-K for the year ended December 31, 2017 and in its subsequent Quarterly Reports on Form 10-Q for the quarters ended March 31, 2018, June 30, 2018 and September 30, 2018 each of which is on file with the SEC and available in the “Investors” section of Chesapeake’s website, https://www.chk.com/, under the heading “SEC Filings” and in other documents Chesapeake files with the SEC. All forward-looking statements speak only as of the date they are made and are based on information available at that time. Neither WildHorse nor Chesapeake assumes any obligation to update forward-looking statements to reflect circumstances or events that occur after the date the forward-looking statements were made or to reflect the occurrence of unanticipated events except as required by federal securities laws. As forward-looking statements involve significant risks and uncertainties, caution should be exercised against placing undue reliance on such statements. We use certain terms in this presentation such as “Resource Potential,” “Net Resource,” “Net Reserves” and similar terms that the SEC’s guidelines strictly prohibit us from including in filings with the SEC. These terms include reserves with substantially less certainty, and no discount or other adjustment is included in the presentation of such reserve numbers. U.S. investors are urged to consider closely the disclosure in our Form 10-K for the year ended December 31, 2017, File No. 1-13726 and in our other filings with the SEC, available from us at 6100 North Western Avenue, Oklahoma City, Oklahoma 73118. These forms can also be obtained from the SEC by calling 1-800-SEC-0330. Important Additional Information This communication relates to a proposed business combination transaction (the “Transaction”) between WildHorse Resource Development Corporation (“WildHorse”) and Chesapeake Energy Corporation (“Chesapeake”). This communication is for informational purposes only and does not constitute an offer to sell or the solicitation of an offer to buy any securities or a solicitation of any vote or approval, in any jurisdiction, pursuant to the Transaction or otherwise, nor shall there be any sale, issuance, exchange or transfer of the securities referred to in this document in any jurisdiction in contravention of applicable law. In connection with the Transaction, Chesapeake will file with the SEC a registration statement on Form S-4 that will include a joint proxy statement of Chesapeake and WildHorse and a prospectus of Chesapeake, as well as other relevant documents concerning the Transaction. The Transaction involving WildHorse and Chesapeake will be submitted to WildHorse’s stockholders and Chesapeake’s shareholders for their consideration. STOCKHOLDERS OF WILDHORSE AND SHAREHOLDERS OF CHESAPEAKE ARE URGED TO READ THE REGISTRATION STATEMENT AND THE JOINT PROXY STATEMENT/ PROSPECTUS REGARDING THE TRANSACTION WHEN IT BECOMES AVAILABLE AND ANY OTHER RELEVANT DOCUMENTS FILED WITH THE SEC, AS WELL AS ANY AMENDMENTS OR SUPPLEMENTS TO THOSE DOCUMENTS, BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION. Investors will be able to obtain a free copy of the registration statement and the joint proxy statement/prospectus, as well as other filings containing information about WildHorse and Chesapeake, without charge, at the SEC’s website (http://www.sec.gov). Copies of the documents filed with the SEC can also be obtained, without charge, by directing a request to Investor Relations, WildHorse, P.O. Box 79588, Houston, Texas 77279, Tel. No. (713) 255-9327 or to Investor Relations, Chesapeake, 6100 North Western Avenue, Oklahoma City, Oklahoma, 73118, Tel. No. (405) 848-8000. Participants in the Solicitation WildHorse, Chesapeake and certain of their respective directors, executive officers and employees may be deemed to be participants in the solicitation of proxies in respect of the Transaction. Information regarding WildHorse’s directors and executive officers is available in its definitive proxy statement, which was filed with the SEC on April 2, 2018, and certain of its Current Reports on Form 8-K. Information regarding Chesapeake’s directors and executive officers is available in its definitive proxy statement, which was filed with the SEC on April 6, 2018, and certain of its Current Reports on Form 8-K. Other information regarding the participants in the proxy solicitation and a description of their direct and indirect interests, by security holdings or otherwise, will be contained in the joint proxy statement/prospectus and other relevant materials filed with the SEC. Free copies of this document may be obtained as described in the preceding paragraph. November 2018 Update 2

WILDHORSE ACQUISITION ACCELERATES CHESAPEAKE’S STRATEGIC PLAN Acquisition of WildHorse Margin Enhancement Increases margins from high-value oil production Free Cash Flow Accelerates transition to positive free cash flow Long Term Net Debt / Accelerates deleveraging EBITDA of 2x Chesapeake’s continued commitment EHS Excellence Improving environmental and safety performance November 2018 Update 3

TRANSACTION OVERVIEW > $3.977 billion transaction value • At the election of WildHorse shareholders, 5.989 shares of Chesapeake common Consideration stock per WildHorse share of common stock or 5.336 shares of Chesapeake common stock plus $3.00 per WildHorse share of common stock • Total cash consideration expected to be between $275 – $400 million Pro Forma > Chesapeake’s shareholders will own approximately 55% and WildHorse shareholders Ownership and will own approximately 45% of the combined company Governance > WildHorse will nominate two directors to the Chesapeake Board of Directors > Approval by both Chesapeake and WildHorse shareholders > NGP Energy Capital Management, Carlyle and WRD CEO have entered into a voting Path to Close and support agreement with respect to the transaction > Customary regulatory approvals November 2018 Update 4

STRATEGIC PORTFOLIO ADDITION POSITIONS CHK FOR ADDITIONAL VALUE CREATION ACREAGE POSITION Adds significant premier Eagle Ford asset at an attractive valuation Accelerates cash flow generation with profitable oil growth Materially improves margins and financial profile WildHorse Leasehold CHK Leasehold WildHorse Resource Development Corporation Net acres (84% WI / 66% NRI)(1) ~420,000 ~655,000 Percentage undeveloped acreage 80% – 85% Pro forma Eagle Ford net acreage position Net production 47 mboe/d(2) ASSET ASSET OVERVIEW ~150,000 boe/d (~60% Oil) Liquids / Oil 88% / 73% 2Q’18 Pro forma Eagle Ford production (1) Estimated average interest of future operated locations (2) 2Q’18 Actuals WRD data reflects CHK’s analysis based solely on public information. November 2018 Update 5

ACCELERATING VALUE, DELIVERING ON OUR PROMISES(1) 160165 – 170 30 125130 – 130 25 Improves 19 Enhances 80 oil mix percentage oil production approximately approximately bbls/d % oil % 2x by 2020 60% by 2020 CHK18E(2) PF19E PF20E CHK18E PF19E PF20E Efficiencies drive average annual $200 – $280 million savings total of $1.0 – $1.5 billion by 2023 $19 4.2x $16 3.6x Increases $12 Accelerates 2.8x EBITDA per boe margin deleveraging approximately approximately $ / boe / $ by 2020 by 2020 35% 50% EBITDAadj. / debt Net CHK18E PF19E PF20E CHK18E PF19E PF20E (1) Assumes full year results and strip pricing as of 10/25/2018 (2) Adjusted for Utica disposition as of 1/1/2018 WRD data reflects CHK’s analysis based solely on public information. November 2018 Update 6

COST SAVINGS CREATE SIGNIFICANT SHAREHOLDER VALUE ANNUAL SAVINGS Operational Efficiencies $50 – $80 million Capital Efficiencies $150 – $200 million Total $200 – $280 million Five Year Total Savings(1) $1.0$1.0 –– $1.51.5 billion Operational efficiencies include savings from reduced LOE, G&A and downtime Capital efficiencies include savings from longer laterals and improved well design (1) Realized post closing WRD data reflects CHK’s analysis based solely on public information. November 2018 Update 7

OPPORTUNITIES TO CAPTURE ADDITIONAL MARKETING SYNERGIES Significant synergies available by leveraging Chesapeake’s existing crude transportation options Cooks Point Terminal Large, contiguous Eagle Ford oil position • Abundant pipeline capacity and infrastructure • Advantaged pricing due to proximity Houston Markets to Gulf Coast and export markets 2019 WTI +$5.50 Gardendale Terminal Corpus Christi Terminal 2019 WTI +$5.50 WildHorse Leasehold CHK Leasehold Pipeline WRD data reflects CHK’s analysis based solely on public information. November 2018 Update 8

CREATING AN EAGLE FORD POWERHOUSE Well understood geology similar to existing CHK position ACREAGE POSITION WildHorse Leasehold B CHK Leasehold High on the learning curve Eagle Ford Play • Learnings from more than 2,000 Eagle Ford wells directly transferable to large undeveloped WildHorse position Austin Chalk and improved oil recovery (IOR) offer tangible upside A A Chesapeake WildHorse B Eagle Ford Eagle Ford SW NE Austin Chalk Woodbine Sands 150ʹ – 450ʹ thickness 100ʹ – 500ʹ thickness Eagle Ford 6,000ʹ – 11,000ʹ TVD 6,000ʹ – 11,000ʹ TVD Buda Maverick Basin South Texas Basin Karnes Trough San Marcos Arch East Texas Basin WRD data reflects CHK’s analysis based solely on public information. November 2018 Update 9

THE CHESAPEAKE ADVANTAGE Eagle Ford Lateral Length (mean)(1) Operations Support Center 12,000 10,000 Reservoir Technology Center 8,000 Drilling and completion leadership 6,000 4,000 • >2,000 Eagle Ford wells to date 2,000 Logistics expertise 0 Proven operational performance EHS excellence Eagle Ford D&C $ / Lateral Foot(1) 1,600 1,400 In-house marketing team 1,200 1,000 800 600 Proven expertise helps 400 drive costs down 200 0 (1) Source: RS Energy Group 2017+ TIL as of 9/2018; Peers include: Carrizo, ConocoPhillips, Devon, Encana, Enervest, EOG, EP Energy, Equinor, Lewis Energy Group, Marathon, Murphy, Sanchez, SM Energy; WRD wells could contain science and evaluation capital. WRD data reflects CHK’s analysis based solely on public information. November 2018 Update 10

CHK TODAY: DIVERSE & STRONG PORTFOLIO CORE POSITIONS ACROSS MULTIPLE BASINS Powder River Basin: Oil-growth Engine Marcellus: Leading the Industry Oil production will more than double in 2019 Generating ~$350 million in free cash flow(1) in 2018 Mid-Continent: Growth Optionality Efficient oil volumes, appraising liquid-rich opportunities Gulf Coast: Consistent Performance Access to premium Gulf Coast markets South Texas: Free Cash Flow Machine Generating ~$560 million in free cash flow(1) in 2018 (1) Free cash flow defined as net revenue less all operating costs and capital expenditures. Excludes corporate overhead costs such as capitalized interest and capitalized G&A expenses. WRD data reflects CHK’s analysis based solely on public information. November 2018 Update 11

ACQUISITION CREATES PREMIER DIVERSIFIED INDEPENDENT WITH SIGNIFICANT HIGH-MARGIN OIL-GROWTH RUNWAY Targeting 80%+ of future drilling and completion activity focused on high-margin oil-growth assets High-margin Oil-growth Assets(1) Powder River Basin ~253,000 Acres 29 mboe/d CHK Eagle Ford ~235,000 Acres 100 mboe/d WRD Eagle Ford ~420,000 Acres 47 mboe/d(2) Cash-generating Gas Assets(1) Gulf Coast ~339,000 Acres 128 mboe/d Appalachia North ~547,000 Acres 135 mboe/d Growth Optionality(1) Mid-Continent ~775,000 Acres 25 mboe/d WildHorse Addition Exploration/Other ~1,521,000 Acres N/A Premier high-margin oil-growth engine (1) Unless otherwise noted, operational statistics are as of 9/30/2018 for acreage totals and total production as of 3Q’18. Acreage and production volumes are net to CHK. (2) Actual production for 2Q’18 WRD data reflects CHK’s analysis based solely on public information. November 2018 Update 12

ACCELERATES CHK’S STRATEGIC AND FINANCIAL PLAN Adds significant premier Eagle Ford asset at attractive valuation Increases cash flow generation with profitable oil growth Materially improves margins and financial profile Positions Chesapeake for greater value creation November 2018 Update 13

WildHorse Technical Review November 2018 Update 14

EASTERN EAGLE FORD EVALUATION INITIATED IN 2012 Chesapeake valuation of Eastern Eagle Ford based on bottoms-up internal regional knowledge and expertise 2012 – 2017: CHK Woodbine team evaluates emerging Eastern Eagle Ford play • Play level subsurface evaluation and detailed reservoir mapping to determine 1Q’18: main controls on production First WRD/CHK • Identified high-potential area in and around Burleson County discussions 2012 2017 2018 T e c h n o l o g y e v o l v e s 1H’17: 1Q’18: Regional assessment highgrades Updated evaluation WRD position in the play with additional well • Subsurface evaluation with proprietary and public data performance and detailed reservoir mapping • Well level economic assessment • Management review May 2017 November 2018 Update 15

CHESAPEAKE’S EVALUATION FOUNDATION Eastern Eagle Ford Data Map Extensive review of WRD’s Eagle Ford position conducted 3D seismic Dense log footprint prior to receipt of proprietary data coverage Existing subsurface and commercial evaluations initiated in 2012 ~1,200 wells with logs • Equivalent to ~2 wells/mi2 WildHorse acreage ~300 producing horizontals • ~145 with Gen 3 completions(1) 10 wells with core data • Analyses available through commercial labs Eagle Ford Producing Well Eagle Ford Core On/Near Acreage Additional Eagle Ford Core 20 miles Eagle Ford Penetration with Logs (1) WRD 2Q’18 earnings deck WRD data reflects CHK’s analysis based solely on public information. November 2018 Update 16

THE WILDHORSE ROCK ADVANTAGE WELL CONSTRAINED RESERVOIR CHARACTERISTICS Organic-rich calcareous mudstone Eastern Eagle Ford Type Log Gamma ray Resistivity • Outer shelf depositional setting Top Austin Eastern Eagle Ford Reservoir Thin Section(1) • Similar to South Texas Eagle Ford Chalk organic-rich calcareous mudstone 6,000 – 11,000' TVD 100 – 500' gross interval thickness ~4% average TOC 4 – 6% effective porosity WildHorse WildHorse pay CHK minimum pay (log analysis) CHKstimulated rock volume 0.5 mm Over-pressured, up to 0.7 psi/ft Top Buda Core porosity measurement varies between labs Lab Lab A RTC (CHK) Lab A Lab B Area STX EGFD STX EGFD Eastern EGFD Eastern EGFD Avg. Porosity 8.0% 5.0% 9.0% 4.5% (1) CoreLab Eagle Ford Shale Study WRD data reflects CHK’s analysis based solely on public information. November 2018 Update 17

WildHorse acreage THE WILDHORSE LOCATION ADVANTAGE A’ POSITIONED IN THE CORE OF THE PLAY Controlling the sweet spot • Optimal thickness, organic content, maturity and clay content A 20 miles Gross thickness c.i. = 100' Eastern Eagle Ford Regional Stratigraphic Cross-Section Shale Gross Thickness A A’ Gamma ray Resistivity 100' Austin Chalk Eagle Ford Lower TOC Thin Highest-quality rock Higher clay Buda WildHorse Acreage WRD data reflects CHK’s analysis based solely on public information. November 2018 Update 18

THE WILDHORSE RESERVOIR ADVANTAGE SIGNIFICANT OIL WINDOW EXPOSURE Overlying Austin Chalk GOR aligns with Eagle Ford maturity trends Validated with Eagle Ford production data Eastern Eagle Ford Maturity and Austin Chalk GOR (1) Interpreted Eastern Eagle Ford Fluid Windows WildHorseWildHorse acreage acreage WildHorse acreage Austin Chalk 6-month GOR <2,000 scf/bbl 2,001 – 3,300 scf/bbl 3,301 – 50,000 scf/bbl Black Oil 50,001 – 100,000 scf/bbl >100,001 scf/bbl Volatile Oil EGFD Maturity Condensate to Wet Gas c.i. = 0.1%Ro (1) Data from IHS Markit WRD data reflects CHK’s analysis based solely on public information. November 2018 Update 19

SUBSURFACE CONFIDENCE, REDUCING UNCERTAINTY History of Eastern Eagle Ford Activity Extensive knowledge Deep regional knowledge of Eastern Eagle Ford Well defined, low-risk subsurface elements Production aligns with mapped subsurface properties Oil window well constrained by existing production and maturity trends Attacking uncertainties WildHorse Leasehold Core analysis CHK Leasehold CHK Drilled Wells • Refine in-place volumes (1992 – 2011) • In-house rock mechanics expertise to optimize PRELIMINARY ASSESSMENT (1) completion design PVT analysis Currently 90% • Fluid properties to optimize spacing and draw down of WRD acreage economic 3D seismic reprocessing with longer laterals • Optimize well planning and geosteering • Build earth and reservoir simulation model ~$35 – $45/bbl Breakeven (1) Pricing of $60/bbl and $2.75/mcf, assumes 10,000' lateral WRD data reflects CHK’s analysis based solely on public information. November 2018 Update 20

CHK’S D&C PERFORMANCE ADVANTAGE Operations Support Center provides 24/7 D&C Cost Per Lateral Foot drilling support • Continuous monitoring of drilling performance (1) ~$1,250 • Improved geosteering = higher percentage in zone ~30% • Drilling parameter optimization (2) ~$1,050 reduction Updated well design (2) • Improved hole cleaning ~$850 • Increased ROP • Eliminate sidetracks Cost/ft($/ft) Improve completions performance by two stages/day • Optimize pump schedule, apply best practices $600 – 900M per well in sand savings • On 10,000' laterals with in-field sand mine Current 6,500' Cost Design Improvements Extended Laterals (1) RS Energy estimate for 2017+ TILs, could contain science and evaluation capital (2) Internal estimates WRD data reflects CHK’s analysis based solely on public information. November 2018 Update 21

PROVEN TRACK RECORD Eagle Ford Appalachia South Appalachia North 21% 41% 36% reduction reduction reduction D&C D&C Cost/ft($/ft) 2014 2015 2016 2017 2014 2015 2016 2017 2014 2015 2016 2017 TIL Year TIL Year TIL Year WildHorse ~30% expected reduction Demonstrated efficiency gains in all operating areas driven by: • CHK’s technical and operational advantage • Longer laterals and enhanced completions D&C Cost/ft ($/ft) D&C Cost/ft 2018E 2019E 2020E 2021E TIL Year WRD data reflects CHK’s analysis based solely on public information. November 2018 Update 22

EXTENDED LATERALS DRIVE VALUE Existing WRD Opportunity to increase NPV with extended laterals Short Laterals • Largely undeveloped, contiguous position Unparalleled extended lateral experience • Proven performance across all assets Estimated 30 – 100% improvement in NPV per foot Potential CHK Extended Laterals CHK Longest Lateral by Asset Eagle Ford Drilling Performance(1) 20,000 $3.0 18,000 WildHorse 16,000 $2.5 Chesapeake 15,000 14,000 $2.0 12,000 10,00010,000 $1.5 4,000' longer 8,500' 8,000 than peer group Lateral Length (ft.) LengthLateral $1.0 6,000 5,000 4,000 $0.5 2,000 ($mm)Mean Cost, Drilling Total 00 $0.0 EAGLEEagle FORD GULFGulf COAST APPALACHIAApp MID-CONTINENTMid-Con APPALACHIAApp POWDERPowder RIVER WildhorseWildHorse Average SOUTH NORTH 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000 11,000 12,000 Ford Coast South North River Basin Lateral Length (ft.) (1) RS Energy – Peers include COP, CRZO, DVN, ECA, Enervest, EOG, EPE, EQNR, Lewis, MRO, MUR, NBL, SM, SN, WRD; Represents TILs from 2017 to present, size by number of wells. WRD data reflects CHK’s analysis based solely on public information. November 2018 Update 23

SUBOPTIMAL SPACING DEGRADES 2018 WILDHORSE WELL PERFORMANCE WRD TIL Composition Nearly half of 2018 WRD TILs are 100% 90% Austin Chalk or downspaced Eagle Ford 80% 70% • Versus ~20% in 2017 60% 50% 40% 2018 WRD Eagle Ford performance 30% 20% continues to deliver at 750'+ spacing 10% 0% 2017 2018 Austin Chalk Downspaced Eagle Ford 750'+ Eagle Ford WRD Oil IP90 Performance(1) WRD Oil IP90 Performance(1) (All Wells) (excludes Austin Chalk and Downspacing) 60 60 Completion Degradation 50 Evolution 50 40 40 30 30 No 20 20 Oil IP90 (mbo)IP90 Oil Oil IP90 (mbo)IP90 Oil Degradation 10 10 0 0 TIL Year TIL Year (1) RS Energy (Oil IP90) WRD data reflects CHK’s analysis based solely on public information. November 2018 Update 24

OPTIMIZING WELL SPACING CHK model spacing assumption currently Well Spacing Comparison(1) 1,000' and 10,000' lateral length 180 • 750' spacing probable over most fluid windows • 500' spacing potential with additional evaluation 160 Improved wellbore management 140 • Geosteering in-zone and in-plain 120 Burleson County Example 100 375' Spacing 80 Cumulative Oil (mbo) 60 40 20 0 Unbounded 0 5 10 15 750' Spacing Producing Months 375' Spacing 750' Spacing Unbounded (1) RS Energy (production data) WRD data reflects CHK’s analysis based solely on public information. November 2018 Update 25

REDUCING DOWNTIME, IMPROVING BASE PRODUCTION Opportunity to reduce downtime downtime reduction • Operate by intention ~35% since 2015 in CHK STX Eagle Ford • WellTender mobile app Improved artificial lift designs reduce base production decline rates • Leverage expertise from 2,000+ Eagle Ford wells across all fluid windows WRD Downtime ~5.5% ~5.0% ~3.5% Downtime (%) 2017 2018 CHK Projected Downtime November 2018 Update 26

CHESAPEAKE’S VALUE OPPORTUNITY Technical and Operational Excellence Improved Capital NAV Drives Value Recovery Efficiency Impact Drilling and Completions Optimization • Reduced costs through improved performance and execution Extended Laterals • Develop resource with fewer wells • Substantial reduction in cost per foot Base Management • Reducing downtime • Artificial lift design improvements Subsurface Optimization • Maximize NPV per acre with improved well spacing Future Opportunity • Austin Chalk, IOR and optimized development WRD data reflects CHK’s analysis based solely on public information. November 2018 Update 27

CHK’S CURRENT WRD EAGLE FORD ASSUMPTIONS CHK’s WRD Eagle Ford Model Assumptions CHK’s WRD Eagle Ford Type Curve(2) 1,200 Avg. Lateral Length ~10,000' Locations 1,000 – 1,400 1,000 WI / NRI ~84 / 66% 800 EUR 600 – 700 mboe 600 Well Costs $7.5 – $8.5mm 400 NPV per well(1) $5 – $7mm Avg. Daily Rate (boe/d) DailyAvg. 200 Base spacing assumption 1,000' at 10,000' 0 lateral length 0 10 20 30 40 • 750' spacing probable over most fluid windows Producing Months • 500' spacing potential with additional understanding Additional upside in Austin Chalk: 150 – 200 locations Production Mix(3) • Condensate play in Washington County and oil matrix play Natural in various areas of acreage 85% 9% 6% Gas Line of sight on improved economics and well performance Oil NGL • 30% expected reduction in well cost per lateral foot • Increased % in-zone with improved geosteering $1.2B of NPV on PDP to be optimized ~1,200 – 1,600+ • Downtime management • Production optimization Estimated future locations (1) Strip pricing as of 10/25/2018 (2) Type curve represents five-year drilling plan (3) Forecasted production mix for new wells over the next five years WRD data reflects CHK’s analysis based solely on public information. November 2018 Update 28

PREMIER DIVERSIFIED INDEPENDENT WITH SIGNIFICANT HIGH-MARGIN OIL-GROWTH RUNWAY Targeting 80%+ of future drilling and completion activity focused on high-margin oil-growth assets High-margin Oil-growth Assets(1) Powder River Basin ~253,000 Acres 29 mboe/d CHK Eagle Ford ~235,000 Acres 100 mboe/d WRD Eagle Ford ~420,000 Acres 47 mboe/d(2) Cash-generating Gas Assets(1) Gulf Coast ~339,000 Acres 128 mboe/d Appalachia North ~547,000 Acres 135 mboe/d Growth Optionality(1) Mid-Continent ~775,000 Acres 25 mboe/d WildHorse Addition Exploration/Other ~1,521,000 Acres N/A Premier high-margin oil-growth engine (1) Unless otherwise noted, operational statistics are as of 9/30/2018 for acreage totals and total production as of 3Q’18. Acreage and production volumes are net to CHK. (2) Actual production for 2Q’18 WRD data reflects CHK’s analysis based solely on public information. November 2018 Update 29

POWDER RIVER BASIN OIL-GROWTH ENGINE ClickProduction to edit Ramp takeaway Ahead of Schedule ClickTurner to Leads edit thetakeaway Way ~2.6 bboe ClickStacked to Future, edit takeaway Hotspot Advantage Gross resource size ~1.7 bboe net Production Mix (1) 41% 17% 42% Oil NGL Natural Gas (1) Represents average for 3Q’18 November 2018 Update 30

ACCELERATING THE TURNER Delineated BB 1 18H Turner Producing 2,725 Max boe/d Planned TIL Exceptional productivity (86% oil) SFU 19 23H Planned 2019 Well • 24 Chesapeake TILs to date 1,479 Max boe/d Turner (84% oil) High GOR • Proven, repeatable results • ~60% of Turner acreage delineated • Currently running five rigs - Four TILs in October WYOMING 36 1H 3,133 Max boe/d - Three TILs in November (46% oil) - Eight TILs in December NWFU 26 20H RANKIN 5 1H 400,000 CHK Turner vs. Peers COMBS 13 20H 1,900 Max boe/d 2,886 Max boe/d 1,987 Max boe/d (76% oil) (51% oil) 350,000 (21% oil) 300,000 PRB TIL Schedule 250,000 25 21 200,000 20 19 18 15 150,000 15 14 Cumulative Boe Cumulative 100,000 10 50,000 5 0 0 0 20 40 60 80 100 120 140 160 180 200 4Q'18E 1Q'19E 2Q'19E 3Q'19E 4Q'19E Days November 2018 Update 31

TURNER SPACING TEST UPDATE Delineated Turner Producing Field test yielding positive initial Planned TIL Planned 2019 Well results through 190 days Turner High GOR Optimal spacing drives maximum field development value Two additional tests underway 40 Spacing Performance 35 30 1,980' Unbounded 25 2,300' 20 2,300ꞌ 2,300ꞌ 15 10 Unbounded 5 1,980ꞌ 1,980ꞌ Gross Cumulative Production (boe/lateral Production ft.)(boe/lateral Cumulative Gross 0 0 15 30 45 60 75 90 105 121120 135136 150151 165166 180181 Days November 2018 Update 32

PRB – PREMIER GROWTH OPPORTUNITY Progress to date • Moved to Development phase of the Turner • More than 5,000' of oil-rich, stacked pay opportunities • Continue to appraise new formations 2018 2019 2020+ • Turner spacing tests • Turner development • Appraisal in the Teapot, Parkman, • Successful Turner • Additional Turner Sussex, Frontier step-out tests step-out tests and Mowry • Develop the • Parkman and • Upside spacing tests Turner core Niobrara appraisal (~60% delineated) • Continued Turner development November 2018 Update 33

SOUTH TEXAS FOUNDATIONAL ASSET Consistent High-Margin EBITDA Delivery ~$560 Million FCF(1) in 2018 1.3 bboe Multi-Zone Growth Potential Net resource size(2) Production Mix (3) 58% 22% 20% Oil NGL Natural Gas (1) Free cash flow defined as net revenue less all operating costs and capital expenditures. Excludes corporate overhead costs such as capitalized interest and capitalized G&A expenses. (2) Includes IOR potential (3) Represents average for 3Q’18 November 2018 Update 34

OPTIMIZING SOUTH TEXAS DELIVERING MORE WITH LESS Expected to generate ~$560 million Range of Capex Estimates ($/Lateral Foot)(3) (1) free cash flow in 2018 $1,100 $1.10 RSEG WoodMac $1,000 $1.00 Increased lateral length, spacing and $0.90$900 completions design results in: $0.80$800 • 45% increase in initial well performance(2) $0.70$700 $ D&C/Lateral Foot $ D&C/Lateral $0.60$600 • Stabilization of base production performance $0.50$500 CHK Peer Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer Peer 10 Peer Peer 11 Eagle Ford TIL Schedule CHK Outpaces Basin Peers 16,000 in First Six Month Oil Delivery(4) 53 14,000 46 12,000 34 10,000 30 28 8,000 6,000 4,000 First Six Month Oil (bbl/1,000') Oil Month Six First 2,000 0 4Q'18E 1Q'19E 2Q'19E 3Q'19E 4Q'19E 2014 2015 2016 2017 2018 Peer 1 CHK Peer 2 Peer 3 (1) Free cash flow defined as net revenue less all operating costs and capital expenditures. Excludes corporate overhead costs such as capitalized interest and capitalized G&A expenses. (2) Cumulative production to date of optimized Blakeway development program vs. historic development of the area at 330ꞌ spacing (3) Peer and CHK data pulled from RS Energy Group from wells turned in line in 2017 – 2018 near CHK’s position. Peers include: Carrizo, EOG, EP Energy, Lewis, Marathon, Murphy, Noble, Sanchez, Silverbow, SM Energy, Venado. (4) Peer and CHK data pulled from RS Energy Group from wells turned in line in 2017 – 2018 near CHK’s position. Peers include: Carrizo, EP Energy, Sanchez. November 2018 Update 35

IMPROVED OIL RECOVERY PUSHING THE ENVELOPE Oil-window opportunity • 1.3 – 1.7x potential improvement in oil recovery Proven technology • Multiple in-basin pilots and up-scaled projects Expected benefits • Adds value to existing well set • Lower capital cost per barrel Potential CHK IOR Project Path forward Industry IOR Project • 65-well project underway Oil CHK Phase I Volatile Oil • First injection: June 2019 Condensate/Wet Gas Dry Gas Evaluating expansion west in 2020 November 2018 Update 36

FAITH RANCH PROJECT BATCH DEVELOPMENT YIELDS CONTINUED SUCCESS Faith Ranch ~21,300 net acres Faith Ranch Phase 1 2018 Development • 283 producing wells Phase 2 (1) ~$33/bbl breakeven 16 Wells • Faith – Toro ~80% ROR(2) Faith-San Pedro • Faith – San Pedro ~45% ROR(2) 29 Wells Faith Production Profile Faith-Toro 35,000 30,000 Base 2018 Wedge 25,000 20,000 15,000 Gross Oil (bbl/d) Oil Gross 45 TILs 10,000 in late 3Q, 4Q 5,000 0 31-Jan-18Jan’18 31-Jul-18Jul’18 31-Jan-19Jan’19E 31-Jul-19Jul’19E (1) Assumes $2.75/mcf gas price (2) Assumes $2.75/mcf and $60/bbl November 2018 Update 37

APPALACHIA NORTH LEADING THE INDUSTRY ~$350 Million FCF(1) in 2018 Premier Position 12.6 tcf Expanding Inventory Net resource size Production Mix (1) 100% Natural Gas (1) Free cash flow defined as net revenue less all operating costs and capital expenditures. Excludes corporate overhead costs such as capitalized interest and capitalized G&A expenses. (2) Represents average for 3Q‘18 November 2018 Update 38

LEADING THE COMPETITION IP30 Expected to generate ~$350 million 70 (Scaled to 10,000ꞌ LL)(2) free cash flow(1) in 2018 60 Median 50 Range Production outpacing competitors 40 • 25 TILs in 4Q 30 Technology changing the play 20 10 • Longer laterals, enhanced completions (mmcf/d)Rate Gas Gross IP30: 0 14 CHK Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 12 10 Six-Month Gross Cumulative 8 (Scaled to 10,000ꞌ LL)(2) 8 6 6 4 4 2 2 Average Gross Cumulative Production (bcf) Production Cumulative Gross Average 0 NA NA 0 5 10 15 20 25 30 35 Production Gross (bcf) Cumulative 0 Normalized Producing Months ChesapeakeCHK Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 McGavin 6H (10,400ꞌ LL) CHK Historical (6,100ꞌ LL) Peers (5,000ꞌ – 8,500ꞌ LL) DPH 3H (6,100ꞌ LL) Wood 3H (12,500ꞌ LL) (1) Free cash flow defined as net revenue less all operating costs and capital expenditures. Excludes corporate overhead costs such as capitalized interest and capitalized G&A expenses (2) Peer and CHK data pulled from IHS for wells turned in line in 2017 and 1Q’18. Peers include: Cabot, Chief, EQT, Repsol, Seneca and SWN. November 2018 Update 39

GULF COAST CONSISTENT PERFORMANCE, SIGNIFICANT RUNNING ROOM Completion and Drilling Excellence Redefines Play Expansive Inventory 15 tcf Access to Premium Markets Net resource size Production Mix (1) 100% Natural Gas (1) Represents average for 3Q’18 November 2018 Update 40

HAYNESVILLE FIRST MOVER, INNOVATION LEADER First 15k lateral – GEPH 1HC Existing Planned 15k Well • 5.8 bcf in 170 days 15k Fairway Substantial portfolio of extended reach laterals(1) Driving capital efficiency by increasing lateral length • Currently drilling two additional 15k laterals GEPH 1HC • Potential for five 15k laterals in 2019 Operational advances continue to unlock value GEPH 1HC 60 7.0 10k Fairway 50 6.0 5.0 40 4.0 30 3.0 20 2.0 10 Daily Production Daily Gross Production (mmcf/d) Production Gross Daily 1.0 Cumulative Production (bcf) Production Gross Cumulative 0 0.0 0 20 40 60 80 100 120 140 160 180 Days (1) Includes laterals of 10,000ꞌ or greater in lateral length November 2018 Update 41

MID-CONTINENT REINVENTING A LEGACY ASSET Well-Positioned Acreage Appraising Liquid-Rich Opportunities ~550 mmboe Efficient Oil Volumes Net resource size Production Mix(1) 36% 16% 48% Oil NGL Natural Gas (1) Represents average for 3Q 2018 November 2018 Update 42

REINVENTING THE MID-CONTINENT Current Rig Location ~783,000 (96% HBP) of Producing Well multi-zone stacked potential Wedge Planned TIL Oswego Targeting liquid-rich opportunities • Appraising six formations in 2018 Reopening mature plays through modern technology Woods Major Blaine Kingfisher Canadian County County County County County Penn Shales Osage Oil Chester Woodford Meramec Silt Hunton Meramec Lime November 2018 Update August 2018 Update 43

APPENDIX November 2018 Update 44

LEADING PERFORMANCE G&A per boe Lease Operating Expenses (LOE) per boe(1) $7.00 $10.00 $6.00 $8.00 $5.00 $6.00 $4.00 $3.00 $4.00 $2.00 $2.00 $1.00 $0.00 $0.00 Peer 1 Peer 2 CHK Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer 10 Peer 11 Peer 1 Peer 2 Peer 3 CHK Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer 10 Peer 11 Return on Capital Employed (ROCE) F&D per boe 25.0% $20.00 20.0% $15.00 15.0% $10.00 10.0% $5.00 5.0% 0.0% $0.00 Peer 1 CHK Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer 10 Peer 11 Peer 1 Peer 2 Peer 3 CHK Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer 10 Peer 11 -5.0% Peer 1 Peer 2 Peer 3 CHK Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer 10 Peer 11 Data pulled from Capital IQ and recent company reported filings and represent last twelve months of performance from 9/30/18; Peer group includes: Apache, Anadarko, Antero Resources, Cimarex Energy, Devon Energy, Encana, EQT Corporation, Newfield Exploration, Noble Energy, Pioneer Natural Resources, Range Resources; F&D defined as total D&C capital over total reserve extensions. (1) LOE is a component of oil, natural gas and NGL production expenses in CHK’s statements of operations November 2018 Update 45

HEDGING POSITION AS OF 10/26/18 Natural Gas Oil NGL 2018 2018 2018 7% Collars 6% Collars $3.00/$3.25/mcf $39.15/$47/$55/bbl HH WTI 46% Swaps 74% Swaps 85% Swaps $3.00/mcf $54.09/bbl HH WTI • ~88 bcf of 2019 natural gas hedged with three way collars @ $2.50/$2.80/$3.10/mcf • ~325 bcf of 2019 natural gas hedged with swaps @ $2.83/mcf • ~55 bcf of 2019 natural gas hedged with collars @ $2.75/3.02/mcf • ~15 mmbbls of 2019 oil hedged with swaps @ $59.44/bbl Note: As of October 26, 2018 and percentages based on midpoints of Management’s Outlook dated October 30, 2018, less actual settlements through September 30, 2018. November 2018 Update 46

BASIS HEDGES AS OF 10/26/18 CIG 2019: 11 bcf @ ($0.89) / mcf Tennessee Zone 4-300 Leg 2018: 5.9 bcf @ ($0.77) / mcf Tetco M3 2019: 4.63 bcf @ $2.22 / mcf Argus LLS vs Argus WTI 2018: 3,128 mbbls @ $3.51 / bbl HSC 2019: 4,015 mbbls @ $6.20 / bbl 2019: 22.5 bcf @ $0.03 / mcf Argus Houston vs Argus WTI 2018: 460 mbbls @ $3.57 / bbl 2019: 2,896 mbbls @ $5.75 / bbl Note: As of October 26, 2018, less actual settlements through October 26, 2018. November 2018 Update 47

CORPORATE INFORMATION Headquarters Publicly Traded Securities Cusip Ticker 6100 N. Western Avenue 7.25% Senior Notes due 2018 #165167CC9 CHK18A Oklahoma City, OK 73118 3mL + 3.25% Senior Notes due 2019 #165167CM7 CHK19 WEBSITE: www.chk.com 6.625% Senior Notes due 2020 #165167CF2 CHK20A #165167BU0 Corporate Contacts 6.875% Senior Notes due 2020 #165167BT3 CHK20 #U16450AQ8 BRAD SYLVESTER, CFA 6.125% Senior Notes Due 2021 #165167CG0 CHK21 Vice President – Investor Relations and Communications 5.375% Senior Notes Due 2021 #165167CK1 CHK21A 4.875% Senior Notes Due 2022 #165167CN5 CHK22 DOMENIC J. DELL’OSSO, JR. #165167CQ8 8.00% Senior Secured Second Lien Notes due 2022 N/A Executive Vice President and #U16450AT2 Chief Financial Officer 5.75% Senior Notes Due 2023 #165167CL9 CHK23 Investor Relations department #165167CT2 8.00% Senior Notes due 2025 N/A can be reached at ir@chk.com #U16450AU9 #165167CV7 8.00% Senior Notes due 2027 N/A #U16450AV7 5.50% Contingent Convertible Senior Notes due 2026 #165167CY1 N/A 2.25% Contingent Convertible Senior Notes due 2038 #165167CB1 CHK38 4.5% Cumulative Convertible Preferred Stock #165167842 CHK PrD #165167834 5.0% Cumulative Convertible Preferred Stock (Series 2005B) N/A #165167826 #U16450204 5.75% Cumulative Convertible Preferred Stock #165167776 N/A #165167768 #U16450113 5.75% Cumulative Convertible Preferred Stock (Series A) #165167784 N/A #165167750 Chesapeake Common Stock #165167107 CHK November 2018 Update 48