SCOTIA HOWARD WEIL 2018 ENERGY CONFERENCE New Orleans, Louisiana March 2018 Doug Lawler President and Chief Executive Officer
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, management's outlook guidance 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, anticipated timing of wells to be placed into production, general and administrative expenses, capital expenditures, the timing of anticipated asset sales and proceeds to be received therefrom, the expected use of proceeds of anticipated asset sales, projected cash flow and liquidity, our ability to enhance our cash flow and financial flexibility, plans and objectives for future operations, 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/secfilings). 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; the availability of cash flows from operations and other funds to finance reserve replacement costs or satisfy our debt obligations; 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 to 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; an interruption in operations at our headquarters due to a catastrophic event; certain anti-takeover provisions that affect shareholder rights; and our inability to increase or maintain our liquidity through debt repurchases, capital exchanges, asset sales, joint ventures, farmouts or other means. In addition, disclosures concerning the estimated contribution of derivative contracts to our future results of operations are based upon market information as of a specific date. These market prices are subject to significant volatility. Our production forecasts are also dependent upon many assumptions, including estimates of production decline rates from existing wells and the outcome of future drilling activity. Expected asset sales may not be completed in the time frame anticipated or at all. We caution you not to place undue reliance on our forward-looking statements, which speak only as of the date of this presentation, and we undertake no obligation to update any of the information provided in this presentation, except as required by applicable law. In addition, this presentation contains time-sensitive information that reflects management's best judgment only as of the date of this presentation. We use certain terms in this presentation such as Resource Potential, 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,, 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. Scotia Howard Weil 2018 Energy Conference 2
UPDATE ON RECENT PROGRESS Cash proceeds from divestitures ~$500 million in asset sales signed in late- and 2018; expected to close in 1H 2018 Represents an EBITDA multiple of 7.1x ~$74 million in net proceeds from sale of FTSI shares Pursuing multiple, large transactions Current liquidity is strong ~$3.3 billion Revolver availability as of February 28, 2018 (1) ~$300 million In pending receipts (2) (1) Approximately $338 million borrowed on revolving credit facility and includes approximately ~$115mm of letters of credit (2) Includes proceeds from announced asset sales. Scotia Howard Weil 2018 Energy Conference 3
WHAT S THE IMPACT? Sold ~23,000 boe/d (25% oil) while maintaining flat 2018 adjusted production YOY Cost structure reduced by ~$0.14/boe (1) Interest expense may be reduced by up to ~$50 million Overhead reduction of ~$70 million through efficiencies and synergies Remaining FTSI ownership of ~22 million shares + We expect to be cash flow positive with signed/closed A&D activity at current strip prices in 2018 (1) Cash costs include production expenses and gathering, processing and transportation expenses. Scotia Howard Weil 2018 Energy Conference 4
2018 GUIDANCE HIGHLIGHTS 515 550 mboe/d ~3% adjusted growth ~5% adjusted oil growth Decreases 12% YOY (1) Excluding capitalized interest Scotia Howard Weil 2018 Energy Conference 5
Equivalent Net Volume (mboe/d) OIL ASSETS IN OUR PORTFOLIO High-quality assets Accelerate Turner development Maximize free cash flow in South Texas Test new plays in Mid-Continent 2018 Plan Maximize value of every dollar Grow cash flow Improve margins 200 180 160 140 120 100 80 60 40 20 0 Q1 Q2 Production from Oil Assets Q3 ~70% liquids, ~30% gas Q4 Q1 Q2 Q3 Q4 Denotes volumes sold from announced transactions Scotia Howard Weil 2018 Energy Conference 6
POWDER RIVER GROWING TO A CORE ASSET WY Oil growth engine Ramping up activity Fourth rig in April Evaluating fifth rig Stacked pay opportunities ~275,000 net acres (75% held) 13+ prospective horizons 40 35 30 25 20 15 10 Equivalent Net Volume (mboe/d) ~40% oil, ~58% liquids ~2.6 bboe gross Recoverable resource potential ~1.7 bboe net 5 0 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Scotia Howard Weil 2018 Energy Conference 7
TURNER CONTINUOUS IMPROVEMENT WY Drilling improvements Extending laterals Batch drilling Slim hole casing design Drilling days from 60+ to ~21 $320 Turner Avg Drilling Cost Per Foot $267 $308 $206 Completion improvements Optimizing cluster spacing design More efficient stimulation operations Continue to drive more efficiency Q1 Q2 Q3 Q4 Q1 Turner Avg Completion Cost Per Lateral Foot $542 $518 $469 $420 $353 Q1 Q2 Q3 Q4 Q1 Scotia Howard Weil 2018 Energy Conference 8
POWDER RIVER BASIN OPPORTUNITY WY 600 500 400 300 200 100 0 Location Inventory Above 40% ROR (1) Fall Fall 2016 2016 Analyst YE 2016 YE Analyst Day Day Parkman 205 mmboe resource base 425+ undrilled locations 1,980' spacing Sussex 67 mmboe resource base 72 undrilled locations 1,980' spacing Niobrara 538 mmboe resource base 650+ undrilled locations 1,100' 1,320' spacing Turner Up to 1.2 bboe resource base 350 600 undrilled locations 1,760 2,640' spacing Mowry 570 mmboe resource base 875+ undrilled locations 1,320' spacing Premium inventory expanding Over ~500 locations with ROR >40% Other future potential formations: Teapot, Surrey and Frontier (1) Oil held flat at $60/bbl and gas held flat at $3/mcf Scotia Howard Weil 2018 Energy Conference 9
Equivalent Net Volume (mboe/d) GAS ASSETS IN OUR PORTFOLIO Competitive returns Marcellus is strongest investment in portfolio, ~75% ROR at $2.75/mcf ~40% ROR at $2.75/mcf for Haynesville and Utica Well-hedged at ~$3.10/mcf in 2018 2018 Plan Maximize value of every dollar Optimize drilling and completions 450 400 350 300 250 200 150 100 50 0 Q1 Q2 Production from Gas Assets Q3 ~90% gas, ~10% liquids Q4 Q1 Q2 Q3 Q4 Scotia Howard Weil 2018 Energy Conference 10
MARCELLUS FREE CASH FLOW ENGINE PA Powerhouse shale gas asset Technology driving greater value Working additional market opportunities Growth potential and portfolio flexibility 2,040 locations remaining Low maintenance ~2.1 bcf/d with 7 /mcf LOE (1) Operational excellence Delivering measurable improvement 150 125 100 75 50 25 Equivalent Net Volume (mboe/d) ~100% gas, ~0% liquids ~34.5 tcf gross Recoverable resource potential ~12.6 tcf net 0 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 (1) Excludes Ad Val taxes Scotia Howard Weil 2018 Energy Conference 11
Average Cumulative Gas per Well (bcf) LOWER MARCELLUS DRIVING MORE VALUE PA Average Cumulative Gas per Well 5.0 4.5 4.0 3.5 3.0 2.5 2.0 1.5 1.0 0.5 17 16 15 14 13 < 13 0.0 0 2 4 6 8 10 12 Month Game changing Longer laterals and enhanced completions Stacked pay Upper Marcellus, Lower Marcellus and Utica potential Scotia Howard Weil 2018 Energy Conference 12
0 5 10 15 20 25 30 35 40 45 50 55 60 65 70 75 80 85 90 95 100 105 110 Gas Flowrate (MCFD) UPPER MARCELLUS FUTURE POTENTIAL PA New Completions vs. Expectations 35,000 30,000 25,000 20,000 15,000 10,000 5,000 0 Normalized Producing Days MARIS SUS 25H KIPAR S SUS 6H MARIS SUS 4H PREVIOUS MRCLU TC Increasing NAV Proving potential and increasing locations ~750 locations (1) Unrealized value Longer laterals and enhanced completion drive rival productivity to Upper Marcellus (1) Upper Marcellus development assumes 1,200' spacing Scotia Howard Weil 2018 Energy Conference 13
GULF COAST DEEP HIGH-QUALITY INVENTORY LA Acreage position is 100% HBP, 25% developed ideal for long lateral development Completions breakthrough is scalable across entire acreage position Unlocking the Bossier Ample takeaway capacity to markets with favorable pricing 180 160 140 120 100 80 60 Equivalent Net Volume (mboe/d) ~100% gas, ~0% liquids 40 20 0 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Scotia Howard Weil 2018 Energy Conference 14
Average Cumulative Gas per Well (bcf) GULF COAST IMPROVEMENT CONTINUES LA Significant running room 30+ years of Haynesville and Bossier drilling Large refrac potential ~23.3 tcf gross Recoverable resource potential ~15.2 tcf net 7.0 6.0 Average Cumulative Gas per Well 17 5.0 4.0 3.0 2.0 1.0 Peer data and one slide? 16 14 15 10 13 08 09 0.0 0 2 4 6 8 10 12 14 Month Scotia Howard Weil 2018 Energy Conference 15
PREMIER, DIVERSIFIED ASSET BASE POWDER RIVER BASIN Grow oil production Advance new concepts APPALACHIA SOUTH Maximize free cash flow APPALACHIA NORTH Maximize free cash flow MID-CONTINENT Develop new plays Execute divestitures GULF COAST Maximize free cash flow Optimize FT SOUTH TEXAS Stable high margin oil production Maximize free cash flow IOR potential Scotia Howard Weil 2018 Energy Conference 16
STRATEGY AND GOALS Our strategy remains unchanged resilient to commodity price volatility Financial discipline Profitable and efficient growth from captured resources Exploration Business development STRATEGIC GOALS 1 Debt reduction of $2 $3 billion ultimate goal of net debt to EBITDA of 2X 2 3 Free cash flow neutrality Margin enhancement Scotia Howard Weil 2018 Energy Conference 17
Costs, $ millions Costs, $/boe CASH COST LEADERSHIP $2,000 $1,800 $1,600 $1,400 Production Expense + G&A (1) Cash Cost (PE + G&A) $ / boe $8.00 $7.00 $6.00 $1,200 $5.00 $1,000 $4.00 $800 $600 $400 $200 $3.00 $2.00 $1.00 $0 2012 2013 2014 2015 2016 $0.00 (1) Includes stock-based compensation expenses Scotia Howard Weil 2018 Energy Conference 18
$ millions APPROACHING FREE CASH FLOW NEUTRALITY Free Cash Flow $3,000 $5,000 ~$5,600 $2,000 Excluding Asset Sales Including Asset Sales $1,000 $0 2012 2013 2014 2015 2016 -$1,000 -$2,000 -$11,000 -$3,000 ~($11,200) See non-gaap reconciliation on page 34 Scotia Howard Weil 2018 Energy Conference 19
Equivalent Net Volume (mboe/d) Capex ($ billions) CAPITAL EFFICIENCY 800 $16,000 700 $14,000 600 2018 MIDPOINT $12,000 500 $10,000 400 $8,000 300 $6,000 200 $4,000 100 $2,000 0 2012 2013 2014 2015 2016 $0 Scotia Howard Weil 2018 Energy Conference 20
Return on Capital (%) $/bbl RETURN ON CAPITAL 25% $120 20% NYMEX Oil OIL OCF/Net Return on Debt+Equity Capital (1) $100 $80 15% $60 10% $40 5% $20 0% 2012 2013 2014 2015 2016 $0 (1) Return on capital is cash flow from operations divided by net debt plus shareholder equity Scotia Howard Weil 2018 Energy Conference 21
CHESAPEAKE ENERGY: THE UNCONVENTIONAL LEADER A Transformed Company Leadership attributes Capital efficiency Operational excellence Portfolio depth Technology EH&S excellence Undervalued currency Scotia Howard Weil 2018 Energy Conference 22
Appendix Scotia Howard Weil 2018 Energy Conference 23
BEST-IN-CLASS EH&S PERFORMANCE 304 PROTECTING THE ENVIRONMENT Reportable Spills 214 1.47 PROTECTING OUR EMPLOYEES Total Recordable Incident Rate REGULATORY COMPLIANCE LEADER Notice of Regulatory Violations Incident Count (1) 1,929 191 133 72 61 0.48 0.31 0.51 0.38 371 0.05 184 126 29 2012 2013 2014 2015 2016 2012 2013 2014 2015 2016 2013 2014 2015 2016 80% improvement 97% improvement 98% improvement (1) 2013 NOV count is 1,929 due to how NOVs were uploaded/managed in KMI database Scotia Howard Weil 2018 Energy Conference 24
HEDGING POSITION AS OF 3/21/18 (1) Natural Gas 2018 Collars 68% 47 bcf $3.00/$3.25/mcf HH Oil 2018 Collars 80% 1.8 mmbbls $39.15/$47/$55/bbl WTI NGL 2018 4% Swaps 532 bcf $3.11/mcf HH Swaps 24 mmbbls $52.87/bbl WTI 365 mbbls Propane Swaps $0.73/gal 181 mbbls Ethane Swaps $0.28/gal 255 mbbls Butane Swaps $0.88/gal 10.7 mmbbls of 2018 LLS-WTI oil basis hedges @ +$3.32 52 bcf of March October 2018 Tenn Zone 4-300 gas basis hedges @ -$0.77 7.7 mmbbls of 2019 oil hedged with swaps at an average price of $56.64 87 bcf of 2019 gas collars @ $2.50/$2.80/$3.10 (1) As of 3/21/18, does not reflect January - March 2018 settlements Scotia Howard Weil 2018 Energy Conference 25
DEBT MATURITY PROFILE 2018 OUTLOOK (1) $9.2 billion Senior Notes & Term Loan 7.10% WACD $338 million Revolving Credit Facility $3,000 $2,500 Revolving Credit Facility $2,000 Secured Unsecured Convertibles $2,047 $1,868 $ millions $1,500 $1,000 $1,300 $1,250 $1,300 $718 $665 $500 $338 $53 $0 2015 2016 2018 2019 2020 2021 2022 2023 2025 2026 2027 (1) As of 2/28/2018 Scotia Howard Weil 2018 Energy Conference 26
SOUTH TEXAS CONTINUES TO DELIVER TX Improved oil recovery Proven technology Evaluating multiple pilot opportunities Stacked pay potential Upper Eagle Ford and Austin Chalk provide additional resource potential ~4 rig program in 2018 Projected reduction of 2018 D&C capex of ~$150 million provides flat production, with significantly higher free cash flow 140 120 100 80 60 40 20 Equivalent Net Volume (mboe/d) ~60% oil, ~78% liquids 0 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Scotia Howard Weil 2018 Energy Conference 27
Cumulative Oil/ft (bbl/ft) Cumulative Oil/ft (bbl/ft) Cumulative Oil/ft (bbl/ft) SOUTH TEXAS DRIVING FOR VALUE TX Fit-for-purpose completions and targeting are improving well results Right-sized spacing Longer laterals optimizing development plan 16 14 12 10 8 6 4 2 0 N McMullen +58% Producing Days 0 100 200 300 10 Four Corners NORTH MCMULLEN 5 +44% NORTH MCMULLEN 0 Producing Days 0 50 100 150 SOUTH DIMMIT CHK LEASEHOLD 25 20 15 S Dimmit +61% 10 Down-spaced wells Up-spacing test 5 0 Producing Days 0 50 100 150 200 Scotia Howard Weil 2018 Energy Conference 28
Daily Production (boe/d) SOUTH TEXAS MULTI-ZONE POTENTIAL TX 2,000 1,800 1,600 1,400 1,200 1,000 800 600 400 200 0 Blakeway 3 D DIM 2H Upper Eagle Ford SERIES2 PRE-DRILL EXPECTATIONS BLAKEWAY 3 D DIM 2H 0 50 100 150 200 Days on Production Spud 3/17 Spud 6/17 TIL 3Q17 Pad Level Co-development Test w/lefg & UEFG Austin Chalk Upper Eagle Ford 1/17 Spud 5/17 TIL 4Q17 3Q18 Pad Level Co-development Test w/lefg Scotia Howard Weil 2018 Energy Conference 29
Cumulative boe POWDER RIVER BASIN TURNER WY Cumulative boe vs. Producing Months 400,000 Industry Turner Offsets CHK Turner Producers 300,000 200,000 100,000 Condensate 0 0 2 4 6 8 10 Producing Months ~1,600 bo/d 24-hr rate from BB 35-35-72 21H Well continues to improve Strong performance Beating industry offsets Actively reducing capex Scotia Howard Weil 2018 Energy Conference 30
POWDER RIVER BASIN 17 PROSPECTIVE FORMATIONS WY Scotia Howard Weil 2018 Energy Conference 31
UTICA IMPROVEMENT CONTINUES OH Optimizing dry gas design ~60% improvement in 180-day cumulative production Continuing to test economic bounds Enhancing wet gas completions ~40 100% improvement in 100-day cumulative production Continuing to optimize proppant loading and well spacing 2.0 1.8 1.6 1.4 1.2 1.0 0.8 0.6 0.4 0.2 0.0 Average Cumulative Gas per Well (bcf) 17 16 15 14 11 13 12 0 2 4 6 8 10 12 Month Scotia Howard Weil 2018 Energy Conference 32
MID-CON STACKED PAY POTENTIAL OK Oil growth potential Oswego provides low-cost, high-return oil Chester and Hunton delineation provides near-term growth options 70 Equivalent Net Volume (mboe/d) 60 50 40 ~28% 30oil, ~46% liquids 20 10 0 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Represents volumes sold in and 2018 Scotia Howard Weil 2018 Energy Conference 33
RECONCILIATION OF FREE CASH FLOW In Millions of USD except Per Share FY 2012 FY 2013 FY 2014 FY 2015 FY 2016 FY FY 12 Months Ending 12/31/2012 12/31/2013 12/31/2014 12/31/2015 12/31/2016 12/31/ 12/31/2018 Cash flow Net income -594.0 894.0 2,056.0-14,635.0-4,399.0 953.0 DD&A 2,811.0 2,903.0 2,915.0 2,229.0 1,107.0 995.0 Unrealized loss (gain) on derivatives -926.0-71.0-1,102.0-932.0 739.0-409.0 Deferred income taxes -427.0 526.0 1,097.0-4,427.0-171.0 11.0 Impairments 3,631.0 483.0 63.0 18,466.0 3,150.0 4.0 Gain on sale -267.0-302.0-199.0 4.0-12.0-3.0 Other cash before changes in working capital -308.0 523.0 316.0 1,563.0 114.0-335.0 Cash flow before changes in working capital 3,920.0 4,956.0 5,146.0 2,268.0 528.0 1,216.0 1,500.0 Changes in working capital -1,083.0-342.0-512.0-1,034.0-732.0-471.0 Cash flow from operations 2,837.0 4,614.0 4,634.0 1,234.0-204.0 745.0 1,500.0 Divestitures of oil and gas properties 5,884.0 3,467.0 5,813.0 189.0 1,406.0 1,249.0 574.0 Proceeds from other sales 4,492.0 1,037.0 1,242.0 89.0 131.0 55.0 Cash flow before changes in working capital plus net proceeds from asset sales 14,296.0 9,460.0 12,201.0 2,546.0 2,065.0 2,520.0 2,074.0 Capital expenditures Exploration and development capital expenditures 8,930.0 5,604.0 4,581.0 3,095.0 1,295.0 2,186.0 2,000.0 Acquisitions of oil and gas properties 3,161.0 1,032.0 1,311.0 533.0 788.0 285.0 Other property additions 3,046.0 1,016.0 726.0 144.0 106.0 21.0 Total capital expenditures 15,137.0 7,652.0 6,618.0 3,772.0 2,189.0 2,492.0 2,000.0 Free cash flow, excluding asset sales -11,217.0-2,696.0-1,472.0-1,504.0-1,661.0-1,276.0-500.0 Free cash flow, including asset sales -841.0 1,808.0 5,583.0-1,226.0-124.0 28.0 74.0 Source: SEC filings; Excludes net proceeds from asset divestitures and other property sales (1) Free cash flow is defined as net cash provided by operating activities before changes in components of working capital minus total capital expenditures. Free cash flow is presented because management believes it is a useful adjunct to net cash provided by operating activities under GAAP and provides useful information to investors for analysis of the Company's ability to generate cash to fund exploration and development, and to service debt. Free cash flow is widely accepted as a financial indicator of an oil and natural gas company's ability to generate cash that 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 oil and natural gas exploration and production industry. Free cash flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating activities as an indicator of cash flows, or as a measure of liquidity. Because free cash flow excludes some, but not all, items that affect net cash provided by operating activities and may vary among companies, our calculation of free cash flow may not be comparable to similarly titled measures of other companies. Free cash flow for the year ended December 31, includes $290 million paid to assign an oil transportation agreement to a third party and $126 million paid to terminate future natural gas transportation commitments. Scotia Howard Weil 2018 Energy Conference 34
CORPORATE INFORMATION HEADQUARTERS 6100 N. Western Avenue Oklahoma City, OK 73118 WEBSITE: www.chk.com CORPORATE CONTACTS BRAD SYLVESTER, CFA Vice President Investor Relations and Communications DOMENIC J. DELL OSSO, JR. Executive Vice President and Chief Financial Officer Investor Relations department can be reached at ir@chk.com PUBLICLY TRADED SECURITIES CUSIP TICKER 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 #165167BT3 #U16450AQ8 CHK20 6.125% Senior Notes Due 2021 #165167CG0 CHK21 5.375% Senior Notes Due 2021 #165167CK1 CHK21A 4.875% Senior Notes Due 2022 #165167CN5 CHK22 8.00% Senior Secured Second Lien Notes due 2022 #165167CQ8 #U16450AT2 5.75% Senior Notes Due 2023 #165167CL9 CHK23 8.00% Senior Notes due 2025 8.00% Senior Notes due 2027 #165167CT2 #U16450AU9 #165167CV7 #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 5.0% Cumulative Convertible Preferred Stock (Series 2005B) 5.75% Cumulative Convertible Preferred Stock 5.75% Cumulative Convertible Preferred Stock (Series A) #165167834 #165167826 #U16450204 #165167776 #165167768 #U16450113 #165167784 #165167750 Chesapeake Common Stock #165167107 CHK N/A N/A N/A N/A N/A N/A Scotia Howard Weil 2018 Energy Conference 35