CITIBANK ENERGY INVESTOR TOUR December 16, 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. They include statements that give our current expectations or forecasts of future events, production and well connection forecasts, estimates of operating costs, planned development drilling and expected drilling cost reductions, capital expenditures, expected efficiency gains, our ability to improve margins, reduce operating and G&A expenses, optimize base production, and use leading-edge technology to drive capital efficiency, the timing of anticipated noncore asset sales and proceeds to be received therefrom, projected cash flow and liquidity, business strategy and other opportunities, plans and objectives for future operations (including restructuring of midstream gathering agreements), and the assumptions on which such statements are based. Although we believe the expectations and forecasts reflected in the forward-looking statements are reasonable, we can give no assurance they will prove to have been correct. They can be affected by inaccurate or changed assumptions or by known or unknown risks and uncertainties. Factors that could cause actual results to differ materially from expected results include those described under "Risk Factors in Item 1A of our annual report on Form 10-K and any updates to those factors set forth in Chesapeake's subsequent quarterly reports on Form 10-Q or current reports on Form 8-K (available at http://www.chk.com/investors/sec-filings). These risk factors include the volatility of oil, natural gas and NGL prices; 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. 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. CITIBANK ENERGY INVESTOR TOUR DECEMBER 2015 2
3Q 15 FINANCIAL AND OPERATIONAL RESULTS ADJ. EARNINGS/FDS ($0.05) ADJ. EBITDA $560mm PROD. and G&A EXP. 9% YOY $4.88/boe (1) ADJ. PRODUCTION 3% YOY (2) 667 mboe/d LIQUIDS MIX (3) 28% of total production ADJ. OIL PRODUCTION 4% YOY (2) 114 mbo/d (1) Includes stock-based compensation (2) Adjusted for asset sales (3) Oil and NGLs collectively referred to as liquids Note: Reconciliation of non-gaap measures to comparable GAAP measures appear on pages 18 19 CITIBANK ENERGY INVESTOR TOUR DECEMBER 2015 3
BUSINESS DELIVERY Chesapeake continues to execute on its strategy Financial Stability Operational Leadership Portfolio Strength & Flexibility CITIBANK ENERGY INVESTOR TOUR DECEMBER 2015 4
NEAR-TERM STRATEGY Maximize liquidity Improve margins Use operating and capital flexibility as a strength Preserve cash flow generation capability Amended credit facility Divest noncore assets Restructure midstream contracts Reduce field operating expenses Optimize base production Focus on core positions Enhance field development Leading-edge technology to drive capital efficiency Reduce G&A expenses CITIBANK ENERGY INVESTOR TOUR DECEMBER 2015 5
FINANCIAL STABILITY MAXIMIZING LIQUIDITY Proactively working to increase liquidity Amended credit facility agreement maturing in 2019 Noncore divestitures expected to total $200 $300mm by 1Q 16 Maintaining capital discipline during challenging commodity environment On target to beat February production guidance for FY 2015 despite: $500mm capital spending reduction Average voluntary curtailment of ~35,000 boe/d YTD Portfolio strength and flexibility provides financial stability; spending less and producing more CITIBANK ENERGY INVESTOR TOUR DECEMBER 2015 6
FINANCIAL STABILITY CREDIT FACILITY AMENDMENT Financial security and flexibility > Borrowing base confirmed at $4.0 billion > Facility maturing in 2019 > Covenants restructured in light of low commodity prices > $2.4 billion of additional secured debt available, should conditions warrant Operational flexibility > Reduced commitments and continually improving capital efficiency positions Chesapeake to run a reduced capital program in 2016 to support liquidity focus > Depth of portfolio allows for continued, methodical sales of noncore assets to enhance value $5.7 billion In cash and undrawn credit facility on 9/30/15 CITIBANK ENERGY INVESTOR TOUR DECEMBER 2015 7
OPERATIONAL LEADERSHIP Enhanced base production of existing assets Generated an additional 7 mmboe net YTD Focused programs on compression and artificial lift Reduced downtime through enhanced winterization activities Development teams extending technological limits with operations program Drilled the longest laterals (1) in each of our major operating areas in 2015; significantly enhancing economics Long laterals improve capital efficiency ($/boe) by 20 25% companywide 2015 Record LL (ft.) Avg. 2014 LL (ft.) 12,976 13,192 ~7 mmboe Additional net base production YTD vs. 2015 budget forecast 9,395 9,366 4,464 6,186 10,020 4,998 7,371 5,955 Miss Lime PRB Haynesville Utica Eagle Ford (1) Lateral lengths reported are drilled footage, not completed footage CITIBANK ENERGY INVESTOR TOUR DECEMBER 2015 8
SUBSTANTIAL GROWTH OPPORTUNITIES MID-CONTINENT: MERAMEC AND OSWEGO Meramec First well 27 days spud to RR Second well 18 days spud to RR Mississippian/Meramec Oswego All Rights Shallow Rights CHK Rouce 4-17-10 1H Initial CHK 9,350 Meramec well CHK Hughes Trust 1H Oswego Test 2052 BOEPD Peak (93% Oil) CHK Industry Oswego Three Oswego wells drilled to date 1723 BOEPD IP (85% Oil) CHK Wittrock 16-16-9 1H 9,220 Meramec well 1374 BOEPD IP (80% Oil) 1309 BOEPD IP (79% Oil) Second Meramec well exceeds play performance at a stabilized rate of 1,900 boe/d with greater than 2,000 psi CHK Stangl 36-16-9 1H 10,000 Meramec well ~1,200 locations Meramec and Oswego Limestone Meramec Oswego $36 PV-10 Break-Even (1)(2) $37 PV-10 Break-Even (1)(3) Production Mix Production Mix (1) Assumes NYMEX natural gas price of $3.00/mcf held constant (2) Assumes $7.1mm well cost (3) Assumes $3.2mm well cost NGL Oil Gas CITIBANK ENERGY INVESTOR TOUR DECEMBER 2015 9
SUBSTANTIAL VALUE UNDER HBP ACREAGE UPPER MARCELLUS Recent successful appraisal of the Upper Marcellus unlocks more than 1,000 economic locations (1) Well 1 peak rate 19 mmcf/d Well 2 peak rate 17 mmcf/d Future test wells in Susquehanna and Wyoming counties Test Well 1 19 mmcf/d Test Well 2 17 mmcf/d Favorable development flexibility as position is held by production No communication between Upper and Lower Marcellus confirmed >1,000 locations Break-Even (PV-10) (1) Upper Marcellus (1) Assumes NYMEX natural gas price of $3.00/mcf. CITIBANK ENERGY INVESTOR TOUR DECEMBER 2015 10
Avg Daily Rate (mboe/d) OPTIMIZING VALUE FROM BASE PRODUCTION UTICA SHALE Operating more efficiently Compressor/Artificial lift optimization Pressure maintenance program Choke management Better winter ops preparation 180 160 140 120 100 80 60 2015 Gross Operated Base Production Midstream improvements Line pressure decrease Fewer disruptions 40 Incremental Production Avg Mboe/d mboe/d 20 Previous Trend Current Trend 0 Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15 12% increase 2015 1H production driven by base optimization CITIBANK ENERGY INVESTOR TOUR DECEMBER 2015 11
Bopd Bopd DEVELOPMENT OPTIMIZATION EAGLE FORD Leveraging Chesapeake s technical advantage First wells with laterals greater than 12,500 on flowback Rogers E-1H; 12,611 LL (1) 13,000 wells provide capital reduction of more than 20% when compared to two 6,500 laterals Extended laterals improve Eagle Ford capital efficiency ($/boe) by ~20% Faith-San Pedro F-4H; 13,192 LL (1) Current Rigs CHK Leasehold County MATURITY WINDOW Oil Window Dry Gas Window Wet Gas Window Transition Window 1800 1200 Oil Production Rate Rogers Extended Lateral Control 6400' 1800 1200 Oil Production Rate Faith Extended Lateral Control 6500' 600 600 0 0 5 10 15 20 25 30 35 40 45 0 0 5 10 15 20 25 30 35 40 Days Days (1) Lateral lengths reported are drilled footage, not completed footage CITIBANK ENERGY INVESTOR TOUR DECEMBER 2015 12
Avg Daily Gas Rate (mmcf/d) $/Foot Wells Spud TURNING EFFICIENCY INTO VALUE HAYNESVILLE Extended laterals Two 7,500 lateral tests flowing an average of 16.1 mmcf/d for more than 170 days Production test of first three 10,000 laterals in 4Q 15 Technological innovation and continued cost improvement are driving value into the Haynesville Producing 7,500 Nguyen wells 10,000 lateral in progress 7,500 8,500 laterals in progress CHK Operated Rigs CHK Leasehold Haynesville Shale Extended Lateral Performance Drilling Cost Per Foot 25 20 15 10 Nguyen 7500 Rate (mcfpd) Nguyen 7500 Avg FTP (psi) Unit Rate (mcfpd) Unit FTP (psi) 10 mmcf/d higher $300 $250 $200 $150 $100 $50 $289 $275 $246 $241 $234 18 18 19 15 13 $209 18 30 25 20 15 10 5 5 $0 Q2 Q3 Q4 Q1 Q2 Q3 0 0 0 50 100 150 Days 2014 2014 2014 2015 2015 2015 Avg(CPF) Well Count CITIBANK ENERGY INVESTOR TOUR DECEMBER 2015 13
APPLYING NEW TECHNOLOGIES MID-CONTINENT Multilateral wells First multilateral expected to TIL mid-december Potential to spread technology to other plays significant cost saving potential Multisection extended laterals Drilled two extended multisection laterals Saves ~$1.4mm as compared to two standard laterals 27% decrease in D&C costs compared to drilling two standard laterals Extend and Multilateral Wells Mississippi Lime County CHK Section Summary Extended Laterals JJJ 23-25-11 1H Est TIL 11/20/2015 Sunny 23-25-11 1H TIL in Q4 2015 Multilateral Wilber 26-27-11 1H TD 10/8/2015 Initial Miss Lime Multilateral well exceeds 1,200 boe/d Multisection Extended Laterals Multilateral Wells CITIBANK ENERGY INVESTOR TOUR DECEMBER 2015 14
PORTFOLIO STRENGTH AND FLEXIBILITY Natural Gas Break-Even (PV-10) (1) Oil Break-Even (PV-10) (2) $3.50 $60.00 $3.00 $50.00 $2.50 $40.00 $2.00 $30.00 $1.50 $1.00 $20.00 $0.50 $10.00 $0.00 HAYNESVILLE UTICA DRY UTICA WET MARCELLUS $0.00 PRB SUSSEX MISS LIME EAGLE FORD MID-CON STACK Chesapeake s diverse portfolio of highly efficient investments is built to withstand the current commodity price environment (1) Assumes NYMEX oil price of $50/bbl held constant (2) Assumes NYMEX natural gas price of $3.00/mcf held constant CITIBANK ENERGY INVESTOR TOUR DECEMBER 2015 15
CHESAPEAKE S STRATEGIC SCORECARD Financial Stability Operational Leadership Portfolio Strength and Flexibility Maximize liquidity Restructure midstream contracts Divest noncore assets Improve margins Base production optimization Field development optimization High-grade and optimize portfolio Appraise HBP acreage position Credit facility maturing in 2019; Covenants restructured in light of low commodity prices Finalized new gas gathering agreements in the Haynesville and dry gas Utica Noncore divestitures expected to total $200 $300mm by 1Q 16; evaluating substantial noncore assets still in the portfolio Significant improvements in LOE and G&A; ~$200mm removed from cost structure Optimized base production generated an additional 7 mmboe net vs. 2015 base production forecast Chesapeake drilled record laterals in major operating areas in 2015; significantly enhancing economics Optimization and reservoir characterization has created a diverse portfolio with multiple economic investment opportunities at current prices Substantial progress toward appraising HBP position; currently appraising Meramec, Oswego and Upper Marcellus Chesapeake is executing on its strategy to simplify and optimize the business for a prosperous future CITIBANK ENERGY INVESTOR TOUR DECEMBER 2015 16
APPENDIX CITIBANK ENERGY INVESTOR TOUR DECEMBER 2015 17
RECONCILIATION OF ADJUSTED EARNINGS PER SHARE ($ in mm) Three Months Ended: 9/30/2015 9/30/2014 Net income available to common stockholders ($4,695) $169 Adjustments, net of tax: Unrealized (gains) losses on commodity derivatives 58 (384) Unrealized gains on supply contract derivatives (58) -- Restructuring and other termination costs 44 (9) Provision for legal contingencies -- 62 Impairment of oil and natural gas properties 4,506 -- Impairments of fixed assets and other 66 9 Net (gains) losses on sales of fixed assets (1) (54) Repurchase of preferred shares of CHK Utica -- 447 Other (3) 11 Adjusted net income available to common stockholders (1) ($83) $251 Preferred stock dividends 43 43 Earnings allocated to participating securities -- 3 Total adjusted net income attributable to CHK ($40) $297 Weighted average fully diluted shares outstanding (2) 777 776 Adjusted earnings per share assuming dilution (1) ($0.05) $0.38 (1) Adjusted net income available to common stockholders and adjusted earnings per share assuming dilution are not measures of financial performance under accounting principles generally accepted in the United States (GAAP), and should not be considered as an alternative to net income available to common stockholders or diluted earnings per share. Adjusted net income available to common stockholders and adjusted earnings per share assuming dilution exclude certain items that management believes affect the comparability of operating results. The company believes these adjusted financial measures are a useful adjunct to earnings calculated in accordance with GAAP because: i. Management uses adjusted net income available to common stockholders to evaluate the company's operational trends and performance relative to other oil and natural gas producing companies. ii. Adjusted net income available to common stockholders is more comparable to earnings estimates provided by securities analysts. iii. Items excluded generally are one-time items or items whose timing or amount cannot be reasonably estimated. Accordingly, any guidance provided by the company generally excludes information regarding these types of items. (2) Weighted average fully diluted shares outstanding include shares that were considered antidilutive for calculating earnings per share in accordance with GAAP. CITIBANK ENERGY INVESTOR TOUR DECEMBER 2015 18
RECONCILIATION OF ADJUSTED EBITDA ($ in mm) Three Months Ended: 9/30/2015 9/30/2014 Cash provided by operating activities $318 $1,184 Changes in assets and liabilities 158 109 Operating cash flow (1) $476 $1,293 Net income ($4,639) $692 Interest expense 88 17 Income tax expense (benefit) (937) 437 Depreciation and amortization of other assets 31 37 Oil, natural gas and NGL depreciation, depletion and amortization 488 688 EBITDA (2) ($4,969) $1,871 Adjustments: Unrealized losses on oil, natural gas and NGL derivatives 67 (622) Unrealized gains on supply contract derivatives (70) -- Restructuring and other termination costs 53 (14) Provision for legal contingencies -- 100 Impairment of oil and natural gas properties 5,416 -- Impairments of fixed assets and other 79 15 Net (gains) losses on sales of fixed assets (1) (86) Net income attributable to noncontrolling interests (13) (30) Other (2) 2 Adjusted EBITDA (3) $560 $1,236 (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 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. 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 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 ebitda because: (1) Management uses adjusted ebitda to evaluate the company's operational trends and performance relative to other oil and natural gas producing companies. (2) Adjusted ebitda is more comparable to estimates provided by securities analysts. (3) 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. Accordingly, adjusted ebitda 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. CITIBANK ENERGY INVESTOR TOUR DECEMBER 2015 19
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 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 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 CITIBANK ENERGY INVESTOR TOUR DECEMBER 2015 20