NYSE: CHAP Investor Presentation May 2020

Forward Looking and Cautionary Statements 2 This presentation contains 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. Statements made in this presentation and by representatives of Chaparral Energy (the company) during the course of this presentation that are not historical facts are forward-looking statements. These statements are based on certain assumptions and expectations made by the company, which reflect management’s experience, estimates and perception of historical trends, current conditions and anticipated future developments. Although the company believes these assumptions and expectations are reasonable, they are subject to a number of assumptions, risks and uncertainties, many of which are difficult to predict and are beyond the control of the company and which may cause actual results to differ materially from those implied or anticipated in the forward-looking statements. Among those risks, trends and uncertainties are volatility and declines in oil and natural gas prices, including to the extent affected by COVID-19 pandemic and the recovery therefrom; takeaway constraints and storage capacity for oil and natural gas; the extent to which our strategy to stop drilling and completion and to shut-in non-essential oil production results in incremental future value; the extent to which we are able to continue to reduce lease operating expenses and G&A costs; our inability to retain key personnel; the impact of COVID-19 on the health of our key personnel; the nature or results, if any, of any strategic initiatives; current borrowings, capital resources and liquidity; covenant compliance under our credit agreement; activities on properties we do not operate; the impact of natural disasters on our present and future operations; the impact of legislative and regulatory initiatives, including in response to the COVID-19 pandemic; and the operating hazards attendant to the oil and natural gas business. Please read risk factors in the company’s annual reports on Form 10-K as amended, quarterly reports on Form 10-Q and other public filings. We undertake no obligation to publicly update any forward-looking statements, whether as a result of new information or future events. This presentation includes financial measures that are not in accordance with generally accepted accounting principles (GAAP). For reconciliation of such measures to the most directly comparable GAAP measures, please refer to the appendix.

3 Company Overview

Current Macro & Industry Outlook 4 The current macro environment has presented significant challenges to the global economy… • COVID-19/Saudi/Russia • Actions taken in early March by Saudi Arabia and Russia combined with the rapid global response to the COVID-19 pandemic has caused significant uncertainty across the oil sector • Commodity prices • Prices are depressed as a result of a severe supply-demand imbalance, resulting in an unprecedented negative settlement day of the May WTI crude futures contract • Widespread shut-ins • Responding to demand and pricing concerns, significant reductions to drilling activity and production shut-ins are occurring and will likely continue …Our decisive response • Suspension of drilling and completion (D&C) operations • Provided notice of suspension in early March and ceased all D&C operations by early April; deferred completions of recently drilled wells • Production shut-ins • Shut-in uneconomic wells beginning in March and implemented plan to further reduce crude sales beginning in May by shutting in additional, non-essential production as we preserve value for a more favorable price environment • Increasing cash on hand • Borrowed an additional $105 million under our credit facility in early April to provide additional financial flexibility Taking Actions to Minimize Capex, Maximize Cash Flow and Provide Financial Stability

Strategy Anchored to Strengths 5 Experienced Flexible Technical Low Cost Management Development Excellence Operator Team Strategy • Extensive experience • Differentiated results • Large held-by- • Low cost operator developing horizontal due to focus on production position and focused on the oil wells in the Mid-Con subsurface and technical no rig or minimum window of the Mid-Con volume commitments • Exceptional track record expertise • Constant attention to of meeting or exceeding • Rapidly incorporating • Manage commodity performance and cost guidance learnings into near-term price risk through improvements planning process hedging - oil hedges in place averaging over $51 per barrel for 2020

Mid-Con Operator in Oil Window of Anadarko Basin 6 Geologically Advantaged Nemaha Ridge • Core acreage in sweet spot of oil window • Moderately pressured • Distanced from Nemaha Ridge Large Oil Rich Production Base • 30.7 MBoe/d Q1 2020 total production • ~30% Oil (~62% Liquids) Large Acreage Position • Mid-Con: ~207,000 net acres • STACK: ~120,000 net acres • Core: ~100,000 net acres Significant Operational Control in Core Acreage • >80% Held by Production Kingfisher Canadian Garfield • >70% Operatorship . Net acres: ~33,000 . Net acres: ~23,000 . Net acres: ~44,000 • >160 Operated DSU’s . HBP: ~98% . HBP: ~98% . HBP: ~61% . Average Operated WI: 75% . Average Operated WI: 70% . Average Operated WI: 66%

7 Operational Overview

Core Area Subsurface 8 N Play Attributes • Multiple reservoirs proximal to the world-class Woodford source rock • Efficient hydrocarbon stratigraphic trap creates a continuous petroleum system S Garfield Kingfisher Canadian STACK CHESTER MERAMEC MANNING HIGH POROSITY UPPER OSAGE MERAMEC MIDDLE LOWER OSAGE SYCAMORE LOWER WOODFORD HUNTON Landing 1 Meramec 1 Meramec 2 Osage Zones 1 Lower Osage 1 Sycamore/ Lower Meramec N S

Detailed Subsurface Data Analysis 9 Enhanced 3D Seismic Imaging Reservoir Enhanced Subsurface Image Attributes • Combination of 3D seismic and well data using Facies Volume stochastic inversion and neural networks Canadian County, OK • Latest high resolution technology Percent Quartz • State of the art logs calibrated with core data • Provides high resolution image of the subsurface Feet ~250 and key reservoir attributes • Facies Percent Clay • Lithology • Porosity Hunton • Brittleness (“Fracability”) Meramec / Sycamore • Oil in place Woodford • Faults and Fractures Porosity • Continually refined with new data and results Maps Oil-In-Place Faults and Fractures • Detailed analysis performed and applied on a section by section basis Brittleness • Greatly reduces risk in horizontal well placement and spacing development 3 miles 3 miles Differentiating Subsurface and Geoscience Expertise Applied to Development Strategy

Application of Science & Technology 10 Chemical Tracers Finding landing zones, well spacing and frac designs to maximize returns Assess performance of landing zone, fault impacts & well-to-well communication Machine Learning to Microbial DNA Interpret Frac Hits DNA sequencing of microbes from fluid and cuttings to determine geologic source of fluid production. Evaluate vertical connection for Real time identification & quantification development planning Leveraging Technology That Produces Tangible, Actionable Results

Improving Efficiencies – D&C and Cost Structure 11 Avg. Drilling Feet per Day Avg. Completion Stages per Day 1,200 15 1,100 1,000 10 900 800 5 FEET DRILLED FEETDRILLED PERDAY FRAC STAGESPER DAY 700 600 0 1H18 2H18 1H19 2H19 1Q20 1H18 2H18 1H19 2H19 1Q20 LOE per BOE Cash G&A per BOE $15 $6 $5 $12 $4 $9 $3 $ $ BOE / $ $ BOE / $6 $2 $3 $1 $0 $0 2017 2018 2019 1Q20 2017 2018 2019 1Q20 Continuing to Increase Efficiencies and Reduce Cost Structure

Recent Spacing Performance in Focus Areas 12 Canadian Miss1 South Kingfisher Osage2 80,000 100,000 80,000 60,000 60,000 40,000 40,000 Cumulative BO Cumulative BO 20,000 20,000 - - - 100 200 300 400 500 0 100 200 300 400 500 Production Days Production Days Canadian Miss '19 and '20 Activity (9 Sections) South Kingfisher Osage '19 Activity (4 Sections) • 92% of oil expectation at 350 days • 108% of oil expectations at 340 days • 26 wells in 9 spacing projects, 7 with existing • 9 wells in 4 spacing projects with existing parent parent wells wells Recent Operated Spacing Well Results in Line with Expectations 1 Cumulative results represent all 4 spacing developments in Q1 2020 and 5 of the 7 spacing developments in 2019 that are comparable to focus areas. Scaled to lateral length of 4,800 feet 2 Cumulative results represent 2019 spacing developments that are comparable to focus areas. Scaled to lateral length of 4,800 feet

Focus Areas & Economics 13 • Given current pricing environment we have suspended drilling and completions operations • Focus areas are 98% held by production Canadian Miss South Kingfisher Osage Focus Areas 50% 50% 40% 40% Kingfisher Focus Area 30% 30% IRR IRR 20% 20% 10% 10% 0% 0% Low EUR Base EUR Low EUR Base EUR $3.2mm (D&C) $4.0mm (D&C) $2.8mm (D&C) $3.6mm (D&C) Canadian IRR1 13% - 39% 12% - 38% Focus Area EUR (MBoe) 862 - 967 547 - 614 EUR Mix 17% Oil (61% Liquids) 31% Oil (66% Liquids) D&C Costs ($mm) $3.2 – $4.0 $2.8 – $3.6 1 IRR range using $40 / $2.50 / 25% for oil, gas, and NGL pricing, respectively

14 Financial Overview

Financial Strategy 15 Capital Discipline • No long-term contracts, allowing for flexibility in operated development plan • Entered 2020 with 2 operated rigs; provided notice of release in early March and both rigs released by April 8 Balance Sheet • $13 million in cash and $145 million drawn on revolver at the end of Q1 2020 • Subsequent to Q1 2020, drew additional $105 million on revolver to maintain financial flexibility in challenging environment Risk Management • Manage commodity price risk through hedging program • 2020 oil and gas hedges in place averaging over $51 and $2.70, respectively Maximizing Value • Suspended all drilling activity and deferred completions • Began shutting-in unprofitable wells in March and April and have begun implementing plan to further reduce production in May • Continuous focus on reducing LOE and G&A costs

Financial Position Position 16 Simple Capital Structure Capitalization Table1 • No near-term maturities Pro Forma2 $ in millions Q1-2020 Q1-2020 • Revolving credit facility with borrowing base of $175mm as of April 3, 2020 Cash 13 118 • $250mm drawn on revolver as of April 3, 2020 Credit Facility 145 250 • Repaying borrowing base deficiency in six equal Senior Notes 300 300 installments with first payment having been Other Debt 2 2 made on May 1, 2020 Total Net Debt $434 $434 Stockholders Equity 423 423 • Spring redetermination reaffirmed borrowing base of $175mm on May 5, 2020 Total Capitalization $856 $856 • $300 million of senior notes Net Debt to TTM EBITDA ~2.6x ~2.6x Longer Dated Maturities December December RBL Effective Date RBL Maturity 2017 2018 2019 2020 2021 2022 2023 June July $300mm Senior Notes Issued $300mm Senior Notes Due 1 Numbers may not add due to rounding 2 Pro forma for $105mm drawn on credit facility in early April

Hedge Summary 17 Hedge Positions1 2Q20 3Q20 4Q20 Bal 2020 FY 2021 Crude Oil Swaps Hedge Volume (BBL) 744,000 494,500 531,500 1,770,000 689,300 Average Price ($/BBL) $51.99 $50.63 $50.49 $51.16 $46.24 Crude Oil Roll Hedge Volume (BBL) 110,000 90,000 90,000 290,000 150,000 Average Ceiling Price ($/BBL) $0.42 $0.30 $0.30 $0.35 $0.30 Natural Gas Swaps Hedge Volume (MMBTU) 2,340,000 1,500,000 1,500,000 5,340,000 Average Price ($/MMBTU) $2.67 $2.75 $2.75 $2.71 Natural Gas Basis Swaps (PEPL) Hedge Volume (MMBTU) 2,040,000 1,500,000 1,500,000 5,040,000 Average Price ($/MMBTU) ($0.46) ($0.46) ($0.46) ($0.46) NGL Swaps Propane Hedge Volume (BBL) 140,100 140,100 Propane Average Price ($/BBL) $21.56 $21.56 Iso Butane Hedge Volume (BBL) 11,830 11,830 Iso Butane Average Price ($/BBL) $22.26 $22.26 Natural Gasoline Hedge Volume (BBL) 58,950 58,950 Natural Gasoline Average Price ($/BBL) $49.05 $49.05 1 As of March 31, 2020

Building the Foundation for Future Success 18 Low Cost Rapidly Operator That Operational Responding Focused on Has Delivered and Financial to Current Controlling on Guidance Flexibility Environment Costs

19 Appendix

2019 Proved Reserves 20 67% Proved Developed 28% Oil (62% Liquids) (MMBoe) 28% 31.8 34% 1.3 63.4 38% PDP PNP PUD OIL GAS NGL YE ‘19 Total Proved Reserves1 Net Oil Net Gas Net NGL Net % of Total PV – 10 Reserve Category (MMBo) (BCF) (MMBo) (MMBoe) Proved ($mm) PDP 18.0 149.5 20.5 63.4 66% $444 PNP 0.5 2.7 0.4 1.3 1% $11 PUD 8.8 68.6 11.6 31.8 33% $69 Total Proved 27.2 220.8 32.5 96.6 100% $523 Total Including ARO $514 Note: numbers may not add due to rounding 1 At year-end 2019 SEC prices of $55.69/bbl and $2.58/mcf

Non-Core Asset Overview 21 Western Miss Lime Anadarko Basin Mature legacy fields Minimal maintenance capital Southern OK Low decline production base Net Production1 Net Proved Reserves Area Boe/d % Oil MMBoe2 PV-102 ($mm) Miss Lime 1,434 25% 5.3 $27 Western Anadarko Basin 795 14% 3.0 $13 Southern OK 1,744 60% 8.1 $66 Other 300 15% 0.7 $3 Total 4,273 37% 17.2 $109 Total Including ARO $103 Note: numbers may not add due to rounding 1 Q1 2020 actuals 2 At year-end 2019 SEC prices of $55.69/bbl and $2.58/mcf

Reserve and Non-GAAP Information Statement 22 Reserve Estimates The SEC permits oil and natural gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves that meet the SEC’s definitions for such terms. The company may use terms in this presentation that the SEC’s guidelines strictly prohibit in SEC filings, such as estimated ultimate recovery or EUR, resources, net resources, total resource potential and similar terms to estimate oil and natural gas that may ultimately be recovered. These estimates are by their nature more speculative than estimates of proved, probable and possible reserves as used in SEC filings and, accordingly, are subject to substantially greater uncertainty of being actually realized. These estimates have not been fully risked by management. Actual quantities that may be ultimately recovered will likely differ substantially from these estimates. Factors affecting ultimate recovery include the scope of the company’s actual drilling program, which will be directly affected by the availability of capital, drilling and production costs, commodity prices, availability of drilling services and equipment, lease expirations, transportation constraints, regulatory approvals, field spacing rules, actual drilling results and recoveries of oil and natural gas in place and other factors. These estimates may change significantly as the development of properties provides additional data. The company’s production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates and results of future drilling activity which is subject to commodity price fluctuations and changes in drilling costs. PV-10 PV-10 value is a non-GAAP measure that differs from the standardized measure of discounted future net cash flows in that PV-10 value is a pre-tax number, while the standardized measure of discounted future net cash flows is an after-tax number. We believe that the presentation of the PV-10 value is relevant and useful to investors because it presents the discounted future net cash flows attributable to our proved reserves prior to taking into account future corporate income taxes, and it is a useful measure of evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We use this measure when assessing the potential return on investment related to our oil and natural gas properties. However, PV- 10 value is not a substitute for the standardized measure of discounted future net cash flows. Our PV-10 value measure and the standardized measure of discounted future net cash flows do not purport to present the fair value of our oil and natural gas reserves.

Reconciliations 23 Three Months Three Months Ended Ended ($ in thousands) March 31, 2020 March 31, 2019 Net (loss) income 4,917 (103,540) Interest expense 6,636 4,564 Depreciation, depletion, and amortization 23,012 23,715 Non-cash change in fair value of derivative instruments (69,206) 51,531 Impact of derivative repricing 702 — Stock-based compensation expense 406 802 Loss (gain) on sale of assets (102) 1 Loss on impairment of oil and gas assets 71,371 49,722 Loss on impairment of other assets 153 — Credit loss on uncollectible receivables 1,517 (258) Restructuring, reorganization and other 1,317 1,520 Adjusted EBITDA $40,723 $28,057 ($ in thousands) 2019 Standardized measure of discounted future net cash flows 514,203 Present value of future income tax discounted at 10% — PV-10 value $514,203

Reconciliations 24 Three Months Twelve Months Twelve Months Twelve Months Ended Ended Ended Ended ($ in thousands) March 31, 2020 December 31, 2019 December 31, 2018 December 31, 2017 General and administrative 8,068 34,210 38,793 46,460 Less: Stock compensation, gross 660 2,208 13,402 12,595 Capitalized stock compensation (274) (722) (2,543) (2,812) Severance costs 733 7,534 362 — Credit loss (gain) on receivables 1,517 (194) 553 149 Plus: Cash-settled RSUs, net (7) — 19 — Cash G&A $5,425 $25,384 $27,038 $36,528 Production (MBoe) 2,793 9,593 7,490 8,399 Cash G&A per Boe $1.94 $2.65 $3.61 $4.35

25 Contact Information Chaparral Energy, Inc. 701 Cedar Lake Boulevard Oklahoma City, OK 73114 Investors Patrick Graham Senior Director of Corporate Finance Investor.Relations@chaparralenergy.com 405.426.6700

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