Investor Presentation November 2018 NYSE: CHAP NYSE:CHAP0

Forward-Looking Statements and Risk Factors 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, which 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. These include risks relating to financial performance and results, ability to improve our financial results and profitability following emergence from bankruptcy, availability of sufficient cash flow to execute our business plan, continued low or further declining commodity prices and demand for oil, natural gas and natural gas liquids, ability to hedge future production, ability to replace reserves and efficiently develop current reserves and the regulatory environment and other important factors that could cause actual results to differ materially from those anticipated or implied in the forward-looking statements. Initial production (IP) rates are discreet data points in each well’s productive history. These rates are sometimes actual rates and sometimes extrapolated or normalized rates. As such, the rates for a particular well may decline over time and change as additional data becomes available. Peak production rates are not necessarily indicative or predictive of future production rates or economic rates-of-return from such wells and should not be relied upon for such purpose. The ability of the company or the relevant operator to maintain expected levels of production from a well is subject to numerous risks and uncertainties, including those referenced and discussed above. In addition, methodology the company and other industry participants utilize to calculate peak IP rates may not be consistent and, as a result, the values reported may not be directly and meaningfully comparable. These and other important factors could cause actual results to differ materially from those anticipated or implied in the forward-looking statements. 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 principals (GAAP). For reconciliation of such measures to the most directly comparable GAAP measures in the appendix. NYSE: CHAP 1

Company Overview NYSE: CHAP 2

Chaparral Growth Story Evolution • 7,000-acre Kingfisher County Acquisition • Emerged from Q2/Q3 2018 Chapter 11 • New CEO & Independent BOD Late 2017 Q1 2018 • Dual Strategy - EOR Focused • Constrained Balance Sheet • Increased 2018 Production & Limited 2Q 2016 1Q 2017 Guidance Growth • $100mm Drilling JV • Lowered G&A and LOE • Divested EOR Assets Guidance • De-risked 50% of Garfield County • De-risked 80% of Canadian County Merge Miss Pre-2016 •Entered • Announced Addition of Chapter 11 Fourth Rig • Issued $300mm Sr. Unsecured Notes • Uplisted to NYSE (July) Focused Strategy Built on Prolific STACK Assets NYSE: CHAP 3

Chaparral Story • High-growth, pure-play STACK oil company • 15.7 MBoe/d Q3 2018 STACK production • 45 - 55% projected 2018 STACK production growth • Premier, contiguous acreage position • 127,000 acres in world-class STACK resource play STACK • Primarily in black oil, normal pressure window in Kingfisher, Garfield and Canadian counties • Large resource base with deep inventory • Year-end 2017 proved reserves of ~76 MMBoe and PV-10 of ~$705 million1 • Decades of high-return inventory Merge • Highly efficient, low-cost STACK assets STACK Held By Operated Non-Operated County • $26.32/Boe YTD 2018 STACK cash margins Acreage Production WI WI Average Average • $4.95/Boe YTD 2018 STACK LOE cost Kingfisher ~34,000 ~96% 71% 16% Canadian ~22,000 ~99% 71% 14% • Strong balance sheet Garfield ~52,000 ~38% 64% 19% Major ~6,000 ~98% 56% 16% • No long-term maturities until December 2022 Other ~13,000 ~100% 52% 13% 1 At September 28, 2018 NYMEX prices; five-year average prices $67.40 and $2.70 NYSE: CHAP 4

2018 Strategy • Transitioned to pure-play STACK operator with 2017 asset sale PURE-PLAY STACK COMPANY • Delineation and de-risking of Canadian (Merge) and Garfield acreage • Continue to rationalize non-core legacy assets RETURNS • Focus exclusively on creating value for our stakeholders FOCUSED • Achieve 50% to 100%+ IRRs from STACK/Merge drilling opportunities • Employ leading drilling and completion techniques TECHNICAL EXCELLENCE • Improve operations, costs and returns with continuous learning • Deliver safe, repeatable results and drive down costs STRONG, FLEXIBLE • Protect strong balance sheet to execute strategy CAPITAL • Provide sufficient liquidity through cash flow, hedging, borrowing STRUCTURE capacity, non-core asset sales and access to capital markets NYSE: CHAP 5

Recent Chaparral Highlights • Recorded STACK production growth of: • 19% Q2 2018 to Q3 2018 • 53% Q3 2017 to Q3 2018 • Grew STACK reserves by 58% from year-end 2016 to year-end 2017 • Replaced 604% of 2017 STACK production at $7.26/Boe F&D cost • Completed successful partial section spacing test in Canadian County Merge Miss acreage • Achieved 2018 average 30-day peak IP rate of 784 Boe/d for Meramec and Osage wells • De-risked ~50% of Garfield County and ~80% of Canadian County Merge Miss acreage Operated Meramec and Osage Well Performance Above Type Curve Average Type Curve Time Period Gross Wells Lateral Length IP-301 Liquids WI IP-302 YTD Q3 2018 31 60% 4,672 feet 784 72% 709 1 IP 30s represent the gross three-phase, peak 30-day production rate in Boe/d and are scaled to type curve lateral length of 4,800 feet 2 Represents the average gross three-phase, peak 30-day production rate in Boe/d of the STACK Meramec, Upper Osage, Lower Osage and Merge Miss type curves NYSE: CHAP 6

Operational Overview NYSE: CHAP 7

STACK/Merge Attributes • World-class Woodford source rock Favorable Geology • +700 feet of saturated hydrocarbon column • Multiple reservoir development opportunities • Robust service sector support Extensive Infrastructure • Numerous midstream alternatives • Abundant pipeline capacity Excellent Crude Net • Chaparral STACK: WTI less ~$1.00/Bbl1 1 Back • Bakken: WTI less ~$4.00/Bbl • Permian Basin: WTI less ~$4.00/Bbl2 • STACK Merge Miss: 100%+ rate-of-return3 Top-quartile Economics • STACK Lower Osage: 98% rate-of-return3 • STACK Meramec: 85% rate-of-return3 3 1 Based on company filings • STACK Upper Osage: 56% rate-of-return 2 Based on November 8, 2018 CME Group settlement pricing for December 2018 delivery • 3 At September 28, 2018 NYMEX prices; five-year average prices $67.40 and $2.70 NYSE: CHAP 8

One Petroleum System STACK Attributes N • Stacked reservoirs proximal to the world-class Woodford source rock STACK • Efficient hydrocarbon stratigraphic trap creates a continuous petroleum system • Play attributes are identical – only rock thickness and GOR vary • MERGE represents intersection of historical SCOOP/STACK play Merge outlines S Garfield Kingfisher Canadian STACK Merge NYSE: CHAP N S 9

STACK Geology Osage Heat Map1 Meramec Heat Map2 Chaparral Chaparral Scale Scale Core Tier 1 Tier 2 Core Tier 1 Tier 2 1 Heat map integrates major factors affecting well performance in the Osage: 1.Osage hydrocarbon pore volume 2.Net resistivity (brittleness) 3.Woodford hydrocarbon pore volume 2 Heat map integrates major factors affecting well performance in the Meramec: 1.Meramec hydrocarbon pore volume 2.Net resistivity (brittleness) 3.Woodford hydrocarbon pore volume Geological Benefits • Chaparral’s position is in overlapping areas of optimal Osage, Meramec, Oswego and Woodford formation rock • Shelf carbonates in shallower, normal pressure window provide lower D&C costs and higher liquids content • STACK is currently defined by >1,000 Hz Mississippian wells and >1,250 Hz Woodford wells NYSE: CHAP 10

STACK Break-Even Economics Oil Economics – WTI Basin Breakeven Estimates1 $45 $40 $35 $30 $25 Delaware STACK Midland SCOOP Eagle Ford Bakken Niobrara Oil Economics – Chaparral Counties of Focus1 $45 $35 $25 $15 Canadian Kingfisher Source: BMO Capital Markets equity research report 1 Data based on 2016-17 vintage public well production data NYSE: CHAP 11

Highly Profitable Breakeven Acreage Recent Operated Performance 11 2 10 3 No. Well Name Spud Date IP-30 Boe/d Liquids 9 8 1 1 BARBEE 2105 1LMH-4 12/17/2017 1,122 69% 5 2 GLOCK 2205 1LMH-15 2/9/2018 913 61% 4 3 DOGWOOD 2205 1LMH-28 3/15/2018 1,193 54% 7 6 4 FUKSA 2007 1LMH-14 11/2/2017 710 83% 5 PEAR 2106 1LMH-23 5/6/2018 1,351 87% 6 PLATTER 2007 1LMH-36 3/29/2018 729 83% 16 12 7 COLONIAL 2007 1LMH-26 7/9/2018 621 92% 13 8 GERKEN 2205 1UMH-33 12/21/2017 1,063 55% 14 15 9 WHITE OAK 2206 1UMH-36 5/7/2017 892 53% 10 COTTONWOOD 2205 1UMH-34 3/1/2018 757 59% 11 BROWNING 2205 1UMH-22 1/26/2018 667 55% 12 LOW VALLEY 1807 1LMH-36 4/18/2017 1,335 82% 13 BRANDT 1707 1LMH-12 7/8/2017 885 86% 14 STAY PUFT 1707 1LMH-23 9/26/2017 863 86% 22 15 SLIMER 1707 1UMH-23 9/5/2017 719 85% 25 16 HIGH VALLEY 1807 1UMH-36 8/19/2017 652 77% 20 19 24 17 SHASTA 1106 1UMH-28 10/14/2017 1,368 70% 21 18 23 18 LASSEN 1107 1UMH-15 12/2/2017 1,218 73% 17 19 BANFF 1207 1UMH-29 3/23/2018 1,209 59% 20 KATMAI 1206 1UMH-29 2/7/2018 1,168 76% 21 KILIMANJARO 1106 1UMH-2 7/28/2017 1,044 78% 22 BEECHAM-HUNT 1307 1UMH-13 9/8/2017 927 72% 23 OLYMPUS 1107 1UMH-10 11/3/2017 823 72% 24 DENALI 1206 (3 Well Pad) 5/29/2018 1,214 75% 25 RAINIER 1206 1UMH-7 7/2/2018 889 60% MERAMEC • Garfield County Osage and Meramec wells demonstrating OSAGE solid results; 52,000-acre position 50% de-risked Chaparral Leasehold • Continued strong Kingfisher County Meramec and Osage well performance from de-risked acreage • Canadian County Merge Miss delivering Breakeven heat map from May 2018 SCOOP/STACK insights by RS Energy Group excellent results; 22,000-acre position 80% de-risked NYSE: CHAP 12

Core STACK & Merge Type Curve Overview STACK Osage, Meramec & Merge Miss Merge North South Lower Upper Meramec Miss Woodford Woodford Osage Osage Lateral Length (ft.) 4,800 4,800 4,800 4,800 4,800 4,800 Well Cost ($mm) $4.0 $4.5 $4.4 $4.4 $3.9 $4.1 Well Cost ($/ft.) $833 $938 $917 $917 $813 $854 Total EUR (MBoe) 584 1,023 579 1,456 629 853 % Liquids 70% 66% 72% 62% 70% 54% IP-30 612 881 475 736 599 744 Single Well Economics STACK Woodford 120% 100% 80% 60% IRR IRR % 40% 20% 0% Meramec Merge North South Lower Upper Miss Woodford Woodford Osage Osage $55.00/$2.75 $60.00/$3.00 $65.00/$3.25 9/28 NYMEX NYSE: CHAP 13

STACK & Merge Overview STACK/Merge Production 18,000 16,000 14,000 12,000 10,000 8,000 16,750 Boe/d 15,663 6,000 12,300 13,198 10,260 10,379 9,188 4,000 7,475 8,169 2,000 - 1 Q4 2016 Q1 2017 Q2 2017 Q3 2017 Q4 2017 Q1 2018 Q2 2018 Q3 2018 Q4 2018E Chaparral STACK & Merge Position • 127,000 acres • 117 operated horizontal wells as of Q3 2018 • Excellent Merge acreage 100% held-by-production 1 Based on mid-point of guidance range NYSE: CHAP 14

Meramec Well Performance • Excellent recent operated well performance for Merge Miss and STACK Meramec type curve areas • Actual oil results are in-line or exceeding current type curve expectations • Type curve rates-of-return: ~85% to 100%+1 Merge MISS Actual Cumulative Oil STACK Meramec Actual Cumulative Oil vs. CHAP Type Curve 2 vs. CHAP Type Curve 2 90000 100000 80000 90000 70000 80000 70000 60000 60000 50000 50000 40000 40000 Cumulative BO Cumulative Cumulative BO Cumulative 30000 30000 Merge MISS STACK Meramec 20000 20000 Merge MISS Type Curve STACK Meramec Type Curve 10000 10000 0 0 Days on Production Days on Production 1 At September 28, 2018 NYMEX prices; five-year average prices $67.40 and $2.70 2 Cumulative results are scaled to type curve lateral length of 4,800 feet and include operated wells since June 30, 2017 NYSE: CHAP 15

Osage Well Performance • Strong recent operated well performance for Upper and Lower Osage type curve areas • Actual oil results are in-line or exceeding current type curve expectations • Type curve rates-of-return: ~55% - 100%1 Upper Osage Actual Cumulative Oil Lower Osage Actual Cumulative Oil vs. CHAP Type Curve 2 vs. CHAP Type Curve 2 60000 100000 90000 50000 80000 40000 70000 60000 30000 50000 40000 Cumulative BO Cumulative 20000 Cumulative BO Cumulative Upper Osage 30000 Lower Osage 10000 20000 Upper Osage Type Curve Lower Osage Type Curve 10000 0 0 Days on Production Days on Production 1 At September 28, 2018 NYMEX prices; five-year average prices $67.40 and $2.70 2 Cumulative prices from September 28, results are scaled to type curve lateral length of 4,800 feet and include operated wells since June 30, 2017 NYSE: CHAP 16

Recent Canadian County Merge Spacing Test • Denali pad is a Canadian county Merge Miss 3 well partial section spacing test • Average initial production for the 3 wells is ~50% oil (~75% liquids) and through 70 days is ~40% above type curve • Spacing test was drilled in two targets of the Merge Miss and implies approximately 4 wells per drillable target or 8-9 wells per section spacing for Merge Miss Upper Meramec Lower Meramec Woodford 100,000 90,000 80,000 70,000 60,000 50,000 40,000 Cumulative BOE Cumulative 30,000 20,000 AVG DENALI 10,000 MERGE MISS Type Curve 0 0 30 60 90 Days on Production NYSE: CHAP 17

Spacing Tests in Progress Upper Meramec Lower Meramec King Koopa Osage Section • 3 Meramec and 2 Osage wells (Q4-2018 anticipated first production) Upper Meramec Lower Meramec Foraker Section Woodford • Given success of initial spacing test (Denali), testing full undeveloped section in Merge Miss and partial section Woodford spacing test • 9 Meramec and 2 Woodford wells (1H-2019 anticipated first production) NYSE: CHAP 18

Operational Excellence – Drilling and Completions Strong, Effective Focus on Cost Control • Chaparral Osage and Meramec D&C represents best-in-class in normal pressure STACK • Low well cost and consistent production results produce excellent returns D&C Cost Comparison ($/lateral foot) $1,200 $1,000 D&C ($/lateral foot) avg. $800 $600 $400 $200 $- CHAP Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Source: Company presentations and analyst research Note 1: CHAP includes average for Osage and Meramec and assumes multi-well pad development Note 2: Peers include AMR, GST, CLR, DVN, MRO, XEC and NFX NYSE: CHAP 19

2018 Capital Budget Expectations Capital Program Objectives • Delineate Garfield and Canadian (Merge) County position • Drill at least five wells on Kingfisher County acquisition acreage • Increase 3-D seismic and lease acquisitions • Begin spacing tests in Kingfisher and Canadian counties by adding fourth rig in Q4 2018 • Monetize non-core assets Capital Spend Guidance Range Total Capital ($mm) $300 - $325 Operated STACK D&C $140 - $150 OBO STACK D&C $35 - $45 Lease Acquisition1/3-D Seismic $95 - $100 Other2 $30 1 Kingfisher County acquisition accounts for $55 million of total budget 2 Includes workovers, capitalized interest, capitalized G&A and PP&E NYSE: CHAP 20

2018 Updated Guidance Updated Guidance Highlights 2018 Guidance Range Production (MBoe/d) • Increased full year STACK production guidance 7% Total Company 20.25 - 20.75 Q4 Total Company 21.25 - 22.25 • Q4 STACK guidance: STACK 14.25 - 14.75 16.25 -17.25 MBoe/d Q4 STACK 16.25 - 17.25 Capital ($mm) $300 - $325 • Increased full year total company Operated STACK D&C $140 - $150 production guidance 5% OBO STACK D&C $35 - $45 Lease Acquisition1/3-D Seismic $95 - $100 • Q4 total company guidance: Other2 $30 21.25 – 22.25 MBoe/d Expenses ($/Boe) LOE $7.25 - $7.65 • Decreased LOE expense/Boe Cash G&A Expense $3.50 - $4.00 1 Kingfisher County acquisition accounts for $55 million of budget, as well as poolings and guidance by 6% other lease acquisitions/renewals 2 Includes workovers, capitalized interest, capitalized G&A and PP&E NYSE: CHAP 21

Financial Overview NYSE: CHAP 22

Financial Strategy • Maintain balance sheet strength • Target net debt to adjusted EBITDA ratio of approximately 2.5x or less • Supplement cash flow with proceeds from non-core asset sales • Development plan funding available due to ample liquidity • $49 million in cash as of Q3 2018 plus undrawn revolver • Significant capital spend flexibility with no long-term commitments • Allocate capital based on strategic and rate-of-return priorities • Allocate capital to high-return STACK assets • Held-by-production acreage and delineation of Canadian and Garfield counties • Manage commodity price risk through hedging program • Program includes crude oil and natural gas, as well as gas basis, NGLs and crude oil roll contracts • NYSE listing under symbol CHAP (July 24, 2018) • Access to larger investor base and increased trading liquidity NYSE: CHAP 23

Financial Position and Liquidity Highlights Chaparral Liquidity • Closed on a $300 million senior ($ in Millions) Q3 2018 unsecured notes offering on June 29, Actual Actual 2018 Cash and Cash Equivalents $49 • Paid down all outstanding borrowings Revolving Credit Facility due Dec. 2022 $0 on credit facility Other $21 • Continue to rationalize non-STACK assets to add liquidity Senior Notes $300 • Develop long runway to unlock value Total Debt $321 of deep STACK drilling inventory Net Debt $272 • Fall 2018 redetermination process Undrawn Revolver Amount $265 currently in process Chaparral Debt Maturity Schedule $500 $400 $300 No maturities until 2022 $200 $265 $300 $100 $- 2018 2019 2020 2021 2022 2023 2024 2025 2025+ Senior Notes Revolver NYSE: CHAP 24

Crude Oil Marketing Crude Oil • Acreage in close proximity to Cushing and in-state refineries • Premium price due to gravity and quality of barrel • Substantial capacity to market via truck or existing pipeline • Evaluating pipeline gathering alternatives direct to Cushing for several development sections NYSE: CHAP 25

Natural Gas & NGL Marketing Natural Gas and NGL • Midstream super system, with multiple plants and residue outlets • Two Bcf of incremental capacity to North Texas, eastern and southeastern U.S. and Gulf Coast markets (mid-year 2018 and Q3 2019) • Residue and NGL agreements with midstream operators who have firm transportation • Approximate 50/50 NGL markets and pricing split between Conway and Mt. Belvieu NYSE: CHAP 26

Why Chaparral? Strong Balance Sheet Experienced Execution-focused, Management with Pure-play STACK Excellent Track Operations Record Deep Inventory of High-return Drilling Prospects NYSE: CHAP 27

Appendix NYSE: CHAP 28

Hedging Summary Hedge Positions1 Q4 2018 2019 2020 2021 Crude Oil Swaps Hedge Volume (BBL) 515,200 1,562,200 1,547,000 543,300 Average Price ($/BBL) $58.21 $55.90 $49.54 $44.34 Crude Oil Collars Hedge Volume (BBL) 46,000 Average Ceiling Price ($/BBL) $60.50 Average Floor Price ($/BBL) $50.00 Crude Oil Roll Hedge Volume (BBL) 150,000 530,000 410,000 150,000 Average Ceiling Price ($/BBL) $0.59 $0.52 $0.38 $0.30 Natural Gas Swaps Hedge Volume (MMBTU) 2,519,000 7,631,500 3,600,000 Average Price ($/MMBTU) $2.88 $2.81 $2.77 Natural Gas Basis Swaps (PEPL) Hedge Volume (MMBTU) 1,500,000 2,500,000 Average Price ($/MMBTU) ($0.70) ($0.70) NGL Swaps Propane Hedge Volume (BBL) 84,000 273,000 102,000 Propane Average Price ($/BBL) $36.96 $31.08 $31.08 Natural Gasoline Hedge Volume (BBL) 36,000 118,000 45,000 Natural Gasoline Average Price ($/BBL) $65.10 $58.40 $58.40 1 As of September 30, 2018 NYSE: CHAP 29

Year-End 2017 Proved Reserves Grew STACK year-end 2017 reserves by 58% Replaced 604% of 2017 STACK production at $7.26/Boe F&D cost 76.3 MMBoe of Reserves1 39% Oil, 63% Liquids Reserves by Area 24% 25.6 39% 26.9 49.4 1.1 49.7 37% PDP PDNP PUD OIL GAS NGL STACK OTHER YE ‘17 Total Proved Reserves YE ‘17 Proved Reserves PV-10 Reserve Net Oil Net Gas Net NGL Net % of Total SEC Strip $60 and $3 Category (MMBo) (BCF) (MMBo) (MMBoe) Proved Pricing1 Pricing2 PDP 18.1 119.4 11.7 49.7 65% 427.1 566.0 519.7 PNP 0.2 4.1 0.2 1.1 1% 6.0 7.4 7.1 PUD 11.3 46.7 6.5 25.6 34% 77.4 131.1 127.0 Total Proved 29.6 170.2 18.3 76.3 100% 510.5 704.5 653.8 STACK 18.7 107.4 12.8 49.4 65% 312.5 434.5 405.7 OTHER 10.9 62.8 5.6 26.9 35% 198.0 270.1 248.2 Total Proved 29.6 170.2 18.3 76.3 100% 510.5 704.5 653.8 Total Proved Inc. 29.6 170.2 18.3 76.3 100% 497.9 691.9 641.2 ARO 1 At year-end 2017 SEC prices of $51.34 and $2.98 2 At September 28, 2018 NYMEX prices; five-year average prices $67.40 and $2.70 Note: Numbers may not add due to rounding NYSE: CHAP 30

Non-Core Legacy Asset Overview • Mature legacy fields • Low-maintenance capital • Provides free cash flow to fuel STACK growth • Potential strategic alternatives Net Production1 Gross Margin1 Net Proved Reserves Area Boe/d % Oil $/Boe MMBoe2 PV-102 ($mm) PV-103 ($mm) Miss Lime 2,018 29% $19.98 6.8 $45.4 $60.9 Western Anadarko Basin 955 14% $12.04 7.9 $46.9 $56.8 Southern OK 1,679 60% $27.74 7.3 $67.8 $96.7 Other 1,032 41% $20.53 4.9 $38.0 $55.7 TOTAL 5,685 38% $21.03 26.9 $198.0 $270.1 TOTAL Incl. ARO 5,685 38% $21.03 26.9 $187.4 $259.5 1 Q3 2018 actuals 2 At year-end 2017 SEC prices of $51.34 and $2.98 3 Based on year-end 2017 reserves run on September 28, 2018 NYMEX prices; Five-year average prices $67.40 and $2.70 NYSE: CHAP 31

Recent Transactions Support CHAP Acreage Valuation • Significant A&D activity demonstrates value of Chaparral’s acreage position • Staghorn, PayRock, Alta Mesa and Longfellow transactions were primarily in the black oil, normal pressure window of the play 5 1 2 3 4 5 STACK 2 Sales Package/Seller Alta Mesa Staghorn PayRock Felix Longfellow 1 Silver Run Purchaser Chisholm Marathon Devon SK II 4 Date 8/16/2017 1/16/2017 6/20/2016 12/7/2015 3/20/2018 3 Purchase Price ($mm) $2,200 $613 $888 $1,900 $280 Net Acres 120,000 41,386 61,000 80,000 30,000 Production (MBoe/d) 20 2.8 8.6 9 1 $/Acre Not Adjusted for $18,333 $14,812 $14,557 $23,750 $9,333 Production $/Acre Merge Adjusted for $17,1581 $13,120 $11,033 $20,938 $8,500 Production, $25,000/Boe/d 1 Does not include approximately 20,000 net acres in Major County NYSE: CHAP 32

STACK Type Curve Assumptions STACK Meramec Lower Osage Upper Osage North Woodford South Woodford Merge Miss Well Cost Assumptions Well Costs ($mm) $4.0 $3.9 $4.1 $4.4 $4.4 $4.5 Well Costs ($/ft) $833 $813 $854 $917 $917 $938 Type Curve Assumptions Lateral Length (ft) 4,800 4,800 4,800 4,800 4,800 4,800 Oil EUR (MBbls) 236 254 152 212 167 211 Oil IP-30 (Bo/d) 381 397 231 281 211 320 Oil B factor 1.2 1.2 1.4 1.1 1.2 1.2 Initial decline 82% 81% 84% 74% 75% 80% NGL EUR (MBbls) 175 189 306 207 729 460 NGL IP-30 (Bo/d) 116 102 224 110 297 317 NGL Yield (Bbls/MMcf) 112 112 97 152 152 152 Wellhead Gas EUR (MMcf) 1,564 1,684 3,157 1,365 4,795 3,024 Gas IP-30 (Mcf/d) 1,039 908 2.314 724 1,955 2,088 Gas B factor 1.3 1.4 1.4 1.2 1.2 1.2 Initial decline 56% 50% 62% 45% 35% 55% Gas Shrink 66% 66% 75% 70% 70% 70% Three-stream EUR (MBoe) 584 629 853 579 1,456 1,023 Three-stream IP-30 (Boe/d) 612 599 744 475 736 881 NYSE: CHAP 33

STACK Meramec and Merge Miss Overview Spud Peak IP-301 Liquids1 Lateral Lease Operator Date Boe/d % Length 1 SLIMER 1707 #1UMH-23 CHAPARRAL 9/5/2017 713 85% 4,839 2 HIGH VALLEY 1807 #1UMH-36 CHAPARRAL 8/19/2017 682 77% 4,588 3 BIG TIMBER 1408 #1UMH-2 CHAPARRAL 6/4/2017 799 82% 4,623 4 CATERPILLAR 1506 1-11MH ALTA MESA 2/1/2018 717 85% 4,958 5 WINFIELD 1807 31-1MH GASTAR 8/15/2017 657 82% 4,608 6 RHINO 8_5-14N-9W 1HX DEVON 7/22/2017 918 67% 10,054 7 JORDAN 10_15-14N-9W 1HX DEVON 4/17/2017 876 67% 10,050 8 H&W 1H-28X NEWFIELD 1/15/2017 878 80% 9,713 9 RAINIER 1206 1UMH-7 CHAPARRAL 7/2/2018 929 60% 4,595 10 DENALI 1206 (3 Well Pad) CHAPARRAL 5/29/2018 1,290 75% 4,548 11 BANFF 1207 #1UMH-29 CHAPARRAL 3/23/2018 1,178 59% 4,926 12 HOOD 1006 #1UMH-5 CHAPARRAL 3/2/2018 838 73% 4,840 13 KATMAI 1206 #1UMH-29 CHAPARRAL 2/7/2018 1,262 76% 4,439 14 LASSEN 1107 #1UMH-15 CHAPARRAL 12/2/2017 1,302 73% 4,490 15 OLYMPUS 1107 #1UMH-10 CHAPARRAL 11/3/2017 934 72% 4,228 16 SHASTA 1106 #1UMH-28 CHAPARRAL 10/14/2017 1,349 70% 4,869 17 BEECHAM-HUNT 1307 #1UMH-13 CHAPARRAL 9/8/2017 977 72% 4,394 18 KILIMANJARO 1106 1UMH-2 CHAPARRAL 7/30/2017 1,105 78% 4,392 19 GAMBLE 3-11-6 3H JONES 11/10/2017 1,097 78% 4,467 20 JO 26-35-10-6 1XH ROAN 9/23/2017 1,157 65% 10,055 21 GAMBLE 3-11-6 2H JONES 9/17/2017 1,123 78% 4,362 22 CANNONBALL 1208 24-2MH 89 ENERGY 7/22/2017 1,086 68% 4,826 23 ROSEWOOD 16-12-7 2H JONES 6/9/2017 1,457 67% 4,625 24 ROSEWOOD 16-12-7 1H JONES 6/9/2017 1,232 69% 4,617 Type Curve Meramec Merge Miss IP-301 (Boe/d) 612 881 ROR at NYMEX Strip2 85% 100%+ Total EUR1 (MBoe) 584 1,023 % Liquids1 70% 66% Lateral Length (feet) 4,800 4,800 Well Cost ($mm) $4.0 $4.5 1 Gross three-phase scaled to type curve lateral length of 4,800 feet 2 At September 28, 2018 NYMEX prices; five-year average prices $67.40 and $2.70 NYSE: CHAP 34

STACK Osage Type Curves Overview Spud Peak IP-301 Liquids1 Lateral Lease Operator Date Boe/d % Length 1 PEAR 2106 #1LMH-23 CHAPARRAL 5/6/2018 1,326 87% 4,892 2 DOGWOOD 2205 1LMH-28 CHAPARRAL 3/15/2018 1,182 54% 4,844 3 COTTONWOOD 2205 #1UMH-34 CHAPARRAL 3/1/2018 766 59% 4,741 4 GLOCK 2205 #1LMH-15 CHAPARRAL 2/9/2018 902 61% 4,855 5 BROWNING 2205 #1UMH-22 CHAPARRAL 1/26/2018 675 55% 4,743 6 GERKEN 2205 #1UMH-33 CHAPARRAL 12/21/2017 1,110 55% 4,594 7 BARBEE 2105 #1LMH-4 CHAPARRAL 12/17/2017 1,224 69% 4,359 8 WHITE OAK 2206 #1UMH-36 CHAPARRAL 5/7/2017 1,156 53% 4,743 9 PATRICIA 5-21N-5W 1MH WHITE STAR 5/2/2017 668 76% 4,686 10 PATRICIA 5-21N-5W 2MH WHITE STAR 4/14/2017 865 71% 4,194 11 COLONIAL 2007 #1LMH-26 CHAPARRAL 7/9/2018 584 92% 5,108 12 PLATTER 2007 #1LMH-36 (JV) CHAPARRAL 3/29/2018 721 83% 4,852 13 FUKSA 2007 #1LMH-14 CHAPARRAL 11/2/2017 834 83% 4,087 14 STAY PUFT 1707 #1LMH-23 CHAPARRAL 9/26/2017 863 86% 4,571 15 BRANDT 1707 #1LMH-12 CHAPARRAL 7/8/2017 948 86% 4,482 16 LOW VALLEY 1807 #1LMH-36 CHAPARRAL 4/18/2017 1,345 82% 4,766 17 DR J 1808 7-1UOH GASTAR 10/1/2017 843 80% 4,593 18 BUGABAGO 2006 1-31MH LONGFELLOW 3/5/2017 568 89% 5,064 Lower Type Curve Upper Osage Osage IP-301 (Boe/d) 599 744 ROR at NYMEX Strip2 98% 56% Total EUR1 (MBoe) 629 853 % Liquids1 70% 54% Lateral Length (feet) 4,800 4,800 Well Cost ($mm) $3.9 $4.1 1 Gross three-phase scaled to type curve lateral length of 4,800 feet 2 At September 28, 2018 NYMEX prices; five-year average prices $67.40 and $2.70 NYSE: CHAP 35

STACK Woodford Type Curves Overview Spud Peak IP-301 Liquids1 Lateral Lease Operator Date Boe/d % Length 1 CUTTHROAT 1307 1WH-13 CHAPARRAL 2/11/2017 588 76% 4,225 2 GLACIER 11-14-12-6 1HX JONES 12/31/2017 463 63% 9,890 3 ACADIA 13-12-12-6-1HX JONES 12/9/2017 581 65% 7,277 4 EVEREST 1107 #1WH-24 CHAPARRAL 2/12/2018 451 59% 4,451 5 KATMAI 1206 #1WH-29 CHAPARRAL 1/5/2018 405 61% 4,086 6 LASSEN 1107 #1WH-15 CHAPARRAL 11/24/2017 499 64% 4,021 7 OLYMPUS 1107 #1WH-10 CHAPARRAL 11/13/2017 462 58% 4,122 8 FRANK EATON 36-1-11-6 1XH ROAN 2/3/2018 454 80% 9,941 9 LOUDERMILK 1H-32-29 ROAN 12/3/2017 490 60% 10,182 10 ASHCRAFT 1-19H CIMAREX 9/20/2017 640 63% 5,172 11 COWBOY 1H-34-3 ROAN 8/30/2017 402 60% 9,282 12 CANNONBALL 1208 24-1WH 89 ENERGY 7/21/2017 769 62% 4,639 13 RAFTER J 1H-17-20 ROAN 7/16/2017 1,059 57% 8,423 14 ROSEWOOD 16-12-7 3H JONES 7/3/2017 933 69% 4,465 North South Type Curve Woodford Woodford IP-301 (Boe/d) 475 736 ROR at NYMEX Strip2 50% 95% Total EUR1 (MBoe) 579 1,456 % Liquids1 72% 62% Lateral Length (feet) 4,800 4,800 Well Cost ($mm) $4.4 $4.4 1 Gross three-phase scaled to type curve lateral length of 4,800 feet 2 At September 28, 2018 NYMEX prices; five-year average prices $67.40 and $2.70 NYSE: CHAP 36

Commodity Realizations Crude Oil Differentials Oil & NGL Realizations as % of WTI 97% 99% • Proximity to numerous markets provides better CHAP 95% 93% 96% net back as compared to other basins $100 100% $90 90% • STACK crude oil quality meets Oklahoma refineries $80 80% specification $70 70% $60 60% • New trucking terminals and pipeline infrastructure $50 50% have reduced transportation costs, providing better net $40 40% back at the wellhead $30 44% 30% 38% 35% 37% Realizations % $20 31% 20% $10 10% WTI Average Daily Settle Daily Average WTI $0 0% NGL Differentials 2014 2015 2016 2017 YTD Q3 2018 • Increased pipeline capacity to the Gulf Coast to new WTI NGL % Oil % markets • Increased Gulf Coast demand, with new petrochemical Natural Gas Realizations as % of HH crackers coming online 98% • Access to Mont Belvieu and increased NGL export 92% capacity provided increased pricing to STACK $4.50 85% 87% 100% $4.00 75% 90% $3.50 80% $3.00 70% 60% $2.50 Natural Gas Differentials 50% $2.00 40% • Increased supply from STACK/SCOOP and other $1.50 30% basins competing for pipeline capacity has caused $1.00 20% Realizations % $0.50 10% Mid-Continent to widen Settle Daily Average HH $0.00 0% • New pipeline capacity out of STACK/SCOOP to south 2014 2015 2016 2017 YTD Q3 2018 and Gulf Coast will provide price strength for the basin Henry Hub Gas % NYSE: CHAP 37

STACK Drilling Joint Venture • Joint venture between Chaparral and Bayou City Energy (BCE) • Accelerate development of 127,000 STACK acres • 20 wells drilled and producing as of Q3 2018 • Key driver in de-risking Garfield 50% and Canadian County Merge 80% to date STACK • BCE funds 100% of D&C cost • $100 million maximum investment, associated with 30 joint venture STACK wells • 17 Canadian County • 13 Garfield County • BCE receives 85% working interest in Merge each well until program reaches 14% rate-of-return • After which, Chaparral working interest increases to 75% and BCE retains 25% working interest • Chaparral retains all acreage and resources outside wellbore NYSE: CHAP 38

Reserve and Non-GAAP Information Statement 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. F&D Finding and development (“F&D”) costs are non-GAAP metrics commonly used by the company, as well as analysts and investors, to measure and evaluate the company’s cost of adding proved reserves. STACK F&D costs are computed below by dividing exploration and development capital costs incurred, excluding capitalized interest and expenses, for the indicated period by proved reserve extensions and discoveries, and revisions (excluding price revisions) for that same period. Due to various factors, historical F&D costs do not reflect the cost or timing of future production of new reserves and therefore may not be a reliable predictor of future results. For example, development costs may be recorded in periods after the periods in which the related reserves are recorded. In addition, changes in commodity prices can affect the magnitude of recorded increases (or decreases) in reserves independent of the related costs of such increases. As a result of the foregoing factors and various factors that could materially affect the timing and amounts of future increases in reserves and the timing and amounts of future costs, future F&D costs may differ materially from those set forth below. The methods used by the company to calculate its F&D costs may differ significantly from methods used by other companies to compute similar measures. As a result, the company’s F&D costs may not be comparable to similar measures provided by other companies. NYSE: CHAP 39

Reconciliations Successor Three Months Three Months Ended Ended (in thousands) Sept 30, 2018 Sept 30, 2017 Net (loss) income $ (12,068) $ (19,115) Interest expense 4,205 5,283 Income tax expense — 37 Depreciation, depletion, and amortization 22,252 32,167 Non-cash change in fair value of derivative instruments 16,804 22,236 Impact of derivative repricing (1,698) — Interest income (7) (4) Stock-based compensation expense 2,304 2,776 (Gain) loss on sale of assets 2,024 13 Restructuring, reorganization and other 493 892 Adjusted EBITDA $ $34,309 $ 44,285 (in thousands) 2017 Standardized measure of discounted future net cash flows $497,873 Present value of future income tax discounted at 10% — PV-10 value $497,873 NYSE: CHAP 40

Reconciliations STACK F&D and Reserve Replacement 2017 Metrics Calculation STACK Production (MBoe) 3,464 (A) Proved Reserves (MBoe) STACK Extensions and Discoveries 20,927 (B) STACK Revisions 597 (C) (excluding price revisions) Capital Costs Incurred (in thousands) STACK Only $166,758 (D) (includes D&C, acquisitions and enhancements) STACK Only $156,183 (E) (excludes capitalized interest and capitalized G&A) STACK Reserve Replacement 604% (B)/(A) All-in STACK F&D $7.26 (E)/(B+C) NYSE: CHAP 41

Contact Information Chaparral Energy, Inc. 701 Cedar Lake Boulevard Oklahoma City, OK 73114 Investors Media Joe Evans Brandi Wessel Chief Financial Officer Manager – Communications joe.evans@chaparralenergy.com brandi.wessel@chaparralenergy.com 405-426-4590 405-426-6657 NYSE: CHAP 42

ENERGIZING America’s Heartland NYSE: CHAP chaparralenergy.com NYSE: CHAP 43