rbcpresentationfinal

June 2014 Royal Bank of Canada Finance Conference

Company Representatives 2 Mark Fischer Chief Executive Officer Earl Reynolds President & Chief Operating Officer Joe Evans Chief Financial Officer Melinda Merideth Corporate Finance Manager

This presentation contains "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. These forward-looking statements are subject to certain risks, trends and uncertainties that could cause actual results to differ materially from those projected. Among those risks, trends and uncertainties are our ability to find oil and natural gas reserves that are economically recoverable, the volatility of oil and natural gas prices, the uncertain economic conditions in the United States and globally, the decline in the values of our properties that have resulted in and may in the future result in additional ceiling test write-downs, our ability to replace reserves and sustain production, our estimate of the sufficiency of our existing capital sources, our ability to raise additional capital to fund cash requirements for future operations, the uncertainties involved in prospect development and property acquisitions or dispositions and in projecting future rates of production or future reserves, the timing of development expenditures and drilling of wells, the impact of hurricanes and other natural disasters on our present and future operations, the impact of government regulation, and the operating hazards attendant to the oil and natural gas business. In particular, careful consideration should be given to cautionary statements made in the various reports we have filed with the Securities and Exchange Commission. We undertake no duty to update or revise these forward-looking statements. Forward-Looking Statements 3

Chaparral: Overview

2014 Highlights 5 55%33% 12% Q1 2014 Production by Product Oil Gas NGLs Q1 2014 Net Production Oil (MBbls) 1,415 Gas (MBoe) 862 NGLs (MBbls) 314 Total (MBoe) 2,591  Q1 production volume increase of 16% year over year to 28,793 MBoe per day  Record EBITDA of $110.8 million in Q1  Q1 capital expenditures of $155.6 million  Exceptional operational execution • Drilled 37 new wells during the quarter - 8 NOMP - 14 EOR - 9 Marmaton - 6 Other • 19 wells drilled in March - a company record • Consistent improvements in spud to rig release and rig release to first production in NOMP and Marmaton  Maintain guidance  Burbank response of 400-500 boe per day  Achieving objective of becoming pure Mid-Continent player • Signed purchase and sale agreements for three of the five divestiture packages for $201 million • Expected proceeds from property sales to date of $218 million • Redeploying capital for Mid-Continent development

Ark-La-Tex Sale Update 6 Divestiture Properties: 2013 YE Proved Reserves – 22 mmboe (42% Liquids) 2014 Production ~ 4.2 mboepd 2014 Cash Flow ~ $45.0 million  Sale properties split into five packages  Closed sales of first two packages  Sale of Ft. Worth Basin properties to Scout Energy closed on May 19, 2014 for $25 million* - approximately 200 BOE of average daily production  Sale of Delaware Basin to RKI closed on May 23, 2014 for $125 million* - approximately 1,800 BOE of average daily production  Entered into sale agreements for third package  Ark-La-Tex Package to RAM Energy for $51 million* - approximately 1,000 BOE of average daily production  Negotiations on remaining two packages are ongoing * the Purchase Price is subject to customary pre- and post- closing adjustments as described in the Agreements.

Burbank Production Progress 7 1000 1500 2000 J a n ‐ 1 3 F e b ‐ 1 3 M a r ‐ 1 3 A p r ‐ 1 3 M a y ‐ 1 3 J u n ‐ 1 3 J u l ‐ 1 3 A u g ‐ 1 3 Se p ‐ 1 3 O c t ‐ 1 3 N o v ‐ 1 3 D e c ‐ 1 3 J a n ‐ 1 4 F e b ‐ 1 4 M a r ‐ 1 4 A p r ‐ 1 4 M a y ‐ 1 4 B O P D NBU Gross Production Net Base Prod Weekly Average ~475 BOPD

Strong Track Record of Growth 8 Production (Boe) / Day EBITDA ($mm) Reserves (Mmboe) $- $50 $100 $150 $200 $250 $300 $350 $400 $450 2009 2010 2011 2012 2013 $224 $288 $313 $337 $389 $ M M 130 135 140 145 150 155 160 2009 2010 2011 2012 2013 142 149 156 146 158 Overview - 5,000 10,000 15,000 20,000 25,000 30,000 2010 2011 2012 2013 Q1 2014 11,214 13,831 15,881 13,715 15,727 10,841 9,882 9,033 9,247 9,580 3,729 3,486 Oil Gas NGL  Core Operating Area – Mid-Continent Region  Key Plays – NOMP, Panhandle Marmaton, Woodford and EOR  Oil Focused (Reserves – 68% oil / liquids)  Strong future growth potential  Prudent balance sheet and liquidity  Key Growth Drivers • Repeatable Resource Plays • CO2 Enhanced Oil Recovery 22,055 23,713 24,914 26,691 28,793

Mid-Continent Geographic Focus 9 Mid‐Continent Core: 2013 Proved Reserves – 136 mmboe (72% Liquids) 2013 Production – 22.2 mboepd (70% Liquids)

Mid-Continent Advantages • Prolific hydrocarbon producing basin • Numerous reservoirs with stacked pay potential for horizontal drilling • Material infrastructure for enhanced execution • Lower historical oil differentials • Industry friendly environment  Constructive regulatory environment  Potential to increase acreage through pooling Why Mid-Continent – The Next Untold Story 10 lan dm as s Amarillo-Wichita Uplift La nd ma ss Sh all ow S ea s Sh all ow S ea s Ft. Worth Basin Anadarko Basin Midland BasinDelaware Basin

Our Position  532,000 net surface acres  Portfolio poised to deliver double digit growth  Oil-rich portfolio with focus on high return, oil leveraged plays  Significant inventory of repeatable drilling opportunities • 23 year drilling life with 10 rigs running  Long-term stable oil and cash flow growth from EOR Midcontinent Focus – The Next Untold Story 11 Source: The Oklahoman

NOMP Marmaton Core Plays Net Surface Acres: 210,982 Gross Drilling Locations: 2,088 Gross Operated Drilling Locations: 1,123 Net Surface Acres: 128,225 Gross Drilling Locations: 1,124 Gross Operated Drilling Locations: 768 12 Woodford Net Surface Acres: 164,945 Gross Drilling Locations: 2,108 Gross Operated Drilling Locations: 1,033 Cana SCOOP Arkoma Central OK Woodford Meramec NOMP EOR Q1 2014 Net Daily Production (boe/d): 7,408 Total Resource Potential: 193 Mmboe Active Operated Projects: 8 Burbank Area Panhandle Area Central OK Area Marmaton Meramec Shale

Stacked High Quality Oil Plays NOMP & Woodford 13 OK TX KS Chaparral Acreage NOMP – 119,224 Prospective Acres Total Stacked Net Acres – 343,319 Acres (1) Much of Chaparral’s Mid-Continent acreage is located within a stacked pay environment Woodford – 118,095 Prospective Acres New Play – 106,000 Prospective Acres (1) Acreage is duplicated for stacked plays

Multiple Pay Zones in the Mid-Continent 14 Industry Horizontal Drilling Targets

Horizontal Drilling Inventory and Play Resource Potential 15 Oil Rich (2) Gas Rich (2) Total (2) Play Net Acres(1) Gross Locations Resource (mmboe) Net Acres(1) Gross Locations Resource (mmboe) Net Acres(1) Gross Locations Resource (mmboe) NOMP/Meramec Shale 199,569 1,104 60 43,414 984 190 242,983 2,088 250 Panhandle Marmaton 128,225 1,124 88 ‐ ‐ ‐ 128,225 1,124 88 Woodford (Upside) 145,418 1,768 139 19,527 340 108 164,945 2,108 247 New Play 106,168 1,086 80 ‐ ‐ ‐ 106,168 1,086 80 Grand Total 579,380 5,082 367 62,941 1,324 298 642,321 6,406 665 Inventory Life (NOMP and Panhandle Marmaton – Oil Rich) Number of Rigs 10 15 20 Inventory Life (Years) 23 15 11 (1) Acreage is duplicated for stacked plays (2) Inclusive of proved reserves

Expected Returns in our Core Areas 16 0% 10% 20% 30% 40% 50% 60% 70% 80% Play IRRs (1) ‐ 5,000 10,000 15,000 20,000 25,000 CXO ATHL CHAP * AR JONE ROSE MPO 22,000 7,308 6,406 4,872 2,542 2,064 1,100 Gross Unrisked Drilling Locations (1) Obtained from Credit Suisse Research and Analytics using futures strip as of 6/17/2013 (2) Management Type Curve Source: Company presentations as of May 2014 * ‐ Horizontal Only

Over 1 BBOE - Reserve and Inventory Upside Potential 17 Planned 2014 Divestiture 158 (22) 223 241 81 193 145 1,019 0 200 400 600 800 1000 1200 2013 Proved Reserves Planned Divestiture NOMP/ Meramec Shale Woodford Marmaton EOR Other Total M M b o e

NOMP Resource Potential

Northern Oklahoma Mississippi Play (NOMP) 19  242,983 net acres including the Meramec Shale  Principally carbonate in north, and develops into carbonate/shale sequence as the play moves south  Multiple benches with ongoing development  Over 250 MMBoe of potential recovery  2,088 (1,123 operated) unrisked drilling locations (on 3‐4 wells per section spacing)  Chaparral has drilled/participated in over 100 wells  2014 Expectations: ‐ Run 3‐5 rigs ‐ $140 million in capital ‐ 34 ‐ 38 wells Overview NOMP Asset Map OK TX KS Chaparral Acreage Meramec Shale

NOMP Carbonate Economics 20 • EUR: 352 Mboe • Oil %: 40‐50% • D&C cost: $3.3 ‐ $3.7 million Oil • EUR: 154 MBbl • IP (30 Day) 155 BOPD • Initial Decline: 73% • b Factor: 1.5 Wet Gas • EUR: 1,190 MMCF • IP (30 Day) 1,044 MCFD • Initial Decline: 73% • b Factor: 1.5 NGLs(a) • EUR: 60 MBBL • IP (30 Day) 59 BOPD • NGL Yield: 50 BBLS/MMCF • Gas Shrink Factor: 75% Type Curve Parameters (a) After processing shrink 12% 20% 30% 41% 54% 68% 0% 10% 20% 30% 40% 50% 60% 70% 80% $60/ $3 $70/ $3.5 $80/ $4 $90/ $4.5 $100/ $5 $110/ $5.5 R O R % Rate of Return versus Wellhead Pricing 0 200 400 600 800 1000 1200 1400 0 50 100 150 200 250 0 12 24 36 48 60 72 84 96 108 120 132 144 156 168 180 192 204 B O P D PRODUCTION DAYS NOMP TYPE CURVES(1) EUR = 352 MBOE OIL BOPD GAS MCFD 6% 4% M C FD 18% 9% 5% % EUR per Year (1) Management Estimate

NOMP Well Performance 21 NOMP Well Performance OK TX KS Chaparral Acreage OPERATOR WELL 30 DAY IP CHAPARRAL GLADYS 3H-25 1,292 BOEPD CHAPARRAL KUDU 1H-21 513 BOEPD CHAPARRAL CENTIPEDE 1H-15 876 BOEPD CHAPARRAL LEE 1MH-1 711 BOEPD CHAPARRAL DOLEZAL 1H-15 185 MBO (1) CHAPARRAL SALT CREEK 1H-10 126 BOEPD CHAPARRAL DU CARDINAL 1MH-27 1,076 BOEPD B&W BODE 1-2H 471 BOEPD ARP SALUKI 2-4H 683 BOEPD LONGFELLOW HLADIK 15-M4H 1,884 BOEPD NEWFIELD KRETCHMAR 1H-2W 772 BOEPD MIDSTATES LONGHURST 3H-34 2,559 BOEPD NEWFIELD YOST 1H-18X 854 BOEPD 12 3 4 9 8 5 6 10 11 12 13 1 2 3 4 5 6 7 8 9 10 11 12 13 7 MeramecMeramec Shale (1) Represents cumulative production from unstimulated well drilled in 2001 and 2,200’ lateral

0 1 2 3 4 5 6 7 8 9 10 < 200 200 - 350 350 - 500 500 - 800 800 + N u m b e r o f W e l l s 2013 Q1 2014 3 NOMP 2013 and Q1 2014 Results 22 0 100 200 300 400 500 600 Average - 37 Wells 513 3 0 D a y I P R a t e ( B O E P D ) Type Curve 10 8 7 7 30 – Day IP Rate (BOEPD)

Improved NOMP Execution 23 0 10 20 30 40 50 60 70 80 Q2 2012 Q3 2012 Q4 2012 Q1 2013 Q2 2013 Q3 2013 Q4 2013 Q1 2014 79 59 49 49 42 40 38 43 D a y s Spud to Rig Release Rig Release to First Production

NOMP Growth 24 Production (Boe) / Day Net Surface Acres - 50 100 150 200 250 2011 2012 2013 Q1 2014 153 175 211 211 N e t A c r e s ( 0 0 0 ) - 1,000 2,000 3,000 4,000 5,000 6,000 2011 2012 2013 Q1 2014 174 906 1,765 2,402 114 584 1,714 2,617 468 721 B o e / D a y Liquids Gas NGLs 3,947 1,490 288 5,740

Panhandle Marmaton Resource Potential

OK TX KS Panhandle Marmaton Play 26  The Marmaton Play is another key oil resource consisting of multiple carbonate benches with ongoing development  Largest operator in play  128,225 net acres  1,124 (768 Operated) unrisked drilling locations  Over 88 MMBoe of potential recovery  Chaparral has drilled/participated in 38 wells and also acquired 60 wells from Cabot  2014 Expectations: ‐ Run 2 ‐ 3 rigs ‐ $155 million in capital ‐ 37 ‐ 41 wells Overview Marmaton Asset Map Chaparral Acreage HANSFORD LIPSCOMB OCHILTREE TEXAS ELLIS BEAVER

Panhandle Marmaton Economics 27 Type Curve Parameters • EUR: 168 Mboe • Oil %: 90% • D&C cost: $3.3 ‐ $3.7 million Oil • EUR: 157 MBbl • IP (30 Day) 285 BOPD • Initial Decline: 99.7% • b Factor: 1.18 Wet Gas • EUR: 65 MMCF • IP (30 Day) 124 MCFD • Initial Decline: 99.7% • b Factor: 1.18 NGLs(a) • EUR: 12 MBBL • IP (30 Day) 29 BOPD • NGL Yield: 180 BBLS/MMCF • Gas Shrink Factor: 60% (a) After processing shrink 10% 22% 36% 52% 70% 91% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% $60 /$3 $70 / $3.5 $80 / $4 $90 /$ 4.5 $100 / $5 $110 / $5.5 R O R % Rate of Return versus Wellhead Pricing 0 20 40 60 80 100 120 140 0 50 100 150 200 250 300 350 400 0 12 24 36 48 60 72 84 96 108 120 132 144 156 168 180 192 204 B O P D PRODUCTION DAYS PANHANDLE MARMATON TYPE CURVES(1) EUR = 168 MBOE OIL BOPD GAS MCFD M C FD 7% 4%29% 11% 5% % EUR per Year (1) Management Estimate

HANSFORD LIPSCOMB OCHILTREE TEXAS ELLIS BEAVER Panhandle Marmaton Well Performance 28 Panhandle Marmaton Well Performance Chaparral Acreage OK TX KS OPERATOR WELL 30 DAY IP CHAPARRAL NORA 49-1H 427 BOEPD CHAPARRAL THOMAS 1HX-35 922 BOEPD CHAPARRAL 4 RED CATTLE 1-23H 622 BOEPD CHAPARRAL KILE 1-7H 1414 BOEPD CHAPARRAL LOWERY 2H-14 479 BOEPD UNIT PRICE TRUST 1-28H 886 BOEPD UNIT GIFT 1-27H 672 BOEPD UNIT FISH 1H 466 BOEPD UNIT STATE OF OK A 1-6H 599 BOEPD UNIT SIMPSON 1-7H 543 BOEPD TEXAS AMER. CONNER UT 101H 300 BOEPD TEXAS AMER. FRIESEN-JOHNSON 171 BOEPD 1 2 3 4 8 7 5 9 10 1112 6 6

Woodford Shale Play

Woodford Shale Play 30  The Woodford Shale Play is a material resource play and provides significant upside  The Woodford Shale Play consists of well defined productive regions  164,945 net acres  247 MMBoe of potential recovery  2,108 (1,033 Operated) unrisked drilling locations  Chaparral has drilled/participated in 50 wells  2014 Expectations: ‐ $20 million in capital (1) ‐ 3 ‐ 5 wells (1) Includes approximately $4M of completion capital from 2013 drilling program Overview Woodford Asset Map Chaparral Acreage CANA SCOOP ARKOMA CENTRAL OK TX KS

Woodford Well Performance 31 OK TX KS Chaparral Acreage Woodford Well Performance CANA SCOOP ARKOMA CENTRAL 1 23 4 5 6 7 8 9 10 11 OPERATOR WELL BEST 30 DAY IP DEVON ROTHER 1-24H 1,404 BOEPD DEVON BESSIE 6-2H 863 BOEPD CIMAREX DRAPER 1-25H 3,228 BOEPD NEWFIELD/DCP KLADE 1H-3X 476 BOEPD CONTINENTAL MILLS 1-21H 872 BOEPD CONTINENTAL LYLE 1-30H 1,294 BOEPD DEVON LECK 1-16H 1,154 BOEPD DEVON THOMAS 1-8WH 260 BOEPD DEVON WINNEY 1-5H 432 BOEPD PLYMOUTH MARCELLA 1-36H 730 BOEPD PLYMOUTH THOMPSON 2-6H 415 BOEPD DEVON WALKING WOMAN - 8 Wells in 2014 1,116 BOEPD (AVG) 1 2 3 4 5 6 7 8 9 10 11 1 2 3 4 5 6 7 8 9 10 11 12 12

CO2 EOR is a Major Part of Chaparral’s Growth Story

Chaparral is a Leader in the CO2 EOR Industry 33 Chaparral is the third most active CO2-EOR operator in the U.S.

CO2 EOR Focused Areas 34  CO2 Project Inventory  10 units with proved reserves  40 units with 1P, 2P & 3P EOR reserves  CO2 Infrastructure – 473 Miles  85 MMscf/D of existing CO2 supply  2014 Expectations:  $162 million in capital  Increase in net uplift by 1,500 boepd  Expect CO2 EOR Business Unit to be cash flow positive in 2015 and beyond Overview Total OOIP 3,041 MMBo Primary Production 533 MMBo Secondary Recovery 449 MMBo Tertiary Potential 364 MMBo Net Tertiary Potential 213 MMBo Chaparral EOR Fields Chaparral CO2 Pipelines Third Party CO2 Pipelines CO2 Source Locations" Panhandle Area Burkank Area Central Oklahoma Area

Proven Track Record of CO2 EOR Performance 35 Field CO2 Initiation Production prior to Injection (Bopd) April 2014 Production (Bopd) Gross EOR Estimated Ultimate Recovery (Mmboe) Panhandle Area Camrick 2001 103 1,342 8.0 North Perryton 2006 21 513 3.4 Booker 2009 9 858 2.0 Farnsworth 2010 139 1,689 7.5 Central Oklahoma NW Velma Hoxbar 2010 78 420 1.2 Burbank Area Burbank 2013 1,372 1,498 88.3

Total EOR Uplift Growth 36 - 1,000 2,000 3,000 4,000 2011 2012 2013 Q1 2014 1,217 1,994 2,704 2,961 B O E / D a y

North Burbank CO2 EOR Development

Burbank Area Overview 38  Chaparral’s North Burbank unit is its largest EOR field  CO2 injection started in June 2013  Oklahoma’s largest unit with over 820 Mmbo OOIP and 320Mmbo cumulative production to date  2014 Expectations:  1,000 Net Bopd EOR uplift  $85 million in capital ‐ Drill 20 wells ‐ 120 workovers ‐ Phase 2 facility expansion North Burbank Overview Burbank Area Asset Map Total OOIP 1,163 MMBbls Primary Production 239 MMBbls Secondary Recovery 211 MMBbls Tertiary Potential 119 MMBbls Net Tertiary Potential 100 MMBbls  Anthropogenic CO2 from fertilizer plant  68.3 miles of 8” pipeline  19,500 HP compression facility  Commenced CO2 injection in June 2013 with current rate at 45 mmcfpd Coffeyville CO2 System

100 1,000 10,000 100,000 1,000,000 100 1,000 10,000 100,000 1,000,000 Jan‐20 Jan‐30 Jan‐40 Jan‐50 Jan‐60 Jan‐70 Jan‐80 Jan‐90 Jan‐00 Jan‐10 Jan‐20 Jan‐30 G r o s s B o e / D Primary Development Secondary Development Tertiary Development North Burbank CO2-EOR Flood 39 +14000 “Waterflood” “CO2 EOR”

Financial Overview

Financial Metrics per BOE 41 Production (Boe) / Day LOE / Boe EBITDA / BoeG&A / Boe - 5,000 10,000 15,000 20,000 25,000 30,000 35,000 2011 2012 2013 Q1 2014 2014 B* 13,831 15,881 13,715 15,727 20,821 9,882 9,033 9,247 9,580 8,179 3,729 3,486 B o e / d a y Liquids Gas NGL 23,713 24,914 26,691 $0.00 $2.00 $4.00 $6.00 $8.00 $10.00 $12.00 $14.00 $16.00 2011 2012 2013 Q1 2014 2014 B* $14.03 $14.36 $14.35 $13.52 $13.25 $ / B O E $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 2011 2012 2013 Q1 2014 2014 B* $4.86 $5.46 $5.53 $5.17 $5.50 $ / B O E $0.00 $5.00 $10.00 $15.00 $20.00 $25.00 $30.00 $35.00 $40.00 $45.00 2010 2011 2012 2013 Q1 2014 $35.56 $35.98 $37.03 $39.93 $42.78 $ / B O E 28,793 29,000 *2014 B based on Midpoint of guidance

Financial Flexibility to Execute Strategy 42 Net Debt / EBITDA Liquidity ($mm) $325 $300 $400 0 100 200 300 400 500 600 2013 2016 2017 2018 2019 2020 2021 2022 $329 $300 $400 $550 0.0x 0.5x 1.0x 1.5x 2.0x 2.5x 3.0x 3.5x 4.0x 4.5x 5.0x 2009 2010 2011 2012 2013 Q1 2014 4.9x 3.2x 3.3x 3.9x 3.5x 3.5x $- $100 $200 $300 $400 $500 $600 2009 2010 2011 2012 2013 Q1 2014 $77 $429 $407 $504 $376 $319  No senior note maturities before 2020  Hedge positions in place to secure cash flow in near term *Subject to 4.5x Debt / EBITDA covenant. Maximum availability at 5/27/14 was $307mm. Current Maturity Profile ($mm)

Capital Budget ($mm) 43 Component 2011 2012 2013 Q1 2014 2014 Budget 2014B Allocation % Drilling $172 $239 $269 $85 $376 59% EOR 86 187 $128 $34 $162 26% Enhancements 32 20 $22 $5 $16 3% Acquisitions 17 48 $209 $22 $35 5% Other (P&E, Capitalized G&A, etc) 28 37 $42 $13 $46 7% Total $336 $531 $670 159 $635 100% Key Drilling Areas Capital (*) Wells NOMP $140 34-38 Panhandle Marmaton 155 37-41 Woodford 20 3-5 Other 61 Total $376 EOR Field Capital N. Burbank $85 Panhandle Area 71 Other 6 Total $162 *Includes both Operated and Non‐Operated Wells 2014 Capital Allocation

2014 Guidance 44 Operating Statistics 2014 Guidance Capital Expenditures ($MM) $625 - $650 Production (MMBoe) 10.4 - 10.8 General and Administrative $5.25 - $5.75/Boe Lease Operating Expense $13.00 -$13.50/Boe