February 2014 JP Morgan Global High Yield & Leveraged 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

Strong Track Record of Growth 5 Production (Boe) / Day EBITDA ($mm) Reserves (Mmboe) $- $50 $100 $150 $200 $250 $300 $350 $400 $450 2009 2010 2011 2012 2013 E $224 $288 $313 $337 $389 $M M 130 135 140 145 150 155 160 2009 2010 2011 2012 2013 E 142 149 156 146 158 Overview - 5,000 10,000 15,000 20,000 25,000 30,000 2009 2010 2011 2012 2013 E 10,613 11,214 13,831 15,881 17,446 10,313 10,841 9,882 9,033 9,245 Oil Production (Boe) / Day Gas Production (Boe) / Day  Core Operating Area – Mid-Continent Region  Key Plays – NOMP, Panhandle Marmaton 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 20,926 22,055 23,713 24,914 26,691

Mid-Continent Geographic Focus 6 2014 Permian/Ark-La-Tex Planned Divestiture Divestiture Properties: 2013 Proved Reserves – 25 mmboe (42% Liquids) 2013 Production – 4.5 mboepd (45% Liquids) Mid-Continent Focus Mid-Continent Core: 2013 Proved Reserves – 133 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  Our Position • 532,000 net 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 • Long-term stable oil and cash flow growth from EOR • Experienced Mid-Continent management team Mid-Continent Focus 7

Exposure to Stacked High Quality Oil Plays 8 NOMP – 119,224 Prospective Acres Total Net Acres – 237,319 Acres (1) OK TX KS Chaparral Acreage NOMP Woodford STACK Most of Chaparral’s Mid- Continent acreage is located within a stacked pay environment Woodford – 118,095 Prospective Acres Other-New Plays - TBD (1) Acreage is duplicated for stacked plays

Multiple Pay Zones in the Mid-Continent 9 Hunton Woodford Big Lime Cherokee Meramec Osage Oswego M a r m a t o n S il u r ia n D e v o n ia n P e n n s y l v a n i a n M i s s i s s i p p i a n Anadarko BasinAge Industry Horizontal Drilling Targets

NOMP Panhandle Marmaton Core Plays Net Acres: 210,982 Q4 2013 Net Daily Production (boe/d): 5,400 Gross Drilling Locations: 3,034 Woodford EOR Net Acres: 128,351 Q4 2013 Net Daily Production (boe/d): 180 Gross Drilling Locations: 2,510 Q4 2013 Net Daily Production (boe/d): 4,300 Total Resource Potential: 213 Mmboe Active Operated Projects: 8 Net Acres: 130,771 Q4 2013 Net Daily Production (boe/d): 1,390 Gross Drilling Locations: 1,093 10 Meramec Shale/Carbonate Carbonate Rich Cana SCOOP Arkoma Central OK Woodford

Drilling Inventory and Play Resource Potential 11 Oil Rich Gas Rich Total Play Net Acres (1) Gross Locations Resource (mmboe) Net Acres (1) Gross Locations Resource (mmboe) Net Acres (1) Gross Locations Resource (mmboe) NOMP 166,700 2,114 162 44,282 920 80 210,982 3,034 242 Panhandle Marmaton 130,771 1,093 81 - - - 130,771 1,093 81 Woodford (Upside) 108,400 2,049 151 19,951 461 155 128,351 2,510 306 Grand Total 405,871 5,256 394 64,233 1,381 235 470,104 6,637 629 Core Inventory Life (NOMP and Panhandle Marmaton) Number of Rigs 10 15 20 Inventory Life (Years) 23 15 11 (1) Combined acreage position prospective for horizontal drilling for each zone

Returns in our Core Areas 12 0% 10% 20% 30% 40% 50% 60% 70% 80% Play IRRs (1) - 2,000 4,000 6,000 8,000 10,000 12,000 14,000 CXO CHAPAR LPI ATHL AR JONE ROSE MPO 12,269 6,637 6,000 5,981 4,576 2,435 1,933 1,600 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 December 2013

158 1,020 - 25 306 242 193 81 65 0 200 400 600 800 1000 1200 2013 Proved Reserves Planned Divestiture Woodford NOMP EOR Marmaton Other Total Potential Mmb o e Reserve and Inventory Upside Potential 13

NOMP Resource Potential

Northern Oklahoma Mississippi Play (NOMP) 15  210,982 net acres  Principally carbonate in north, and develops into carbonate/shale sequence as the play moves south  Multiple benches with ongoing development  Over 242 MMBoe of potential recovery  3,034 un-risked drilling locations (on 3-4 wells per section spacing)  Chaparral has drilled/participated in over 100 wells  2014 Expectations: - Run 3-5 rigs - $116 million in capital - 35-45 wells Overview NOMP Asset Map OK TX KS Chaparral Acreage Carbonate Rich Meramec Shale/Carbonate

NOMP Carbonate Economics 16 • 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 OR % 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 OPD PRODUCTION MONTHS NOMP TYPE CURVES(1) EUR = 352 MBOE OIL BOPD GAS MCFD 6% 4% M C F D 18% 9% 5% % EUR per Year (1) Management Estimate

NOMP Individual Well Performance 17 OPERATOR WELL 30 DAY IP (BOEPD) CHAPARRAL GLADYS 3H-25 1292 CHAPARRAL 17 WELLS IN 2013 459 (AVG) CHAPARRAL CENTIPEDE 1H-15 876 CHAPARRAL DIETERICH 2MH-10 693 CHAPARRAL DOLEZAL 1H-15 180 MBOE (1) CHAPARRAL SALT CREEK 1H-10 126 B&W BODE 1-2H 471 SANDRIDGE SIMPSON TR 2407 2-27H 421 LONGFELLOW HLADIK 15-M4H 1884 NEWFIELD KRETCHMAR 1H-2W 772 MIDSTATES LONGHURST 3H-34 2559 HINKLE O&G LNU 49-4H 661 NEWFIELD YOST 1H-18X 854 NOMP Well Performance OK TX KS Chaparral Acreage Carbonate Rich Meramec Shale/Carbonate 1 2 3 4 9 8 7 5 6 10 11 12 13 (1) Represents cumulative production from unstimulated well drilled in 2001 and 2,200’ lateral

0 1 2 3 4 5 6 7 0 - 200 200 - 350 350 - 500 500 - 800 800 - x 3 6 6 7 6 W e ll Cou n t 30 Day IP Rate (BOEPD) NOMP 2013 Results 18 0 100 200 300 400 500 600 Average - 28 Wells 506 3 0 D ay IP R at e ( B OE P D ) Type Curve

NOMP Execution 19 0 10 20 30 40 50 60 70 80 Q2 2012 Q3 2012 Q4 2012 Q1 2013 Q2 2013 Q3 2013 Q4 2013 79 59 49 49 42 40 38 D ay s Spud to Rig Release Rig Release to First Production

NOMP Growth 20 Production (Boe) / Day Net Acres - 50 100 150 200 250 2011 2012 2013 153 175 210 N et A cr es (0 0 0 ) - 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 2011 2012 2013 E 174 782 2,131 114 571 1,705 Bo e /D ay Liquids Gas 3,835 1,353 288

Panhandle Marmaton Resource Potential

Panhandle Marmaton Play 22  The Panhandle Marmaton Play is another key oil resource consisting of multiple carbonate benches with ongoing development  Largest operator in play  130,771 net acres  1,093 unrisked drilling locations  Over 81 MMBoe of potential recovery  Chaparral has drilled/participated in 33 wells and also acquired 59 wells from Cabot  2014 Expectations: - Run 3-5 rigs - $162 million in capital - Drill or participate in 50-55 wells Overview Panhandle Marmaton Asset Map OK TX KS Chaparral Acreage

Panhandle Marmaton Economics 23 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 OR % 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 MONTHS PANHANDLE MARMATON TYPE CURVES(1) EUR = 168 MBOE OIL BOPD GAS MCFD M C F D 7% 4% 29% 11% 5% % EUR per Year (1) Management Estimate

Panhandle Marmaton Results 24

Panhandle Marmaton Well Performance 25 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 JAY 1098 150 BOEPD CHAPARRAL MILLER 44 1H 154 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 Panhandle Marmaton Well Performance OK TX KS Chaparral Acreage 1 2 3 4 5 6 7 8 9 10 11 12 13

Woodford Shale Play

Woodford Shale Play 27  The Woodford Shale Play is a material resource play and provides significant upside  The Woodford Shale Play consists of well defined productive regions  128,351 net acres  Over 306 MMBoe of potential recovery  2,510 unrisked drilling locations  Drilled/participated in 75 wells  2014 Expectations: - Approximately $20 million in capital - Drill or participate in 7-12 wells Overview Woodford Asset Map OK TX KS Chaparral Acreage CANA SCOOP ARKOMA CENTRAL

OPERATOR WELL BEST 30 DAY IP DEVON ROTHER 1-24H 1404 BOEPD DEVON ROTHER 1-5H 990 BOEPD CIMAREX DRAPER 1-25H 3228 BOEPD NEWFIELD KLADE 1H-3X 476 BOEPD CONTINENTAL MILLS 1-21H 872 BOEPD CONTINENTAL LYLE 1-30H 1294 BOEPD DEVON LECK 1-16H 1154 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 Woodford Well Performance 28 OK TX KS Chaparral Acreage CANA SCOOP ARKOMA CENTRAL 1 2 3 4 5 6 7 8 9 10 11 Woodford Well Performance

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

Chaparral is a Leader in the CO2 EOR Industry 30 # of Active Producer CO2-EOR Projects 31 22 8 7 7 7 6 5 4 4 4 Total 105 Source: April 2012 Oil & Gas Journal Note: Chaparral projects include the North Burbank Unit Chaparral is the third most active CO2-EOR operator in the U.S.

CO2 EOR Focused Areas 31  CO2 Project Inventory  50 units with 1P, 2P & 3P EOR reserves  9 units with proved reserves  CO2 Infrastructure – 473 Miles  85 MMscf/D of existing CO2 supply  2014 Budget Expectations:  $162 million in capital  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 "

Proven Track Record of CO2 EOR Performance 32 Field CO2 Initiation Production prior to Injection (Bopd) Current Production (Bopd) Gross EOR Estimated Ultimate Recovery (Mmboe) Camrick 2001 103 1,270 8.0 North Perryton 2006 21 467 3.4 Booker 2009 9 954 2.0 NW Velma Hoxbar 2010 78 266 1.2 Farnsworth 2010 139 1,545 7.5 Burbank 2013 1,372 1,372 88.3

Total EOR Uplift Growth 33 - 500 1,000 1,500 2,000 2,500 3,000 2010 2011 2012 2013 B OE/D ay

North Burbank CO2 EOR Development

Burbank Area Overview 35  Chaparral’s Burbank field is its largest EOR field and CO2 injection started in June 2013  2014 Expectations:  $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  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

North Burbank in Perspective 36 Secondary Development Primary Development N et B O P D Tertiary Development “Waterflood” +12000 BOPD “CO2 EOR”

Financial Overview

Financial Metrics per BOE 38 Production (Boe) / Day LOE / Boe EBITDA / Boe G&A / Boe - 5,000 10,000 15,000 20,000 25,000 30,000 2010 2011 2012 2013 E 2014 B 11,214 13,831 15,881 17,446 20,821 10,841 9,882 9,033 9,245 8,179 Bo e /d ay Oil Production (Boe) / Day Gas Production (Boe) / Day 23,713 22,055 24,914 26,691 $0.00 $2.00 $4.00 $6.00 $8.00 $10.00 $12.00 $14.00 $16.00 2010 2011 2012 2013 E 2014 B $13.18 $14.03 $14.37 $14.39 $13.25 $ /BO E $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 2010 2011 2012 2013 E 2014 B $3.72 $4.86 $5.46 $5.53 $5.53 $/B O E $0.00 $5.00 $10.00 $15.00 $20.00 $25.00 $30.00 $35.00 $40.00 2010 2011 2012 2013 E $35.56 $35.98 $37.03 $39.92 $/B O E 29,000

Financial Flexibility to Execute Strategy 39 Net Debt / EBITDA Liquidity ($mm) $325 $300 $400 0 100 200 300 400 500 600 2013 2016 2017 2018 2019 2020 2021 2022 $284 $300 $400 $550 0.0x 1.0x 2.0x 3.0x 4.0x 5.0x 6.0x 2007 2008 2009 2010 2011 2012 2013 5.6x 4.4x 4.9x 3.2x 3.3x 3.9x 3.5x $- $100 $200 $300 $400 $500 $600 2007 2008 2009 2010 2011 2012 2013 $88 $55 $77 $429 $407 $504 $376  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 12/31/13 was $327mm. Current Maturity Profile ($mm)

Capital Budget ($mm) 40 Component 2011 2012 2013 2014 Budget 2014B Allocation % Drilling $172 $239 $269 $376 59% EOR 86 187 $128 $162 26% Enhancements 32 20 $22 $16 3% Acquisitions 17 48 $209 $35 5% Other (P&E, Capitalized G&A, etc) 28 37 $42 $46 7% Total $336 $531 $670 $635 100% Key Drilling Areas Capital Wells NOMP $116 40 Panhandle Marmaton 162 50 Woodford 20 7 Other 78* 37 Total $376 134 EOR Field Capital N. Burbank $85 Panhandle Area 71 Other 6 Total $162 *Includes both Operated and Non-Operated Wells

2013 Results and 2014 Guidance 41 Operating Statistics 2013 Forecast 2014 Guidance Capital Expenditures ($MM) $516 (1) $625 - $650 Production (MMBoe) 9.7 10.4 - 10.8 General and Administrative $5.53/Boe $5.25 - $5.75/Boe Lease Operating Expense $14.39/Boe $13.00 - $13.50/Boe (1) – Excluding Cabot Acquisition

 Mid-Continent oil rich pure play  Material high return drilling inventory  EOR portfolio that will be cash flow positive in 2015  Proved stacked pay reservoirs offer efficiency improvement opportunities  Track record of execution Summary 42 2/21/2014

Appendix

NOMP Upside - Meramac Shale 44 • Mississippi carbonate intervals evolve into higher Meremac Shale sequence as you move south and west • Meramec portion of Mississippi becomes shaley and silty further south • Proven vertical production • Multiple lateral potential

NOMP Carbonate – Results vs. Type Curve 45

 Burbank Area  North Burbank Unit $85  Panhandle Area  Farnsworth Unit $40  Camrick Area 18  Booker Area 13 $71  Central Oklahoma  NW Velma Hoxbar $6 $162 EOR 2014 Capital Budget 46 Capex by Category ($mm)(1) 2013E 2014B Infrastructure / Pipelines 65 31 Drilling 15 47 Enhancements / CO2 Purchases 48 84 Total $128 $162 2014 Field Projects ($mm) Panhandle Area Central Oklahoma Area Burbank Area (1) Does not include Capitalized G&A or Capitalized Interest

CO2 Resource Upside Potential 47 Existing Chaparral CO2 PL Possible Chaparral CO2 PL Third Party Pipelines Cum. Recovered 1-3 MMBbls Cum. Recovered 3-5 MMBbls Cum. Recovered 5-10 MMBbls Cum. Recovered 10-50 MMBbls Cum. Recovered 50-100 MMBbls Cum. Recovered 100+ MMBbls US Department of Energy estimates 10.6 BBO are technically recoverable from 246 fields through CO2 EOR in the Mid-Continent

Financial Summary 48 2010 2011 2012 2013 E Price Oil – Wellhead ($/Bbl) $76.45 $92.36 $90.87 $95.07 Gas – Wellhead ($/Mcf) $4.36 $4.08 $2.64 $3.48 NGL – Wellhead ($/Bbl) $55.66 $60.84 $34.04 $33.18 Production (MMBoe) 8.1 8.7 9.1 9.7 Oil (MMBbls) 3.7 4.3 4.6 5.0 Gas (Bcf) 23.7 21.6 19.8 20.2 NGL (MMBbls) .4 .8 1.2 1.4 Financial Data ($millions) Operating Expenses: Lease Operating Expenses $106.1 $121.4 $131.1 $140.2 Production and Ad Valorem Taxes 26.5 34.3 32.0 33.3 General and Administrative Expenses (excludes noncash deferred comp) 27.3 38.3 46.7 53.9 Interest Expense $83.6 $96.7 $98.4 $96.9 EBITDA $288 $313 $337 $389 Total Capital Expenditures $344 $336 $531 $681

Hedge Portfolio 49 % of Total Proved Reserves Hedged (as of February 18, 2014) Note: Dollars represent average strike price of hedges (includes all derivative instruments)

Thank you © 2014 Chaparral Energy