Wells Fargo Energy Conference December 7, 2011

Chaparral Overview  Founded in 1988, Based in Oklahoma City  Core areas — Mid-Continent (Oklahoma) and Permian Basin (W. Texas)  Oil-weighted producer (63% oil; 37% gas); R/P ratio 18 years  Third largest oil producer in Oklahoma  Stable 1P base with large 2P and 3P Upside  Near-term growth potential through drilling in conventional & emerging plays  Long-term growth through CO2 EOR 2 ¹Based on 12/31/2010 SEC methodology Company Statistics 3rd Quarter 2011 Avg Production Rate (Boe/d) ~24,000 YE 2010 Proved Reserves (MMBoe)1 149.3 YE 2010 Proved Reserves PV-10 ($ in mm)1 $1,770

3 Operating Areas As of December 31, 2010 (SEC) Core Area Growth Area Acreage Field Offices Headquarters North Texas Reserves: 3.9 MMBoe, 3% of total Production: 0.5 MBoe/d, 2% of total Permian Basin Reserves: 19.6 MMBoe, 13% of total Production: 4.1 MBoe/d, 19% of total Rocky Mountains Reserves: 2.8 MMBoe, 2% of total Production: 0.4 MBoe/d, 2% of total Company Total December 2010 proved reserves – 149.3 MMBoe 2010 average daily production – 22.1 MBoe/d Acreage (gross / net): 1,218,485 / 599,069 Val Verde Basin Sabine Uplift Midland Basin Delaware Basin Ouachita Uplift Arkoma Basin Fort Worth Basin Williston Basin Powder River Basin Greater Green River Basin San Juan Basin Anadarko Woodford Basin OKC Gulf Coast Reserves: 3.6 MMBoe, 2% of total Production: 0.7 MBoe/d, 3% of total Mid-Continent (Anadarko Basin & Central Oklahoma) Reserves: 110.9 MMBoe, 74% of total Production: 15.2 MBoe/d, 69% of total Ark-La-Tex Reserves: 8.5 MMBoe, 6% of total Production: 1.2 MBoe/d, 5% of total Sold 11/30/11

Strong Record of Reserve and Production Growth Year-End SEC Reserves (MMBoe) (1)(2)(3)(4) 2003 – 2010 CAGR = 17% Annual Production (MMBoe) 2003 – 2010 CAGR = 18% 142 113 164 151 103 73 51 0 25 50 75 100 125 150 175 2003 2004 2005 2006 2007 2008 2009 2010 149 Note: 1) Reserves as of December 31, 2007 are based on flat SEC pricing of $96.01/Bbl and $6.80/Mcf 2) Reserves as of December 31, 2008 are based on flat SEC pricing of $44.60/Bbl and $5.62/Mcf 3) Reserves as of December 31, 2009 are based on flat SEC pricing of $61.18/Bbl and $3.87/Mcf 4) Reserves as of December 31, 2010 are based on flat SEC pricing of $79.43/Bbl and $4.38/Mcf Chaparral’s reserve replacement ratio averaged 485% per year since 2002 4 2.6 3.2 4.2 5.4 6.8 7.1 7.6 8.1 8.7 0 2 4 6 8 10 2003 2004 2005 2006 2007 2008 2009 2010 2011P

Net Debt / EBITDA Liquidity ($ in mm) 5.6x 4.4x 4.9x 3.2x 3.3x 2.3x 2.0x 2.0x 0.0x 0.0x 2007 2008 2009 2010 9/30/2011 Total net debt to EBITDA Net secured debt to EBITDA $88.0 $55.4 $76.6 $429.2 $390.8 2007 2008 2009 2010 9/30/2011 Financial Position to Execute Strategy 5 1) Note: Debt balances do not reflect discounts on Senior Notes of $1.721mm on the 2017s and $6.551mm on the 2020s 0 $325 0  Strong Financial Position  Hedge positions in place to secure cash flow in near term  Plan to spend within free cash flow (including divestiture proceeds)  Current Liquidity of approximately $400 MM  No debt maturities before 2017 Current Maturity Profile ($ in mm)1 2011 2017 2018 2019 2020 2021 $325 $300 $400

6 Resource Potential

Substantial Resource Potential for both Near Term and Long Term Growth 7 Near Term  Conventional Drilling (ROR 50% - 75%)  Anadarko Granite Wash  Anadarko Cleveland Sand  Leading Emerging Plays (ROR 35% - 75%)  Northern Oklahoma Mississippi Play (NOMP) ~244,000 acres  Developing Emerging Plays (ROR 25% - 75%)  Anadarko/Arkoma Woodford Shale ~23,000 acres  West Texas Bone Spring/Avalon Shale ~17,000 acres  Panhandle Marmaton ~24,000 acres Long Term  CO2 EOR – 82 fields, 200+ MMBO (ROR 25% - 40%)

Capital Budget ($millions) Component 2008 2009 2010 2011 Budget 2011 % Drilling $176 $83 $207 $177 55% Tertiary Recovery 25 15 38 93 29% Enhancements 55 35 41 32 10% Acquisitions 46 18 41 18 6% Total $302 $151 $327 $320 100% 85% 7% Play Drilling Northern OK Mississippi Horizontal $34 Anadarko Cleveland Sand 28 Anadarko Granite Wash 22 Tunstill 13 Osage Creek 11 Sivells Bend 10 Bone Spring / Avalon 5 Anadarko Woodford Shale 5 Other 49 Total $177 Key Drilling Areas 8

9 Well Positioned for Near-Term and Long Term Growth NOMP 120 Million Barrels EOR 200 Million Barrels  Key near-term growth driver  Shallow oil target  Attractive F&D costs  Extensive history of vertical drilling  Long-term growth driver  Low-risk, stable production  Expertise to execute strategy

10 NOMP: A Key Near-Term Focus Area  244,000 Net Acres  Wildhorse Concession gives Chaparral exclusive rights to 138,000 acres  Drilled 9 wells to date  17 wells planned in 2012  Play Economics:  IP rates: 200 – 500 Boe/d  EURs: 200 – 400 MBOE  Well costs: $2.5 - $4 Million  Percent Oil: 60 – 80%  ROR: 35% - 75% Wildhorse Concession Chaparral Acreage

Northern Oklahoma Mississippi Play (NOMP) 11 Mississippi Horizontals CEI Leasehold 244,000 Net Acres Anadarko Basin Anadarko Shelf Chaparral NOMP Outline Sandridge NOMP Outline Osage Concession Area 217,000 Gross Acres 138,000 Net Available Oil Acres Plymouth Expl Sebranek 1-3H 4/28/11 IP 1021 bopd 1327 mcfd 3799 bwpd Currently 40-45 bopd Spyglass NW Strohm Osage 1A-29H 250 bopd, 5 mmcfgpd 250bwpd, Natural Shaw 1A-8H 423 bopd after frac SandRidge & Territory Activity Beast 1-27H 27-23n-4e IP 585 bopd 1000 mcfd 2300 bwpd Pablo Energy II LLC 31-22n-4e Ripley 1H-31 Best Mo. Avg-286 bopd C-50.1 MBO 32-22N-3E Gilbert 1H-32 10/26/10 IP 743 bopd 500 mcfd 673 bwpd 8/3/11 IP 137 bopd 164 mcfd 1305 bwpd Calyx Wheeler 14-1H IP 160 bopd 434 mcfd 1780 bwpd on 6/3/11 Spirit Creek 15-1H IP 180 bopd 177 mcfd 1350 bwpd on 6/5/11 State M 16-2H IP 302 bopd 588 mcfd 3314 bwpd CELLC Scout 1H-1 40 bopd, 250 mcfd CELLC Nabhi 1H-22 IP 244 bopd, 562 mcfd, 6210 bwpd Lawco Cline 2-34H WOCT 1/24/11 Vitruvian Page 1-24H RR 5/8/11. Bowling 2-32H >500 bopd 200 mcfd rptd Chaparral Drilling Activity CELLC Elsie 3H-25 Currently 360 bopd 3439 mcfd CELLC Joachim 2H-14 Currently 112 bopd 904 mcfd CELLC Erikson wells

Northern Oklahoma Mississippi Type Curve Comparison IP Dei H Sandridge Energy Mississippi: 263 80 1.5 Cum at 50 Yrs = 406,852 Chesapeake Energy Mississippi: 300 82 1.2 Cum at 50 Yrs = 349,081 CELLC – NOMP West: 291 94 1.3 Cum at 50 Yrs = 271,421 CELLC – NOMP East: 215 94 1.3 Cum at 50 Yrs = 200,449 12

13 Chaparral: A Growing Mid-Continent CO2 EOR Company

Advantages of CO2 EOR  Lower risks than most other oil field projects  Can be deployed faster if the infrastructure is in place  Large reserves associated with its application can be booked  Only 1 in 81 CO2 projects have failed in the last 35 years Most oil companies are exploration-oriented and can be misled by the “unrisked” rates of return present in exploration projects. Acquisitions CO2 EOR Waterflooding Workovers Development Drilling Exploratory Drilling Risk Triangle 14

15 Long Life EOR Assets in Four Key Growth Areas Panhandle Area Permian Basin Central Oklahoma Area Burbank Area  200+ MMBOe Potential Reserves  Low Geologic Risk  Attractive Economics  ROR – 25% to 40%  ROI – 2.5:1 to 3.5:1  Capital Requirements - $75-$125 MM/yr  Long-term growth potential - 20-30% CAGR expected through 2020  405 miles of CO2 Pipelines (net 245) (50 MMcf/D supply)

16 Currently Owned CO2 Development Potential and Infrastructure Total OOIP 3,735 MMBO Primary Production 628 MMBO Secondary Recovery 597 MMBO Tertiary Potential 410 MMBO Net Tertiary Potential 197 MMBO Existing CELLC CO2 Pipelines Existing Third Party CO2 Pipelines Planned CELLC CO2 Pipelines Proposed CELLC CO2 Pipelines Owned Active CO2 fields Owned Potential CO2 fields CO2 Source Locations Coffeyville Fertilizer Plant Koch Fertilizer Plant Agrium Fertilizer Plant Arkalon Ethanol Plant

EOR 2011 Capital Budget 17 Budget by Category ($millions) Infrastructure / Pipelines $42 Drilling 24 Enhancements / CO2 Purchases 27 Total $93  Panhandle Area  Camrick Area $17 MM  Farnsworth Unit 27 MM  NE Hardesty (Non-op) 8 MM  Booker Area 3 MM  Other 1 MM $56 MM  Burbank Area  North Burbank Unit $35 MM  Central Oklahoma  NW Velma Hoxbar $2 MM  Permian  No planned expenditures for 2011 Field Projects Panhandle Area Permian Basin Central Oklahoma Area Burbank Area

PROCESSING RATE: The Key to Improved Rate of Return 18 Hovey Morrow Unit (HMU) Time BO P D 25% hcpv Inj./Yr 10% hcpv Inj./Yr HMU Model: Processing Rate v. Reserve Recovery • CO2 Injection initiated Sep’07 • Processing Rates Average 25% hcpv Inj./Yr

Contracted CO2 Supply 19 Source MMcfCO2/D Serving… Coffeyville 47 Burbank Enid 10 S. Central OK Arkalon 15* Agrium 23* Misc. 5 OBO 100 * Includes future CapEx upgrades Panhandle Area

CO2 Infrastructure & Resource Potential 20 Chaparral CO2 Pipelines Planned Chaparral Pipelines Proposed Chaparral Pipelines Third Party Pipelines Cum. Recovered 1-3 MMBO Cum. Recovered 3-5 MMBO Cum. Recovered 5-10 MMBO Cum. Recovered 10+ MMBO Coffeyville Fertilizer Plant

U.S. Department of Energy – Office of Fossil Energy – Office of Oil and Natural Gas CO2 – EOR Technically Recoverable Resource Potential Basin / Area No. Large Reservoirs Assessed All Reservoirs (Ten Basins / Areas Assessed) OOIP (Billion Barrels) ROIP (Billion Barrels) Technically Recoverable (Billion Barrels) Alaska 34 67.3 45.0 12.4 California 172 83.3 57.3 5.2 Gulf Coast 239 44.4 27.5 6.9 Mid-Continent 222 89.6 65.6 11.8 Illinois & Michigan 154 17.8 11.5 1.5 Permian 207 95.4 61.7 20.8 Rocky Mountains 162 33.6 22.6 4.2 Texas: East & Central 199 109.0 73.6 17.3 Williston 93 13.2 9.5 2.7 Louisiana Offshore 99 28.1 15.7 5.9 Total 1,581 581.7 390.0 88.7  CO2 - EOR is the fastest growing form of Enhanced Oil Recovery in the US  272,109 BOPD in 2010, mostly in Permian Basin and New Mexico  5% of US crude oil production Source: Advanced Resources International, February 2006 Notes: (1)Original oil in place, in all reservoirs in basins / areas (2)Remaining oil in place, in all reservoirs in basins / areas (1) (2) EOR Potential 21

22 North Burbank CO2 Development

23 Burbank Area Potential CO2 Projects Total OOIP 1,163 MMBO Primary Production 239 MMBO Secondary Recovery 211 MMBO Tertiary Potential 119 MMBO Net Tertiary Potential 100 MMBO Burbank Area: Net Potential: 100 MMBoe, 51% of total

BUSINESS PLAN: Economic Indices – Risk/Sensitivity “BURBANK” in Perspective 24 Secondary Development Primary Development B O P D Tertiary Development “Business Plan”

25 Farnsworth Unit CO2 Development

Farnsworth is largest of several CO2 floods in Oklahoma and Texas Panhandle area CO2 injection initiated late 2010 26 Farnsworth Area Map

27 Farnsworth Production Response Actual Budget Forecast YTD Actual + Remaining Forecast 62,859 Bbl

28 Other Developing Drilling Plays

Anadarko Basin - Woodford Shale 29 Woodford Shale Geology  Unconventional Shale Gas Play  NE flank of the Anadarko Basin  Gas and Oil Production  Successful Horizontal Drilling  Depth, Thickness, & Maturity Constraints Chaparral’s Acreage  23,000 (+/-) Net Acres including 2,100 Non-Producing  181 Sections in Play  134 PUD, Probable, & Possible Locations  Potential for 8+ Wells Per Section

West Texas – Delaware Basin 30 Tunstill Acreage Block Haley Acreage Block

Chaparral Energy, LLC Avalon Shale Position 17,000 Net Acres in West and Central Loving County, TX Upper and Lower Avalon Production Surrounding Acreage Block Over 80 Potential Avalon Drill Sites  Oil & NGL Rich Play  High Initial Production  Prime Acreage Position  Large Development Opportunity  Average Well Depth : 12,000 – 12,250 Ft. (MD) Chaparral Energy, LLC TXL 17 #1H (Avalon Horiz) Chaparral Energy, LLC Johnson 20 #1RE Scheduled 1st Quarter 2012 Chaparral Energy, LLC Johnson 32 #1RE Scheduled 1st Quarter 2012 IP: 508 boe/d Cum: 126,250 boe in 11 Mo’s Avg. 377 boe/d past 11 Mo’s IP: 830 boe/d No Avail. Prod. Data IP: 425 boe/d Cum: 96,440 BOE in 9 Mo’s Avg. 411 boe/d past 9 Mo’s IP: 195 boe/d Cum: 151,511 BOE in 15 Mo’s Avg. 348 boe/d past 15 Mo’s IP: 572 boe/d Cum: 67,872 boe in 7 Mo’s Avg. 324 boe/d past 7 Mo’s Chaparral Energy, LLC TXL 3 #1H (Avalon Horiz.) Scheduled 1st Quarter 2012 Bone Spring / Avalon

• Unit’s average 30 day IP + 238 BOE/D • Unit’s average reserves 130 MBOE (76% oil, 14% NGL, 10% gas) • Unit’s average CWC: $2.8 MM Chaparral continues to lease in the play and currently has ~24,000 confirmed net acres in the Emerging Marmaton Play Avg Depth to Marmaton 6600’ Marmaton Vertical Producers Marmaton Horizontal BEAVER LIPSCOMB OCHILTREE CAMRICK BOOKER FWU Panhandle Marmaton

33 More than 700 Million BOE Potential  Near-term + Long-term strategy yields significant value increase  ~ 70% Oil  Near-term focus on NOMP  De-risk play, unlock value  Production growth  Long-term focus on EOR  Low-risk production upside  Long-life, stable production * Woodford, Bone Spring, Avalon, Cleveland Sand, Granite Wash, and Marmaton

34 Financial Overview

Financials 2009 2010 YTD 09/30/2011 Production (MMBoe) 7.6 8.1 6.5 Oil (MMBbls) 3.5 3.7 3.2 Gas (Bcf) 22.6 23.7 16.5 NGL (MMBbls) 0.4 0.4 .5 Revenue Including Cash Settled Derivatives ($MM) $348.0 $448.5 382.4 Lease Operating Expenses $94.2 $106.1 $91.1 Production and Ad Valorem Taxes 20.3 26.5 26.7 General and Administrative Expenses (excludes non- cash deferred comp) 23.7 27.3 26.0 Operating Expenses 138.2 $159.9 $143.8 Interest (Expense) – (includes non-cash amortization) (90.1) (83.6) (72.4) Other Income (Expense) 13.9 (0.8) .4 EBITDA $224 $288 $239 35

Financial Metrics per BOE Production (BOE) / Day LOE / BOE EBITDA / BOE G&A / BOE 19,323 20,926 22,055 23,732 15,000 20,000 25,000 2008 2009 2010 YTD Sep 2011 $17.05 $12.33 $13.18 $14.07 $0.00 $5.00 $10.0 $15.00 $20.00 2008 2009 2010 YTD Sep 2011$3.16 $3.11 $3.72 $4.42 $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 2008 2009 2010 YTD Sep 2011 $39.43 $29.47 $35.56 $36.90 $10.00 $20.00 $30.00 $40.00 $50.00 2008 2009 2010 YTD Sep 2011 36

Operating Statistics 2010 Results 2011 “Revised” Guidance Oil & Gas CAPEX $327 million $320 million Production 8.1 MMBoe 8.6 - 8.9 MMBoe General and Administrative $3.72/Boe $4.25 - $4.75/Boe Lease Operating Expense $13.18/Boe $13.75 - $14.25/Boe 2010 Results and 2011 Guidance 37

Hedge Portfolio Note: 1) Dollars represent average strike price of hedges (includes all derivative instruments) Gas Basis Hedges Price % Gas PDP Nov-Dec 2011 $0.65 62% Jan-Dec 2012 $0.30 43% $7.02 $7.24 $7.34 $69.10 $69.94 $68.40 $10.00 % of Proved Developed Producing Hedged (As of Dec. 1, 2011) $90.46 38 $6.64 $5.06 $5.24 $78.46 $94.08 $102.45 $ 153.00 $110.00 $108.70 $92.25 $121.43 $97.17 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Nov-Dec 2012 2013 % o f P ro v e d D e v e lo p e d P ro d u c in g Oil Collars Oil Swaps Gas Swaps