Chaparral Energy Royal Bank of Canada Finance Conference June, 2013
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. 2
3 Company Representatives Joe Evans Chief Financial Officer & Executive Vice President Mark Fischer Chief Executive Officer & President Melinda Conner Corporate Finance Manager
Chaparral Overview Founded in 1988, Based in Oklahoma City Core areas — Mid-Continent (Oklahoma) and Permian Basin (W. Texas) Stable 1P base with large potential upside – 727 MMBoe, R/P 16 years Oil focused: Third largest “oil” producer in Oklahoma (71% oil; 29% gas) – 2012 SEC Reserves (64% oil; 36% gas) – 2013 Production Estimate Growth drivers: Near-term growth potential through drilling ~ 350,000 acres Long-term growth through CO2 EOR – 70 fields Company Statistics 2011 2012 Q1, 2013 Average Production (Boe/d) ~23,700 ~24,910 ~24,930 SEC Proved Reserves (MMBoe) 156.3 146.1 NA SEC Proved Reserves PV-10 ($ in mm) $2,309 $2,069 NA TTM EBITDA ($ mm) $313 $337 $342 4
Operating Areas As of December 31, 2012 (SEC) Core Area Growth Area Acreage Field Offices Headquarters North Texas Reserves: 3.8 MMBoe, 3% of total Production: 0.4 Mboe/d, 2% of total Permian Basin Reserves: 17.1 MMBoe, 12% of total Production: 3.2 MBoe/d, 13% of total Company Total December 2012 proved reserves – 146.1 MMBoe 2012 average daily production – 24.9 MBoe/d Acreage (gross / net): 1,238,747 / 628,564 Val Verde Basin Sabine Uplift Midland Basin Delaware Basin Ouachita Uplift Arkoma Basin Fort Worth Basin Anadarko Woodford Basin OKC Gulf Coast Reserves: 2.0 MMBoe, 1% of total Production: 0.8 MBoe/d, 3% of total Mid-Continent (Anadarko Basin & Central Oklahoma) Reserves: 117.8 MMBoe, 81% of total Production: 19.3 MBoe/d, 78% of total Ark-La-Tex Reserves: 5.4 MMBoe, 4% of total Production: 1.2 MBoe/d, 5% of total 5
Strong Record of Reserve and Production Growth Year-End SEC Reserves (MMBoe) (1) 2003 – 2012 CAGR = 12% Annual Production (MMBoe) 2003 – 2012 CAGR = 15% Chaparral’s reserve replacement ratio averaged 383% per year since 2003 6 Year Oil Gas 2007 $96.01 $6.80 2008 $44.60 $5.62 2009 $61.18 $3.87 2010 $79.43 $4.38 2011 $96.19 $4.11 2012 $94.71 $2.76 1) Reserves as of December 31 for each year calculated using flat SEC pricing per the following: 0 20 40 60 80 100 120 140 160 180 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 51 73 103 151 164 113 142 149 156 146 0 1 2 3 4 5 6 7 8 9 10 2.6 3.2 4.2 5.4 6.8 7.1 7.6 8.1 8.7 9.1 9.6-9.8 *2013B illustrated at midpoint of guidance
2011 to 2012 SEC Reserves Reconciliation 7 Total YTD Proved Volume Reconciliation Volumes in MMBOE Beginning Balance (12/31/2011) 156.3 2012 Production -9.1 Extensions & Discoveries 13.3 Improved Recoveries (EOR) 0.8 Divestitures -3.8 Pricing Revisions -12.0 Other Revisions 0.5 Ending Balance (12/31/2012) 146.1 Negative price revisions due to low natural gas pricing and divestitures reduced year end reserves by ~15.8 mmboe or 11% Product Pricing - SEC 12/31/2011 Price 12/31/2012 Price Difference Difference (%) Oil ($/bbl) 96.19 94.71 -1.48 -1.5% Gas ($/MMBtu) 4.11 2.76 -1.35 -32.8
Current Production Production by Quarter 8 23,278 23,018 26,098 27,223 24,928 - 5,000 10,000 15,000 20,000 25,000 30,000 Q1,2012 Q2,2012 Q3,2012 Q4,2012 Q1,2013 BO E P D Production in the 1th quarter of 2013 decreased 10% over the previous quarter and increased 6% when compared to the 1th Quarter 2012 From 2011 to 2012, estimated liquids production increased by over 15% and gas production declined by approximately 8% Production results reflect the impact of reduced 4th quarter rig count due to front-end loading of capital budgets in 2011 and 2012
Net Debt / EBITDA Liquidity ($mm) Financial Position to Execute Strategy $325 $300 $400 $69 $300 $400 $550 2012 2016 2017 2018 2019 2020 2021 2022 Current Maturity Profile ($mm) 5.6x 4.4x 4.9x 3.2x 3.3x 3.9x 3.9x 2.3x 2.0x 2.0x 0.0x 0.0x 0.1x 0.1x 2007 2008 2009 2010 2011 2012 Q1 2013 Total net debt to EBITDA Net secured debt to EBITDA 9 $88 $55 $77 $429 $407 $505 $458* 2007 2008 2009 2010 2011 2012 Q1 2013 Strong Financial Position 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 3/31/13 was $210mm.
Capital Budget ($mm) Component 2010 2011 2012 2013B 2013B Allocation% Drilling $196 $172 $239 $206 50% EOR 36 86 187 $130 32% Enhancements 39 32 20 $20 5% Acquisitions 41 17 48 $25 6% Other (P&E, Capitalized G&A, etc) 32 28 37 $30 7% Total $344 $336 $531 $411 100% Key Drilling Areas Capital Wells Northern OK Mississippi Horizontal $107 38 Marmaton 40 11 Anadarko Cleveland Sand 20 7 Anadarko Granite Wash 7 3 Other 32 * Total $206 59 10 EOR Field Capital N. Burbank $84 Panhandle Area 42 Other 4 Total $130 99% of 2013 Capital Program is Oil Focused *Includes both Operated and Non-Operated Wells
11 Drilling Resource Potential
Substantial Resource Potential 12 Near-Term 1,697 Unrisked (1,116 Risked) Net Undrilled Wells 146 MMBoe Proved Reserves Plus 581 MMBoe Unproved Resource Potential Conventional Drilling (ROR 50% - 75%) Anadarko Granite Wash Anadarko Cleveland Sand Unconventional Resource Play Drilling (ROR 25% - 75%) Northern Oklahoma Mississippi Play (NOMP) ~ 128,000 acres Panhandle Marmaton ~ 50,000 acres Anadarko Woodford Shale ~ 22,000 acres Bone Spring/Avalon Shale ~ 18,000 acres Long-Term CO2 EOR – 70 fields, 200+ MMBO (ROR 25% - 40%)
Northern Oklahoma Mississippi Play The Northern Oklahoma Mississippi Play (“NOMP”) is a key near–term focus area for Chaparral Chaparral acreage over 128,000 net acres in the NOMP Over 107 MMBoe of potential 800 unrisked drilling well inventory Chaparral Acreage 13 Overview NOMP Asset Map NOMP Well Economics IP Rates: 300 – 600 Boe/d EUR: 300 – 400 MBoe Well Cost: $3.3 – $4.0 million % Oil 40% – 50% IRR: 25% – 60%
NOMP Play Map 14
15 West Noble Area: ~20,500 Net Acres Recent NOMP Acquisition – 14,500 Acres
NOMP Economics • EUR : 352 Mboe • Oil and NGL %: 40-50% • Well cost: $3.3 - $4.0 million Oil • EUR: 154 MBbl • IP (30 Day) 155 BOPD • Initial Decline: 73% • b Factor: 1.5 Gas • EUR: 1,190 MMCF • IP (30 Day) 1,044 MCFD • Initial Decline: 73% • b Factor: 1.5 NGLs(a) • EUR: 67 MBBL • IP (30 Day) 59 BOPD • NGL Yield: 56.3 BBLS/MMCF • Gas Shrink Factor: 72% Type Curve Parameters (a) After processing shrink 16% 21% 29% 38% 47% 58% 0% 10% 20% 30% 40% 50% 60% 70% $60/ $3 $70/ $3.5 $80/ $4 $90/ $4.5 $100/ $5 $110/ $5.5 R O R % Rate of Return versus Wellhead Pricing 16 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 EUR = 352 MBOE OIL BOPD GAS MCFD 6% 4% M C F D 18% 9% 5% % EUR per Year
17 NOMP CORE BOEPD – ALL INTEREST MISS-HZ NORMALIZED AVERAGE VS 352 MBOE TYPE CURVE
Marmaton Shelf Play 18 Lamaster 2H-23 Peak Rate: 579 Boepd Johnston 1H-24 Peak Rate: 606 Boepd Jay 1H-1098 Peak Rate: 265 Boepd Lamaster 1H-23 Peak Rate: 769 Boepd Marmaton Well Economics IP Rates: 150 – 600 Boe/d EUR: 150 – 200 Mboe Well Cost: $3.5 – $4.0 million % Oil 90% IRR: 25% – 70% Chaparral Acreage Marmaton Wells
Marmaton Shelf Activity 19 Chaparral Acreage Marmaton Vertical Wells 2013 Horizontal Wells Current Chaparral Rigs
Marmaton Shelf Economics Type Curve Parameters • EUR : 168 Mboe • Oil and NGL %: 90% • Well cost: $3.5 - $4.0 million Oil • EUR: 157 MBbl • IP (30 Day) 285 BOPD • Initial Decline: 99.7% • b Factor: 1.18 Gas • EUR: 65MMCF • IP (30 Day) 124 MCFD • Initial Decline: 99.7% • b Factor: 1.18 NGLs(a) • EUR: 13 MBBL • IP (30 Day) 29 BOPD • NGL Yield: 195 BBLS/MMCF • Gas Shrink Factor: 60% (a) After processing shrink 14% 29% 45% 69% 93% 138% 0% 20% 40% 60% 80% 100% 120% 140% 160% $60 /$2.5 $70 / $3 $80 / $3.5 $90 /$ 4 $100 / $4.5 $110 / $5 R O R % Rate of Return versus Wellhead Pricing 20 0 20 40 60 80 100 120 140 0 50 100 150 200 250 300 350 400 0 12 24 36 48 60 72 84 96 108 120 132 144 156 168 180 192 204 B OPD PRODUCTION MONTHS MARMATON TYPE CURVES EUR = 168 MBOE OIL BOPD GAS MCFD M C F D 7% 4% 29% 11% 5% % EUR per Year
Marmaton Shelf Results 21
22 Chaparral: A Growing Mid-Continent CO2 EOR Company
# of Active Producer CO2-EOR Projects 31 22 8 7 7 7 6 5 4 4 4 Total 105 Source: April 2012 Oil & Gas Journal Note: Chaparral projects include the North Burbank Unit 23 Chaparral is a Leader in the CO2-EOR Industry Chaparral is the third most active CO2-EOR producer in the U.S.
CO2 EOR Focused Areas 24 CO2 Project Inventory 70 units with 1P, 2P & 3P EOR reserves 9 units with proved reserves 9 units with CO2 injection CO2 Infrastructure – 473 Miles 318 miles of active line 68 miles under construction 87 miles of inactive line CO2 Supply 47 MMscf/D of existing CO2 supply 43 MMscf/D new CO2 supply CO2 Tertiary Recovery Projects Panhandle Area Permian Basin Central Oklahoma Area Burbank Area
Coffeyville Fertilizer Plant Koch Fertilizer Plant Arkalon Ethanol Plant Agrium Fertilizer Plant 25 Current CO2 Infrastructure/Future EOR Potential Total OOIP 3,735 MMBo Primary Production 628 MMBo Secondary Recovery 597 MMBo Tertiary Potential 410 MMBo Net Tertiary Potential 197 MMBo Active CO2 fields CO2 fields in 5 year plan Chaparral Owned Potential CO2 fields CO2 Source Locations Chaparral CO2 Pipelines Third Party CO2 Pipelines
EOR 2013 Capital Budget(1) 26 Budget by Category ($mm) 2012 2013B Infrastructure / Pipelines 105 62 Drilling 20 16 Enhancements / CO2 Purchases 62 52 Total $187 $130 Burbank Area North Burbank Unit $84 Panhandle Area Farnsworth Unit $21 Booker Area 9 Camrick Area 9 NE Hardesty (Non-op) 3 $42 Central Oklahoma NW Velma Hoxbar $4 Permian No planned expenditures - $130 2013 Field Projects ($mm) Panhandle Area Permian Basin Central Oklahoma Area Burbank Area (1) Does not include Capitalized G&A
“Enhanced Oil Recovery” – Active Projects* 27 * NBU included in base beginning October 2013; no EOR expected until Q4’13. Initial NBU Added
Chaparral – Potential EOR Production Growth 0 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 2010 2015 2020 2025 2030 2035 2040 Net Oil Production 28 Additional production from non Business Plan projects meeting corporate economic hurdles Additional CO2 Plan w/ +100 mmcfpd in 2015 at Burbank Business Plan w/ 95 mmcfpd in 2015 Business Plan Add C02 Others
29 North Burbank CO2 Development
North Burbank Unit – Overview Chaparral’s North Burbank Unit is its largest EOR field and CO2 injection into the North Burbank Unit started in June 2013 Chaparral anticipates that it will spend $800 million associated with this EOR project throughout the life of the field 30 Burbank Area: Net Potential: 100 MMBoe, 51% of total Total OOIP 1,163 MMBbls Primary Production 239 MMBbls Secondary Recovery 211 MMBbls Tertiary Potential 119 MMBbls Net Tertiary Potential 100 MMBbls
31 Burbank in Perspective Secondary Development Primary Development Ne t B O P D Tertiary Development “Waterflood” +12000 BOPD “CO2 EOR”
32 May 2012 Average pressure 1405 psia Ph-I Vicinity North Burbank Unit – Achieved Miscibility Pressure in Phase 1 June 2012 1438 Jul 1461 August 2012 1492 September 2012 1553 October 2012 161 November 162 psia December 1650 February 2013 1704 March 2013 1736 April 3 174
Coffeyville CO2 System 33 The Coffeyville CO2 System $110 million of total capital expenditures 23,500 HP compression facility 68.3-mile 8-inch pipeline with potential capacity of approximately 60 MMcf/d. CO2 is sourced from the CVR Partners fertilizer plant in Coffeyville, KS. Commenced CO2 injection in June 2013 Oklahoma Kansas Coffeyville CO2 System Asset Map Panhandle CO2 System Coffeyville CO2 System
34 COFFEYVILLE CO2 PLANT – PHASE 1 COMPLETE
35 COFFEYVILLE CO2 PLANT
36 COFFEYVILLE CO2 PLANT
37 COFFEYVILLE CO2 PLANT
38 COFFEYVILLE CO2 PIPELINE: TRENCHING RIGHT OF WAY Digging the trench in preparation for laying the pipeline ~68 miles; Coffeyville, KS to Shidler, OK
Operating Team - Injection into North Burbank – June 2013 39
40 Other CO2 Injection Projects
G ro ss B o e /d G ro ss C O 2 P u rc h ases, M c f/ d Secondary Development Primary Development Tertiary Development Camrick CO2–EOR Flood 41 +1500 BOPD
42 North Perryton CO2–EOR Flood G ro ss B o e /d G ro ss C O 2 P u rc h ases, M c f/ d Secondary Development Primary Development Tertiary Development +600 BOPD
43 Primary Development Secondary Development Tertiary Development Booker Area CO2–EOR Flood G ro ss B o e /d G ro ss C O 2 P u rc h ases, M c f/ d +1100 BOPD
44 Primary Development Tertiary Development Secondary Development Farnsworth Area CO2–EOR Flood (West Side Only) Gr o ss B o e /d G ro ss C O 2 P u rc h ases, M c f/ d +2900 BOPD
45 Potential in Excess of 727 MMBoe Near-term + Long-term strategy yields significant value increase ~ 70% Oil Near-term focus on NOMP De-risk play, unlock value Production growth Long-term focus on EOR Low-risk production upside Long-life, stable production * Woodford, Bone Spring, Avalon, Cleveland Sand, and Granite Wash (1) 727 136 200 138 107 146 0 100 200 300 400 500 600 700 800 2012 Proved Reserves +NOMP and Marmaton Drilling Potential +EOR Potential + Developing Emerging Plays* +Other Drilling =Total Potential
Financial Overview 46
47 Financial Summary 2010 2011 2012 1Q, 2013 Price Oil & NGL – Wellhead ($/Bbl) $74.53 $87.52 $78.65 $78.16 Gas – Wellhead ($/Mcf) $4.36 $4.08 $2.64 $3.14 Production (MMBoe) 8.1 8.7 9.1 2.2 Oil & NGL (MMBbls) 4.0 5.0 5.8 1.4 Gas (Bcf) 23.7 21.6 19.8 4.8 Financial Data ($mm) Operating Expenses: Lease Operating Expenses $106.1 $121.4 $131.0 $34.0 Production and Ad Valorem Taxes 26.5 34.3 32.0 7.9 General and Administrative Expenses (excludes noncash deferred comp) 27.3 38.3 46.7 12.7 Interest Expense $81.4 $96.7 $98.4 $24.3 EBITDA $288 $313 $337 $83 Total Capital Expenditures $344 $336 $531 $129
Financial Metrics per Boe Production (Boe) / Day LOE / Boe EBITDA / Boe G&A / Boe 48 20,926 22,055 23,712 24,912 24,928 0 10,000 20,000 30,000 2009 2010 2011 2012 1Q, 2013 $12.32 $13.18 $14.03 $14.37 $15.15 $0 $5 $10 $15 $20 2009 2010 2011 2012 1Q,2013 $3.11 $3.72 $4.86 $5.46 $6.25 $0 $2 $4 $6 $8 2009 2010 2011 2012 1Q,2013 $29.47 $35.56 $35.98 $37.03 $37.73 $0 $10 $20 $30 $40 2009 2010 2011 2012 1Q, 2013
Operating Statistics 2013 Guidance Capital Expenditures $410 - $420 million Production 9.6 - 9.8 MMBoe General and Administrative $5.50 - $6.00/Boe Lease Operating Expense $14.25 - $14.75/Boe 2013 Guidance 49
50 Hedge Portfolio : % of TP Reserves (As of June 3, 2013) Note: Dollars represent average strike price of hedges (includes all derivative instruments) Gas Basis Hedges YR Price % TP ’13 $ 0.20 78% ’14 $ 0.22 68%
Question & Answer 51
