Investor Presentation November 2019 NYSE: CHAP 0
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 that 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; availability of sufficient cash flow and liquidity 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 at attractive prices; ability to replace reserves and efficiently develop current reserves; geological complexity of targeted formations; reservoir depletion; 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 discrete 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, please refer to the appendix. NYSE: CHAP 1
Company Overview NYSE: CHAP 2
Chaparral Story Expectations to be cash flow neutral in 2020 High-growth, pure-play STACK/Merge oil company • 26.2 MBoe/d Q3 2019 total production • 21.5 MBoe/d Q3 2019 STACK production Premier, contiguous acreage position STACK • 129,000 acres in world-class STACK Play • Primarily in black oil, normal pressure window in Kingfisher, Garfield and Canadian counties Large resource base with deep inventory • 2018 proved reserves of 94.8 MMBoe, a 35% increase from 2017, adjusted for 2018 divestitures Merge • 2018 STACK proved reserves increased 50% compared to 2017 Average Average STACK Held By Highly efficient, low-cost STACK assets County Operated Non-Operated Acreage Production WI WI • $18.61/Boe YTD Q3 2019 STACK cash margins Kingfisher ~33,000 ~98% 72% 16% • $4.21/Boe YTD Q3 2019 STACK LOE cost Canadian ~23,000 ~98% 66% 15% Garfield ~53,000 ~50% 64% 19% Flexible capital structure Major ~6,000 ~100% 52% 16% • No long-term maturities until December 2022 Other ~13,000 ~100% 51% 10% NYSE: CHAP 3
Recent Chaparral Highlights • Recorded STACK production growth of: • 37% Q3 2018 to Q3 2019 • 49% YTD 2018 to YTD 2019 • Increased Adjusted EBITDA by: • 4% Q3 2018 to Q3 2019 (8% increase excluding 2018 divestitures) Despite average WTI prices and NGL realizations declining 19% & 52%, respectively • 19% YTD 2018 to YTD 2019 (26% increase excluding 2018 divestitures) Despite average WTI prices and NGL realizations declining 15% & 40%, respectively • Reduced full year guidance for Capex, LOE & G&A, while reaffirming full year production guidance • Reduced $18mm of debt in Q3 through building sale and elimination of compressor leases • Implemented proactive G&A cost reduction initiatives, expecting annualized reductions of approximately 20% to 25% Operated Meramec/Osage Spacing Program Performance Above Type Curve Average Gross Average Type Curve Target Lateral IP-302 Liquids Wells1 WI IP-303 Length Meramec 28 79% 4,901 feet 943 74% 747 Osage 18 85% 4,937 feet 621 80% 599 1 Represents operated full and partial spacing program wells 2 IP 30s represent the gross three-phase, peak 30-day production rate in Boe/d and are scaled to type curve lateral length of 4,800 feet 3 Represents the average IP 30s in Boe/d of the STACK Meramec and Merge Miss for Meramec and Lower Osage for Osage NYSE: CHAP 4
2019 Strategy PURE-PLAY • Accelerate development in Canadian County Merge STACK/MERGE • Define optimal spacing across de-risked acreage COMPANY • Continue operated delineation and development of acreage position RETURNS • Focus exclusively on maximizing stakeholder value FOCUSED • Achieve excellent returns from STACK/Merge drilling opportunities • Deliver safe, repeatable results and drive down costs TECHNICAL EXCELLENCE • Employ leading drilling and completion techniques • Improve operations, costs and returns with continuous learning • Protect balance sheet to execute strategy FLEXIBLE CAPITAL STRUCTURE • Provide sufficient liquidity through cash flow, hedging, borrowing capacity, and non-core asset sales NYSE: CHAP 5
2019 Updated Guidance FY 2019 FY 2019 Reduced Capital Guidance Original Updated • Reducing midpoint of capital guidance by 6% Guidance Guidance from original guidance Production (MBoe/d) Total Company 25.0 - 27.0 25.0 - 27.0 • Reduced Operated rigs from 3 to 2 in October Q4 Total Company 27.5 - 29.0 • Allocate ~85% of total capital to D&C in higher STACK 21.0 - 23.0 21.0 - 23.0 return areas Q4 STACK 23.0 - 24.5 • Operated D&C by county Capital ($mm) • ~55% Canadian County Operated D&C $210 - $225 $210 - $220 • ~35% Kingfisher County Non-Operated D&C $17.5 - $22.5 $7.5 - $12.5 • ~10% in Garfield County Lease Acquisitions $12.5 - $17.5 $7.5 - $12.5 Other Capital1 $35 $35 Reduced Expense Guidance Total CAPEX $275 - $300 $260 - $280 • Reduced STACK LOE $/Boe midpoint by ~4% Proceeds from Asset Sales $5 - $10 $14+ • Reduced cash G&A expenses $/Boe midpoint by ~11% Expenses ($/Boe) LOE $5.00 - $5.50 $4.90 - $5.40 Re-affirming Production Guidance STACK LOE $3.75 - $4.25 $3.60 - $4.10 Cash G&A $2.85 - $3.35 $2.50 - $3.00 • Maintaining full year production guidance while 1 Includes enhancements, capitalized G&A, capitalized interest and ARO lowering both capital and expense guidance Reducing Capital And Operating Expense Guidance While Maintaining Production NYSE: CHAP 6
Operational Overview NYSE: CHAP 7
Continuous Petroleum System STACK/Merge Attributes N • Stacked reservoirs proximal to the world-class Woodford source rock • Efficient hydrocarbon stratigraphic trap creates a continuous petroleum STACK system • Merge represents intersection of historical SCOOP/STACK Play Merge outlines S Garfield Kingfisher Canadian STACK Merge NYSE: CHAP N S 8
Systematic and Flexible Development Approach Illustrative Spacing Development Assessment Chaparral Development Approach Optimum • Ideal development approach seeks the Development for optimal balance of IRRs and NPV Maximum IRR Optimum 80% Development for $40.0 • In current commodity pricing and capital Maximum PV-10 70% $35.0 markets environment, development approach 60% $30.0 focused on maximizing IRR 50% $25.0 • Geologically driven, collaborative approach 10 ($mm) 10 40% $20.0- built by a strong culture of continuous IRR IRR (%) learning 30% $15.0PV 20%% Return of Rate $10.0 • “Fit-for-purpose” approach designed to account for variations in primary factors 10% $5.0 10 of Section Development ($MM) - impacting optimal DSU development strategy 0% $- PV 2 4 Wells6 per8 DSU10 12 14 Wells per Section (Two Benches) IRR PV-10 Less Wells per Section: More Wells per Section: Higher IRR Higher PV-10 Lower PV-10 Lower IRR Primary factors impacting optimal number of wells developed per DSU Existing Business Environment • Geology • Commodity Price Currently Indicates Four To Eight • Parent wells • Capital Markets • Technology Meramec/Osage Wells Per Section NYSE: CHAP 9
Canadian County Foraker – Well Performance Merge Miss Performance (9-well average) Woodford Performance (2-well average) • 230% of oil type curve at 30 days • 138% of oil type curve at 30 days • 195% of oil type curve at 60 days • 120% of oil type curve at 60 days • 120% of oil type curve at 210 days • 89% of oil type curve at 210 days • Frac and spacing design create significant oil • Frac and spacing design create early oil outperformance through 210 days and higher oil outperformance declines • Economic returns slightly below expectations • Economic returns meeting expectations Foraker Cumulative Oil vs. Type Curve1 50,000 Merge Miss 120% of Type Curve at 210 days 40,000 30,000 Woodford 89% of Type Curve at 210 days 20,000 Cumulative Cumulative BO 10,000 0 0 50 100 150 200 250 Production Days Merge Miss Avg (9 Wells) Merge Miss TC S. Woodford Avg (2 Wells) South Woodford TC Meramec Well Results Continue to Outperform NYSE: CHAP 1Cumulative results are scaled to type curve lateral length of 4,800 feet 10
Canadian County Spacing Tests 3,000’ Upper Meramec 200’ 1,500’ 1,500’ 1,500’ Lower Meramec/Sycamore Woodford Greenback Greenback • Meramec 6-well spacing test in undeveloped section • Estimated first sales in Q1 2020 Foraker • Meramec 9-well spacing test and Woodford 2-well partial spacing test in undeveloped section • First sales in late March/early April of 2019 Denali • Meramec 3-well partial spacing test in undeveloped section • First sales in Q3 2018 NYSE: CHAP 11
Recent Spacing Program Performance Canadian County Merge Miss • 111% of oil type curve at 150 days (16-well average) • 1 full section development spacing project without a parent well • 3 spacing projects with existing parent wells Kingfisher County Osage • 96% of oil type curve at 150 days (15-well average) • 7 spacing projects with existing parent wells Merge Miss Oil vs. Type Curve1 Osage Oil vs. Type Curve1 50,000 50,000 40,000 40,000 30,000 30,000 20,000 20,000 Cumulative Cumulative BO Cumulative Cumulative BO 10,000 10,000 - - 0 50 100 150 200 250 0 50 100 150 200 250 Production Days Production Days Merge Miss TC 16 Well Avg. Lower Osage TC 15 Well Avg. Existing Business Environment Currently Indicates Four To Eight Meramec/Osage Wells Per Section 1 Cumulative results represent 2019 spacing wells (Osage excludes one well due to mechanical issue) scaled to type curve lateral length of 4,800 feet NYSE: CHAP 12
STACK/Merge Overview STACK/Merge Production 25 24.5 23.0 23.0 20 21.0 15 14.5 MBoe/d 10 9.5 5 7.3 0 2016 2017 2018 FY 2019E STACK Production Guidance Range Q4 2019 Guidance (Low) Q4 2019 Guidance (High) Chaparral STACK/Merge Position • 129,000 net acres • 184 operated horizontal wells as of Q3 2019 Strong Execution and Positive Well Performance Driving Production Growth 1 Based on midpoint of 2019 production guidance NYSE: CHAP 13
Drilling and Completions – Increased Efficiencies Reduction in current average Osage & Merge Miss well costs to $3.5 - $4.0 million • Represents a 15% - 20% reduction in from 2018 results Further well cost reduction expected in 2020 to $3.4 - $3.8 million • Lower than offset operators’ recent AFEs by ~20% - 30% Drilling Completions Avg. Feet/day Avg. Stages/day 9 900 8 7 6 600 5 4 300 3 2 Feet Drilled Feet Drilled per Day Frac Stages per Day 1 0 0 1H18 2H18 YTD19 1H18 2H18 YTD19 Faster Cycles Lower Cost Higher Returns Best-in-Class STACK/Merge Operator NYSE: CHAP 14
Financial Overview NYSE: CHAP 15
Financial Strategy �� Expectations to be cash flow neutral in 2020 • Maintain balance sheet strength • Significant capital spend flexibility with no long-term commitments • Reduced ~$18 million of debt in Q3 through sale of corporate headquarters and elimination of CO2 compressor leases • Development plan funding available due to ample liquidity • $22 million in cash as of Q3 2019 plus $110 million drawn revolver • Reaffirmed $325 million borrowing base in fall 2019 redetermination • Allocate capital based on strategic and rate-of-return priorities • Allocate capital to high-return STACK/Merge assets • Reduced operated rig count to 2 rigs in Q4 2019 • Maintaining flexibility in operated development plan (entering 2020 with 2 rigs) • 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: CHAP 16
Financial Position and Liquidity Highlights ChaparralChaparral Net DebtDebt • $325 million borrowing base ($ in millions) reaffirmed in fall 2019 Q3 2019 redetermination Cash and Cash Equivalents $22 • Eliminated ~$18 million of Other Revolving Credit Facility due Dec. 2022 $110 Debt in Q3 2019 Other Debt $2 • Sufficient liquidity to fund capital Senior Notes $300 program Total Debt $412 • No maturities until 2022 Net Debt $390 Borrowing Base Amount $325 Chaparral Debt Maturity Schedule $500 $400 $325 $300 $300 No maturities until 2022 $200 Debt ($mm) Debt $100 $- 2019 2020 2021 2022 2023 2024 2025 2025+ Senior Notes Drawn Revolver Undrawn Revolver NYSE: CHAP 17
Why Chaparral? Experienced Management with Excellent Track Record Best in Class, Pure- Flexible Capital play STACK/Merge Structure Operations 2020 Cash Flow Neutrality NYSE: CHAP 18
Appendix NYSE: CHAP 19
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 • Majority of oil marketed via truck and currently five sections on pipe Crude Pipelines Cushing Hub Centurion Pipeline Plains Pipeline Glass Mountain Pipeline Magellan Pipeline Great Salt Plains Pipeline Velocity Midstream Central OK Pipeline Refinery Phillips Pipeline NYSE: CHAP 20
Natural Gas & NGL Marketing Natural Gas and NGL • Midstream super system, with multiple plants and residue outlets • Residue and NGL agreements with midstream operators who have firm transportation • Approximately 55/45 NGL markets and pricing split between Mt. Belvieu and Conway • Incremental 1.4 Bcf/d of residue capacity to Gulf Coast markets expected in Q1 2020 (Midship) NYSE: CHAP 21
Commodity Realizations Oil & NGL Realizations as % of WTI Crude Oil Differentials 96% 99% 98% $80 93% 100% • Proximity to numerous markets provides better CHAP $70 90% net back compared to other basins 80% $60 • STACK crude oil quality meets Oklahoma refineries 70% $50 specification 60% • New trucking terminals and pipeline infrastructure $40 50% $30 40% have reduced transportation costs, providing better net 44% 30% back at the wellhead $20 35% 37% %Realizations as 20% WTI Average WTI Average Settle Daily 26% $10 10% $0 0% NGL Differentials 2016 2017 2018 YTD 2019 WTI NGL % Oil % • Increased pipeline capacity to the Gulf Coast to new markets • Increased Gulf Coast demand, with new petrochemical Natural Gas Realizations as % of HH crackers coming online and new export capacity $4.00 87% 100% • Flexibility to reject/recover ethane on majority of 85% $3.50 77% operated production for value maximization 74% 80% $3.00 Natural Gas Differentials $2.50 60% $2.00 • Increased mainline capacity out of STACK/SCOOP $1.50 40% providing improved basis value $1.00 HH Average HH Average Daily Settle 20% • New pipeline capacity out of STACK/SCOOP to South $0.50 Realizations % as and Gulf Coast will provide price strength for the basin $0.00 0% 2016 2017 2018 YTD 2019 Henry Hub Gas % NYSE: CHAP 22
Hedging Summary Hedge Positions1 Q4 2019 2020 2021 Crude Oil Swaps Hedge Volume (BBL) 687,400 2,274,000 689,300 Average Price ($/BBL) $55.90 $51.01 $46.24 Crude Oil Collars Hedge Volume (BBL) 195,000 Average Ceiling Price ($/BBL) $66.42 Average Floor Price ($/BBL) $55.00 Crude Oil Roll Hedge Volume (BBL) 120,000 410,000 150,000 Average Ceiling Price ($/BBL) $0.46 $0.38 $0.30 Natural Gas Swaps Hedge Volume (MMBTU) 3,977,200 7,680,000 Average Price ($/MMBTU) $2.85 $2.70 Natural Gas Basis Swaps (PEPL) Hedge Volume (MMBTU) 3,977,200 7,080,000 Average Price ($/MMBTU) ($0.51) ($0.46) NGL Swaps Propane Hedge Volume (BBL) 218,000 354,100 Propane Average Price ($/BBL) $25.62 $23.94 Iso Butane Hedge Volume (BBL) 15,000 26,830 Iso Butane Average Price ($/BBL) $30.24 $26.88 Normal Butane Hedge Volume (BBL) 42,000 41,000 Normal Butane Average Price ($/BBL) $29.40 $29.40 Natural Gasoline Hedge Volume (BBL) 100,000 154,950 Natural Gasoline Average Price ($/BBL) $47.46 $48.30 1 As of October 31, 2019 NYSE: CHAP 23
Year-End 2018 Proved Reserves Grew STACK year-end 2018 reserves by 50% Replaced 519% of 2018 STACK production at $7.80/Boe F&D cost 94.8 MMBoe of Reserves1 34% Oil, 61% Liquids Reserves by Area 1.9 27% 34% 53.6 74.1 20.7 39.3 39% PDP PDNP PUD OIL GAS NGL STACK OTHER YE ‘18 Proved YE ‘18 Total Proved Reserves Reserves PV-101 Reserve Net Oil Net Gas Net NGL Net % of Total SEC Category (MMBo) (BCF) (MMBo) (MMBoe) Proved Pricing1 PDP 17.3 131.3 14.4 53.6 57% 517.1 PNP 0.7 4.1 0.5 1.9 2% 23.2 PUD 14.2 84.8 11.0 39.3 41% 154.1 Total Proved 32.3 220.2 25.8 94.8 100% 694.4 STACK 23.3 173.0 22.0 74.1 78% 519.5 OTHER 9.0 47.3 3.8 20.7 22% 174.9 Total Proved 32.3 220.2 25.8 94.8 100% 694.4 Total Proved Inc. 32.3 220.2 25.8 94.8 100% 686.4 ARO 1 At year-end 2018 SEC prices of $65.56 and $3.10 Note: Numbers may not add due to rounding NYSE: CHAP 24
Non-Core Legacy Asset Overview • Mature legacy fields • Low-maintenance capital • Provides free cash flow to fuel STACK/Merge growth • Potential strategic alternatives Net Production1 Gross Margin1 Net Proved Reserves Area Boe/d % Oil $/Boe MMBoe2 PV-102 ($mm) Miss Lime 1,788 27% $12.79 7.4 $53.2 Western Anadarko Basin 909 13% $6.50 4.6 $28.1 Southern OK 1,639 56% $16.24 7.8 $87.1 Other 344 15% $3.23 0.9 $6.5 TOTAL 4,681 34% $12.26 20.7 $174.9 TOTAL Incl. ARO $170.2 1 YTD Q3 2019 actuals 2 At year-end 2018 SEC prices of $65.56 and $3.10 NYSE: CHAP 25
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 26
Reconciliations Three Months Three Months Ended Ended (in thousands) September 30, 2019 September 30, 2018 Net (loss) income $ (130,935) $ (12,068) Interest expense 5,994 4,205 Depreciation, depletion, and amortization 28,021 22,252 Loss on impairment of oil and gas assets 147,686 — Non-cash change in fair value of derivative instruments (18,718) 16,804 Impact of derivative repricing — (1,698) Interest income (2) (7) Stock-based compensation expense 705 2,304 Loss (gain) on sale of assets (141) 2,024 Loss on extinguishment of debt 1,624 — Restructuring, reorganization and other 1,587 493 Adjusted EBITDA $ $35,821 $ 34,309 (in thousands) 2018 Standardized measure of discounted future net cash flows $686,366 Present value of future income tax discounted at 10% — PV-10 value $686,366 NYSE: CHAP 27
Reconciliations STACK Drillbit F&D and Reserve Replacement 2017 Metrics 2018 Metrics Calculation Total Company Production (MBoe) 8,399 7,490 STACK Production (MBoe) 3,464 5,279 (A) Proved Reserves (MBoe) Total Company Proved Reserves 76,827 94,807 STACK Extensions and Discoveries 20,927 27,406 (B) STACK Revisions 597 623 (C) (excluding price revisions) Capital Costs Incurred (in thousands) Total Company $212,505 $341,018 Development & Exploration Costs $174,994 $218,709 (D) STACK Reserve Replacement 604% 519% (B)/(A) STACK Drillbit F&D $8.13 $7.80 (D)/(B+C) NYSE: CHAP 28
Contact Information Chaparral Energy, Inc. 701 Cedar Lake Boulevard Oklahoma City, OK 73114 Investors Scott Pittman Chief Financial Officer investor.relations@chaparralenergy.com 405-426-6700 NYSE: CHAP 29
ENERGIZING America’s Heartland NYSE: CHAP chaparralenergy.com NYSE: CHAP 30