Exhibit 99-2 NYSE: CHAP Investor Presentation March 2020
Forward Looking and Cautionary Statements 2 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. 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 production 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.
3 Company Overview
Strategy Anchored to Strengths 4 Experienced Flexible Technical Low Cost Management Development Excellence Operator Team Strategy • Extensive experience • Differentiated results • Large HPB position and • Low cost operator developing horizontal due to focus on no long term rig focused on the oil wells in the Mid-Con subsurface and technical commitments or MVC’s window of the Mid-Con • Exceptional track record expertise • Aligning pace of region of meeting or exceeding • Rapidly incorporating development and capital • Constant attention to guidance learnings into near term deployment with performance and cost planning process revenue improvements
What’s New in 2020? 5 CHAP 2020 • Aggressively pursuing further cost Leveraging reductions and Experience efficiency gains • Designed to manage Capital • Extensive technical through current cycle Discipline and operational and position company experience to capture value and New • Aligning capital • Rapid incorporation of opportunities in the program to revenues learnings into future Leadership development plan • Focused on returns • New CEO, new focus on appropriate response to current market
Mid-Con Operator in Oil Window of Anadarko Basin 6 Geologically Advantaged Nemaha Ridge • Core acreage in sweet spot of oil window • Moderately pressured • Distanced from Nemaha Ridge Large Oil Rich Production Base • 29.7 MBoe/d Q4 total production • ~32% Oil (~63% Liquids) Large Acreage Position • Mid-Con: ~210,000 net acres • STACK: ~122,000 net acres • Core: ~102,000 net acres Significant Operational Control in Core Acreage • >80% Held by Production Kingfisher Canadian Garfield • >70% Operatorship . Net acres: ~33,000 . Net acres: ~23,000 . Net acres: ~46,000 • >160 Operated DSU’s . HBP: ~98% . HBP: ~98% . HBP: ~58% . Average Operated WI: 72% . Average Operated WI: 71% . Average Operated WI: 64%
2019 Highlights 7 ~25% ~$1.10 Increase in adjusted EBITDA, a ~$30mm Decline in cash G&A per BOE or ~30% yoy uplift from 2018 decline ~$2.10 ~30 MBoe/d Decline in LOE per BOE or ~30% yoy Sizeable liquids rich (63%) Q4 2019 decline production base ~$15mm In non-core asset sales during the year, with proceeds used for debt paydown
8 Operational Overview
Core Area Subsurface 9 N Play Attributes • Multiple reservoirs proximal to the world-class Woodford source rock • Efficient hydrocarbon stratigraphic trap creates a continuous petroleum system S Garfield Kingfisher Canadian STACK CHESTER MERAMEC MANNING HIGH POROSITY UPPER OSAGE MERAMEC MIDDLE LOWER OSAGE SYCAMORE LOWER WOODFORD HUNTON Landing 1 Meramec 1 Meramec 2 Osage Zones 1 Lower Osage 1 Sycamore/ Lower Meramec N S
Systematic and Flexible Development Approach 10 Chaparral Development Approach Illustrative Spacing Development Assessment • “Fit-for-purpose” approach for each section 80% $40.0 Optimum • Ideal development approach seeks the Development for Optimum 70% Maximum IRR $35.0 optimal balance of IRRs and NPV Development for Maximum PV-10 • Designed to account for variations in factors 60% $30.0 impacting optimal development strategy • Geology 50% $25.0 • Existing wells 40% $20.0 10 ($mm) 10 - • Technology IRR (%) PV Rate of Return % Return of Rate 30% $15.0 • Commodity price 10 10 of Section Development ($MM) - • Geologically driven, collaborative approach 20% $10.0 PV built by a strong culture of continuous learning 10% $5.0 0% $- 2 4 6 8 10 12 14 Wells perWells Section per (Two DSU Benches) IRR PV-10 Less Wells per Section: More Wells per Section: Higher IRR Higher PV-10 Lower PV-10 Lower IRR Current Environment Implies Spacing of Four to Six Meramec/Osage Wells per Section
Detailed Subsurface Data Analysis 11 Enhanced 3D Seismic Imaging Reservoir Enhanced Subsurface Image Attributes • Combination of 3D seismic and well data using Facies Volume stochastic inversion and neural networks Canadian County, OK • Latest high resolution technology Percent Quartz • State of the art logs calibrated with core data • Provides high resolution image of the subsurface Feet ~250 and key reservoir attributes • Facies Percent Clay • Lithology • Porosity Hunton • Brittleness (Fracability) Meramec / Sycamore • Oil in place Woodford • Faults and Fractures Porosity • Continually refined with new data and results Maps Oil-In-Place Faults and Fractures • Detailed analysis performed and applied on a section by section basis Brittleness • Greatly reduces risk in horizontal well placement and spacing development 3 miles 3 miles Differentiating Subsurface and Geoscience Expertise Applied to Development Strategy
Application of Science & Technology 12 Chemical Tracers Finding landing zones, well spacing and frac designs to maximize returns Assess performance of landing zone, fault impacts & well-to-well communication Machine Learning to Microbial DNA Interpret Frac Hits DNA sequencing of microbes from fluid and cuttings to determine geologic source of fluid production. Evaluate vertical connection for Real time identification & quantification development planning Leveraging Technology That Produces Tangible, Actionable Results
Improving Efficiencies – D&C and Cost Structure 13 Avg. Drilling Feet per Day Avg. Completion Stages per Day 1,000 12 900 9 800 6 700 3 FRAC FRAC STAGESPER DAY FEET DRILLED FEETDRILLED PERDAY 600 0 1H18 2H18 1H19 2H19 1H18 2H18 1H19 2H19 LOE per BOE Cash G&A per BOE $14 $6 $12 $5 $10 $4 $8 $3 $ $ BOE / $ $ BOE / $6 $2 $4 $2 $1 $- $- 2017 2018 2019 2017 2018 2019 Increased Efficiencies and Reduced Cost Structure…with More to Come
Recent Spacing Performance in 2020 Focus Areas 14 Canadian Miss1 South Kingfisher Osage2 80,000 80,000 60,000 60,000 40,000 40,000 Cumulative Cumulative BO Cumulative Cumulative BO 20,000 20,000 - - - 100 200 300 400 500 0 60 120 180 240 300 360 Production Days Production Days Canadian Miss - 2020 '19 Activity (5 Sections) South KF Osage - 2020 '19 Activity (4 Sections) • 99% of oil expectations at 290 days • 107% of oil expectations at 270 days • 11 wells in 5 spacing projects with existing parent • 9 wells in 4 spacing projects with existing parent wells wells 1 Cumulative results represent 5 of the 7 spacing developments in 2019 that are comparable to 2020 plan. Scaled to lateral length of 4,800 feet 2 Cumulative results represent 2019 spacing developments that are comparable to 2020 plan. Scaled to lateral length of 4,800 feet
2020 Focus Areas & Economics 15 Canadian Miss South Kingfisher Osage 2020 Focus Areas 50% 50% 40% 40% Kingfisher Focus Area 30% 30% IRR IRR 20% 20% 10% 10% 0% 0% Low EUR Base EUR Low EUR Base EUR $3.4mm (D&C) $4.2mm (D&C) $3.0mm (D&C) $3.8mm (D&C) Canadian IRR1 15% - 43% 14% - 42% Focus Area EUR (MBoe) 862 - 967 547 - 614 EUR Mix 17% Oil (61% Liquids) 31% Oil (66% Liquids) D&C Costs ($mm) $3.4 – $4.2 $3.0 – $3.8 1 IRR range using $45 / $2.25 / 25% for oil, gas, and NGL pricing, respectively
16 Financial Overview
Financial Strategy 17 Capital Discipline • Maintaining flexibility in operated development plan • Operating 2 rigs in Q1 2020 as compared to 4 rigs in Q1 2019 • Allocate capital to high-return areas Balance Sheet • $23 million in cash as of Q4 2019 and $130 million drawn revolver • Reaffirmed $325 million borrowing base in fall 2019 redetermination • Significant capital spend flexibility with no long-term commitments Risk Management • Manage commodity price risk through hedging program • 2020 oil and gas hedges in place averaging over $51 and $2.70, respectively Cash Flow Neutrality • Aggressively pursuing cost reduction and increased efficiency initiatives • Long term goal is cash flow neutrality in a volatile market
Financial Position Position 18 Simple Capital Structure Capitalization Table (4Q19) • No near-term maturities $ in millions Q4-2019 • Revolving credit facility with borrowing base of $325mm Cash 23 Credit Facility 130 • $300 million of senior notes Senior Notes 300 • Sufficient liquidity to fund capital program Other Debt 2 Total Net Debt $409 Stockholders Equity 417 Total Capitalization $827 Net Debt to TTM EBITDA ~2.6x Longer Dated Maturities December December RBL Effective Date RBL Maturity 2017 2018 2019 2020 2021 2022 2023 June July $300mm Senior Notes Issued $300mm Senior Notes Due
2019 Actuals vs. Guidance 19 2020 operating plan remains highly flexible due to our large HBP position, no long term rig contracts or minimum volume commitments and 2020 oil and gas hedges in place averaging over $51 and $2.70, respectively Guidance Actuals 2019 2019 Avg. Production (MBoe/d) 25.0 – 27.0 26.3 Avg. Q4 Production (MBoe/d) 29.7 Capital Expenditures ($mm) $275 - $300 $270 Drilling & Completion $218 - $248 $229 Other Capital1 $48 - $53 $41 Proceeds from Asset Sales ($mm) $5 - $10 $15 Lease Operating Expense ($/boe) $5.00 - $5.50 $5.17 Cash G&A ($/boe) $2.85 - $3.35 $2.63 Continue to Meet or Exceed Expectations 1 Includes enhancements, capitalized G&A, capitalized interest and ARO
Building the Foundation for Future Success 20 Low Cost Operator That Operational Focused on Aligning Delivers on and Financial Controlling Spend to Guidance Flexibility Costs Revenue
21 Appendix
2019 Proved Reserves 22 67% Proved Developed 28% Oil (62% Liquids) (MMBoe) 28% 31.8 34% 1.3 63.4 38% PDP PNP PUD OIL GAS NGL YE ‘19 Total Proved Reserves1 Net Oil Net Gas Net NGL Net % of Total PV – 10 Reserve Category (MMBo) (BCF) (MMBo) (MMBoe) Proved ($mm) PDP 18.0 149.5 20.5 63.4 66% $444 PNP 0.5 2.7 0.4 1.3 1% $11 PUD 8.8 68.6 11.6 31.8 33% $69 Total Proved 27.2 220.8 32.5 96.6 100% $523 Total Including ARO $514 Note: numbers may not add due to rounding 1 At year-end 2019 SEC prices of $55.69/bbl and $2.58/mcf
Non-Core Asset Overview 23 Western Miss Lime Anadarko Basin Mature legacy fields Low-maintenance capital Southern OK Provides free cash flow Net Production1 Net Proved Reserves Area Boe/d % Oil MMBoe2 PV-102 ($mm) Miss Lime 1,717 27% 5.3 $27 Western Anadarko Basin 907 14% 3.0 $13 Southern OK 1,646 57% 8.1 $66 Other 349 14% 0.7 $3 Total 4,619 34% 17.2 $109 Total Including ARO $103 Note: numbers may not add due to rounding 1 2019 actuals 2 At year-end 2019 SEC prices of $55.69/bbl and $2.58/mcf
Commodity Realizations 24 Crude Oil Oil & NGL Realizations as % of WTI 99% 96% 98% • Proximity to numerous markets provides improved $80 100% CHAP net back compared to other basins $70 90% 80% • Crude oil quality meets Oklahoma refining $60 specifications 70% $50 • New trucking terminals and pipeline infrastructure 60% have reduced transportation costs, providing $40 50% 40% better net back at the wellhead $30 44% 37% 30% Realization % $20 26% 20% NGLs WTIAverage Daily Settle $10 10% • Increased pipeline capacity to the Gulf Coast to $0 0% new markets 2017 2018 2019 WTI NGL % Oil % • Increased Gulf Coast demand, with new petrochemical crackers coming online and new export capacity Natural Gas Realizations as % of HH $4.00 100% • Flexibility to reject/recover ethane on majority of 85% 90% operated production for value maximization $3.50 77% 80% $3.00 70% 70% $2.50 Natural Gas 60% $2.00 50% • Increased mainline capacity out of Mid-Con $1.50 40% providing improved basis value 30% Realization % $1.00 20% • New pipeline capacity out of STACK/SCOOP to $0.50 the South and Gulf Coast expected to Average HH Daily Settle 10% $0.00 0% strengthen basin pricing 2017 2018 2019 Henry Hub Gas %
Hedge Summary 25 Hedge Positions1 1Q20 2Q20 3Q20 4Q20 FY 2020 FY 2021 Crude Oil Swaps Hedge Volume (BBL) 504,000 744,000 494,500 531,500 2,274,000 689,300 Average Price ($/BBL) $50.47 $51.99 $50.63 $50.49 $51.01 $46.24 Crude Oil Collars Hedge Volume (BBL) 195,000 195,000 Average Ceiling Price ($/BBL) $66.42 $66.42 Average Floor Price ($/BBL) $55.00 $55.00 Crude Oil Roll Hedge Volume (BBL) 120,000 110,000 90,000 90,000 410,000 150,000 Average Ceiling Price ($/BBL) $0.46 $0.42 $0.30 $0.30 $0.38 $0.30 Natural Gas Swaps Hedge Volume (MMBTU) 2,340,000 2,340,000 1,500,000 1,500,000 7,680,000 Average Price ($/MMBTU) $2.67 $2.67 $2.75 $2.75 2.71 Natural Gas Basis Swaps (PEPL) Hedge Volume (MMBTU) 2,040,000 2,040,000 1,500,000 1,500,000 7,080,000 Average Price ($/MMBTU) ($0.46) ($0.46) ($0.46) ($0.46) ($0.46) NGL Swaps Propane Hedge Volume (BBL) 214,000 140,100 354,100 Propane Average Price ($/BBL) $25.42 $21.56 $23.94 Iso Butane Hedge Volume (BBL) 15,000 11,830 26,830 Iso Butane Average Price ($/BBL) $30.20 $22.26 $26.88 Normal Butane Hedge Volume (BBL) 41,000 41,000 Normal Butane Average Price ($/BBL) $29.53 $29.53 Natural Gasoline Hedge Volume (BBL) 96,000 58,950 154,950 Natural Gasoline Average Price ($/BBL) $47.59 $49.05 $48.15 1 As of December 31, 2019
Reserve and Non-GAAP Information Statement 26 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.
Reconciliations 27 Twelve Months Twelve Months Ended Ended ($ in thousands) December 31, 2019 December 31, 2018 Net (loss) income (468,948) 33,442 Interest expense 22,666 11,383 Income tax (benefit) expense — (77) Depreciation, depletion, and amortization 109,633 87,888 Loss on impairment of oil and gas assets 430,695 20,065 Loss on impairment of other assets 7,188 — Non-cash change in fair value of derivative instruments 40,765 (37,807) Impact of derivative repricing — (5,649) Interest income (6) (12) Stock-based compensation expense 1,583 10,873 Loss (gain) on sale of assets 6 2,582 Loss (gain) on settlement of liabilities subject to — 48 compromise Loss on extinguishment of debt 1,624 — Restructuring, reorganization and other 9,287 2,344 Adjusted EBITDA $154,493 $125,080 ($ in thousands) 2019 Standardized measure of discounted future net cash flows 514,203 Present value of future income tax discounted at 10% — PV-10 value $514,203
Reconciliations 28 Twelve Months Twelve Months Twelve Months Ended Ended Ended ($ in thousands) December 31, 2019 December 31, 2018 December 31, 2017 General and administrative 34,210 38,793 46,460 Less: Stock compensation, gross 2,208 13,402 12,595 Capitalized stock compensation (722) (2,543) (2,812) Severance costs 7,534 362 — Plus: Cash-settled RSUs, net — 19 — Cash G&A $25,190 $27,591 $36,677 Production (MBoe) 9,593 7,490 8,399 Cash G&A per Boe $2.63 $3.68 $4.37
29 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
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