Investor Presentation August 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, ability to improve our financial results and profitability following emergence from bankruptcy, availability of sufficient cash flow 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, ability to replace reserves and efficiently develop current reserves 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 High-growth, pure-play STACK/Merge oil company • 28.3 MBoe/d Q2 2019 total production • 23.8 MBoe/d Q2 2019 STACK production Premier, contiguous acreage position • 130,000 acres in world-class STACK Play STACK • 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 Highly efficient, low-cost STACK assets Average Average STACK Held By County Operated Non-Operated Acreage Production • $20.50/Boe Q2 2019 STACK cash margins WI WI • $3.90/Boe Q2 2019 STACK LOE cost Kingfisher ~34,000 ~98% 72% 16% Canadian ~23,000 ~99% 66% 15% Garfield ~54,000 ~49% 64% 19% Strong balance sheet 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: • 50% Q1 2019 to Q2 2019 • 80% Q2 2018 to Q2 2019 • Increased Adjusted EBITDA by: • 54% Q1 2019 to Q2 2019 • 62% Q2 2018 to Q2 2019 • Reduced full year guidance for Capex, LOE & G&A, while reaffirming full year production guidance • Implemented proactive G&A cost reduction initiatives, expecting annualized reductions of approximately 20% to 25% • Lowered average expected well costs an average of 15% - 20% from 2018 average • Achieved first sales on 28 gross wells in Q2 2019, compared to 12 gross wells in Q1 2019 • Continued outperformance from Foraker through 120 days of initial production Operated Meramec/Osage Spacing Program Performance Above Type Curve Average Type Curve Gross Wells1 Average WI IP-302 Liquids Lateral Length IP-303 32 79% 4,899 feet 937 75% 697 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 NYSE: CHAP 3 Represents the average gross three-phase, peak 30-day production rate in Boe/d of the STACK Meramec, Lower Osage and Merge Miss type curves 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 STRONG, FLEXIBLE • Protect strong balance sheet to execute strategy CAPITAL • Provide sufficient liquidity through cash flow, hedging, borrowing STRUCTURE capacity, non-core asset sales and access to capital markets NYSE: CHAP 5
2019 Updated Guidance FY 2019 FY 2019 Reduced Capital Guidance Previous Updated • Maintaining capital discipline in volatile Guidance Guidance commodity environment Production (MBoe/d) Total Company 25.0 - 27.0 25.0 - 27.0 • Allocate ~85% of total capital to D&C in higher Q3 Total Company 26.0 - 27.5 return areas STACK 21.0 - 23.0 21.0 - 23.0 • Operated D&C by county Q3 STACK 21.5 - 23.0 • ~50% Canadian County Capital ($mm) • ~40% Kingfisher County Operated D&C $210 - $225 $210 - $225 • ~10% in Garfield County Non-Operated D&C $17.5 - $22.5 $7.5 - $12.5 Lease Acquisitions $12.5 - $17.5 $7.5 - $12.5 Reduced Expense Guidance Other Capital1 $35 $35 • Reducing STACK LOE $/Boe midpoint by ~4% Total CAPEX $275 - $300 $260 - $285 • Reducing cash G&A expenses $/Boe midpoint Proceeds from Asset Sales $5 - $10 $5 - $10 by ~11% Expenses ($/Boe) Re-affirming Production Guidance LOE $5.00 - $5.50 $4.90 - $5.40 STACK LOE $3.75 - $4.25 $3.60 - $4.10 • Maintaining full year production guidance while lowering both capital and expense guidance Cash G&A $2.85 - $3.35 $2.50 - $3.00 1 Includes enhancements, capitalized G&A, capitalized interest and ARO Reducing Capital And Operating Expense Guidance While Maintaining Production NYSE: CHAP 6
Operational Overview NYSE: CHAP 7
Oil Price Breakevens for U.S. Shale Plays $55 $50 $45 $40 $35 $30 Eagle Ford Northern STACK Southern Southern SCOOP Northern Bakken Eagle Ford Niobrara (Oil) Delaware Midland Delaware Midland (Gas & Cond.) Source: Credit Suisse Equity Research, U.S. Exploration & Production, November 2018 The STACK Continues To Be One Of The Premier Low-cost, High-margin Plays In The U.S. NYSE: CHAP 8
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 • Play attributes are identical – only rock thickness and GOR vary Merge • Merge represents intersection of historical SCOOP/STACK Play S outlines Garfield Kingfisher Canadian STACK Merge NYSE: CHAP N S 9
Strong Culture of Continuous Learning • Science and technology driven collaborative approach • Process of continuous improvement drives results Science Learnings Technology Results Execution Key Spacing Principals • Development design strives for balance of maximum ROR and NPV • Targeting/well density • Earth model derived from 3D seismic • Frac design for enhanced near wellbore SRV • Manage parent well communication risk • Frac efficiency diagnostics for continuous learning NYSE: CHAP 10
Systematic Approach to Spacing Development Canadian / Kingfisher Recent Developments • Initial oil production outperformance • Full and partial section Merge Miss, Osage and Meramec developments • Partial section Woodford development • Targeting undeveloped and developed sections • Minimal Merge Miss and Osage inter-well communication • Testing “Come & Go” concept On the Horizon Non-Operated Future Development • 16 spacing tests • Merge Miss / Osage focused program • Learn from others • Incorporate additional full section • Minimal capital exposure developments • Incorporate “Come & Go” learnings Optimized Development Plan Initial Indications Of Six To Eight Meramec/Osage Wells Per Section NYSE: CHAP 11
Canadian County Foraker Spacing Test Upper Meramec Lower Meramec/Sycamore Foraker Woodford • Testing full undeveloped section in Meramec (9 wells) and partial section Woodford (2 wells) spacing test • 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 12
Canadian County Foraker – Well Performance Merge Miss Outperformance • 148% of oil type curve at 120 days (9-well average) Woodford Outperformance • 101% of oil type curve at 120 days (2-well average) Foraker Cumulative Oil vs. Type Curve1 45,000 40,000 Merge Miss 148% of Type 35,000 Curve at 120 days 30,000 25,000 20,000 Woodford 101% of Type 15,000 Curve at 120 days Cumulative BO Cumulative 10,000 5,000 - 0 50 100 150 Production Days Merge Miss Avg (9 Wells) Merge Miss TC S. Woodford Avg (2 Wells) S. Woodford TC Meramec and Woodford Well Results Continue to Outperform NYSE: CHAP 1Cumulative results are scaled to type curve lateral length of 4,800 feet 13
Recent Spacing Program Performance Type curve IRRs: >50%* (initial well results materially exceeding type curve) Canadian County Merge Miss Outperformance • 147% of oil type curve at 60 days (15-well average) • 1 full section development spacing project without a parent well • 2 partial spacing projects with existing parent wells Kingfisher County Osage/Meramec Outperformance • 122% of oil type curve at 60 days (6-well average) • 2 partial spacing projects with existing parent wells Canadian Oil vs. Type Curve1 Kingfisher Oil vs. Type Curve1 45,000 45,000 40,000 40,000 35,000 35,000 30,000 30,000 25,000 25,000 20,000 20,000 15,000 15,000 Cumulative Cumulative BO Cumulative Cumulative BO 10,000 10,000 5,000 5,000 0 0 0 50 100 150 0 50 100 150 Production Days Production Days Merge Miss TC 15 Well Avg. STACK - Osage/Meramec TC 6 Well Avg. Initial Indications Of Six To Eight Meramec/Osage Wells Per Section * At July 31, 2019 NYMEX prices; five-year average prices of $54.16 and $2.57 NYSE: CHAP 1 Cumulative results are scaled to type curve lateral length of 4,800 feet 14
STACK/Merge Overview STACK/Merge Production 25 23.0 23.0 21.5 20 21.0 15 14.5 MBoe/d 10 9.5 5 7.3 0 2016 2017 2018 FY 2019E STACK Production Guidance Range Q3 2019 Guidance (Low) Q3 2019 Guidance (High) Chaparral STACK/Merge Position • 130,000 net acres • 171 operated horizontal wells as of Q2 2019 Positive Well Performance Driving Production Growth 1 Based on midpoint of 2019 production guidance NYSE: CHAP 15
Drilling and Completions – Increased Efficiencies Reduction in average Osage and Merge Miss well costs to $3.5 - $4.0 million • Represents a 15% - 20% reduction in from 2018 results Drilling Completions Avg. Feet/day Avg. Stages/day 9 900 8 7 6 600 5 4 3 300 Feet Drilled Feet Drilled per Day 2 Frac Stages per Day 1 0 0 1H18 2H18 1H19 1H18 2H18 1H19 Faster Cycles Lower Cost Higher Returns Best-in-Class STACK/Merge Operator NYSE: CHAP 16
Financial Overview NYSE: CHAP 17
Financial Strategy • Targeting cash flow neutrality by the second half of 2020 • Maintain balance sheet strength • Significant capital spend flexibility with no long-term commitments • Entered into agreement to sell headquarters building; proceeds from sale will be used to eliminate related debt of ~$8.3 million • Development plan funding available due to ample liquidity • $33 million in cash as of Q2 2019 plus $85 million drawn revolver ($325 million borrowing base) • Target net debt to adjusted EBITDA ratio of approximately 2.5x or less • Allocate capital based on strategic and rate-of-return priorities • Allocate capital to high-return STACK/Merge assets • 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 18
Financial Position and Liquidity Highlights Chaparral Liquidity • $325 million borrowing base ($ in millions) reaffirmed in spring 2019 Q2 2019 redetermination Cash and Cash Equivalents $33 • Closed on $300 million senior Revolving Credit Facility due Dec. 2022 $85 unsecured notes offering in June 2018 Other Debt $20 • Develop long runway to unlock Senior Notes $300 value of deep STACK/Merge Total Debt $405 drilling inventory Net Debt $372 • No maturities until 2022 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 19
Why Chaparral? Strong Balance Sheet Experienced Execution-focused, Management with Pure-play Excellent Track STACK/Merge Record Operations Deep Inventory of High-return Drilling Prospects NYSE: CHAP 20
Appendix NYSE: CHAP 21
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 22
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 capacity of 1.4 Bcf/d to Gulf Coast markets expected in Q4 2019 (Midship) • New ethane crackers scheduled to be in service in Q3 2019 NYSE: CHAP 23
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 28% $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 $4.00 87% 100% • Flexibility to reject/recover ethane on majority of 85% $3.50 77% 79% operated production for value maximization 80% $3.00 Natural Gas Differentials $2.50 60% $2.00 • Increased supply from STACK/SCOOP and other $1.50 40% basins competing for pipeline capacity has caused $1.00 HH Average Average HH Daily Settle 20% Mid-Continent to widen $0.50 Realizations % as • New pipeline capacity out of STACK/SCOOP to South $0.00 0% and Gulf Coast will provide price strength for the basin 2016 2017 2018 YTD 2019 Henry Hub Gas % NYSE: CHAP 24
Hedging Summary Hedge Positions1 Q3-Q4 2019 2020 2021 Crude Oil Swaps Hedge Volume (BBL) 1,310,800 2,007,000 689,300 Average Price ($/BBL) $55.92 $50.56 $46.24 Crude Oil Collars Hedge Volume (BBL) 195,000 Average Ceiling Price ($/BBL) $66.42 Average Floor Price ($/BBL) $55.00 Crude Oil Roll Hedge Volume (BBL) 240,000 410,000 150,000 Average Ceiling Price ($/BBL) $0.46 $0.38 $0.30 Natural Gas Swaps Hedge Volume (MMBTU) 7,824,400 6,000,000 Average Price ($/MMBTU) $2.85 $2.75 Natural Gas Basis Swaps (PEPL) Hedge Volume (MMBTU) 4,994,200 3,600,000 Average Price ($/MMBTU) ($0.59) ($0.46) NGL Swaps Propane Hedge Volume (BBL) 416,000 254,000 Propane Average Price ($/BBL) $25.50 $26.32 Iso Butane Hedge Volume (BBL) 28,000 15,000 Iso Butane Average Price ($/BBL) $30.20 $30.20 Normal Butane Hedge Volume (BBL) 80,000 41,000 Normal Butane Average Price ($/BBL) $29.53 $29.53 Natural Gasoline Hedge Volume (BBL) 188,000 114,000 Natural Gasoline Average Price ($/BBL) $47.60 $49.27 1 As of July 31, 2019 NYSE: CHAP 25
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 26
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 1,682 28% $12.74 7.4 $53.2 Western Anadarko Basin 915 14% $8.79 4.6 $28.1 Southern OK 1,585 56% $16.40 7.8 $87.1 Other 313 14% $2.58 0.9 $6.5 TOTAL 4,495 34% $12.59 20.7 $174.9 TOTAL Incl. ARO $170.2 1 Q2 2019 actuals 2 At year-end 2018 SEC prices of $65.56 and $3.10 NYSE: CHAP 27
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 28
Reconciliations Three Months Three Months Ended Ended (in thousands) June 30, 2019 June 30, 2018 Net (loss) income $ (45,229) $ (21,993) Interest expense 5,571 1,739 Depreciation, depletion, and amortization 30,282 20,407 Loss on impairment of oil and gas assets 63,593 — Loss on impairment of other assets 6,407 Non-cash change in fair value of derivative instruments (17,596) 26,761 Impact of derivative repricing — (1,680) Interest income (2) (1) Stock-based compensation expense 852 1,671 Loss (gain) on sale of assets (491) (469) Restructuring, reorganization and other 313 480 Adjusted EBITDA $ $43,700 $ 26,915 (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 29
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 30
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 31
ENERGIZING America’s Heartland NYSE: CHAP chaparralenergy.com NYSE: CHAP 32
