Investor Presentation NYSE:CHAP August 2018 Exhibit 99.2
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, which 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 discreet 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 in the appendix. Forward-Looking Statements and Risk Factors
Company Overview
High-growth, pure-play STACK oil company 13.2 MBoe/d Q2 2018 STACK production 35 - 45% projected 2018 STACK production growth Premier, contiguous acreage position 119,000 acres in world-class STACK resource play Primarily in black oil, normal pressure window in Kingfisher, Garfield and Canadian counties Large resource base with deep inventory Year-end 2017 proved reserves of approximately 76 MMBoe and PV-10 of approximately $659 million1 Decades of high-return inventory Highly efficient, low-cost STACK assets $26.30/Boe year-to-date 2018 STACK cash margins $5.34/Boe year-to-date 2018 STACK LOE cost Strong balance sheet No long-term maturities until December 2022 Approximately $353 million of liquidity as of June 30 Chaparral Story County STACK Acreage Held By Production Operated WI Average Non-Operated WI Average Kingfisher ~33,000 ~97% 72% 17% Canadian ~22,000 ~99% 72% 15% Garfield ~45,000 ~25% 60% 19% Major ~6,000 ~98% 56% 15% Other ~13,000 ~100% 50% 11% 1 At NYMEX prices from June 29, 2018; five-year average prices $62.80 and $2.80 Merge STACK
2018 Strategy PURE-PLAY STACK COMPANY TECHNICAL EXCELLENCE STRONG, FLEXIBLE CAPITAL STRUCTURE Employ leading drilling and completion techniques Protect strong balance sheet to execute strategy RETURNS FOCUSED Focus exclusively on creating value for our stakeholders Transitioned to pure-play STACK operator with 2017 asset sale Deliver safe, repeatable results and drive down costs Improve operations, costs and returns with continuous learning Achieve 45 - 100% IRRs from STACK/Merge drilling opportunities Provide sufficient liquidity through cash flow, hedging, borrowing capacity, non-core asset sales and access to capital markets Continue to rationalize non-core legacy assets Delineation and de-risking of Canadian (Merge) and Garfield acreage
Recorded STACK production growth of: 7% Q1 2018 to Q2 2018 44% Q2 2017 to Q2 2018 Grew STACK reserves by 58% from year-end 2016 to year-end 2017 Replaced 604% of 2017 STACK production at $7.26/Boe F&D cost Achieved 2018 average 30-day peak IP rate of 823 Boe/d for Meramec and Osage wells De-risked ~50% of Garfield County acreage and ~80% of Canadian County Merge acreage Completed accretive 7,000-acre bolt-on Kingfisher County acquisition Issued $300 million of senior unsecured notes in June 2018 Listed on NYSE under symbol CHAP in July 2018 Recent Chaparral Highlights Time Period Gross Wells1 Average WI Lateral Length IP-302 Liquids Type Curve IP-303 YTD Q2 2018 18 52% 4,595 feet 823 69% 709 1 Excludes one Osage well, which did not have a peak 30-day production rate 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 gross three-phase, peak 30-day production rate in Boe/d of the STACK Meramec, Upper Osage, Lower Osage and Merge Miss type curves Operated Meramec and Osage Well Performance Above Type Curve
Operational Overview
World-class Woodford source rock +700 feet of saturated hydrocarbon column Multiple reservoirs development opportunities Robust service sector support Numerous midstream alternatives Abundant pipeline capacity Chaparral STACK: WTI less ~$1.00/Bbl1 Bakken: WTI less ~$5.00/Bbl1 Permian Basin: WTI less ~$16.00/Bbl2 STACK Merge Miss: 98% rate-of-return3 STACK Lower Osage: 90% rate-of-return3 STACK Meramec: 77% rate-of-return3 STACK Upper Osage: 53% rate-of-return3 STACK/Merge Attributes 1 Based on company filings 2 Based on the August 7, 2018 WTI Midland contract vs. WTI for August, 2018 3 Based on June 29, 2018 NYMEX five-year average prices of $62.80 and $2.80 Favorable Geology Extensive Infrastructure Excellent Crude Net Back Top-quartile Economics
Chaparral Core Scale Tier 2 Tier 1 STACK Geology Osage Heat Map1 Meramec Heat Map2 Chaparral Core Scale Tier 2 Tier 1 1 Heat map integrates major factors affecting well performance in the Osage: 1.Osage hydrocarbon pore volume 2.Net resistivity (brittleness) 3.Woodford hydrocarbon pore volume 2 Heat map integrates major factors affecting well performance in the Meramec: 1.Meramec hydrocarbon pore volume 2.Net resistivity (brittleness) 3.Woodford hydrocarbon pore volume Chaparral position in overlapping areas of optimal Osage, Meramec, Oswego and Woodford formation rock Shelf carbonates in shallower, normal pressure window provide lower D&C costs and higher liquids content STACK currently defined by >1,000 Hz Mississippian wells and >1,250 Hz Woodford wells Geological Benefits
Oil Economics – WTI Basin Breakeven Estimates1 Source: BMO Capital Markets equity research report 1 Data based on 2016-17 vintage public well production data STACK Break-Even Economics Oil Economics – Chaparral Counties of Focus1
Breakeven heat map from May 2018 SCOOP/STACK insights by RS Energy Group Highly Profitable Breakeven Acreage 4 5 7 8 10 6 1 Recent Operated Performance 2 3 9 13 11 12 14 20 15 16 17 18 19 MERAMEC OSAGE Chaparral Leasehold No. Well Name Spud Date IP-30 Boe/d Liquids 1 BARBEE 2105 1LMH-4 12/17/2017 1,122 69% 2 GLOCK 2205 1LMH-15 2/9/2018 913 61% 3 DOGWOOD 2205 1LMH-28 3/15/2018 870 57% 4 FUKSA 2007 1LMH-14 11/2/2017 710 83% 5 GERKEN 2205 1UMH-33 12/21/2017 1,063 55% 6 WHITE OAK 2206 1UMH-36 5/7/2017 892 36% 7 COTTONWOOD 2205 1UMH-34 3/1/2018 757 59% 8 BROWNING 2205 1UMH-22 1/26/2018 667 55% 9 LOW VALLEY 1807 1LMH-36 4/18/2017 1,335 82% 10 BRANDT 1707 1LMH-12 7/8/2017 885 86% 11 STAY PUFT 1707 1LMH-23 9/26/2017 863 86% 12 SLIMER 1707 1UMH-23 9/5/2017 719 85% 13 HIGH VALLEY 1807 1UMH-36 8/19/2017 652 77% 14 SHASTA 1106 1UMH-28 10/14/2017 1,368 70% 15 LASSEN 1107 1UMH-15 12/2/2017 1,218 73% 16 BANFF 1207 1UMH-29 3/23/2018 1,209 59% 17 KATMAI 1206 1UMH-29 2/7/2018 1,168 76% 18 KILIMANJARO 1106 1UMH-2 7/28/2017 1,044 82% 19 BEECHAM-HUNT 1307 1UMH-13 9/8/2017 927 72% 20 OLYMPUS 1107 1UMH-10 11/3/2017 823 72% Garfield County Osage and Meramec wells demonstrating solid results; 45,000-acre position 50% de-risked Continued strong Kingfisher County Meramec and Osage well performance from de-risked acreage Canadian County Merge Meramec delivering excellent results; 22,000-acre position 80% de-risked
Meramec Merge Miss North Woodford South Woodford Lower Osage Upper Osage Lateral Length (ft.) 4,800 4,800 4,800 4,800 4,800 4,800 Well Cost ($mm) $4.0 $4.5 $4.4 $4.4 $3.9 $4.1 Well Cost ($/ft.) $833 $938 $917 $917 $813 $854 Total EUR (MBoe) 584 1,023 579 1,456 629 853 % Liquids 70% 66% 72% 62% 70% 54% IP-30 612 881 475 736 599 744 Single Well Economics STACK Osage, Meramec & Merge Miss STACK Woodford Core STACK & Merge Type Curve Overview
87% Growth Chaparral STACK & Merge Position STACK & Merge Overview STACK/Merge Production Approximately 119,000 acres Approximately 105 operated horizontal wells as of Q2 2018 Excellent Merge acreage 100% held-by-production 1 Based on mid-point of guidance range 1
Osage Well Performance Strong recent operated well performance for Upper and Lower Osage type curve areas Actual oil results are in-line or exceeding current type curve expectations Type curve rates-of-return – 53% - 90%1 1 Based on June 29, 2018 NYMEX five-year average prices of $62.80 and $2.80 2 Cumulative results are scaled to type curve lateral length of 4,800 feet and include operated wells since June 30, 2017
Meramec Well Performance Excellent recent operated well performance for Merge Miss and STACK Meramec type curve areas Actual oil results are in-line or exceeding current type curve expectations Type curve rates-of-return – 77% - 98%1 1 Based on June 29, 2018 NYMEX five-year average prices of $62.80 and $2.80 2 Cumulative results are scaled to type curve lateral length of 4,800 feet and include operated wells since June 30, 2017
D&C Cost Comparison ($/lateral foot) Source: Company presentations and analyst research Note 1: CHAP includes average for Osage and Meramec and assumes multi-well pad development Note 2: Peers include AMR, GST, CLR, DVN, MRO, XEC and NFX Operational Excellence – Drilling and Completions Strong, Effective Focus on Cost Control Chaparral Osage and Meramec D&C represents best-in-class in normal pressure STACK Low well cost and consistent production results produce excellent returns D&C ($/lateral foot) avg.
STACK Drilling Joint Venture Joint venture between Chaparral and Bayou City Energy (BCE) Accelerate development of 119,000 STACK acres 20 wells drilled, 17 producing as of Q2 2018 BCE funds 100% of D&C cost $100 million maximum investment, associated with 30 joint venture STACK wells 17 Canadian County 13 Garfield County BCE receives 85% working interest in each well until program reaches 14% rate-of-return After which, Chaparral working interest increases to 75% and BCE retains 25% working interest Chaparral retains all acreage and resources outside wellbore STACK Merge
Capital Program Objectives Delineate Garfield and Canadian (Merge) County position Drill at least five wells on Kingfisher County acquisition acreage Increase 3-D seismic and lease acquisitions Begin spacing tests in Kingfisher and Canadian counties by adding fourth rig in Q4 2018 Monetize non-core assets 2018 Capital Budget Expectations 1 Kingfisher County acquisition accounts for $55 million of total budget 2 Includes workovers, capitalized interest, capitalized G&A and PP&E Capital Spend Guidance Range Total Capital ($mm) $300 - $325 Operated STACK D&C $140 - $150 OBO STACK D&C $35 - $45 Lease Acquisition1/3-D Seismic $95 - $100 Other2 $30
Updated Guidance Highlights Increased full year STACK production guidance 13% Q3 STACK guidance: 13.5 -14.5 MBoe/d Increased total company production guidance 11% Q3 total company guidance: 19 - 20 MBoe/d Decreased cash G&A expense/Boe guidance by 21% Increased CAPEX guidance by 19% Higher working interest (~$20mm) Addition of fourth operated rig (~$6mm) Cost inflation associated with BCE wells (~$11mm) Leasing activity (~$10mm) 2018 Updated Guidance 1 Kingfisher County acquisition accounts for $55 million of budget, as well as poolings and other lease acquisitions/renewals 2 Includes workovers, capitalized interest, capitalized G&A and PP&E 2018 Guidance Range Production (MBoe/d) Total Company 19.0 - 20.0 STACK 13.0 - 14.0 Capital ($mm) $300 - $325 Operated STACK D&C $140 - $150 OBO STACK D&C $35 - $45 Lease Acquisition1/3-D Seismic $95 - $100 Other2 $30 Expenses ($/Boe) LOE $7.60 - $8.20 Cash G&A Expense $3.50 - $4.00 Non-Core Asset Sales ($mm) $50 - $60 Original Midpoint Production Guidance Updated Production Guidance Legacy 5.5 0 0 6 STACK 12 0 0 16.5 Total 17.5 22.5 19.5 STACK 0.375 TC 0.28571428571428581 0.11428571428571432 Total Comapcy 11% Increase Original Capex Guidance Leasing Activity Higher WI% BCE Cost Inflation 4th Rig Other Updated Capex Guidance 262.5 262.5 272.5 292.5 303.5 309.5 312.5 0 10 20 11 6 3 0 262.5 272.5 292.5 303.5 309.5 312.5 312.5
Financial Overview
Maintain balance sheet strength Target net debt to adjusted EBITDA ratio of approximately 2.5x or less Supplement cash flow with proceeds from non-core asset sales Development plan funding available due to ample liquidity $353 million as of Q2 2018 Significant capital spend flexibility with no long-term commitments Allocate capital based on strategic and rate-of-return priorities Allocate capital to high-return STACK assets Held-by-production acreage and delineation of Canadian and Garfield counties 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 listing under symbol CHAP (July 24, 2018) Access to larger investor base and increased trading liquidity Financial Strategy
1 Liquidity defined as revolver availability base plus unrestricted cash less letters of credit 2 Assumes borrowing base of $285 million as of June 30 Closed on a $300 million senior unsecured notes offering on June 29, 2018 Paid down all outstanding borrowings on credit facility Continue to rationalize non-STACK assets to add liquidity Develop long runway to unlock value of deep STACK drilling inventory Financial Position and Liquidity Chaparral Liquidity ($ in Millions) Q2 2018 Actual Actual Cash and Cash Equivalents $68 Revolving Credit Facility due Dec. 2022 $0 Other $22 Senior Notes $300 Total Debt $322 Net Debt $254 Liquidity1,2 $353 Chaparral Debt Maturity Schedule $265 $300 Highlights
Crude Oil Marketing Acreage in close proximity to Cushing and in-state refineries Premium price due to gravity and quality of barrel Substantial capacity to market via truck or existing pipeline Evaluating pipeline gathering alternatives direct to Cushing for several development sections Crude Oil
Natural Gas & NGL Marketing Natural Gas and NGL Midstream super system, with multiple plants and residue outlets Two Bcf of incremental capacity to North Texas, eastern and southeastern U.S. and Gulf Coast markets (mid-year 2018 and Q3 2019) Residue and NGL agreements with midstream operators who have firm transportation Approximate 50/50 NGL markets and pricing split between Conway and Mt. Belvieu
Crude Oil Differentials Proximity to numerous markets provides better CHAP net back as compared to other basins STACK crude oil quality meets Oklahoma refineries specification New trucking terminals and pipeline infrastructure have reduced transportation costs, providing better net back at the wellhead Natural Gas Differentials Increased supply from STACK/SCOOP and other basins competing for pipeline capacity has caused Mid-Continent to widen New pipeline capacity out of STACK/SCOOP to south and Gulf Coast will provide price strength for the basin NGL Differentials Increased pipeline capacity to the Gulf Coast to new markets Increased Gulf Coast demand, with new petrochemical crackers coming online Access to Mont Belvieu and increased NGL export capacity provided increased pricing to STACK Commodity Realizations
Why Chaparral? Strong Balance Sheet Execution-focused, Pure-play STACK Operations Deep Inventory of High-return Drilling Prospects Experienced Management with Excellent Track Record
Appendix
Hedging Summary Hedge Positions1 2H 2018 2019 2020 2021 Crude Oil Swaps Hedge Volume (BBL) 1,030,400 1,562,200 1,547,000 543,300 Average Price ($/BBL) $58.21 $55.90 $49.54 $44.34 Crude Oil Collars Hedge Volume (BBL) 92,000 Average Ceiling Price ($/BBL) $60.50 Average Floor Price ($/BBL) $50.00 Crude Oil Roll Hedge Volume (BBL) 300,000 530,000 410,000 150,000 Average Ceiling Price ($/BBL) $0.59 $0.52 $0.38 $0.30 Natural Gas Swaps Hedge Volume (MMBTU) 5,128,000 7,631,500 3,600,000 Average Price ($/MMBTU) $2.88 $2.81 $2.77 Natural Gas Basis Swaps (PEPL) Hedge Volume (MMBTU) 3,000,000 2,500,000 Average Price ($/MMBTU) ($0.70) ($0.70) NGL Swaps Propane Hedge Volume (Gallons) 7,308,000 11,466,000 4,284,000 Propane Average Price ($/Gallon) $0.88 $0.74 $0.74 Natural Gasoline Hedge Volume (Gallons) 3,150,000 4,956,000 1,890,000 Natural Gasoline Average Price ($/Gallon) $1.55 $1.39 $1.39 1 As of June 30, 2018
YE ‘17 Total Proved Reserves YE ‘17 Proved Reserves PV-10 Reserve Category Net Oil (MMBo) Net Gas (BCF) Net NGL (MMBo) Net (MMBoe) % of Total Proved SEC Pricing1 Strip Pricing2 $60 and $3 PDP 18.1 119.4 11.7 49.7 65% 427.1 535.1 519.7 PNP 0.2 4.1 0.2 1.1 1% 6.0 7.0 7.1 PUD 11.3 46.7 6.5 25.6 34% 77.4 116.9 127.0 Total Proved 29.6 170.2 18.3 76.3 100% 510.5 659.1 653.8 STACK 18.7 107.4 12.8 49.4 65% 312.5 406.0 405.7 OTHER 10.9 62.8 5.6 26.9 35% 198.0 253.1 248.2 Total Proved 29.6 170.2 18.3 76.3 100% 510.5 659.1 653.8 Total Proved Inc. ARO 29.6 170.2 18.3 76.3 100% 497.9 646.5 641.2 1 At year-end 2017 SEC prices of $51.34 and $2.98 2 At June 29, 2018 NYMEX: Five-year average prices $62.80 and $2.80 Note: Numbers may not add due to rounding Grew STACK year-end 2017 reserves by 58% Year-End 2017 Proved Reserves Replaced 604% of 2017 STACK production at $7.26/Boe F&D cost
Non-Core Legacy Asset Overview Mature legacy fields Low-maintenance capital Provides free cash flow to fuel STACK growth Potential strategic alternatives 1 Based on Q2 2018 2 At year-end 2017 SEC prices of $51.34 and $2.98 3 Based on year-end 2017 reserves run on the June 29, 2018 NYMEX: Five-year average prices $62.80 and $2.80 Area Net Production1 Gross Margin1 Net Proved Reserves Boe/d % Oil $/Boe MMBoe2 PV-102 ($mm) PV-103 ($mm) Miss Lime 1,862 30% $16.06 6.8 $45.4 $57.1 Western Anadarko Basin 1,251 15% $7.90 7.9 $46.9 $54.4 Southern OK 1,770 58% $26.34 7.3 $67.8 $90.1 Other 1,654 46% $14.99 4.9 $38.0 $51.4 TOTAL 6,537 39% $17.07 26.9 $198.0 $253.1 TOTAL Incl. ARO 6,537 39% $17.07 26.9 $187.4 $242.5
Sales Package/Seller Alta Mesa Staghorn PayRock Felix Longfellow Purchaser Silver Run II Chisholm Marathon Devon SK Date 8/16/2017 1/16/2017 6/20/2016 12/7/2015 3/20/2018 Purchase Price ($mm) $2,200 $613 $888 $1,900 $280 Net Acres 120,000 41,386 61,000 80,000 30,000 Production (MBoe/d) 20 2.8 8.6 9 1 $/Acre Not Adjusted for Production $18,333 $14,812 $14,557 $23,750 $9,333 $/Acre Adjusted for Production, $25,000/Boe/d $17,1581 $13,120 $11,033 $20,938 $8,500 Significant A&D activity demonstrates value of Chaparral’s acreage position Staghorn, PayRock, Alta Mesa and Longfellow transactions were primarily in the black oil, normal pressure window of the play 2 3 4 4 3 2 1 1 1 Does not include approximately 20,000 net acres in Major County STACK 5 5 Recent Transactions Support CHAP Acreage Valuation Merge
STACK Type Curve Assumptions STACK Meramec Lower Osage Upper Osage North Woodford South Woodford Merge Miss Well Cost Assumptions Well Costs ($mm) $4.0 $3.9 $4.1 $4.4 $4.4 $4.5 Well Costs ($/ft) $833 $813 $854 $917 $917 $938 Type Curve Assumptions Lateral Length (ft) 4,800 4,800 4,800 4,800 4,800 4,800 Oil EUR (MBbls) 236 254 152 212 167 211 Oil IP-30 (Bo/d) 381 397 231 281 211 320 Oil B factor 1.2 1.2 1.4 1.1 1.2 1.2 Initial decline 82% 81% 84% 74% 75% 80% NGL EUR (MBbls) 175 189 306 207 729 460 NGL IP-30 (Bo/d) 116 102 224 110 297 317 NGL Yield (Bbls/MMcf) 112 112 97 152 152 152 Wellhead Gas EUR (MMcf) 1,564 1,684 3,157 1,365 4,795 3,024 Gas IP-30 (Mcf/d) 1,039 908 2.314 724 1,955 2,088 Gas B factor 1.3 1.4 1.4 1.2 1.2 1.2 Initial decline 56% 50% 62% 45% 35% 55% Gas Shrink 66% 66% 75% 70% 70% 70% Three-stream EUR (MBoe) 584 629 853 579 1,456 1,023 Three-stream IP-30 (Boe/d) 612 599 744 475 736 881
Lease Operator Spud Date Peak IP-301 Boe/d Liquids1 % Lateral Length SLIMER 1707 #1UMH-23 CHAPARRAL 9/5/2017 713 85% 4,839 HIGH VALLEY 1807 #1UMH-36 CHAPARRAL 8/19/2017 682 77% 4,588 BIG TIMBER 1408 #1UMH-2 CHAPARRAL 6/4/2017 799 82% 4,623 CATERPILLAR 1506 1-11MH ALTA MESA 2/1/2018 717 85% 4,958 WINFIELD 1807 31-1MH GASTAR 8/15/2017 657 82% 4,608 RHINO 8_5-14N-9W 1HX DEVON 7/22/2017 918 67% 10,054 JORDAN 10_15-14N-9W 1HX DEVON 4/17/2017 876 67% 10,050 H&W 1H-28X NEWFIELD 1/15/2017 878 80% 9,713 BANFF 1207 #1UMH-29 CHAPARRAL 3/23/2018 1,178 59% 4,926 HOOD 1006 #1UMH-5 CHAPARRAL 3/2/2018 838 73% 4,840 KATMAI 1206 #1UMH-29 CHAPARRAL 2/7/2018 1,262 76% 4,439 LASSEN 1107 #1UMH-15 CHAPARRAL 12/2/2017 1,302 73% 4,490 OLYMPUS 1107 #1UMH-10 CHAPARRAL 11/3/2017 934 72% 4,228 SHASTA 1106 #1UMH-28 CHAPARRAL 10/14/2017 1,349 70% 4,869 BEECHAM-HUNT 1307 #1UMH-13 CHAPARRAL 9/8/2017 977 72% 4,394 KILIMANJARO 1106 1UMH-2 CHAPARRAL 7/30/2017 1,105 78% 4,392 GAMBLE 3-11-6 3H JONES 11/10/2017 1,097 78% 4,467 JO 26-35-10-6 1XH ROAN 9/23/2017 1,157 65% 10,055 GAMBLE 3-11-6 2H JONES 9/17/2017 1,123 78% 4,362 CANNONBALL 1208 24-2MH 89 ENERGY 7/22/2017 1,086 68% 4,826 ROSEWOOD 16-12-7 2H JONES 6/9/2017 1,457 67% 4,625 ROSEWOOD 16-12-7 1H JONES 6/9/2017 1,232 69% 4,617 Type Curve Meramec Merge Miss IP-301 (Boe/d) 612 881 ROR at NYMEX Strip2 77% 99% Total EUR1 (MBoe) 584 1,023 % Liquids1 70% 66% Lateral Length (feet) 4,800 4,800 Well Cost ($mm) $4.0 $4.5 Single Well Economics 1 Gross three-phase scaled to type curve lateral length of 4,800 feet 2 Based on June 29 NYMEX five-year average prices of $62.80 and $2.80 17 1 2 3 4 5 6 7 8 9 10 11 12 16 13 14 15 18 19 20 21 22 STACK Meramec and Merge Miss Overview
Lease Operator Spud Date Peak IP-301 Boe/d Liquids1 % Lateral Length DOGWOOD 2205 1LMH-28 CHAPARRAL 3/15/2018 862 57% 4,844 COTTONWOOD 2205 #1UMH-34 CHAPARRAL 3/1/2018 766 59% 4,741 GLOCK 2205 #1LMH-15 CHAPARRAL 2/9/2018 902 61% 4,855 BROWNING 2205 #1UMH-22 CHAPARRAL 1/26/2018 675 55% 4,743 GERKEN 2205 #1UMH-33 CHAPARRAL 12/21/2017 1,110 55% 4,594 BARBEE 2105 #1LMH-4 CHAPARRAL 12/17/2017 1,224 69% 4,359 WHITE OAK 2206 #1UMH-36 CHAPARRAL 5/7/2017 1,156 53% 4,743 PATRICIA 5-21N-5W 1MH WHITE STAR 5/2/2017 668 76% 4,686 PATRICIA 5-21N-5W 2MH WHITE STAR 4/14/2017 865 71% 4,194 FUKSA 2007 #1LMH-14 CHAPARRAL 11/2/2017 834 83% 4,087 STAY PUFT 1707 #1LMH-23 CHAPARRAL 9/26/2017 863 86% 4,571 BRANDT 1707 #1LMH-12 CHAPARRAL 7/8/2017 948 86% 4,482 LOW VALLEY 1807 #1LMH-36 CHAPARRAL 4/18/2017 1,345 82% 4,766 DR J 1808 7-1UOH GASTAR 10/1/2017 843 80% 4,593 BUGABAGO 2006 1-31MH LONGFELLOW 3/5/2017 568 89% 5,064 1 Gross three-phase scaled to type curve lateral length of 4,800 feet 2 Based on June 29 NYMEX five-year average prices of $62.80 and $2.80 Type Curve Lower Osage Upper Osage IP-301 (Boe/d) 599 744 ROR at NYMEX Strip2 91% 54% Total EUR1 (MBoe) 629 853 % Liquids1 70% 54% Lateral Length (feet) 4,800 4,800 Well Cost ($mm) $3.9 $4.1 Single Well Economics 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 STACK Osage Type Curves Overview
Type Curve North Woodford South Woodford IP-301 (Boe/d) 475 736 ROR at NYMEX Strip2 46% 93% Total EUR1 (MBoe) 579 1,456 % Liquids1 72% 62% Lateral Length (feet) 4,800 4,800 Well Cost ($mm) $4.4 $4.4 Single Well Economics STACK Woodford Type Curves Overview Lease Operator Spud Date Peak IP-301 Boe/d Liquids1 % Lateral Length CUTTHROAT 1307 1WH-13 CHAPARRAL 2/11/2017 588 76% 4,225 GLACIER 11-14-12-6 1HX JONES 12/31/2017 463 63% 9,890 ACADIA 13-12-12-6-1HX JONES 12/9/2017 581 65% 7,277 EVEREST 1107 #1WH-24 CHAPARRAL 2/12/2018 451 59% 4,451 KATMAI 1206 #1WH-29 CHAPARRAL 1/5/2018 405 61% 4,086 LASSEN 1107 #1WH-15 CHAPARRAL 11/24/2017 499 64% 4,021 OLYMPUS 1107 #1WH-10 CHAPARRAL 11/13/2017 462 58% 4,122 FRANK EATON 36-1-11-6 1XH ROAN 2/3/2018 454 80% 9,941 LOUDERMILK 1H-32-29 ROAN 12/3/2017 490 60% 10,182 ASHCRAFT 1-19H CIMAREX 9/20/2017 640 63% 5,172 COWBOY 1H-34-3 ROAN 8/30/2017 402 60% 9,282 CANNONBALL 1208 24-1WH 89 ENERGY 7/21/2017 769 62% 4,639 RAFTER J 1H-17-20 ROAN 7/16/2017 1,059 57% 8,423 ROSEWOOD 16-12-7 3H JONES 7/3/2017 933 69% 4,465 1 2 3 4 5 6 7 8 9 10 11 12 13 14 1 Gross three-phase scaled to type curve lateral length of 4,800 feet 2 Based on June 29 NYMEX five-year average prices of $62.80 and $2.80
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. Reserve and Non-GAAP Information Statement
Successor (in thousands) Three Months Ended June 30, 2018 Three Months Ended June 30, 2017 Net (loss) income $ (21,993) $ 21,365 Interest expense 1,739 5,051 Income tax expense — 37 Depreciation, depletion, and amortization 20,407 30,851 Non-cash change in fair value of derivative instruments 26,761 (16,811) Impact of derivative repricing (1,680) — Interest income (1) (5) Stock-based compensation expense 1,671 — (Gain) loss on sale of assets (469) 863 Restructuring, reorganization and other 480 1,185 Adjusted EBITDA $ $26,915 $ 42,536 Reconciliations (in thousands) 2017 Standardized measure of discounted future net cash flows $497,873 Present value of future income tax discounted at 10% — PV-10 value $497,873
STACK F&D and Reserve Replacement 2017 Metrics Calculation STACK Production (MBoe) 3,464 (A) Proved Reserves (MBoe) STACK Extensions and Discoveries 20,927 (B) STACK Revisions (excluding price revisions) 597 (C) Capital Costs Incurred (in thousands) STACK Only (includes D&C, acquisitions and enhancements) $166,758 (D) STACK Only (excludes capitalized interest and capitalized G&A) $156,183 (E) STACK Reserve Replacement 604% (B)/(A) All-in STACK F&D $7.26 (E)/(B+C) Reconciliations
Contact Information Chaparral Energy, Inc. 701 Cedar Lake Boulevard Oklahoma City, OK 73114 Investors Joe Evans Chief Financial Officer joe.evans@chaparralenergy.com 405-426-4590 Media Brandi Wessel Manager – Communications brandi.wessel@chaparralenergy.com 405-426-6657
ENERGIZING America’s Heartland
