8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 8-K

CURRENT REPORT

Pursuant to Section 13 or Section 15(d) of the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): February 26, 2019

CHAPARRAL ENERGY, INC.

(Exact name of registrant as specified in its charter)

Delaware	001-38602	73-1590941
(State or other jurisdiction of incorporation)	(Commission File Number)	(IRS Employer Identification No.)

701 Cedar Lake Boulevard Oklahoma City, OK	73114
(Address of principal executive offices)	(Zip Code)

Registrant's telephone number, including area code: (405) 478-8770

Not Applicable

(Former name or former address, if changed since last report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§ 230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§ 240.12b-2 of this chapter).

Emerging growth company  ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  ☐

Item 2.02. Results of Operations and Financial Condition; Item 7.01 Regulation FD Disclosure.

On February 26, 2019, Chaparral Energy, Inc. (the “Company”) issued a press release disclosing certain operational results for the year ended December 31, 2018, and operational and capital guidance for 2019. In the press release, the Company also announced the timing of it 2018 year-end earnings release and conference call. A copy of the press release is attached hereto as Exhibit 99.1. On February 26, 2019, the Company presented the following slide show, attached hereto as Exhibit 99.2 and incorporated herein by reference, at the JP Morgan Global High Yield and Leveraged Finance Conference in Miami. The slide show as also been posted on the Company's website.

The Company’s slide show contains non-GAAP financial measures. Generally, a non-GAAP financial measure is a numerical measure of a company’s performance, financial position, or cash flows that either excludes or includes amounts that are not normally excluded or included in the most directly comparable measure calculated and presented in accordance with United States generally accepted accounting principles, or GAAP. Pursuant to the requirements of Regulation G, the Company has provided within the slide show quantitative reconciliations of the non-GAAP financial measures to the most directly comparable GAAP financial measures.

In accordance with General Instruction B.2 of Form 8-K, the information furnished under this Item 7.01 of this Current Report on Form 8-K and the exhibit attached hereto are deemed to be "furnished" and shall not be deemed "filed" for the purpose of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liabilities of that section, nor shall such information and exhibit be deemed incorporated by reference into any filing under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended.

Cautionary Note Regarding Forward-Looking Statements

Many of the statements included or incorporated in this Current Report on Form 8-K and the furnished exhibits constitute “forward-looking statements.” In particular, they include statements relating to future actions, strategies, future operating and financial performance, and the Company’s future financial results. These forward-looking statements are based on current expectations and projections about future events. Readers are cautioned that forward-looking statements are not guarantees of future operating and financial performance or results and involve substantial risks and uncertainties that cannot be predicted or quantified, and, consequently, the actual performance of the Company may differ materially from those expressed or implied by such forward-looking statements. Such risks and uncertainties include, but are not limited to, factors described from time to time in the Company’s Annual Report on Form 10-K and Quarterly Reports on Form 10-Q filed with the Securities and Exchange Commission (including the sections entitled “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained therein).

Item 9.01 Financial Statements and Exhibits.

(d) Exhibits

Exhibit Number	Description
99.1	Chaparral Energy, Inc. press release dated February 26, 2019.
99.2	Conference Presentation.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

February 26, 2019	CHAPARRAL ENERGY, INC.
	By:	/s/    JOSEPH O. EVANS
	Name:	Joseph O. Evans
	Title:	Chief Financial Officer and Executive Vice President

EX-99.1

Exhibit 99.1

Chaparral Energy Announces 2019 Operational and Capital Guidance, Schedules 2018 Year-end Results Call

Oklahoma City, February 26, 2019 - Chaparral Energy, Inc. (NYSE: CHAP) today announced 2019 production and capital investment guidance.

Highlights

• Forecasted 2019 total company production of 25 to 27 thousand barrels of oil equivalent per day (MBoe/d)

• Estimated 2019 STACK production of 21 to 23 MBoe/d, which represents an anticipated 45% to 59% year-over-year growth

• Planned total capital investment of $275 to $300 million, which includes STACK/Merge operated drilling and completion (D&C) capital of $210 to $225 million

• Continued strong lease operating expense (LOE) cost control performance, with 2019 STACK LOE/Boe guidance of $3.75 to $4.25

“Last year was a truly remarkable year in Chaparral’s storied history. From achieving record STACK production to lowering our overall cost structure and enhancing our liquidity through our bond offering, Chaparral continues to set itself apart as a premier STACK operator,” said Chaparral Chief Executive Officer Earl Reynolds. “As we continue to build upon these successes in 2019 and beyond, our focus remains steadfast on drilling highly economic wells, maximizing margins through low-cost operations, industry-leading execution and maintaining financial discipline. Our favorable service contracts and agile operating structure, coupled with the STACK’s numerous economic benefits allow us to quickly and effectively respond to changes within the market and optimize our financial flexibility.”

“Once we complete the drilling of our Canadian County Merge and Kingfisher County near-term spacing tests, we will reduce our rig count from four to three in the second quarter. This strategic reduction will allow us to lower our capital budget, while still competitively growing production,” said Reynolds. “We are extremely excited about the future and will continue to execute on our strategy to profitably grow reserves and production, while protecting our strong balance sheet to generate long-term value for our shareholders.”

2019 Operational and Capital Guidance

Chaparral anticipates 2019 total company production to be between 25 to 27 MBoe/d, which represents an anticipated 22% to 32% year-over-year growth. Total STACK production is expected to be between 21 and 23 MBoe/d, which is a forecasted year-over-year growth rate of 45% to 59%. While full year production will have significant growth, first quarter production will be impacted by the timing of first sales associated with Chaparral’s current spacing tests and remaining drilling joint venture wells. The company anticipates first sales from only approximately 10% of its total 2019 operated D&C program’s net wells in the first quarter. The company expects first sales from its 11-well Canadian County Merge spacing test, which it began drilling late last year, to occur during the second quarter.

Production Guidance

	4Q18E	1Q19E1	2019E
Total Company Average Daily Production (MBoe/d)	21.7	20.5 - 21.5	25.0 - 27.0
STACK Average Daily Production (MBoe/d)	16.6	15.5 - 16.5	21.0 - 23.0

¹First quarter 2019 total company and STACK production guidance reflects impact due to timing associated with production from the company’s multi-well spacing tests and remaining drilling joint venture wells.

The company plans to invest $275 to $300 million in capital in 2019, of which $228 to $248 million is dedicated to D&C activities in the prolific STACK/Merge Play. Chaparral plans to decrease its rig count from four to three rigs during the second quarter. The company expects to invest approximately 60% of its operated D&C in Canadian County, 20% in Kingfisher County and 20% in Garfield County in 2019. Additionally in 2019, the company plans to complete the remaining eight wells in its drilling joint venture program with Bayou City Energy.

Chaparral’s 2019 acquisition budget of $12.5 to $17.5 million will be significantly less than 2018, as 2018 included $55 million associated with its 7,000-acre, bolt-on acquisition in Kingfisher County. The 2019 acquisition budget will be primarily related to acreage poolings associated with its operated D&C program.

Total company LOE/Boe in 2019 is expected to be between $5.00 and $5.50. With a much lower per barrel operating cost, Chaparral’s STACK LOE/Boe is estimated to be between $3.75 and $4.25. The company’s total cash general and administrative per barrel cost (G&A/Boe) is anticipated to be $2.85 to $3.35.

Financial Guidance (in millions unless otherwise noted)

	2019E
Operated D&C	$210 - $225
Non-Operated D&C	$17.5 - $22.5
Acquisitions	$12.5 - $17.5
Other1	$35
Total Capital Expenditures	$275 - $300
Total Company LOE ($/Boe)	$5.00 - $5.50
STACK LOE ($/Boe)	$3.75 - $4.25
Cash G&A Expense ($/Boe)	$2.85 - $3.35
Anticipated Proceeds from Asset Sales	$5 - $10

¹ Includes workovers, capitalized interest and capitalized G&A

2018 Year-End Earnings Release and Conference Call

Chaparral will provide additional guidance details when it announces its year-end 2018 financial and operational results with the filing of its 10-K report on Thursday, March 14. The company will host a conference call to discuss its results that morning at 9 a.m. Central.

Interested parties may access the call toll-free at 877-790-7727 and ask for the Chaparral Energy conference call 10 minutes prior to the start time. The conference ID number is 4093425. In addition, a live webcast of the call will be available through the Investor section of the company’s website. For those who cannot listen to the live call, a recording will be available shortly after the call’s conclusion at chaparralenergy.com/investors.

A copy of the 10-K and corresponding earnings release and presentation will be available on the Investor section of the company’s website at chaparralenergy.com/investors, as well as the Securities and Exchange Commission’s website at sec.gov.

Statements made in this release contain “forward-looking statements.” These statements are based on certain assumptions and expectations made by Chaparral, which reflect management’s experience, estimates and perception of historical trends, current conditions, anticipated future developments, potential for reserves and drilling, completion of current and future acquisitions and growth, benefits of acquisitions, future competitive position and other factors believed to be appropriate. These forward-looking statements are subject to certain risks, trends and uncertainties that could cause actual results to differ materially from those projected. Among those risks, trends and uncertainties are our ability to find oil and natural gas reserves that are economically recoverable, the volatility of oil and natural gas prices, the uncertain economic conditions in the United States and globally, the decline in the reserve values of our properties that may result in ceiling test write-downs, our ability to replace reserves and sustain production, our estimate of the sufficiency of our existing capital sources, our ability to raise additional capital to fund cash requirements for future operations, the uncertainties involved in prospect development and property acquisitions or dispositions and in projecting future rates of production or future reserves, the timing of development expenditures and drilling of wells, the impact of natural disasters on our present and future operations, the impact of government regulation and the operating hazards attendant to the oil and natural gas business. 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. Please read “Risk Factors” in our annual reports, form 10-K or other public filings. We undertake no duty to update or revise these forward-looking statements. 

About Chaparral

Chaparral Energy (NYSE: CHAP) is an independent oil and natural gas exploration and production company headquartered in Oklahoma City. Founded in 1988, Chaparral is a pure-play operator focused in Oklahoma’s highly economic STACK Play, where it has approximately 127,000 net acres primarily in Kingfisher, Canadian and Garfield counties. The company has approximately 265,000 net surface acres in the Mid-Continent region. For more information, visit chaparralenergy.com.

Investor Contact	Media Contact
Al Petrie	Brandi Wessel
Al Petrie Advisors	Communications Manager
504-799-1953	405-426-6657
al@alpetrie.com	brandi.wessel@chaparralenergy.com

EX-99.2

J.P. Morgan High Yield & Leveraged Finance Conference February 2019 NYSE: CHAP NYSE:CHAP0

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, 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. NYSE: CHAP 1

Company Overview NYSE: CHAP 2

Chaparral Story High-growth, pure-play STACK/Merge oil company • 16.6 MBoe/d Q4 2018 estimated STACK production • 21.7 MBoe/d Q4 2018 estimated total production • 52% estimated full year 2018 STACK production growth Premier, contiguous acreage position • 127,000 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 ~95 MMBoe, a 35% increase from 2017, adjusted for 2018 divestitures • 2018 STACK proved reserves increased 49% compared Merge to 2017 • Decades of high-return inventory Highly efficient, low-cost STACK assets Average Average STACK Held By County Operated Non-Operated Acreage Production • $26.32/Boe Q3 YTD 2018 STACK cash margins WI WI • $4.95/Boe Q3 YTD 2018 STACK LOE cost Kingfisher ~34,000 ~96% 71% 16% Canadian ~22,000 ~99% 71% 14% Strong balance sheet Garfield ~52,000 ~38% 64% 19% • No long-term maturities until December 2022 Major ~6,000 ~98% 56% 16% Other ~13,000 ~100% 52% 13% NYSE: CHAP 3

2018 Chaparral Highlights • Issued $300mm in senior notes and increased undrawn borrowing base from $265mm to $325mm • Recorded STACK production growth of: • 6% Q3 2018 to Estimated Q4 2018 • 60% Q4 2017 to Estimated Q4 2018 • Grew STACK reserves by 49% from year-end 2017 to year-end 2018 • Replaced 519% of 2018 estimated STACK production • Completed successful partial section spacing test in Canadian County Merge acreage • De-risked ~50% of Garfield County and ~80% of Canadian County Merge acreage Operated Meramec and Osage Well Performance Above Type Curve Average Type Curve Time Period Gross Wells Lateral Length IP-301 Liquids WI IP-302 YTD Q3 2018 31 60% 4,672 feet 784 72% 709 1 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 2 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 NYSE: CHAP 4

2019 Strategy PURE-PLAY • Accelerate development in Canadian County Merge STACK/MERGE • Define optimal spacing across de-risked acreage COMPANY • Continue delineation and de-risking of Garfield acreage 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 Guidance 2019 Guidance Highlights 2019 Guidance Ranges ▲ from 2018 Production (MBoe/d) • Maintain capital discipline in volatile commodity Guidance environment Total Company 25.0 - 27.0 • Reducing operated rigs from 4 to 3 in Q2 2019 Q1 Total Company 20.5 - 21.5 STACK 21.0 - 23.0 • Allocate 80% of total capital to D&C in higher Q1 Total Company 15.5 - 16.5 return areas Capital ($mm) $275 - $300 • Operated D&C by County Operated STACK D&C $210 - $225 • ~60% Canadian County OBO STACK D&C $17.5 - $22.5 • ~20% Kingfisher County Lease Acquisition $12.5 - $17.5 • ~20% in Garfield County Other1 $35 • Reduce lease acquisition capital Expenses ($/Boe) Total LOE $5.00 - $5.50 • Reduce total company LOE/Boe STACK LOE $3.75 - $4.25 • Reduce Cash G&A/Boe Cash G&A Expense $2.85 - $3.35 1 Includes workovers, capitalized interest and capitalized G&A • Selective non-core asset sales ($5mm - $10mm) NYSE: CHAP 6

Operational Overview NYSE: CHAP 7

STACK/Merge Attributes • World-class Woodford source rock Favorable Geology • +700 feet of saturated hydrocarbon column • Multiple reservoir development opportunities • Robust service sector support Extensive Infrastructure • Numerous midstream alternatives • Abundant pipeline capacity Excellent Crude Net • Chaparral STACK: WTI less ~$1.00/Bbl1 1 Back • Bakken: WTI less ~$4.00/Bbl • Permian Basin: WTI less ~$7.00/Bbl2 • STACK Merge Miss: ~55% rate-of-return3 Top-quartile Economics • STACK Lower Osage: ~50% rate-of-return3 • STACK Meramec: ~45% rate-of-return3 3 1 Based on 2018 Q3 YTD company filings • STACK Upper Osage: ~30% rate-of-return 2 Based on 2018 Q3 YTD average WTI Midland variance to WTI 3 At February 19, 2019 NYMEX prices; five-year average prices $56.20 and $2.75 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 system STACK • Play attributes are identical – only rock thickness and GOR vary • MERGE represents intersection of historical SCOOP/STACK Play outlines Merge S Garfield Kingfisher Canadian STACK Merge NYSE: CHAP N S 9

STACK Break-Even Economics Oil Economics – WTI Basin Breakeven Estimates1 $45 $40 $35 $30 $25 Delaware STACK Midland SCOOP Eagle Ford Bakken Niobrara Oil Economics – Chaparral Counties of Focus1 $45 $35 $25 $15 Canadian Kingfisher Source: BMO Capital Markets equity research report 1 Data based on 2016-17 vintage public well production data NYSE: CHAP 10

Meramec Well Performance • Excellent recent operated well performance for Merge and STACK Meramec type curve areas • Actual oil results are in-line or exceeding current type curve expectations • Type curve rates-of-return: ~45% to ~55%1 Merge Actual Cumulative Oil STACK Meramec Actual Cumulative Oil vs. CHAP Type Curve 2 vs. CHAP Type Curve 2 90000 100000 80000 90000 70000 80000 70000 60000 60000 50000 50000 40000 40000 Cumulative BO Cumulative 30000 BO Cumulative 30000 Merge STACK Meramec 20000 20000 Merge Type Curve STACK Meramec Type Curve 10000 10000 0 0 Days on Production Days on Production 1 At February 19, 2019 NYMEX prices; five-year average prices $56.20 and $2.75 2 Cumulative results are scaled to type curve lateral length of 4,800 feet and include operated wells since June 30, 2017 NYSE: CHAP 11

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: ~30% to ~50%1 Upper Osage Actual Cumulative Oil Lower Osage Actual Cumulative Oil vs. CHAP Type Curve 2 vs. CHAP Type Curve 2 60000 100000 90000 50000 80000 40000 70000 60000 30000 50000 40000 Cumulative BO Cumulative 20000 Cumulative BO Cumulative Upper Osage 30000 Lower Osage 10000 20000 Upper Osage Type Curve Lower Osage Type Curve 10000 0 0 Days on Production Days on Production 1 At February 19, 2019 NYMEX prices; five-year average prices $56.20 and $2.75 2 Cumulative results are scaled to type curve lateral length of 4,800 feet and include operated wells since June 30, 2017 NYSE: CHAP 12

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 Cost Comparison ($/lateral foot) $1,200 $1,000 D&C ($/lateral foot) avg. $800 $600 $400 $200 $- CHAP Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 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 NYSE: CHAP 13

STACK/Merge Overview STACK/Merge Production 25 23.0 20 21.0 16.5 15 15.5 14.5 MBoe/d 10 9.5 5 7.3 0 2016 2017 FY 2018E FY 2019E STACK Production Guidance Range Q1 2019 Guidance (Low) Q1 2019 Guidance (High) Chaparral STACK/Merge Position • 127,000 net acres • 117 operated horizontal wells as of Q3 2018 • Excellent Merge acreage 100% held-by-production 1 Based on mid-point of 2019 production guidance NYSE: CHAP 14

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 maximum of ROR and NPV • Targeting/well density • Earth model derived from 3D seismic • Frac design for enhanced near wellbore SRV • Manage parent well communication risk NYSE: CHAP • Frac efficiency diagnostics for continuous learning 15

Systematic Approach to Spacing Development Canadian Kingfisher Denali King Koopa • Meramec partial spacing test • Meramec/Osage partial spacing test • Minimal inter-well communication • Minimal inter-well communication • Parent at pre-infill rates Foraker • Nearest child frac impacted • Meramec full section development • Woodford partial spacing test Jester • Build on Denali results • Meramec/Osage partial spacing test • Incorporated King Koopa learnings Kingfisher Non-Operated Hennessey Unit • 15 spacing tests • Meramec/Osage partial spacing test • Learn from others • Minimal capital exposure Optimized Development Plan Initial Indication: 6 - 8 Meramec/Osage Wells per Section NYSE: CHAP 16

Financial Overview NYSE: CHAP 17

Financial Strategy • 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 • $49 million in cash as of Q3 2018 plus undrawn revolver • 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/Merge 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: CHAP 18

Financial Position and Liquidity Highlights Chaparral Liquidity • Closed on a $300 million senior ($ in Millions) Q3 2018 unsecured notes offering on June 29, Actual Actual 2018 Cash and Cash Equivalents $49 • Paid down all outstanding borrowings Revolving Credit Facility due Dec. 2022 $0 on credit facility Other $21 • Continue to rationalize non-STACK assets to add liquidity Senior Notes $300 • Develop long runway to unlock value Total Debt $321 of deep STACK/Merge drilling Net Debt $272 inventory Undrawn Revolver Amount1 $325 1 Fall borrowing base redetermination increased borrowing base from $265mm to $325mm Chaparral Debt Maturity Schedule $500 $400 $300 No maturities until 2022 $200 $325 $300 $100 $- 2018 2019 2020 2021 2022 2023 2024 2025 2025+ Senior Notes Undrawn Revolver NYSE: CHAP 19

Why Chaparral? Strong Balance Sheet Experienced Execution-focused, Management with Pure-play STACK Excellent Track Operations Record 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 • Evaluating pipeline gathering alternatives direct to Cushing for several development sections 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 • 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 NYSE: CHAP 23

Commodity Realizations Crude Oil Differentials Oil & NGL Realizations as % of WTI 97% 99% • Proximity to numerous markets provides better CHAP 95% 93% 96% net back as compared to other basins $100 100% $90 90% • STACK crude oil quality meets Oklahoma refineries $80 80% specification $70 70% $60 60% • New trucking terminals and pipeline infrastructure $50 50% have reduced transportation costs, providing better net $40 40% back at the wellhead $30 44% 30% 38% 35% 37% % Realizations $20 31% 20% $10 10% WTI Average Daily Settle Daily WTI Average $0 0% NGL Differentials 2014 2015 2016 2017 YTD Q3 2018 • Increased pipeline capacity to the Gulf Coast to new WTI NGL % Oil % markets • Increased Gulf Coast demand, with new petrochemical Natural Gas Realizations as % of HH crackers coming online 98% • Access to Mont Belvieu and increased NGL export 92% capacity provided increased pricing to STACK $4.50 85% 87% 100% $4.00 75% 90% $3.50 80% $3.00 70% 60% $2.50 Natural Gas Differentials 50% $2.00 40% • Increased supply from STACK/SCOOP and other $1.50 30% basins competing for pipeline capacity has caused $1.00 20% % Realizations $0.50 10% Mid-Continent to widen Settle Daily Average HH $0.00 0% • New pipeline capacity out of STACK/SCOOP to south 2014 2015 2016 2017 YTD Q3 2018 and Gulf Coast will provide price strength for the basin Henry Hub Gas % NYSE: CHAP 24

Hedging Summary Hedge Positions1 2019 2020 2021 Crude Oil Swaps Hedge Volume (BBL) 2,428,200 2,007,000 689,300 Average Price ($/BBL) $56.17 $50.56 $46.24 Crude Oil Roll Hedge Volume (BBL) 530,000 410,000 150,000 Average Ceiling Price ($/BBL) $0.52 $0.38 $0.30 Natural Gas Swaps Hedge Volume (MMBTU) 12,461,500 4,800,000 Average Price ($/MMBTU) $2.852 $2.762 Natural Gas Collars Hedge Volume (MMBTU) 240,000 Average Ceiling Price ($/MMBTU) $5.070 Average Floor Price ($/MMBTU) $4.000 Natural Gas Basis Swaps (PEPL) Hedge Volume (MMBTU) 9,691,300 1,200,000 Average Price ($/MMBTU) ($0.627) ($0.480) NGL Swaps Propane Hedge Volume (BBL) 273,000 102,000 Propane Average Price ($/BBL) $31.08 $31.08 Natural Gasoline Hedge Volume (BBL) 118,000 45,000 Natural Gasoline Average Price ($/BBL) $58.40 $58.40 1 As of February 19, 2019 NYSE: CHAP 25

Core STACK & Merge Type Curve Overview STACK Osage, Meramec & Merge Miss North South Lower Upper Meramec Merge Woodford Woodford Osage 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 Woodford 70% 60% 50% 40% 30% IRR % 20% 10% 0% Meramec Merge North South Lower Upper Woodford Woodford Osage Osage $50.00/$2.75 $55.00/$3.00 $60.00/$3.25 2/19 NYMEX NYSE: CHAP 26

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 NYSE: CHAP 27

Highly Profitable Breakeven Acreage Recent Operated Performance 11 2 10 3 No. Well Name Spud Date IP-30 Boe/d Liquids 9 8 1 1 BARBEE 2105 1LMH-4 12/17/2017 1,122 69% 5 2 GLOCK 2205 1LMH-15 2/9/2018 913 61% 4 3 DOGWOOD 2205 1LMH-28 3/15/2018 1,193 54% 7 6 4 FUKSA 2007 1LMH-14 11/2/2017 710 83% 5 PEAR 2106 1LMH-23 5/6/2018 1,351 87% 6 PLATTER 2007 1LMH-36 3/29/2018 729 83% 16 12 7 COLONIAL 2007 1LMH-26 7/9/2018 621 92% 13 8 GERKEN 2205 1UMH-33 12/21/2017 1,063 55% 14 15 9 WHITE OAK 2206 1UMH-36 5/7/2017 892 53% 10 COTTONWOOD 2205 1UMH-34 3/1/2018 757 59% 11 BROWNING 2205 1UMH-22 1/26/2018 667 55% 12 LOW VALLEY 1807 1LMH-36 4/18/2017 1,335 82% 13 BRANDT 1707 1LMH-12 7/8/2017 885 86% 14 STAY PUFT 1707 1LMH-23 9/26/2017 863 86% 22 15 SLIMER 1707 1UMH-23 9/5/2017 719 85% 25 16 HIGH VALLEY 1807 1UMH-36 8/19/2017 652 77% 20 19 24 17 SHASTA 1106 1UMH-28 10/14/2017 1,368 70% 21 18 23 18 LASSEN 1107 1UMH-15 12/2/2017 1,218 73% 17 19 BANFF 1207 1UMH-29 3/23/2018 1,209 59% 20 KATMAI 1206 1UMH-29 2/7/2018 1,168 76% 21 KILIMANJARO 1106 1UMH-2 7/28/2017 1,044 78% 22 BEECHAM-HUNT 1307 1UMH-13 9/8/2017 927 72% 23 OLYMPUS 1107 1UMH-10 11/3/2017 823 72% 24 DENALI 1206 (3 Well Pad) 5/29/2018 1,214 75% 25 RAINIER 1206 1UMH-7 7/2/2018 889 60% MERAMEC • Garfield County Osage and Meramec wells demonstrating OSAGE solid results; 52,000-acre position 50% de-risked Chaparral Leasehold • Continued strong Kingfisher County Meramec and Osage well performance from de-risked acreage • Canadian County Merge Miss delivering Breakeven heat map from May 2018 SCOOP/STACK insights by RS Energy Group excellent results; 22,000-acre position 80% de-risked NYSE: CHAP 28

STACK Meramec and Merge Miss Overview Spud Peak IP‐301 Liquids1 Lateral Lease Operator Date Boe/d % Length  1 SLIMER 1707 #1UMH‐23 CHAPARRAL 9/5/2017 713 85% 4,839 2 HIGH VALLEY 1807 #1UMH‐36 CHAPARRAL 8/19/2017 682 77% 4,588 3 BIG TIMBER 1408 #1UMH‐2 CHAPARRAL 6/4/2017 799 82% 4,623 4 CATERPILLAR 1506 1‐11MH ALTA MESA 2/1/2018 717 85% 4,958 5 WINFIELD 1807 31‐1MH GASTAR 8/15/2017 657 82% 4,608 6 RHINO 8_5‐14N‐9W 1HX DEVON 7/22/2017 918 67% 10,054 7 JORDAN 10_15‐14N‐9W 1HX DEVON 4/17/2017 876 67% 10,050 8 H&W 1H‐28X NEWFIELD 1/15/2017 878 80% 9,713 9 RAINIER 1206 1UMH‐7  CHAPARRAL 7/2/2018 929 60% 4,595 10 DENALI  1206 (3 Well Pad) CHAPARRAL 5/29/2018 1,290 75% 4,548 11 BANFF 1207 #1UMH‐29 CHAPARRAL 3/23/2018 1,178 59% 4,926 12 HOOD 1006 #1UMH‐5 CHAPARRAL 3/2/2018 838 73% 4,840 13 KATMAI 1206 #1UMH‐29 CHAPARRAL 2/7/2018 1,262 76% 4,439 14 LASSEN 1107 #1UMH‐15 CHAPARRAL 12/2/2017 1,302 73% 4,490 15 OLYMPUS 1107 #1UMH‐10 CHAPARRAL 11/3/2017 934 72% 4,228 16 SHASTA 1106 #1UMH‐28 CHAPARRAL 10/14/2017 1,349 70% 4,869 17 BEECHAM‐HUNT 1307 #1UMH‐13 CHAPARRAL 9/8/2017 977 72% 4,394 18 KILIMANJARO 1106 1UMH‐2 CHAPARRAL 7/30/2017 1,105 78% 4,392 19 GAMBLE 3‐11‐6 3H JONES 11/10/2017 1,097 78% 4,467 20 JO 26‐35‐10‐6 1XH ROAN 9/23/2017 1,157 65% 10,055 21 GAMBLE 3‐11‐6 2H JONES 9/17/2017 1,123 78% 4,362 22 CANNONBALL 1208 24‐2MH 89 ENERGY 7/22/2017 1,086 68% 4,826 23 ROSEWOOD 16‐12‐7 2H JONES 6/9/2017 1,457 67% 4,625 24 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 ~45% ~55% Total EUR1 (MBoe) 584 1,023 % Liquids1 70% 66% Lateral Length (feet) 4,800 4,800 Well Cost ($mm) $4.0 $4.5 1 Gross three-phase scaled to type curve lateral length of 4,800 feet 2 At February 19, 2019 NYMEX prices; five-year average prices $56.20 and $2.75 NYSE: CHAP 29

STACK Osage Type Curves Overview Spud Peak IP‐301 Liquids1 Lateral Lease Operator Date Boe/d % Length  1 PEAR 2106 #1LMH‐23 CHAPARRAL 5/6/2018 1,326 87% 4,892 2 DOGWOOD 2205 1LMH‐28  CHAPARRAL 3/15/2018 1,182 54% 4,844 3 COTTONWOOD 2205 #1UMH‐34 CHAPARRAL 3/1/2018 766 59% 4,741 4 GLOCK 2205 #1LMH‐15 CHAPARRAL 2/9/2018 902 61% 4,855 5 BROWNING 2205 #1UMH‐22 CHAPARRAL 1/26/2018 675 55% 4,743 6 GERKEN 2205 #1UMH‐33 CHAPARRAL 12/21/2017 1,110 55% 4,594 7 BARBEE 2105 #1LMH‐4 CHAPARRAL 12/17/2017 1,224 69% 4,359 8 WHITE OAK 2206 #1UMH‐36 CHAPARRAL 5/7/2017 1,156 53% 4,743 9 PATRICIA 5‐21N‐5W 1MH WHITE STAR 5/2/2017 668 76% 4,686 10 PATRICIA 5‐21N‐5W 2MH WHITE STAR 4/14/2017 865 71% 4,194 11 COLONIAL 2007 #1LMH‐26 CHAPARRAL 7/9/2018 584 92% 5,108 12 PLATTER 2007 #1LMH‐36 (JV) CHAPARRAL 3/29/2018 721 83% 4,852 13 FUKSA 2007 #1LMH‐14  CHAPARRAL 11/2/2017 834 83% 4,087 14 STAY PUFT 1707 #1LMH‐23 CHAPARRAL 9/26/2017 863 86% 4,571 15 BRANDT 1707 #1LMH‐12 CHAPARRAL 7/8/2017 948 86% 4,482 16 LOW VALLEY 1807 #1LMH‐36 CHAPARRAL 4/18/2017 1,345 82% 4,766 17 DR J 1808 7‐1UOH GASTAR 10/1/2017 843 80% 4,593 18 BUGABAGO 2006 1‐31MH LONGFELLOW 3/5/2017 568 89% 5,064 Lower Upper Type Curve Osage Osage IP-301 (Boe/d) 599 744 ROR at NYMEX Strip2 ~50% ~30% Total EUR1 (MBoe) 629 853 % Liquids1 70% 54% Lateral Length (feet) 4,800 4,800 Well Cost ($mm) $3.9 $4.1 1 Gross three-phase scaled to type curve lateral length of 4,800 feet 2 At February 19, 2019 NYMEX prices; five-year average prices $56.20 and $2.75 NYSE: CHAP 30

STACK Woodford Type Curves Overview Spud Peak IP‐301 Liquids1 Lateral Lease Operator Date Boe/d % Length  1 CUTTHROAT 1307 1WH‐13 CHAPARRAL 2/11/2017 588 76% 4,225 2 GLACIER 11‐14‐12‐6 1HX JONES 12/31/2017 463 63% 9,890 3 ACADIA 13‐12‐12‐6‐1HX JONES 12/9/2017 581 65% 7,277 4 EVEREST 1107 #1WH‐24 CHAPARRAL 2/12/2018 451 59% 4,451 5 KATMAI 1206 #1WH‐29 CHAPARRAL 1/5/2018 405 61% 4,086 6 LASSEN 1107 #1WH‐15 CHAPARRAL 11/24/2017 499 64% 4,021 7 OLYMPUS 1107 #1WH‐10 CHAPARRAL 11/13/2017 462 58% 4,122 8 FRANK EATON 36‐1‐11‐6 1XH ROAN 2/3/2018 454 80% 9,941 9 LOUDERMILK 1H‐32‐29 ROAN 12/3/2017 490 60% 10,182 10 ASHCRAFT 1‐19H CIMAREX 9/20/2017 640 63% 5,172 11 COWBOY 1H‐34‐3 ROAN 8/30/2017 402 60% 9,282 12 CANNONBALL 1208 24‐1WH 89 ENERGY 7/21/2017 769 62% 4,639 13 RAFTER J 1H‐17‐20 ROAN 7/16/2017 1,059 57% 8,423 14 ROSEWOOD 16‐12‐7 3H JONES 7/3/2017 933 69% 4,465 North South Type Curve Woodford Woodford IP-301 (Boe/d) 475 736 ROR at NYMEX Strip2 ~30% ~50% Total EUR1 (MBoe) 579 1,456 % Liquids1 72% 62% Lateral Length (feet) 4,800 4,800 Well Cost ($mm) $4.4 $4.4 1 Gross three-phase scaled to type curve lateral length of 4,800 feet 2 At February 19, 2019 NYMEX prices; five-year average prices $56.20 and $2.75 NYSE: CHAP 31

Non-Core Legacy Asset Overview • Mature legacy fields • Low-maintenance capital • Provides free cash flow to fuel STACK growth • Potential strategic alternatives Net Production1 Gross Margin1 Net Proved Reserves Area Boe/d % Oil $/Boe MMBoe2 PV-102 ($mm) Miss Lime 2,018 29% $19.98 6.8 $45.4 Western Anadarko Basin 955 14% $12.04 7.9 $46.9 Southern OK 1,679 60% $27.74 7.3 $67.8 Other 1,032 41% $20.53 4.9 $38.0 TOTAL 5,685 38% $21.03 26.9 $198.0 TOTAL Incl. ARO 5,685 38% $21.03 26.9 $187.4 1 Q3 2018 actuals 2 At year-end 2017 SEC prices of $51.34 and $2.98 NYSE: CHAP 32

Year-End 2017 Proved Reserves Grew STACK year-end 2017 reserves by 58% Replaced 604% of 2017 STACK production at $7.26/Boe F&D cost 76.3 MMBoe of Reserves1 39% Oil, 63% Liquids Reserves by Area 24% 25.6 39% 26.9 49.4 1.1 49.7 37% PDP PDNP PUD OIL GAS NGL STACK OTHER YE ‘17 Total Proved Reserves PV-10 Net Oil Net Gas Net NGL Net % of Total SEC Reserve Category (MMBo) (BCF) (MMBo) (MMBoe) Proved Pricing1 PDP 18.1 119.4 11.7 49.7 65% 427.1 PNP 0.2 4.1 0.2 1.1 1% 6.0 PUD 11.3 46.7 6.5 25.6 34% 77.4 Total Proved 29.6 170.2 18.3 76.3 100% 510.5 STACK 18.7 107.4 12.8 49.4 65% 312.5 OTHER 10.9 62.8 5.6 26.9 35% 198.0 Total Proved 29.6 170.2 18.3 76.3 100% 510.5 Total Proved Inc. ARO 29.6 170.2 18.3 76.3 100% 497.9 1 At year-end 2017 SEC prices of $51.34 and $2.98 Note: Numbers may not add due to rounding NYSE: CHAP 33

STACK Drilling Joint Venture • Joint venture between Chaparral and Bayou City Energy (BCE) • Accelerate development of 127,000 STACK acres • 20 wells drilled and producing as of Q3 2018 • Key driver in de-risking Garfield 50% and Canadian County Merge 80% to date STACK • 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 Merge 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 NYSE: CHAP 34

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 35

Reconciliations Successor Three Months Three Months Ended Ended (in thousands) Sept 30, 2018 Sept 30, 2017 Net (loss) income $ (12,068) $ (19,115) Interest expense 4,205 5,283 Income tax expense — 37 Depreciation, depletion, and amortization 22,252 32,167 Non-cash change in fair value of derivative instruments 16,804 22,236 Impact of derivative repricing (1,698) — Interest income (7) (4) Stock-based compensation expense 2,304 2,776 (Gain) loss on sale of assets 2,024 13 Restructuring, reorganization and other 493 892 Adjusted EBITDA $ $34,309 $ 44,285 (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 NYSE: CHAP 36

Reconciliations 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 597 (C) (excluding price revisions) Capital Costs Incurred (in thousands) STACK Only $166,758 (D) (includes D&C, acquisitions and enhancements) STACK Only $156,183 (E) (excludes capitalized interest and capitalized G&A) STACK Reserve Replacement 604% (B)/(A) All-in STACK F&D $7.26 (E)/(B+C) NYSE: CHAP 37

Contact Information Chaparral Energy, Inc. 701 Cedar Lake Boulevard Oklahoma City, OK 73114 Investors Media Al Petrie Brandi Wessel Al Petrie Advisors Manager – Communications al@alpetrie.com brandi.wessel@chaparralenergy.com 504-799-1953 405-426-6657 NYSE: CHAP 38

ENERGIZING America’s Heartland NYSE: CHAP chaparralenergy.com NYSE: CHAP 39