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): March 14, 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

On March 14, 2019, Chaparral Energy, Inc. (the “Company”) issued a press release announcing its financial and operational results for the year ended December 31, 2018 and conference call information in connection therewith. A copy of the press release is attached hereto as Exhibit 99.1.

Item 7.01. Regulation FD Disclosure

On March 14, 2019, the Company posted a new presentation titled “Investor Presentation - March 2019,” under the “Investors–Presentations” section of the Company’s website, www.chaparralenergy.com/investors. The presentation is attached hereto as Exhibit 99.2.

The Company’s press release, announcing its financial and operational results for the year ended December 31, 2018, and its presentation contain 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 quantitative reconciliations within the press release and presentation 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 set forth in this Item 2.02 and Item 7.01 of this current report on Form 8-K, including Exhibit 99.1 and Exhibit 99.2 attached hereto, is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), or otherwise subject to the liabilities of that Section, nor shall it be deemed incorporated by reference into any filings under the Securities Act of 1933, as amended, or the Exchange Act, whether made before or after the date hereof and regardless of any general incorporation language in such filings, except to the extent expressly set forth by specific reference in such a filing. The filing of this Current Report on Form 8-K shall not be deemed an admission as to the materiality of any information herein that is required to be disclosed solely by reason of Regulation FD.

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	Press release of Chaparral Energy, Inc. dated March 14, 2019.
99.2	March 2019 Investor 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.

March 14, 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 Fourth Quarter and Full Year 2018 Financial and Operational Results

Oklahoma City, March 14, 2019 -Chaparral Energy, Inc. (NYSE: CHAP) announced today its fourth quarter and full year 2018 financial and operational results with the filing of its form 10-K. The company will hold its financial and operating results call this morning, March 14 at 9 a.m. Central.

2018 Highlights

• Recorded 2018 full year STACK production of 14.5 thousand barrels of oil equivalent per day (MBoe/d), representing a 52% year-over-year increase

• Achieved 2018 full year total company production of 20.5 MBoe/d

• Reported full year 2018 net income of $33.4 million, or 73 cents per diluted share

• Achieved full year 2018 adjusted EBITDA, as defined below, of $125 million

• Grew 2018 total proved reserves to 94.8 million barrels of oil equivalent (MMBoe), which adjusted for 2018 divestitures marks a 35% year-over-year increase, and represents a PV-10 value of $686 million

◦ Increased STACK proved reserves by 50% year-over-year to 74.1 MMBoe, while replacing 519% of STACK production

• Invested $194.7 million in STACK drilling and completion (D&C) activities in 2018

• Reduced total company lease operating expense per barrel of oil equivalent (LOE/Boe) almost $4 from $10.96 in 2017 to $7.24 in 2018

• Strengthened the balance sheet by issuing $300 million of unsecured senior notes and increasing the borrowing base to $325 million in 2018

“Our team is extremely proud of all we accomplished in 2018,” said Chief Executive Officer Earl Reynolds. “From strategically adding to our STACK acreage position to uplisting to the New York Stock Exchange to successfully completing a $300 million senior notes offering and increasing our borrowing base, we were able to increase the value of our assets while also strengthening our balance sheet. In addition, our outstanding operational and drilling results allowed us to significantly grow production and reserves in 2018.”

“While we continue to monitor market conditions and plan to be flexible with our capital expenditures, our current plan for 2019 is to invest $275 to $300 million in capital, more than 80% of which is dedicated to low-cost, high-return STACK/Merge D&C activity. Chaparral remains committed to low-cost operations, as is evident in our cost per lateral drilling foot, efficient frac designs and systematic development approach. This focus will continue to drive our efforts as we move toward partial and full section development, with additional spacing tests throughout the first half of 2019 across Canadian and Kingfisher counties. We are extremely proud of the differentiated STACK position we have built. We will continue to prudently manage our capital and protect our balance sheet as we grow production and reserves, work to become cash flow neutral and deliver long-term value for our shareholders.”

Operational Update - STACK Production Soars in 2018

Chaparral increased its STACK production to 16.6 MBoe/d during the fourth quarter, which is up 6% as compared to the previous quarter. Full year STACK production grew by 52% to 14.5 MBoe/d compared to the previous year. Total company production was 21.7MBoe/d during the fourth quarter, which is a 2% quarter-over-quarter increase. Total company production for the full year was 20.5 MBoe/d, which represents an 11% decrease from the previous year. Excluding production from divested EOR assets in 2017, total company production increased by 13% on a year-over-year basis. Total company production for 2018 was 36% oil, 25% natural gas liquids (NGLs) and 39% natural gas.

Chaparral operated four drilling rigs during the fourth quarter of 2018. The company brought 13 new gross operated STACK wells on production during the quarter, two of which were part of its drilling joint venture. For the full year 2018, Chaparral brought 48 gross operated STACK wells online, of which 20 were in Garfield County, 18 in

Canadian County and 10 in Kingfisher County. This includes 19joint venture wells. Additional details on recent well results are included in the company’s current investor presentation, which is available on the investors page of its website.

Overall, 2018 average results from the company’s Meramec and Osage programs continued to exceed type curve expectations. The company believes it has de-risked more than 50% of its Garfield County position, as well as 80% of its Canadian County Merge position. The table below represents the average results of the Meramec and Osage wells, which had first production in 2018.

Reservoir Target	Gross Wells	Average WI	Lateral Length	IP-301	Liquids	Type Curve IP-302
Meramec & Osage	44	63%	4,691	750	73%	709

¹IP 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

Chaparral’s total oil and natural gas capital expenditures (CAPEX) during the fourth quarter were $76 million, of which $67.7million was associated with the STACK. Of its STACK CAPEX, $55.4 million was related to D&C activities, which included $4.2 million of non-operated CAPEX and $5.4 million of inflation driven drilling joint venture CAPEX. Additionally, $10.7 million was spent on acquisition activities, including $5.1million in non-cash acreage trades. The company’s oil and natural gas CAPEX for the full year 2018 was $341 million, of which STACK CAPEX D&C was $194.7 million. STACK D&C CAPEX includes $38 million of non-operated CAPEX and $13.2 million of inflation driven drilling joint venture CAPEX. The company also invested $111.4 million in STACK acquisitions, including $54.8 million for its 7,000-acre, bolt-on acquisition in Kingfisher County, $10.9 million in non-cash acreage trades and $7.7 million for seismic data.

Chaparral acquired 24,600 net acres through leasing and poolings associated with its D&C activities in 2018 and drilled or participated in 165 gross (37 net) horizontal STACK wells. The table below summarizes total oil and natural gas capital expenditures for the fourth quarter and full year 2018.

Capital Expenditures (in millions)	Q4 2018	Full Year 2018
STACK Acquisitions1	$10.7	$111.4
STACK D&C2	$55.4	$194.7
STACK Enhancements	$1.6	$4.8
Total STACK	$67.7	$310.9
OtherEnhancements	$0.6	$6.2
Corporate Allocations3	7.7	$23.9
Total CAPEX	$76.0	$341.0

¹For Q4 2018 and full year 2018, includes non-cash acreage trades of $5.1 million and $10.9 million respectively.

²For Q4 2018 and full year 2018, includes non-operated of $4.2 million and $38.0 million respectively and $5.4 million and $13.2 million of drilling joint venture respectively

³For Q4 2018 and full year 2018, includes capitalized G&A, capitalized interest and asset retirement obligations

2018 Reserves

Chaparral previously announced year-end SEC 2018 proved reserves of 94.8 MMBoe, which adjusted for 2018 divestitures, marks a 35% year-over-year increase. The company’s reserve estimates were prepared by third-party reserve consultant Cawley, Gillespie and Associates. The net present value of the company’s year-end SEC proved reserves, discounted at 10%, was approximately $686 million. This marks a 38% increase compared to the previous year. Chaparral’s reserves were classified as 59% proved developed and were 34% oil, 27% NGLs and 39% natural gas.

Proved reserves for Chaparral’s STACK assets increased 50% on a year-over-year basis, from 49.4 MMBoe to 74.1 MMBoe. In the STACK, Chaparral replaced 519% of 2018 STACK production, with a drillbit finding and development cost of $7.80 per Boe. The following table illustrates the change in Chaparral’s estimated net proved reserves from December 31, 2017 to December 31, 2018.

Total Proved Developed and Undeveloped Reserves

	Oil (MBbls)	Natural Gas (MMcf)	NGLS (MBbls)	Total (MBoe)
As of December 31, 2017	29,604	170,166	18,322	76,287
Revisions	1,254	12,596	1,411	4,7641
Extensions and Discoveries	6,545	69,189	9,329	27,406
Divestitures	(2,422)	(14,184)	(1,374)	(6,160)1
Production	(2,684)	(17,549)	(1,881)	(7,490)
As of December 31, 2018	32,297	220,218	25,807	94,807

¹STACK only revisions, excluding the impact of price, were 623 MBoe

Financial Summary

Chaparral reported net income of $79 million, or $1.73 per diluted share, during the fourth quarter of 2018 and $33.4 million for the full year, or 73 cents per diluted share. Net income in the fourth quarter and full year was driven by a $94 million and $38 million non-cash change in fair value of hedge derivative instruments, respectively. Chaparral’s adjusted EBITDA for the fourth quarter was virtually flat on a quarter-over-quarter basis at $34.4 million. The company’s full year 2018 adjusted EBITDA was $125 million. Its adjusted EBITDA, as well as its production, revenues and expenses mentioned in this release were impacted on a year-over-year basis by the sale of its EOR assets in November 2017, as well as other non-core asset sales.

Total gross commodity sales for the fourth quarter of 2018 were $65.1 million, which included $39.4 million from oil, $10.8 million from NGLs and $14.9 million from natural gas. For the full year, Chaparral recorded $258.8 million in total gross commodity sales, including $171.7 million from oil, $45.6 million from NGLs and $41.5 million in natural gas. This represents a 12% year-over-year decline compared to $293 million in 2017.

Chaparral’s average realized price for crude oil, excluding derivative settlements, decreased to $58.06 per barrel in the fourth quarter of 2018. For the full year, however, the company’s realized crude oil price increased 31% on a year-over-year basis to $63.99. Chaparral’s realized NGL price during the quarter was $22.84 per barrel and $24.24 per barrel for the full year, which represents a 7% year-over-year increase. The company’s realized natural gas price during the quarter was $2.95 per thousand cubic feet (Mcf) and $2.37 per Mcf for the year, which represents a decrease of 10% compared to 2017.

Total company LOE for the fourth quarter of 2018 was $12.1 million, or $6.11 per Boe, which was down 4% on a quarter-over-quarter basis compared to $6.36 per Boe in the third quarter. Chaparral’s STACK LOE/Boe for the fourth quarter was up slightly from $4.34 in the previous quarter to $4.64. For the full year, total company LOE/Boe was down significantly from $10.96 in 2017 to $7.24 in 2018. This decrease was driven primarily by the sale of its EOR properties in 2017 and other non-core divestitures executed in 2018. Full year STACK LOE/Boe was $4.86 compared to $4.31 in 2017.

Chaparral’s net G&A expense was $10 million, or $5.05 per Boe, during the fourth quarter of 2018 and $38.8 million, or $5.18 per Boe, for the full year 2018. Adjusted for non-cash compensation, the company’s cash G&A expense per Boe in the fourth quarter was $3.91 and $3.73 for full year 2018.

Divestitures

The company divested of $50.5 million in non-core assets in 2018, including portions of its legacy and Oklahoma/Texas Panhandle acreage, as well as portions of its saltwater disposal infrastructure. At the time of sale, these properties accounted for approximately 1.9 MBoe/d of production.

Balance Sheet and Liquidity

As of December 31, 2018, Chaparral had approximately $37.4 million in cash and cash equivalents and no borrowings under its $325 million borrowing base. As of March 8, 2019, the company had $29.1 million of cash and cash equivalents and $30 million of borrowings under its $325 million borrowing base. The company’s balance sheet remains strong with no significant debt maturities due until 2022.

In 2018, the company had a non-cash ceiling test impairment of $20.1 million associated with non-core leasehold outside of the STACK, which it does not intend to develop. There is currently no production associated with this acreage.

2019 Guidance

Chaparral expects total company production to be between 25 and 27 MBoe/d, which marks a 22% to 32% year-over-year growth. Total STACK production is forecasted to increase to 21 to 23 MBoe/d or 45% to 59% on a year-over-year basis. First quarter production is expected to be impacted by the timing of first sales associated with Chaparral’s spacing tests and remaining joint venture wells. Only approximately 10% of the company’s 2019 operated D&C program’s net wells are estimated to record first sales during the first quarter, while its 11-well Canadian County Merge spacing test is slated to come online during the second quarter.

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

The company’s 2019 acquisition budget is expected to be significantly less than in 2018. It plans to invest between $12.5 and $17.5 million on acquisitions primarily associated with acreage poolings in support of its operated D&C program.

Total company LOE/Boe for 2019 is estimated to be between $5.00 and $5.50, while its STACK LOE/Boe is expected to be between $3.75 and $4.25. Chaparral’s cash G&A expense per Boe cost is expected to be between $2.85 and $3.35.

	1Q19E1	2019E
Total Company Average Daily Production (MBoe/d)	20.5 - 21.5	25.0 - 27.0
STACK Average Daily Production (MBoe/d)	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.

Financial Guidance (in millions unless otherwise stated)	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

¹Includes workovers, capitalized interest and capitalized G&A

Earnings Call Information

Chaparral will hold its financial and operating results call this morning, Thursday, March 14, 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. A live webcast of the call will also 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.

The company has also provided an updated investor presentation for the quarter, which along with its form 10-K, is available 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 131,000 net acres primarily in Kingfisher, Canadian and Garfield counties. The company has approximately 260,000 net surface acres in the Mid-Continent region. For more information, visit chaparralenergy.com.

Investor Contact	Media Contact
Scott Pittman	Brandi Wessel
Chief Financial Officer	Communications Manager
405-426-6770	405-426-6657
investor.relations@chaparralenergy.com	brandi.wessel@chaparralenergy.com

Chaparral Energy, Inc. and Subsidiaries

Consolidated Statements of Operations

(Unaudited)

	Successor						Predecessor
	Period from			Period from			Period from			Period from
	January 1, 2018			March 22, 2017			January 1, 2017			January 1, 2016
	through			through			through			through
(in thousands, except share and per share data)	December 31, 2018			December 31, 2017			March 21, 2017			December 31, 2016
Revenues:
Commodity sales	$	242,569		$	226,493		$	66,531		$	252,152
Sublease revenue	4,793			586			—			—
Total revenues	247,362			227,079			66,531			252,152
Costs and expenses:
Lease operating	54,219			72,132			19,941			90,533
Transportation and processing	—			9,503			2,034			8,845
Production taxes	13,150			11,750			2,417			9,610
Depreciation, depletion and amortization	87,888			92,599			24,915			122,928
Loss on impairment of oil and gas assets	20,065			42,146			—			281,079
Loss on impairment of other assets	—			179			—			1,393
General and administrative	38,793			39,617			6,843			20,953
Liability management	—			—			—			9,396
Cost reduction initiatives	1,034			691			629			2,879
Other	2,036			3,728			—			—
Total costs and expenses	217,185			272,345			56,779			547,616
Operating income (loss)	30,177			(45,266		)	9,752			(295,464		)
Non-operating (expense) income:
Interest expense	(11,383		)	(14,147		)	(5,862		)	(64,242		)
Loss on extinguishment of debt	—			(635		)	—			—
Non-hedge derivative gains (losses)	19,297			(30,802		)	48,006			(22,837		)
Write-off of Senior Note issuance costs, discount and premium	—			—			—			(16,970		)
(Loss) gain on sale of assets	(2,582		)	(25,996		)	206			(117		)
Other income, net	248			686			1,167			528
Net non-operating (expense) income	5,580			(70,894		)	43,517			(103,638		)
Reorganization items, net	(2,392		)	(3,091		)	988,727			(16,720		)
Income (loss) before income taxes	33,365			(119,251		)	1,041,996			(415,822		)
Income tax (benefit) expense	(77		)	(349		)	37			(102		)
Net income (loss)	$	33,442		$	(118,902	)	$	1,041,959		$	(415,720	)
Earnings per share:
Basic for Class A and Class B	$	0.74		$	(2.64	)	*			*
Diluted for Class A and Class B	$	0.73		$	(2.64	)	*			*
Weighted average shares used to compute earnings per share:
Basic for Class A and Class B	45,288,980			44,984,046			*			*
Diluted for Class A and Class B	45,730,171			44,984,046			*			*

Chaparral Energy, Inc. and Subsidiaries

Consolidated Balance Sheets

(Unaudited)

	December 31,
(dollars in thousands, except share data)	2018			2017
Assets
Current assets:
Cash and cash equivalents	$	37,446		$	27,732
Accounts receivable, net	66,087			60,363
Inventories, net	4,059			5,138
Prepaid expenses	2,814			2,661
Derivative instruments	24,025			—
Total current assets	134,431			95,894
Property and equipment, net	43,096			50,641
Oil and natural gas properties, using the full cost method:
Proved	915,333			634,294
Unevaluated (excluded from the amortization base)	466,616			482,239
Accumulated depreciation, depletion, amortization and impairment	(221,431		)	(124,180		)
Total oil and natural gas properties	1,160,518			992,353
Derivative instruments	2,199			—
Other assets	425			418
Total assets	$	1,340,669		$	1,139,306
Liabilities and stockholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	73,779		$	75,414
Accrued payroll and benefits payable	10,976			11,276
Accrued interest payable	13,359			187
Revenue distribution payable	26,225			17,966
Long-term debt and capital leases, classified as current	3,479			3,273
Derivative instruments	—			8,959
Total current liabilities	127,818			117,075
Long-term debt and capital leases, less current maturities	303,992			141,386
Derivative instruments	1,542			4,167
Deferred compensation	540			696
Asset retirement obligations	22,090			33,216
Commitments and contingencies (Note 17)
Stockholders’ equity:
Preferred stock	—			—
Class A Common stock	467			389
Class B Common stock	—			79
Additional paid in capital	974,616			961,200
Treasury stock	(4,936		)	—
Accumulated deficit	(85,460		)	(118,902		)
Total stockholders' equity	884,687			842,766
Total liabilities and stockholders' equity	$	1,340,669		$	1,139,306

Chaparral Energy, Inc. and subsidiaries

Consolidated Statements of Cash Flows

(Unaudited)

	Successor						Predecessor
	Period from			Period from			Period from			Period from
	January 1, 2018			March 22, 2017			January 1, 2017			January 1, 2016
	through			through			through			through
(in thousands)	December 31, 2018			December 31, 2017			March 21, 2017			December 31, 2016
Cash flows from operating activities
Net income (loss)	$	33,442		$	(118,902	)	$	1,041,959		$	(415,720	)
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Non-cash reorganization items	—			—			(1,012,090		)	—
Depreciation, depletion and amortization	87,888			92,599			24,915			122,928
Loss on impairment of assets	20,065			42,325			—			282,472
Write-off of Senior Note issuance costs, discount and premium	—			—			—			16,970
Deferred income taxes	—			—			—			—
Derivative losses (gains)	(19,297		)	30,802			(48,006		)	22,837
Loss (gain) on sale of assets	2,582			25,996			(206		)	117
Loss on extinguishment of debt	—			635			—			—
Other	5,470			1,573			645			3,611
Change in assets and liabilities:
Accounts receivable	(6,337		)	(12,092		)	198			(9,243		)
Inventories	236			(489		)	466			3,576
Prepaid expenses and other assets	(160		)	3,245			(497		)	(1,620		)
Accounts payable and accrued liabilities	3,441			2,622			8,733			25,987
Revenue distribution payable	8,649			6,941			(1,875		)	509
Deferred compensation	10,262			9,714			143			(5,257		)
Net cash provided by operating activities	146,241			84,969			14,385			47,167
Cash flows from investing activities
Expenditures for property, plant, and equipment and oil and natural gas properties	(324,063		)	(157,718		)	(31,179		)	(146,296		)
Proceeds from asset dispositions	50,523			189,735			1,884			1,349
Proceeds from (payments for) derivative instruments	(18,510		)	15,676			1,285			90,590
Cash in escrow	—			42			—			48
Net cash (used in) provided by investing activities	(292,050		)	47,735			(28,010		)	(54,309		)
Cash flows from financing activities
Proceeds from long-term debt	116,000			33,000			270,000			181,000
Repayment of long-term debt	(243,722		)	(176,407		)	(444,785		)	(1,952		)
Issuance of Senior Notes	300,000			—			—			—
Proceeds from rights offering, net	—			—			50,031			—
Principal payments under capital lease obligations	(2,683		)	(2,017		)	(568		)	(2,491		)
Treasury stock purchased	(4,936		)	—			—			—
Payment of other financing fees	(9,136		)	(4,671		)	(2,410		)	—
Net cash provided by (used in) financing activities	155,523			(150,095		)	(127,732		)	176,557
Net increase (decrease) in cash and cash equivalents	9,714			(17,391		)	(141,357		)	169,415
Cash and cash equivalents at beginning of period	27,732			45,123			186,480			17,065
Cash and cash equivalents at end of period	$	37,446		$	27,732		$	45,123		$	186,480

Non-GAAP Financial Measures and Reconciliations

Adjusted EBITDA is a Non-GAAP financial measure and is described and reconciled to net income in the table “Adjusted EBITDA Reconciliation, NON-GAAP.”

Adjusted EBITDA Reconciliation, Non-GAAP

	Successor						Predecessor
	Period from			Period from			Period from			Period from
	January 1, 2018			March 22, 2017			January 1, 2017			January 1, 2016
	through			through			through			through
(in thousands)	December 31, 2018			December 31, 2017			March 21, 2017			December 31, 2016
Net income (loss)	$	33,442		$	(118,902	)	$	1,041,959		$	(415,720	)
Interest expense	11,383			14,147			5,862			64,242
Income tax (benefit) expense	(77		)	(349		)	37			(102		)
Depreciation, depletion, and amortization	87,888			92,599			24,915			122,928
Non-cash change in fair value of non-hedge derivative instruments	(37,807		)	46,478			(46,721		)	176,607
Impact of derivative repricing	(5,649		)	—			—			—
Loss (gain) on settlement of liabilities subject to compromise	48			—			(372,093		)	—
Fresh start accounting adjustments	—			—			(641,684		)	—
Upfront premiums paid on settled derivative contracts	—			—			—			(20,608		)
Proceeds from monetization of derivatives with a scheduled maturity date more than 12 months from the monetization date excluded from EBITDA	—			—			—			(12,810		)
Interest income	(12		)	(21		)	(133		)	(188		)
Stock-based compensation expense	10,873			9,833			155			(5,238		)
Loss (gain) on sale of assets	2,582			25,996			(206		)	117
Loss on extinguishment of debt	—			635			—			—
Write-off of debt issuance costs, discount and premium	—			—			1,687			16,970
Loss on impairment of assets	20,065			42,325			—			282,472
Restructuring, reorganization and other	2,344			7,313			24,297			19,599
Adjusted EBITDA	$	125,080		$	120,054		$	38,075		$	228,269

STACK Drillbit F&D and Reserve Replacement

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 (excluding price revisions)	597			623			(C)
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)

EX-99.2

Investor Presentation March 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, 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 • 14.4 MBoe/d 2018 STACK production • 20.5 MBoe/d 2018 total production • 52% full year 2018 STACK production growth Premier, contiguous acreage position • 131,000 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 • 2018 STACK proved reserves increased 50% 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 • $25.59/Boe 2018 STACK cash margins WI WI • $4.86/Boe 2018 STACK LOE cost Kingfisher ~34,000 ~98% 72% 16% Canadian ~22,000 ~99% 66% 15% Strong balance sheet Garfield ~55,000 ~38% 64% 19% • No long-term maturities until December 2022 Major ~6,000 ~98% 52% 16% Other ~14,000 ~100% 51% 10% NYSE: CHAP 3

2018 Chaparral Highlights • Issued $300mm in senior notes and increased undrawn borrowing base from $265 to $325 million • Recorded STACK production growth of: • 60% Q4 2017 to Q4 2018 • 52% full-year 2017 to full-year 2018 • Increased total proved reserves by 24% as compared to 2017 (35% after adjusting for 2018 divestitures) • Grew STACK proved reserves by 50% as compared to 2017 • STACK PV-10 increase of 66% as compared to 2017 • 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 2018 44 63% 4,691 feet 750 73% 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

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 Reserves YE ‘18 Total Proved Reserves PV-10 Reserve Net Oil Net Gas Net NGL Net % of Total SEC Strip Category (MMBo) (BCF) (MMBo) (MMBoe) Proved Pricing1 Pricing2 PDP 17.3 131.3 14.4 53.6 57% 517.1 411.4 PNP 0.7 4.1 0.5 1.9 2% 23.2 18.6 PUD 14.2 84.8 11.0 39.3 41% 154.1 79.8 Total Proved 32.3 220.2 25.8 94.8 100% 694.4 509.8 STACK 23.3 173.0 22.0 74.1 78% 519.5 376.2 OTHER 9.0 47.3 3.8 20.7 22% 174.9 133.6 Total Proved 32.3 220.2 25.8 94.8 100% 694.4 509.8 Total Proved Inc. 32.3 220.2 25.8 94.8 100% 686.4 501.8 ARO 1 At year-end 2018 SEC prices of $65.56 and $3.10 2 At February 28, 2019 NYMEX prices; five-year average prices of $56.20 and $2.80 Note: Numbers may not add due to rounding NYSE: CHAP 5

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 6

2019 Guidance 2019 Guidance Highlights FY 2018 FY 2019 YoY Actual Guidance Change • Maintain capital discipline in volatile commodity Production (MBoe/d) environment Total Company 20.5 25.0 - 27.0 • Reducing operated rigs from four to three in Q2 Q1 Total Company 20.5 - 21.5 2019 STACK 14.5 21.0 - 23.0 • Reducing total capital expenditures Q1 STACK 15.5 - 16.5 Capital ($mm) • Allocate 80% of total capital to D&C in higher Operated D&C $157 $210 - $225 return areas Non-Operated D&C $38 $17.5 - $22.5 • Operated D&C by County Lease Acquisitions1 $100 $12.5 - $17.5 • ~60% Canadian County Other Capital2 $35 $35 • ~20% Kingfisher County Total CAPEX $330 $275 - $300 • ~20% in Garfield County Proceeds from Asset Sales $51 $5 - $10 • Reducing lease acquisition capital Expenses ($/Boe) • Reducing total company LOE/Boe LOE $7.24 $5.00 - $5.50 • Reducing STACK LOE/Boe STACK LOE $4.78 $3.75 - $4.25 • Reducing Cash G&A/Boe Cash G&A $3.73 $2.85 - $3.35 1 2018 excludes ~11mm in non-cash acreage trades 2 Includes Enhancements, Capitalized G&A, Capitalized Interest and ARO • Selective non-core asset sales ($5 - $10 million) NYSE: CHAP 7

Operational Overview NYSE: CHAP 8

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 ~$0.80/Bbl1 1 Back • Bakken: WTI less ~$5.50/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 company filings • STACK Upper Osage: ~30% rate-of-return 2 Based on 2018 average WTI Midland variance to WTI • 3 At February 28, 2019 NYMEX prices; five-year average prices of $56.20 and $2.80 NYSE: CHAP 9

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 10

Oil Price Breakevens for US 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 US NYSE: CHAP 11

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 2018 FY 2019E STACK Production Guidance Range Q1 2019 Guidance (Low) Q1 2019 Guidance (High) Chaparral STACK/Merge Position • 131,000 net acres • 131 operated horizontal wells as of year-end 2018 • Excellent Merge acreage ~100% held-by-production 1 Based on mid-point of 2019 production guidance NYSE: CHAP 12

Operational Excellence – Drilling and Completions Strong, Effective Focus on Cost Control • Chaparral Osage and Meramec D&C represents top tier in normal pressure STACK • Low well cost and consistent production results produce excellent returns D&C Cost Comparison ($/lateral foot) $1,400 $1,200 $1,000 D&C ($/lateral foot) avg. $800 $600 $400 $200 $- Peer 1 CHAP Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Source: Company presentations Note 1: CHAP includes average for Osage and Meramec and assumes multi-well pad development Note 2: Peers include AMR, CLR, DVN, JONE, MRO, and XEC NYSE: CHAP 13

Meramec Well Performance • Excellent recent operated well performance for Merge and STACK Meramec type curve areas • Average results are exceeding or in-line with current type curve expectations • Type curve rates-of-return: ~45% to ~55%1 Merge Actual Cumulative Boe STACK Meramec Actual Cumulative Boe vs. CHAP Type Curve 2 vs. CHAP Type Curve 2 250,000 180,000 225,000 160,000 200,000 140,000 175,000 120,000 Boe 150,000 Boe 100,000 125,000 80,000 100,000 60,000 75,000 Cumulative Cumulative Cumulative Cumulative 50,000 40,000 Merge STACK Meramec 25,000 20,000 Merge Type Curve STACK Meramec Type Curve 0 0 Days on Production Days on Production 1 At February 28, 2019 NYMEX prices; Five-year average prices $56.20 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 NYSE: CHAP 14

Osage Well Performance • Strong recent operated well performance for Upper and Lower Osage type curve areas • Average results are exceeding or in-line with current type curve expectations • Type curve rates-of-return: ~30% to ~50%1 Upper Osage Actual Cumulative Boe Lower Osage Actual Cumulative Boe vs. CHAP Type Curve 2 vs. CHAP Type Curve 2 225,000 180,000 200,000 160,000 175,000 140,000 150,000 120,000 Boe Boe 125,000 100,000 100,000 80,000 75,000 60,000 Cumulative Cumulative Cumulative Cumulative 50,000 40,000 Upper Osage 25,000 20,000 Lower Osage Upper Osage Type Curve Lower Osage Type Curve 0 0 Days on Production Days on Production 1 At February 28, 2019 NYMEX prices; five-year average prices of $56.20 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 NYSE: CHAP 15

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 16

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 Indications Six to Eight Meramec/Osage Wells per Section NYSE: CHAP 17

Financial Overview NYSE: CHAP 18

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 • $37 million in cash as of Q4-2018 plus undrawn revolver ($325mm borrowing base) • 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 19

Financial Position and Liquidity Highlights Chaparral Liquidity • Closed on a $300 million senior ($ in Millions) unsecured notes offering in June Actual FYE 2018 2018 Cash and Cash Equivalents1 $37 • Increased credit facility borrowing Revolving Credit Facility due Dec. 20221 $0 base from $265 million to $325 Other $21 million Senior Notes $300 • Continue to rationalize non- Total Debt $321 STACK assets to add liquidity Net Debt $283 • Develop long runway to unlock Borrowing Base Amount $325 value of deep STACK/Merge drilling inventory Chaparral Debt Maturity Schedule $500 $400 $325 $300 $300 No maturities until 2022 $200 $100 $- 2019 2020 2021 2022 2023 2024 2025 2025+ Senior Notes Drawn Revolver1 Undrawn Revolver NYSE: CHAP 1As of 3/8/19 Cash & Cash Equivalents was $29mm and Revolving Credit Facility balance was $30mm 20

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 21

Appendix NYSE: CHAP 22

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 one section 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 23

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 50/50 NGL markets and pricing split between Conway and Mt. Belvieu • Incremental capacity of 1.4 Bcf/d to Gulf Coast markets expected in Q4 2019 (Midship) NYSE: CHAP 24

Commodity Realizations Crude Oil Differentials Oil & NGL Realizations as % of WTI 99% 93% 96% • Proximity to numerous markets provides better CHAP $80 100% net back as compared to other basins $70 90% 80% • STACK crude oil quality meets Oklahoma refineries $60 70% specification $50 60% • New trucking terminals and pipeline infrastructure $40 50% have reduced transportation costs, providing better net $30 40% 44% back at the wellhead 37% 30% $20 35% as Realizations % 20% WTI Average Daily Settle Daily Average WTI $10 10% NGL Differentials $0 0% 2016 2017 2018 • Increased pipeline capacity to the Gulf Coast to new WTI NGL % Oil % markets • Increased Gulf Coast demand, with new petrochemical crackers coming online Natural Gas Realizations as % of HH • Access to Mont Belvieu and increased NGL export $4.00 100% 85% 87% capacity provided increased pricing to STACK $3.50 77% 90% 80% $3.00 70% Natural Gas Differentials $2.50 60% $2.00 50% • Increased supply from STACK/SCOOP and other $1.50 40% basins competing for pipeline capacity has caused 30% $1.00 Mid-Continent to widen 20% as Realizations % $0.50 • New pipeline capacity out of STACK/SCOOP to south Settle Daily Average HH 10% $0.00 0% and Gulf Coast will provide price strength for the basin 2016 2017 2018 Henry Hub Gas % NYSE: CHAP 25

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 $0.30 Natural Gas Swaps Hedge Volume (MMBTU) 14,261,500 6,000,000 Average Price ($/MMBTU) $2.85 $2.75 Natural Gas Collars Hedge Volume (MMBTU) 240,000 Average Ceiling Price ($/MMBTU) $5.07 Average Floor Price ($/MMBTU) $4.00 Natural Gas Basis Swaps (PEPL) Hedge Volume (MMBTU) 11,491,300 3,600,000 Average Price ($/MMBTU) ($0.61) ($0.46) NGL Swaps Propane Hedge Volume (BBL) 273,000 102,000 Propane Average Price ($/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 28, 2019 for full calendar years as noted NYSE: CHAP 26

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 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 2/28 NYMEX NYSE: CHAP 27

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 28

STACK Meramec and Merge Miss Overview Spud Peak IP-301 Liquids1 Lateral Lease Operator Date Boe/d % Length 1 KING KOOPA PAD Avg. (2 wells) CHAPARRAL 9/1/2018 484 66% 4,739 2 SLIMER 1707 #1UMH-23 CHAPARRAL 9/5/2017 713 85% 4,839 3 HIGH VALLEY 1807 #1UMH-36 CHAPARRAL 8/19/2017 682 77% 4,588 4 BIG TIMBER 1408 #1UMH-2 CHAPARRAL 6/4/2017 799 82% 4,623 5 EBH 1707 1H-1 NEWFIELD 4/7/2018 1,046 79% 3,752 6 CATERPILLAR 1506 1-11MH ALTA MESA 2/1/2018 717 85% 4,958 7 WINFIELD 1807 31-1MH GASTAR 8/15/2017 657 82% 4,608 8 H&W 1H-28X NEWFIELD 1/15/2017 878 80% 9,713 9 ALVERSTONE 1206 1LMH-17 (JV) CHAPARRAL 10/23/2018 1,362 71% 4,901 10 FAIRWEATHER 1207 #1UMH-13 (JV) CHAPARRAL 10/4/2018 1,478 65% 4,661 11 ANDES PAD Avg. (2 wells) CHAPARRAL 9/12/2018 1,048 77% 4,739 12 RAINIER 1206 #1UMH-7 CHAPARRAL 7/2/2018 929 60% 4,595 13 DENALI PAD Avg. (3 wells) CHAPARRAL 5/29/2018 1,290 75% 4,549 14 BANFF 1207 #1UMH-29 CHAPARRAL 3/23/2018 1,178 59% 4,926 15 HOOD 1006 #1UMH-5 CHAPARRAL 3/2/2018 838 73% 4,841 16 KATMAI 1206 #1UMH-29 (JV) CHAPARRAL 2/6/2018 1,262 76% 4,439 17 LASSEN 1107 #1UMH-15 (JV) CHAPARRAL 12/2/2017 1,302 73% 4,490 18 GREY SNOW 14-1208 1MH NATIVE 7/13/2018 1,039 68% 4,987 19 VON TUNGELN 1H-20 TRAVIS PEAK 2/25/2018 1,189 52% 5,563 20 MCNEFF 15-10-5 1H ROAN 1/21/2018 1,208 62% 4,355 21 GAMBLE PAD Avg. (2 wells) JONES 11/10/2017 1,110 78% 4,415 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% Meramec Lateral Length (feet) 4,800 4,800 Merge Miss Well Cost ($mm) $4.0 $4.5 1 Gross three-phase scaled to type curve lateral length of 4,800 feet 2 At February 28, 2019 NYMEX prices; five-year average prices $56.20 and $2.80 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 (JV) CHAPARRAL 2/9/2018 902 61% 4,855 5 BROWNING 2205 #1UMH-22 (JV) CHAPARRAL 1/25/2018 675 55% 4,743 6 GERKEN 2205 #1UMH-33 CHAPARRAL 12/21/2017 1,110 55% 4,594 7 BARBEE 2105 #1LMH-4 (JV) CHAPARRAL 12/16/2017 1,224 69% 4,359 8 ALBERT 25-23N-5W 1MH WHITE STAR 6/10/2018 1,583 74% 4,335 9 HENNESSEY UNIT 1907 #1LMH-27 CHAPARRAL 9/24/2018 343 87% 4,906 10 HENNESSEY UNIT 1907 #1LMH-34 CHAPARRAL 9/8/2018 689 87% 5,021 11 KING KOOPA PAD Avg. (2 wells) CHAPARRAL 8/5/2018 661 73% 4,701 12 COLONIAL 2007 #1LMH-26 CHAPARRAL 7/9/2018 584 92% 5,108 13 PLATTER 2007 #1LMH-36 (JV) CHAPARRAL 3/29/2018 721 83% 4,852 14 FUKSA 2007 #1LMH-14 CHAPARRAL 11/2/2017 834 83% 4,087 15 STAY PUFT 1707 #1LMH-23 CHAPARRAL 9/26/2017 906 86% 4,571 16 BRANDT 1707 #1LMH-12 CHAPARRAL 7/8/2017 948 86% 4,482 17 LOW VALLEY 1807 #1LMH-36 CHAPARRAL 4/18/2017 1,345 82% 4,766 18 CAPTAIN SALAZAR 20-07-25 1H CHISHOLM 7/30/2018 962 89% 4,800 Type Curve Lower Osage Upper Osage IP-301 (Boe/d) 599 744 ROR at NYMEX Strip2 ~50% ~30% Total EUR1 (MBoe) 629 853 % Liquids1 70% 54% Upper Osage Lateral Length (feet) 4,800 4,800 Lower Osage Well Cost ($mm) $3.9 $4.1 1 Gross three-phase scaled to type curve lateral length of 4,800 feet 2 At February 28, 2019 NYMEX prices; five-year average prices $56.20 and $2.80 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 (JV) CHAPARRAL 2/12/2018 451 59% 4,451 5 KATMAI 1206 #1WH-29 (JV) CHAPARRAL 1/4/2018 430 61% 4,086 6 LASSEN 1107 #1WH-15 (JV) CHAPARRAL 11/24/2017 499 64% 4,021 7 OLYMPUS 1107 #1WH-10 (JV) CHAPARRAL 11/13/2017 462 58% 4,122 8 FRANK EATON 36-1-11-6 1XH ROAN 2/3/2018 454 79% 9,941 9 LOUDERMILK 1H-32-29 ROAN 12/3/2017 490 60% 10,182 10 ASHCRAFT 1-19H CIMAREX 9/20/2017 847 60% 4,625 11 COWBOY 1H-34-3 ROAN 8/30/2017 402 60% 9,282 12 CANNONBALL 1208 24-1WH 89 ENERGY LLC 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 932 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% North Woodford Lateral Length (feet) 4,800 4,800 South Woodford Well Cost ($mm) $4.4 $4.4 1 Gross three-phase scaled to type curve lateral length of 4,800 feet 2 At February 28, 2019 NYMEX prices; five-year average prices $56.20 and $2.80 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) PV-103 ($mm) Miss Lime 1,878 28% $18.53 7.4 $53.2 $37.3 Western Anadarko Basin 950 14% $15.54 4.6 $28.1 $22.8 Southern OK 1,700 60% $22.40 7.8 $87.1 $68.3 Other 515 41% $10.94 0.9 $6.5 $5.2 TOTAL 5,043 43% $18.49 20.7 $174.9 $133.6 TOTAL Incl. ARO $170.2 $128.9 1 Q4 2018 actuals 2 At year-end 2018 SEC prices of $65.56 and $3.10 3 Based on year-end 2018 reserves run on February 28, 2019 NYMEX prices; Five-year average prices $56.20 and $2.80 NYSE: CHAP 32

STACK Drilling Joint Venture • Joint venture between CHAP and Bayou City Energy (BCE) • Accelerate development of 131,000 STACK acres • Key driver in de-risking Garfield 50% and Canadian County Merge 80% to date • 22 wells online as of year end 2018 • 8 remaining to bring online in 2019 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 each Merge 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 33

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 34

Reconciliations Successor Predecessor Jan 1, 2018 Mar 22, 2017 Jan 1, 2017 through through through (in thousands) Dec 31, 2018 Dec 31, 2017 Mar 21, 2017 Net (loss) income $ 33,442 $ (118,902) $ (19,115) Interest expense 11,383 14,147 5,283 Income tax (benefit) expense (77) (349) 37 Depreciation, depletion, and amortization 87,888 92,599 32,167 Non-cash change in fair value of derivative instruments (37,807) 46,478 22,236 Impact of derivative repricing (5,649) — — Loss (gain) on settlement of liabilities subject to compromise 48 — (372,093) Fresh start accounting adjustments — — (641,684) Interest Income (12) (21) (133) Stock-based compensation expense 10,873 9,833 155 (Gain) loss on sale of assets 2,582 25,996 (206) Loss on extinguishment of debt — 635 — Write-off of debt issuance costs, discount and premium — — 1,687 Loss on impairment of assets 20,065 42,325 — Restructuring, reorganization and other 2,344 7,313 24,297 Adjusted EBITDA $ $125,080 $ $120,054 $ 38,075 (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 35

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 36

Contact Information Chaparral Energy, Inc. 701 Cedar Lake Boulevard Oklahoma City, OK 73114 Investors Media Scott Pittman Brandi Wessel Chief Financial Officer Manager – Communications investor.relations@chaparralenergy.com brandi.wessel@chaparralenergy.com 405-426-6700 405-426-6657 NYSE: CHAP 37

ENERGIZING America’s Heartland NYSE: CHAP chaparralenergy.com NYSE: CHAP 38