Exhibit

“We continue to deliver strong quarterly results within our guidance ranges,” said Chief Executive Officer Earl Reynolds. “At our semi-annual redetermination, we reaffirmed our $325 million borrowing base, demonstrating the considerable value of our differentiated STACK/Merge acreage. We continue to build on our operational excellence, which is evident in our cost per lateral drilling foot, increased drilling footage per day, more efficient frac designs and increased frac stages per day.”

“In addition, we have seen outstanding drilling, completion and early production results from the first three wells of our 11-well cube style, co-development Foraker spacing test, which we brought online in late March,” said Reynolds. “With two Meramec wells and a Woodford well, the initial results from the first three wells have been very encouraging, as they have recorded an average 30-day IP of more than 1,290 Boe/d. The remaining eight wells were brought online early in the second quarter and although we do not yet have 30-day IP rates for those wells, early results are in line with or exceeding those of the first three wells. I am extremely excited about these early results and very proud of our team and their execution on this project as we were able to bring these wells to first sales ahead of schedule while

“As we progress through 2019, we will continue to build our knowledge, apply operational efficiencies and implement learnings from our successful spacing tests to date to pursue additional spacing tests in a deliberate and methodical manner. Our production guidance of 26.0 to 27.5 MBoe/d for the second quarter is significantly higher than our first quarter actual production, which is primarily due to the timing and performance of our new wells. We also expect to see a considerable decrease in per unit operating costs throughout the remainder of 2019,” said Reynolds. “We are proud of the differentiated STACK/Merge position we have built and how we have been able to execute operationally. We will remain focused on capital discipline and operational execution, which will allow us to continue to grow production and move closer to achieving cash flow neutrality, while maintaining a strong balance sheet and creating long-term value for our shareholders.”

Chaparral’s STACK production for the first quarter of 2019 was 15.9 MBoe/d, while total company production was 20.8 MBoe/d, both of which are within the company’s first quarter 2019 guidance range. As expected, due to timing associated with production from the company’s multi-well spacing tests and remaining drilling joint venture wells, STACK and total company production decreased on a quarter-over-quarter basis by 4%. On a year-over-year basis, STACK production was up 30%, while total company production was up 8%. Excluding 2018 divestitures, total company production was up 20% in the first quarter of 2019 as compared to the first quarter of 2018. Overall, total company production consisted of 33% oil, 27% natural gas liquids (NGLs) and 40% natural gas in the first quarter 2019.

Chaparral finalized drilling of its 11-well cube style, co-development Foraker spacing test in Canadian County during the first quarter and began completion of the wells. The multi-well test was drilled from three pads. The first pad had three wells, including two Meramec wells and a Woodford well. The second and third pads each had four wells, including a total of seven Meramec wells and one Woodford well. Currently, the 30-day IP rates for the first three wells are significantly exceeding type curve with an average 30-day IP of 1,292 Boe/d, with 42% oil. The pad’s two Meramec wells had an average 30-day IP rate of 1,569 Boe/d, with 46% oil, while the Woodford well had a 30-day IP rate of 737 Boe/d, with 35% oil. The remaining eight wells have been brought online, but there is not yet enough production data for 30-day IP rates. Early production results from these wells are, however, very encouraging as they are in line or exceeding the well results from the first three wells. In addition, the average capital cost per well for the Foraker test is tracking below Chaparral’s average AFE estimates of approximately $4.4 million.

The company has several additional spacing tests planned for 2019. It will continue to closely monitor production from the Foraker and its other initial spacing test wells as it continues testing the number of wells per pad and section to optimize long-term, full section development. While the growth trajectory of Chaparral’s STACK/Merge production has been impacted by spacing tests in the first half of 2019, the company is projecting its second half of 2019 growth to be more in line with past quarter-over-quarter increases.

Chaparral operated four drilling rigs during the first quarter of 2019, before decreasing, as planned, to three rigs in early April. The company had 12 new gross STACK wells with first sales during the quarter, four of which were part of its drilling joint venture and six of which did not have first sales until the last week of the quarter. In addition, the first three wells of its 11-well cube style, co-development Foraker spacing test in Canadian County were brought online in late March and, as a result, contributed no material production during the first quarter. Of its 12 wells with first sales, four were in Canadian County, three in Kingfisher County and five in Garfield County. Chaparral currently plans to operate three rigs for the remainder of 2019.

Chaparral’s total oil and natural gas capital expenditures (CAPEX) during the first quarter was $76.8 million, of which $70.8 million was associated with the STACK. Of its STACK CAPEX, $65.9 million was related to drilling and completion (D&C) activities, which included $3.1 million of non-operated CAPEX and $3.2 million of inflation-driven drilling joint venture CAPEX. Additionally, $2.6 million was invested in acquisition activities and $2.3 million in workovers and other enhancement capital.

Chaparral reported a net loss of $103.5 million, or $2.28 per share, during the first quarter of 2019. This included $51.5 million in non-cash reductions in the fair value of hedge derivative instruments and a $49.7 million non-cash ceiling test impairment charge primarily due to a decrease in the price used to estimate its reserves. Chaparral’s adjusted EBITDA for the first quarter was down 18% on a quarter-over-quarter basis to $28.3 million, primarily due to lower realized pricing and production. On a year-over-year

Chaparral’s average realized price for crude oil, excluding derivative settlements, decreased to $53.08 per barrel in the first quarter of 2019, down 9% from the fourth quarter of 2018 and down 14% from the first quarter of 2018. Chaparral’s realized NGL price during the quarter was $18.07 per barrel, which represents a 21% quarter-over-quarter decrease and a 23% year-over-year decrease. The company’s realized natural gas price during the first quarter of 2019 was $2.50 per thousand cubic feet (Mcf), which represents a decrease of 15% compared to the fourth quarter of 2018 and an increase of 8% compared to the first quarter of 2018.

Total company LOE for the first quarter of 2019 was $12.3 million, or $6.56 per Boe, which was up 7% compared to $6.11 per Boe in the fourth quarter of 2018 and down 22% compared to $8.37 per Boe in the first quarter of 2018. Chaparral’s STACK LOE/Boe for the first quarter of 2019 was $4.96 per Boe, which was up 7% from $4.64 in the previous quarter and down 8% from $5.37 in the first quarter of 2018. The quarter-over-quarter increases were driven primarily by the reduction in production due to timing of new wells being brought online. Excluding 2018 divestitures, total company LOE per Boe decreased 12% on a year-over-year basis. Additional forecasted production throughout 2019 is expected to significantly drive down LOE per Boe costs.

Chaparral expects second quarter 2019 total company production to be between 26.0 and 27.5 MBoe/d, which, based on the midpoint of this range, marks a growth rate of approximately 28% compared to the first quarter of 2019. Total STACK production for the second quarter is forecasted to increase to 21.5 to 23.0 MBoe/d or approximately 40% on a quarter-over-quarter basis when using this midpoint. The expected increase in production is due to the timing of first sales associated with Chaparral’s spacing tests and new well performance. The company is re-affirming its original CAPEX guidance range of $275 to $300 million for the full year 2019.

Chaparral will hold its financial and operating results call Thursday, May 9, 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 2956609. 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.

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.

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/Merge Play, where it has approximately 132,000 net acres primarily in Kingfisher, Canadian and Garfield counties. The company has approximately 225,000 net surface acres in the Mid-Continent region. For more information, visit chaparralenergy.com.



(in thousands, except share and per share data)	Three months ended
Revenues:	March 31, 2019		December 31, 2018		March 31, 2018
Net commodity sales	48,619		60,734		57,889
Sublease revenue	1,198		1,198		1,198
Total revenues	49,817		61,932		59,087
Costs and expenses:
Lease operating	12,294		12,174		14,543
Production taxes	2,880		3,677		2,677
Depreciation, depletion and amortization	23,715		24,123		21,106
Loss on impairment of other assets	49,722		20,065		—
General and administrative	8,313		10,075		11,507
Other	403		403		828
Total costs and expenses	97,327		70,517		50,661

Operating income	(47,510	)	(8,585	)	8,426
Non-operating (expense) income:
Interest expense	(4,564	)	(4,068	)	(1,371	)
Derivative (losses) gains	(51,016	)	91,761		(16,501	)
(Loss) gain on sale of assets	(1	)	17		(1,044	)
Other income, net	14		125		85
Net non-operating (expense) income	(55,567	)	87,835		(18,831	)
Reorganization items, net	(463	)	(382	)	(1,037	)
(Loss) income before income taxes	(103,540	)	78,868		(11,442	)
Income tax expense	—		(77	)	—
Net (loss) income	(103,540	)	78,945		(11,442	)
Earnings per share:
Basic for Class A and Class B	(2.28	)	1.74		(0.25	)
Diluted for Class A and Class B	(2.28	)	1.73		(0.25	)
Weighted average shares used to compute earnings per share:
Basic for Class A and Class B	45,456,214		45,338,906		45,143,297
Diluted for Class A and Class B	45,456,214		45,746,712		45,143,297



(dollars in thousands, except share data)	March 31, 2019			December 31, 2018
Assets	(unaudited)
Current assets:
Cash and cash equivalents	$	11,118		$	37,446
Accounts receivable, net	62,652			66,087
Inventories, net	3,923			4,059
Prepaid expenses	2,593			2,814
Derivative instruments	—			24,025
Total current assets	80,286			134,431
Property and equipment, net	42,558			43,096
Right of use assets from operating leases	12,064			—
Oil and natural gas properties, using the full cost method:
Proved	976,025			915,333
Unevaluated (excluded from the amortization base)	484,021			466,616
Accumulated depreciation, depletion, amortization and impairment	(292,679		)	(221,431		)
Total oil and natural gas properties	1,167,367			1,160,518
Derivative instruments	—			2,199
Other assets	389			425
Total assets	$	1,302,664		$	1,340,669
Liabilities and stockholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	97,404		$	73,779
Accrued payroll and benefits payable	6,420			10,976
Accrued interest payable	5,934			13,359
Revenue distribution payable	20,714			26,225
Long-term debt and capital leases, classified as current	11,854			12,371
Derivative instruments	10,874			—
Total current liabilities	153,200			136,710
Long-term debt and capital leases, less current maturities	326,198			295,100
Derivative instruments	15,976			1,542
Noncurrent operating lease obligations	2,307			—
Deferred compensation	628			540
Asset retirement obligations	22,248			22,090
Commitments and contingencies (Note 10)
Stockholders’ equity:
Preferred stock	—			—
Common stock	467			467
Additional paid in capital	976,039			974,616
Treasury stock	(5,399		)	(4,936		)
Accumulated deficit	(189,000		)	(85,460		)
Total stockholders' equity	782,107			884,687
Total liabilities and stockholders' equity	$	1,302,664		$	1,340,669



	Three months ended
(in thousands)	March 31, 2019			December 31, 2018			March 31, 2018
Cash flows from operating activities
Net (loss) income	$	(103,540	)	$	78,945		$	(11,442	)
Adjustments to reconcile net (loss) income to net cash provided by operating activities
Depreciation, depletion and amortization	23,715			24,123			21,106
Loss on impairment of assets	49,722			20,065			—
Derivative losses (gains)	51,016			(91,761		)	16,501
Loss (gain) on sale of assets	1			(17		)	1,044
Other	542			1,095			1,630
Change in assets and liabilities
Accounts receivable	7,910			406			(12,140		)
Inventories	207			1,651			(3,168		)
Prepaid expenses and other assets	256			(482		)	(179		)
Accounts payable and accrued liabilities	(16,689		)	15,824			(9,828		)
Revenue distribution payable	(5,511		)	(2,246		)	2,151
Deferred compensation	925			2,371			4,701
Net cash provided by operating activities	8,554			49,974			10,376
Cash flows from investing activities
Expenditures for property, plant, and equipment and oil and natural gas properties	(64,044		)	(71,332		)	(99,941		)
Proceeds from asset dispositions	—			14,188			73
(Payments) proceeds from derivative instruments, net	515			(1,868		)	(4,244		)
Net cash used in investing activities	(63,529		)	(59,012		)	(104,112		)
Cash flows from financing activities
Proceeds from long-term debt	30,000			—			79,000
Repayment of long-term debt	(171		)	(168		)	(146		)
Principal payments under capital lease obligations	(699		)	(680		)	(661		)
Payment of debt issuance costs and other financing fees	(20		)	(1,564		)	—
Treasury stock purchased	(463		)	(64		)	—
Net cash provided by (used in) financing activities	28,647			(2,476		)	78,193
Net decrease in cash, cash equivalents, and restricted cash	(26,328		)	(11,514		)	(15,543		)
Cash, cash equivalents, and restricted cash at beginning of period	37,446			48,960			27,732
Cash, cash equivalents, and restricted cash at end of period	$	11,118		$	37,446		$	12,189



	Three months ended
(in thousands)	March 31, 2019			December 31, 2018			March 31, 2018
Net (loss) income	(103,540		)	78,945			(11,442		)
Interest expense	4,564			4,068			1,371
Income tax expense	—			(77		)	—
Depreciation, depletion, and amortization	23,715			24,123			21,106
Loss on impairment of assets	49,722			20,065			—
Non-cash change in fair value of derivative instruments	51,531			(93,629		)	12,257
Impact of derivative repricing	—			(1,699		)	(572		)
Loss (gain) on settlement of liabilities subject to compromise	—			—			48
Interest income	—			(3		)	(1		)
Stock-based compensation expense	802			2,275			4,623
Loss (gain) on sale of assets	1			(17		)	1,044
Restructuring, reorganization and other	1,520			382			989
Adjusted EBITDA	$	28,315		$	34,433		$	29,423



Capital Expenditures (in millions)	Q1 2019
STACK Acquisitions	$	2.6
STACK D&C¹	65.9
STACK Enhancements	2.3
Total STACK	$	70.8
OtherEnhancements	0.9
Corporate Allocations²	5.2
Total STACK	$	76.8



Production Guidance	2Q19E	2019E
Total Company Average Daily Production (MBoe/d)	26.0 - 27.5	25.0 - 27.0
STACK Average Daily Production (MBoe/d)	21.5 - 23.0	21.0 - 23.0



Investor Contact		Media Contact
Scott Pittman		Brandi Wessel
Chief Financial Officer		Communications Manager
405-426-6700		405-426-6657
investor.relations@chaparralenergy.com		brandi.wessel@chaparralenergy.com


•	Achieved first quarter 2019 total company production of 20.8 thousand barrels of oil equivalent per day (MBoe/d), near the midpoint of guidance


•	Recorded STACK production of 15.9 MBoe/d in the first quarter 2019, within guidance range and represents a 30% increase from the first quarter 2018


•	Reported net loss of $103.5 million for the first quarter 2019, or $2.28 loss per share, which included $51.5 million in non-cash derivative losses and a $49.7 million non-cash ceiling test impairment charge


•	Achieved first quarter 2019 adjusted EBITDA, as defined below, of $28.3 million


•	Announced 30-day initial production (IP) results well above type curve expectations from the first three wells of its 11-well cube style, co-development Foraker spacing test in Canadian County


•	Reaffirmed $325 million borrowing base at semi-annual spring redetermination