Quarterly Report (10-q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q



x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2019



¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number: 001-38602




Chaparral Energy, Inc. (Exact name of registrant as specified in its charter)



Delaware		73-1590941
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

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



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

Securities registered pursuant to Section 12(b) of the Act:



Title of class	Trading Symbol(s)	Name of each exchange on which registered
Class A common stock, par value, $0.01 per share	CHAP	The New York Stock Exchange

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically, if any, every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.



Large accelerated filer	¨	Accelerated filer	x
Non-accelerated filer			¨
Smaller reporting company			¨
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. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes ☒ No ☐

Number of shares outstanding of each of the issuer’s classes of common stock as of November 8, 2019:



Class	Number of Shares
Class A Common Stock, $0.01 par value	46,405,086

CHAPARRAL ENERGY, INC.

Index to Form 10-Q



	Page

Part I. FINANCIAL INFORMATION
Item 1. Financial Statements (Unaudited)	7
Consolidated Balance Sheets	7
Consolidated Statements of Operations	8
Consolidated Statement of Stockholders’ Equity	9
Consolidated Statements of Cash Flows	10
Condensed Notes to Consolidated Financial Statements	11
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	33
Overview	33
Results of Operations	35
Liquidity and Capital Resources	43
Non-GAAP Financial Measure and Reconciliation	46
Critical Accounting Policies	48
Recent Accounting Pronouncements	48
Item 3. Quantitative and Qualitative Disclosures about Market Risk	49
Item 4. Controls and Procedures	51
Part II. OTHER INFORMATION
Item 1. Legal Proceedings	52
Item 1A. Risk Factors	52
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	52
Item 5. Other Information	52
Item 6. Exhibits	53
Signatures	55

CAUTIONARY NOTE

REGARDING FORWARD-LOOKING STATEMENTS

This report includes statements that constitute forward-looking statements within the meaning of the federal securities laws. These statements are subject to risks and uncertainties. These statements may relate to, but are not limited to, information or assumptions about us, our capital and other expenditures, dividends, financing plans, capital structure, cash flow, pending legal and regulatory proceedings and claims, including environmental matters, future economic performance, operating income, cost savings, and management’s plans, strategies, goals and objectives for future operations and growth. These forward-looking statements generally are accompanied by words such as “intend,” “anticipate,” “believe,” “estimate,” “expect,” “should,” “seek,” “project,” “plan” or similar expressions. Any statement that is not a historical fact is a forward-looking statement. It should be understood that these forward-looking statements are necessarily estimates reflecting the best judgment of senior management, not guarantees of future performance. They are subject to a number of assumptions, risks and uncertainties that could cause actual results to differ materially from those expressed or implied in the forward-looking statements. Forward-looking statements in this report may include, for example, statements about:


•	fluctuations in demand or the prices received for oil and natural gas;


•	the amount, nature and timing of capital expenditures;


•	drilling, completion and performance of wells;


•	inventory of drillable locations;


•	competition;


•	government regulations;


•	timing and amount of future production of oil and natural gas;


•	costs of exploiting and developing properties and conducting other operations, in the aggregate and on a per-unit equivalent basis;


•	changes in proved reserves;


•	operating costs and other expenses;


•	our future financial condition, results of operations, revenue, cash flows and expenses;


•	estimates of proved reserves;


•	exploitation of property acquisitions; and


•	marketing of oil and natural gas.

These forward-looking statements represent intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors. Many of those factors are outside of our control and could cause actual results to differ materially from the results expressed or implied by those forward-looking statements. In addition to the risk factors described in Part II, Item 1A. Risk Factors, of this report and Part I, Item 1A. Risk Factors, in our Annual Report on Form 10-K for the year ended December 31, 2018, the risks and uncertainties include or relate to:


•	worldwide supply of and demand for oil and natural gas;


•	volatility and declines in oil and natural gas prices;


•	geologic and reservoir complexity and variability;


•	drilling plans (including scheduled and budgeted wells);


•	the number, timing or results of any wells;


•	changes in wells operated and in reserve estimates;


•	future growth and expansion;


•	future exploration;


•	integration of existing and new technologies into operations;


•	future capital expenditures (or funding thereof) and working capital;


•	effectiveness and extent to our risk management activities;


•	availability and cost of equipment and services;


•	risks related to the concentration of our operations in the mid-continent geographic area;


•	borrowings and capital resources and liquidity;


•	covenant compliance under instruments governing any of our existing or future indebtedness;


•	changes in strategy and business discipline, including our post-emergence business strategy;


•	future tax matters;


•	legislation and regulatory initiatives;


•	loss of key personnel;


•	geopolitical events affecting oil and natural gas prices;


•	outcome, effects or timing of legal proceedings (including environmental litigation);


•	the ability to generate additional prospects; and


•	the ability to successfully complete merger, acquisition or divestiture plans, regulatory or other limitations imposed as a result of a merger, acquisition or divestiture, and the success of the business following a merger, acquisition or divestiture.

Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions may change the schedule of any future production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil and natural gas that are ultimately recovered.

Should one or more of these risks or uncertainties materialize, or should any of our assumptions prove incorrect, actual results may vary in material respects from those projected in the forward-looking statements contained herein. We undertake no obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required under applicable securities laws. All forward-looking statements included herein are expressly qualified in their entirety by the cautionary statements contained or referred to in this section.

GLOSSARY OF CERTAIN DEFINED TERMS

The terms defined in this section are used throughout this Form 10-Q:



Bbl	One stock tank barrel of 42 U.S. gallons liquid volume used herein in reference to crude oil, condensate, or natural gas liquids.

BBtu	One billion British thermal units.

Boe	Barrels of oil equivalent using the ratio of six thousand cubic feet of natural gas to one barrel of oil.

Boe/d	Barrels of oil equivalent per day.

Btu	British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

Chapter 11 Cases	The voluntary petitions filed by Chaparral Energy, Inc. and its subsidiaries on May 9, 2016 seeking relief under Title 11 of the United States Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the District of Delaware commencing cases for relief under chapter 11 of the Bankruptcy Code.

Completion	The process of treating a drilled well followed by the installation of permanent equipment for the production of oil or natural gas, or in the case of a dry well, the reporting to the appropriate authority that the well has been abandoned.

CO₂	Carbon dioxide.

Credit Agreement	Tenth Restated Credit Agreement, as amended, by and among Chaparral Energy, Inc., Royal Bank of Canada as Administrative Agent and the Lenders thereto.

Dry well or dry hole	An exploratory, development or extension well that proves to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.

Effective Date	Date of emergence from bankruptcy, or March 21, 2017.

Enhanced oil recovery (EOR)	The use of any improved recovery method, including injection of CO₂ or polymer, to remove additional oil after Secondary Recovery.

Field	An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

MBbls	One thousand barrels of crude oil, condensate, or natural gas liquids.

MBoe	One thousand barrels of crude oil equivalent.

Mcf	One thousand cubic feet of natural gas.

MMBtu	One million British thermal units.

MMcf	One million cubic feet of natural gas.

Natural gas liquids (NGLs)	Those hydrocarbons in natural gas that are separated from the gas as liquids through the process of absorption, condensation, or other methods in gas processing or cycling plants. Natural gas liquids primarily include propane, butane, isobutane, pentane, hexane and natural gasoline.

NYMEX	The New York Mercantile Exchange.



Play	A term describing an area of land following the identification by geologists and geophysicists of reservoirs with potential oil and natural gas reserves.

Proved developed reserves	Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods, or in which the cost of the required equipment is relatively minor compared to the cost of a new well.

Proved reserves	The quantities of oil and natural gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain.

Proved undeveloped reserves	Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

PV-10 value	When used with respect to oil and natural gas reserves, PV-10 value means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, excluding escalations of prices and costs based upon future conditions, before income taxes, and without giving effect to non-property-related expenses, discounted to a present value using an annual discount rate of 10%.

Reorganization Plan	First Amended Joint Plan of Reorganization for Chaparral Energy, Inc. and its Affiliate Debtors under Chapter 11 of the Bankruptcy Code.

SEC	The Securities and Exchange Commission.

Senior Notes	Our 8.75% senior notes due 2023.

STACK	The STACK is a play in the Anadarko basin of Oklahoma in which we operate and derives its name from the acronym standing for Sooner Trend Anadarko Canadian Kingfisher. It is a horizontal drilling play in an area with multiple productive reservoirs which had previously been drilled with vertical wells. Our STACK areas encompass all or parts of Canadian, Garfield, Kingfisher, Major, Blaine, Dewey, Woodward, Logan and Grady counties in Oklahoma. Our STACK areas’ borders include the Nemaha Ridge (East), the Chester outcrop (North), and deep gas bearing characteristics (South and West). This thick column (500’+) includes multiple, stacked, and productive reservoirs, each with high oil saturations and includes the Woodford, Osage, Meramec, Oswego, and other intervals within the STACK Areas.

Unit	The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.

Chaparral Energy, Inc. and Subsidiaries

Consolidated Balance Sheets

(Unaudited)

PART I — FINANCIAL INFORMATION



ITEM 1.	FINANCIAL STATEMENTS



(dollars in thousands, except share data)	September 30, 2019			December 31, 2018
Assets
Current assets:
Cash and cash equivalents	$	21,534		$	37,446
Accounts receivable, net	45,145			66,087
Inventories, net	3,915			4,059
Prepaid expenses	2,200			2,814
Derivative instruments	11,446			24,025
Total current assets	84,240			134,431
Property and equipment, net	14,265			43,096
Right of use assets from operating leases	5,853			—
Oil and natural gas properties, using the full cost method:
Proved	1,224,620			915,333
Unevaluated (excluded from the amortization base)	373,761			466,616
Accumulated depreciation, depletion, amortization and impairment	(558,339		)	(221,431		)
Total oil and natural gas properties	1,040,042			1,160,518
Derivative instruments	1,111			2,199
Other assets	393			425
Total assets	$	1,145,904		$	1,340,669
Liabilities and stockholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	81,269		$	73,779
Accrued payroll and benefits payable	6,970			10,976
Accrued interest payable	5,673			13,359
Revenue distribution payable	16,275			26,225
Long-term debt and financing leases, classified as current	586			12,371
Derivative instruments	70			—
Total current liabilities	110,843			136,710
Long-term debt and financing leases, less current maturities	400,518			295,100
Derivative instruments	3,022			1,542
Noncurrent operating lease obligations	1,239			—
Deferred compensation	175			540
Asset retirement obligations	22,384			22,090
Commitments and contingencies (Note 10)
Stockholders’ equity:
Preferred stock, 5,000,000 shares authorized, none issued and outstanding	—			—
Common stock, $0.01 par value, 192,130,071 shares authorized; 46,876,041 issued and 46,408,285 outstanding at September 30, 2019 and 46,651,616 issued and 46,390,513 outstanding at December 31, 2018	469			467
Additional paid in capital	978,525			974,616
Treasury stock, at cost, 467,756 and 261,103 shares as of September 30, 2019 and December 31, 2018	(6,107		)	(4,936		)
Accumulated deficit	(365,164		)	(85,460		)
Total stockholders’ equity	607,723			884,687
Total liabilities and stockholders’ equity	$	1,145,904		$	1,340,669

The accompanying notes are an integral part of these consolidated financial statements.

Chaparral Energy, Inc. and Subsidiaries

Consolidated Statements of Operations

(Unaudited)



	Three months ended						Nine months ended
(in thousands, except share and per share data)	September 30, 2019			September 30, 2018			September 30, 2019			September 30, 2018
Revenues:
Net commodity sales	$	51,838		$	65,519		$	167,164		$	181,835
Sublease revenue	799			1,199			3,195			3,595
Total revenues	52,637			66,718			170,359			185,430
Costs and expenses:
Lease operating	12,372			12,493			38,037			42,045
Production taxes	2,925			4,028			9,607			9,473
Depreciation, depletion and amortization	28,021			22,252			82,018			63,765
Impairment of oil and gas assets	147,686			—			261,001			—
Impairment of other assets	—			—			6,407			—
General and administrative	7,809			9,021			23,437			28,718
Cost reduction initiatives	—			210			—			1,034
Other	269			402			1,075			1,633
Total costs and expenses	199,082			48,406			421,582			146,668
Operating (loss) income	(146,445		)	18,312			(251,223		)	38,762
Non-operating income (expense):
Interest expense	(5,994		)	(4,205		)	(16,129		)	(7,315		)
Derivative gains (losses)	23,601			(23,677		)	(9,681		)	(72,464		)
Gain (loss) on sale of assets	141			(2,024		)	631			(2,599		)
Loss on extinguishment of debt	(1,624		)	—			(1,624		)	—
Other (expense) income, net	(84		)	19			(372		)	123
Net non-operating income (expense)	16,040			(29,887		)	(27,175		)	(82,255		)
Reorganization items, net	(530		)	(493		)	(1,306		)	(2,010		)
Loss before income taxes	(130,935		)	(12,068		)	(279,704		)	(45,503		)
Income tax expense	—			—			—			—
Net loss	$	(130,935	)	$	(12,068	)	$	(279,704	)	$	(45,503	)
Earnings per share:
Basic for Class A and Class B (1)	(2.86		)	(0.27		)	(6.13		)	(1.01		)
Diluted for Class A and Class B (1)	(2.86		)	(0.27		)	(6.13		)	(1.01		)
Weighted average shares used to compute earnings per share:
Basic for Class A and Class B (1)	45,716,522			45,333,745			45,605,798			45,272,595
Diluted for Class A and Class B (1)	45,716,522			45,333,745			45,605,798			45,272,595

____________________________________________________________

(1) See “Note 2: Earnings per share.”

The accompanying notes are an integral part of these consolidated financial statements.

Chaparral Energy, Inc. and Subsidiaries

Consolidated Statement of Stockholders’ Equity

(Unaudited)



	Common stock
(dollars in thousands)	Shares outstanding		Amount			Additional paid in capital		Treasury stock			Accumulated deficit			Total
As of December 31, 2017	46,827,762		$	468		$	961,200	$	—		$	(118,902	)	$	842,766
Stock-based compensation	—		—			5,581		—			—			5,581
Restricted stock forfeited	(83,770	)	(1		)	—		—			—			(1		)
Repurchase of common stock	(63,919	)	—			—		(1,422		)	—			(1,422		)
Net loss	—		—			—		—			(11,442		)	(11,442		)
Balance at March 31, 2018	46,680,073		467			966,781		(1,422		)	(130,344		)	835,482
Stock-based compensation	55,000		—			2,336		—			—			2,336
Restricted stock forfeited	(81,683	)	—			—		—			—			—
Repurchase of common stock	(192,976	)	—			—		(3,450		)	—			(3,450		)
Net loss	—		—			—		—			(21,993		)	(21,993		)
Balance at June 30, 2018	46,460,414		467			969,117		(4,872		)	(152,337		)	812,375
Stock-based compensation	—		—			3,112		—			—			3,112
Restricted stock forfeited	—		—			—		—			—			—
Repurchase of common stock	—		—			—		—			—			—
Net loss	—		—			—		—			(12,068		)	(12,068		)
Balance at September 30, 2018	46,460,414		$	467		$	972,229	$	(4,872	)	$	(164,405	)	$	803,419



	Common stock
(dollars in thousands)	Shares outstanding		Amount			Additional paid in capital			Treasury stock			Accumulated deficit			Total
As of December 31, 2018	46,390,513		$	467		$	974,616		$	(4,936	)	$	(85,460	)	$	884,687
Stock-based compensation	94,078		1			1,423			—			—			1,424
Restricted stock forfeited	(97,113	)	(1		)	—			—			—			(1		)
Repurchase of common stock	(80,422	)	—			—			(463		)	—			(463		)
Net loss	—		—			—			—			(103,540		)	(103,540		)
Balance at March 31, 2019	46,307,056		467			976,039			(5,399		)	(189,000		)	782,107
Stock-based compensation	160,400		1			1,249			—			—			1,250
Restricted stock forfeited	—		—			—			—			—			—
Repurchase of common stock	(126,231	)	—			—			(708		)	—			(708		)
Issuance of common stock - litigation settlement	76,217		1			323			—			—			324
Net loss	—		—			—			—			(45,229		)	(45,229		)
Balance at June 30, 2019	46,417,442		469			977,611			(6,107		)	(234,229		)	737,744
Stock-based compensation	17,512		—			924			—			—			924
Restricted stock forfeited	(26,669	)	—			—			—			—			—
Cash settlement of stock based awards	—		—			(10		)	—			—			(10		)
Net loss	—		—			—			—			(130,935		)	(130,935		)
Balance at September 30, 2019	46,408,285		$	469		$	978,525		$	(6,107	)	$	(365,164	)	$	607,723

The accompanying notes are an integral part of these consolidated financial statements.

Chaparral Energy, Inc. and Subsidiaries

Consolidated Statements of Cash Flows

(Unaudited)



	Nine months ended
(in thousands)	September 30, 2019			September 30, 2018
Cash flows from operating activities
Net loss	$	(279,704	)	$	(45,503	)
Adjustments to reconcile net loss to net cash provided by operating activities
Depreciation, depletion and amortization	82,018			63,765
Derivative losses	9,681			72,464
Impairment of oil and gas assets	261,001			—
Impairment of other assets	6,407			—
(Gain) loss on sale of assets	(631		)	2,599
Other	3,630			4,376
Change in assets and liabilities
Accounts receivable	20,446			(6,743		)
Inventories	144			(1,415		)
Prepaid expenses and other assets	645			322
Accounts payable and accrued liabilities	(24,685		)	(12,383		)
Revenue distribution payable	(9,950		)	10,895
Deferred compensation	1,534			7,890
Net cash provided by operating activities	70,536			96,267
Cash flows from investing activities
Expenditures for property, plant, and equipment and oil and natural gas properties	(202,830		)	(252,731		)
Proceeds from asset dispositions	14,333			36,335
Proceeds from (payments on) derivative instruments, net	5,536			(16,642		)
Net cash used in investing activities	(182,961		)	(233,038		)
Cash flows from financing activities
Proceeds from long-term debt	110,000			116,000
Repayment of long-term debt	(8,682		)	(243,554		)
Proceeds from Senior Notes	—			300,000
Principal payments under financing lease obligations	(2,002		)	(2,003		)
Payment of debt issuance costs and other financing fees	(20		)	(7,572		)
Debt extinguishment costs	(1,602		)	—
Cash settlements of stock based awards	(10		)	—
Treasury stock purchased	(1,171		)	(4,872		)
Net cash provided by financing activities	96,513			157,999
Net (decrease) increase in cash and cash equivalents	(15,912		)	21,228
Cash and cash equivalents, at beginning of period	37,446			27,732
Cash and cash equivalents, at end of period	$	21,534		$	48,960

The accompanying notes are an integral part of these consolidated financial statements.

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

Note 1: Nature of operations and summary of significant accounting policies

Nature of operations

Chaparral Energy, Inc. and its subsidiaries (collectively, “we”, “our”, “us”, or the “Company”) are involved in the exploration, development, production, operation and acquisition of oil and natural gas properties. Our properties are located primarily in Oklahoma and our commodity products include crude oil, natural gas and natural gas liquids.

Interim financial statements

The accompanying unaudited consolidated interim financial statements of the Company have been prepared in accordance with the rules and regulations of the SEC and do not include all of the financial information and disclosures required by accounting principles generally accepted in the United States of America (“GAAP”) for complete financial statements. These financial statements and the notes thereto should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2018, as amended.

The financial information as of September 30, 2019, and for the three and nine months ended September 30, 2019 and 2018, is unaudited. The financial information as of December 31, 2018 has been derived from the audited financial statements contained in our Annual Report on Form 10-K for the year ended December 31, 2018. In management’s opinion, such information contains all adjustments considered necessary for a fair presentation of the results of the interim periods. The results of operations for the three and nine months ended September 30, 2019 are not necessarily indicative of the results of operations that will be realized for the year ended December 31, 2019.

Certain reclassifications have been made to prior period financial statements to conform to current period presentation. The reclassifications had no effect on our previously reported results of operations.

Cash and cash equivalents

We maintain cash and cash equivalents in bank deposit accounts and money market funds which may not be federally insured. As of September 30, 2019, cash with a recorded balance totaling approximately $20,379 was held at JP Morgan Chase Bank, N.A. We have not experienced any losses in such accounts and believe we are not exposed to any significant credit risk on such accounts.

Accounts receivable

We have receivables from joint interest owners and oil and natural gas purchasers which are generally uncollateralized. Accounts receivable consisted of the following:



	September 30, 2019			December 31, 2018
Joint interests	$	18,605		$	31,573
Accrued commodity sales	23,408			30,287
Derivative settlements	2,820			2,092
Other	1,412			3,375
Allowance for doubtful accounts	(1,100		)	(1,240		)
	$	45,145		$	66,087

Inventories

Inventories consisted of the following:



	September 30, 2019			December 31, 2018
Equipment inventory	$	3,573		$	3,663
Commodities	521			574
Inventory valuation allowance	(179		)	(178		)
	$	3,915		$	4,059

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

Property and equipment, net

Major classes of property and equipment are shown in the following table:



	September 30, 2019		December 31, 2018
Machinery and equipment	$	7,249	$	21,482
Office and computer equipment	6,951		6,183
Automobiles and trucks	4,911		3,548
Building and improvements	1,899		18,693
Furniture and fixtures	8		520
	21,018		50,426
Less accumulated depreciation, amortization and impairment	9,271		12,449
	11,747		37,977
Land	2,518		5,119
	$	14,265	$	43,096

Impairment of headquarters building and subsequent sales. During the second quarter of 2019, we commenced efforts to locate a buyer for our headquarters building. In conjunction with these efforts, we obtained a third party valuation on the fair value of the property. The valuation appraised the property at an amount lower than its net book value at the time. Based on this market appraisal and our expectations that, more likely than not, the headquarters building would be sold before the end of its useful life, we determined that the net book value of the property would not be recoverable. As a result, we recorded an impairment of $6,407 in June 2019 to write-down the net book value of the property to its fair value based on its market appraisal.

On August 5, 2019, we entered into a real estate purchase and sale agreement for the sale of the building housing our headquarters along with adjacent land, furniture and fixtures. We closed the sale on August 29, 2019, for net proceeds of $11,494 while recognizing an immaterial loss on disposal. The proceeds from the sale were utilized to pay off the outstanding balance of the real estate mortgage note on the property. We incurred a prepayment penalty of $1,624 on the mortgage early payoff which we recorded as a “Loss on extinguishment of debt” on our consolidated statements of operations. Conditioned upon closing of this sale, we entered into a leaseback agreement with the buyer for a portion of the office space, which we discuss in “Note 5: Leases.”

Our property and equipment balance as of December 31, 2018, included CO₂ compressors that were held under finance leases and simultaneously subleased to the buyer of our former EOR oil and natural gas properties (the “Sublessee”). In September 2019, U.S. Bank, the originating lessor, entered into agreements with the Sublessee which resulted in the discharge of all our obligations with respect to these compressor leases and the removal of the associated assets and elimination of associated debt from our consolidated balance sheet.

Oil and natural gas properties

Capitalized Costs. We use the full cost method of accounting for oil and natural gas properties and activities. Accordingly, we capitalize all costs incurred in connection with the exploration for and development of oil and natural gas reserves. Proceeds from the disposition of oil and natural gas properties are accounted for as a reduction in capitalized costs, with no gain or loss generally recognized unless such dispositions involve a significant alteration in the depletion rate. We capitalize internal costs that can be directly identified with exploration and development activities, but do not include any costs related to production, general corporate overhead or similar activities. Capitalized costs include geological and geophysical work, 3D seismic, delay rentals, and drilling completing and equipping oil and natural gas wells, including salaries, benefits, and other internal costs directly attributable to these activities.

Costs associated with unevaluated oil and natural gas properties are excluded from the amortizable base until a determination has been made as to the existence of proved reserves. Unevaluated leasehold costs are transferred to the amortization base with the costs of drilling the related well upon proving up reserves of a successful well or upon determination of a dry or uneconomic well under a process that is conducted each quarter. Furthermore, unevaluated oil and natural gas properties are reviewed for impairment if events and circumstances exist that indicate a possible decline in the recoverability of the carrying amount of such property. The impairment assessment is conducted at least once annually and whenever there are indicators that impairment has occurred. In assessing whether impairment has occurred, we consider factors such as intent to drill; remaining lease term; geological and geophysical evaluations;

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

drilling results and activity; assignment of proved reserves; and economic viability of development if proved reserves are assigned. Upon determination of impairment, all or a portion of the associated leasehold costs are transferred to the full cost pool and become subject to amortization. The processes above are applied to unevaluated oil and natural gas properties on an individual basis or as a group if properties are individually insignificant. Our future depreciation, depletion and amortization rate would increase or we may incur ceiling test write-downs if costs are transferred to the amortization base without any associated reserves.

In the past, the costs associated with unevaluated properties typically related to acquisition costs of unproved acreage. As a result of the application of fresh start accounting on the Effective Date, a substantial portion of the carrying value of our unevaluated properties are the result of a fair value increase to reflect the value of our acreage in our STACK play.

The costs of unevaluated oil and natural gas properties consisted of the following:



	September 30, 2019		December 31, 2018
Leasehold acreage	$	338,892	$	427,206
Capitalized interest	15,469		11,377
Wells and facilities in progress of completion	19,400		28,033
Total unevaluated oil and natural gas properties excluded from amortization	$	373,761	$	466,616

Ceiling Test. In accordance with the full cost method of accounting, the net capitalized costs of oil and natural gas properties are not to exceed their related PV-10 value, net of tax considerations, plus the cost of unproved properties not being amortized.

Our estimates of oil and natural gas reserves as of September 30, 2019, and the related PV-10 value, were prepared using an average price for oil and natural gas on the first day of each month for the prior twelve months as required by the SEC. We recorded ceiling test write-downs to our oil and natural gas properties of $147,686 and $261,001 for the three and nine months ended September 30, 2019, respectively. These losses are reflected in “Impairment of oil and gas assets” in our consolidated statements of operations.

Producer imbalances. We recognize revenue on all natural gas sold to our customers regardless of our proportionate working interest in a well. Liabilities are recorded for imbalances greater than our proportionate share of remaining estimated natural gas reserves. Our aggregate imbalance positions at September 30, 2019, and December 31, 2018, were immaterial.

Revenue recognition

In May 2014, the Financial Accounting Standards Board (“FASB”) issued authoritative guidance that supersedes previous revenue recognition requirements which has been codified as Accounting Standards Codification 606: Revenue from Contracts with Customers (“ASC 606”) and adopted by us in 2018. ASC 606 requires entities to recognize revenue in a way that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.

The following table displays the revenue disaggregated and reconciles the disaggregated revenue to the revenue reported:



	Three months ended September 30,						Nine months ended September 30,
	2019			2018			2019			2018
Revenues:
Oil	$	40,459		$	46,576		$	124,251		$	132,378
Natural gas	8,745			9,458			30,427			26,584
Natural gas liquids	8,801			14,078			29,043			34,789
Gross commodity sales	58,005			70,112			183,721			193,751
Transportation and processing	(6,167		)	(4,593		)	(16,557		)	(11,916		)
Net commodity sales	$	51,838		$	65,519		$	167,164		$	181,835

Please see “Note 16: Revenue recognition” in “Item 8. Financial Statements and Supplementary Data” of our Annual Report on Form 10-K for the year ended December 31, 2018, for a discussion of our revenue recognition policy including a description of products and revenue disaggregation criteria, performance obligations, pricing , measurement and contract assets and liabilities.

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

Income taxes

The provision for income taxes is based on a current estimate of the annual effective income tax rate adjusted to reflect the impact of permanent differences and discrete items. Management judgment is required in estimating operating income in order to determine our effective income tax rate. Our effective income tax rate was 0% and 0% for the three and nine months ended September 30, 2019 and 2018, respectively. The consistent effective tax rate for the nine months ended September 30, 2019, is a result of maintaining a valuation allowance against substantially all of our net deferred tax asset.

Despite the Company’s net loss for the three and nine month period ended September 30, 2019, we did not record any net deferred tax benefit, as any deferred tax asset arising from the benefit is reduced by a valuation allowance as utilization of the loss carryforwards and realization of other deferred tax assets cannot be reasonably assured.

A valuation allowance for deferred tax assets, including net operating losses (“NOLs”), is recognized when it is more likely than not that some or all of the benefit from the deferred tax asset will not be realized. To assess that likelihood, we use estimates and judgment regarding our future taxable income, as well as the jurisdiction in which such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include our current financial position, our results of operations, both actual and forecasted, the reversal of deferred tax liabilities, and tax planning strategies as well as the current and forecasted business economics of our industry.

We will continue to evaluate whether the valuation allowance is needed in future reporting periods. The valuation allowance will remain until we can determine that the net deferred tax assets are more likely than not to be realized. Future events or new evidence which may lead us to conclude that it is more likely than not that some or all of our net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings, improvements in oil prices, and taxable events that could result from one or more transactions. The valuation allowance does not prevent future utilization of the tax attributes if we recognize taxable income. As long as we conclude that the valuation allowance against our net deferred tax asset is necessary, we likely will not have any additional deferred income tax expense or benefit.

The benefit of an uncertain tax position taken or expected to be taken on an income tax return is recognized in the consolidated financial statements at the largest amount that is more likely than not to be sustained upon examination by the relevant taxing authority. Interest and penalties, if any, related to uncertain tax positions would be recorded in interest expense and other expense, respectively. There were no uncertain tax positions at September 30, 2019, or December 31, 2018.

As a result of the Chapter 11 reorganization and related transactions, the Company experienced an ownership change within the meaning of Internal Revenue Code (“IRC”) Section 382 on March 21, 2017. This ownership change subjected certain of the Company’s tax attributes, including $760,067 of federal net operating loss carryforwards, to an IRC Section 382 limitation. This limitation has not resulted in a current tax liability for the nine month period ended September 30, 2019, or any intervening period since March 21, 2017. If we were to experience an additional “ownership change,” as determined under IRC Section 382, our ability to offset taxable income arising after the ownership change with NOLs generated prior to the ownership change would be limited, possibly substantially. In general, an ownership change will occur if there is a cumulative increase in our ownership of more than 50 percentage points by one or more “5% stockholders” at any time during a rolling three-year period. In the event of an ownership change, IRC Section 382 imposes an annual limitation on the amount of the Company’s taxable income that can be offset by these carryforwards after an ownership change. The limitation is generally equal to the product of (a) the fair market value of the equity of the Company multiplied by (b) a percentage approximately equivalent to the yield on long-term tax exempt bonds during the month in which an ownership change occurs. In addition, the limitation is increased if there are net unrealized built-in gains in the Company’s assets at the time of the ownership change, and those net unrealized built-in gains are recognized during the 60 month recognition period following the ownership change. Future ownership changes or future regulatory changes could limit our ability to utilize our NOLs. To the extent we are not able to offset our future income with our NOLs, this could adversely affect our operating results and cash flows once we attain profitability.

Cost reduction initiatives

We incur expenses related to our efforts to reduce our capital, operating and administrative costs in response to industry conditions. The expenses consist of costs for one-time severance and termination benefits in connection with our reductions in force.

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

Other expense

Other expense consisted of the following:



	Three months ended September 30,				Nine months ended September 30,
	2019		2018		2019		2018
Restructuring	$	—	$	—	$	—	$	425
Subleases	269		402		1,075		1,208
Total other expense	$	269	$	402	$	1,075	$	1,633

Restructuring. We previously incurred exit costs in conjunction with our EOR asset divestiture, which predominantly consist of one-time severance and termination benefits for the affected employees. The expense recorded in 2018 is a result of termination benefits for the final group of employees terminated as a result of the divestiture.

Subleases. Our subleases consist of CO₂ compressors that were utilized in our former EOR operations and leased as both financing and operating leases from U.S. Bank but subsequently subleased to the purchaser of our EOR assets. Minimum payments under the subleases were equal to the original leases. All payments received from the Sublessee were reflected as “Sublease revenue” on our statement of operations. Minimum payments made to U.S. Bank on the original operating leases were reflected as “Other” expense on our statement of operations. With respect to the financing leases, upon executing the subleases, we reclassified the amount associated with these leases from the full cost amortization base to “Property and equipment, net” on our balance sheet and amortized the asset on a straight line basis prospectively while continuing to incur interest expense. Please see “Note 5: Leases” for our disclosure on leases. In September 2019, U.S. Bank entered into agreements with the Sublessee which resulted in the discharge of all our obligations with respect to the originating leases and to the subleases including a $9,832 reduction in debt.

Joint development agreement

On September 25, 2017, we entered into a joint development agreement (“JDA”) with BCE Roadrunner LLC, a wholly-owned subsidiary of Bayou City Energy Management, LLC (“BCE”), pursuant to which BCE funded 100 percent of our drilling, completion and equipping costs associated with 30 joint venture STACK wells, subject to average well cost caps that vary by well-type across location and targeted formations, approximately between $3,400 and $4,000 per gross well. The JDA wells, which were drilled and operated by us, include 17 wells in Canadian County and 13 wells in Garfield County. The JDA provided us with a means to accelerate the delineation of our position within our Garfield and Canadian County acreage, realizing further efficiencies and holding additional acreage by production, and adding reserves. In exchange for funding, BCE received wellbore-only interest in each well totaling an 85% carve-out working interest from our original working interest (and we retained 15%) until the program reaches a 14% internal rate of return. Once achieved, a portion of BCE’s ownership interest in all JDA wells will revert to us such that we will own a 75% working interest and BCE will retain a 25% working interest. We retained all acreage and reserves outside of the wellbore, with both parties entitled to revenues and paying lease operating expenses based on their working interest.

Our drilling and completion costs to date have exceeded the well cost caps specified under the JDA primarily due to inflation in the cost of oilfield services subsequent to our negotiations in mid-2017 that culminated in our entering into the JDA. In our negotiation with BCE to cover the inflationary cost increases, BCE had indicated willingness to increase the per well cost caps on remaining wells in exchange for adding more wells to the current program. Since we have achieved our goals to utilize the JDA as a means to delineate our acreage in Garfield and Canadian counties, Oklahoma, we do not currently plan for any expansion of the JDA. For the nine months ended September 30, 2019, we have therefore recorded additions to oil and natural gas properties of $3,986 in drilling and completion costs on JDA wells that have exceeded the well cost caps specified under the JDA. We have drilled and completed all wells under the JDA.

Reorganization items

Reorganization items reflect, where applicable, expenses, gains and losses incurred that are incremental and a direct result of the reorganization of the business. As a result of our emergence from bankruptcy in March 2017, we have also recorded gains on the settlement of liabilities subject to compromise and gains from restating our balance sheet to fair values under fresh start accounting. “Professional fees” in the table below for periods subsequent to the emergence from bankruptcy consist of legal fees for continuing work to resolve outstanding bankruptcy claims and fees to the U.S. Bankruptcy Trustee, which we will continue to incur until our bankruptcy case is closed. Reorganization items are as follows:

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)



	Three months ended September 30,				Nine months ended September 30,
	2019		2018		2019		2018
Loss on the settlement of liabilities subject to compromise	$	—	$	—	$	—	$	48
Professional fees	530		493		1,306		1,962
Total reorganization items	$	530	$	493	$	1,306	$	2,010

Recently adopted accounting pronouncements

In February 2016, the FASB issued authoritative guidance that supersedes previous lease recognition requirements and requires entities to recognize leases on-balance sheet and disclose key information about leasing arrangements. Please see “Note 5: Leases” for our disclosure regarding adoption of this update.

Recently issued accounting pronouncements

In June 2016, the FASB issued authoritative guidance which modifies the measurement of expected credit losses of certain financial instruments. The guidance is effective for fiscal years beginning after December 15, 2020, however early adoption is permitted for fiscal years beginning after December 15, 2018. The updated guidance impacts our financial statements primarily due to its effect on our accounts receivables. Our history of accounts receivable credit losses almost entirely relates to receivables from joint interest owners in our operated oil and natural gas wells. Based on this history and on mitigating actions, we are permitted to take to offset potential losses such as netting past due amounts against revenue and assuming title to the working interest. We do not expect this guidance to materially impact our financial statements or results of operations.

Note 2: Earnings per share

Although we previously had both Class A and Class B common stock outstanding, where both classes of common stock shared equally in voting power, dividends and undistributed earnings, on December 19, 2018, all outstanding shares of our Class B common stock automatically converted into the same number of shares of Class A common stock.

A reconciliation of the components of basic and diluted EPS is presented below:



	Three months ended September 30,						Nine months ended September 30,
(in thousands, except share and per share data)	2019			2018			2019			2018
Numerator for basic and diluted earnings per share
Net loss	$	(130,935	)	$	(12,068	)	$	(279,704	)	$	(45,503	)
Denominator for basic earnings per share
Weighted average common shares - Basic for Class A and Class B (1)	45,716,522			45,333,745			45,605,798			45,272,595
Denominator for diluted earnings per share
Weighted average common shares - Diluted for Class A and Class B (1)	45,716,522			45,333,745			45,605,798			45,272,595
Earnings per share
Basic for Class A and Class B (1)	$	(2.86	)	$	(0.27	)	$	(6.13	)	$	(1.01	)
Diluted for Class A and Class B (1)	$	(2.86	)	$	(0.27	)	$	(6.13	)	$	(1.01	)
Participating securities excluded from earnings per share calculations
Unvested restricted stock units - stock settled	838,552			—			838,552			—
Unvested restricted stock awards	680,152			1,126,669			680,152			1,126,669

________________________________

(1)

Effective December 19, 2018, all our outstanding Class B shares were converted to Class A shares and subsequently, all our outstanding common stock consisted only of Class A common stock. Earnings per share for the three and nine months ended September 30, 2018 reflects earnings per share for Class A and Class B common stock in aggregate whereas earnings per share for the three and nine months ended September 30, 2019 reflects earnings per share for Class A common stock.

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

Note 3: Supplemental disclosures to the consolidated statements of cash flows



	Nine months ended September 30,
	2019			2018
Net cash provided by operating activities included:
Cash payments for interest	$	30,896		$	5,755
Interest capitalized	(9,431		)	(7,155		)
Cash payments for reorganization items	1,244			2,161
Non-cash investing activities included:
Asset retirement obligation additions and revisions	629			1,234
Leasing right of use asset additions (see Note 5: Leases)	1,643			—
Change in accrued oil and gas capital expenditures	17,272			7,222
Non-cash financing activities included:
Discharge of financing lease obligations (See Note 5: Leases)	9,832			—

Note 4: Debt

As of the dates indicated, long-term debt and financing leases consisted of the following:



	September 30, 2019			December 31, 2018
8.75% Senior Notes due 2023	$	300,000		$	300,000
Credit facility	110,000			—
Real estate mortgage note	—			8,588
Installment note payable	433			354
Financing lease obligations	1,487			11,677
Unamortized debt issuance costs	(10,816		)	(13,148		)
Total debt, net	401,104			307,471
Less current portion	586			12,371
Total long-term debt, net	$	400,518		$	295,100

As discussed in “Note 1: Nature of operations and summary of significant accounting policies,” upon the divestiture of our headquarters building in August 2019, we utilized the sale proceeds to pay off the outstanding balance of our real estate mortgage note which was $8,176 at the time of the repayment.

Our financing lease obligations as of December 31, 2018, included leases on CO₂ compressors that were subleased to the buyer of our former EOR oil and natural gas properties. In September 2019, U.S. Bank entered into agreements with the Sublessee which resulted in the discharge of all our obligations with respect to these compressor leases and the removal of the associated debt from our consolidated balance sheet in the amount of $9,832. Our remaining finance leases consist entirely of leases on our fleet vehicles.

Credit Agreement

Pursuant to our Credit Agreement (the “Credit Agreement”) with Royal Bank of Canada, as administrative agent and issuing bank, and the additional lenders party thereto, we have a $750,000 credit facility collateralized by our oil and natural gas properties and is scheduled to mature on December 21, 2022. Availability under our credit facility is subject to the financial covenants discussed below and a borrowing base based on the value of our oil and natural gas properties and set by the banks semi-annually on or around May 1 and November 1 of each year. Our borrowing base under the credit facility as of September 30, 2019, was $325,000.

As of September 30, 2019, our outstanding borrowings were accruing interest at the Adjusted LIBO Rate (as defined in the Credit Agreement, as defined below), plus the Applicable Margin (as defined in the Credit Agreement), which resulted in a weighted average interest rate of 4.34%.

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

The Credit Agreement contains financial covenants that require, for each fiscal quarter, we maintain: (1) a Current Ratio (as defined in the Credit Agreement) of no less than 1.00 to 1.00, and (2) a Ratio of Total Debt to EBITDAX (as defined in the Credit Agreement) of no greater than 4.0 to 1.0 calculated on a trailing four-quarter basis. We were in compliance with these financial covenants as of September 30, 2019.

The Credit Agreement contains covenants and events of default customary for oil and natural gas reserve-based lending facilities. Please see “Note 8: Debt” in “Item 8. Financial Statements and Supplementary Data” of our Annual Report on Form 10-K for the year ended December 31, 2018, for a discussion of the material provisions of our Credit Agreement.

On May 2, 2019, we entered into the Third Amendment to the Tenth Restated Credit Agreement (the “Credit Agreement”), among the Company and its subsidiaries, as borrowers, certain financial institutions party thereto, as lenders, and Royal Bank of Canada, as administrative agent (the “Third Amendment”). The Third Amendment, which was effective March 31, 2019, reaffirmed our borrowing base at the same level as it was at the beginning of 2019, at $325,000.

On September 27, 2019, we entered into the Fourth Amendment (the “Amendment”) to the Credit Agreement. The Amendment, among other things, (i) reaffirmed the borrowing base at $325,000; (ii) amended the definition of EBITDAX to, among other things, (a) added back losses related to or resulting from the full or partial extinguishment of debt, (b) expanded the add-back of amounts associated with retirements, severance or departure to apply to all employees or former employees, and (c) clarified that gains related to or resulting from the full or partial extinguishment of debt are excluded; and (iii) revised certain negative covenants to provide that the Company, under certain circumstances, may prepay or otherwise redeem certain Permitted Senior Additional Debt (as defined in the Credit Agreement) in an aggregate amount not to exceed $30,000.

Senior Notes

On June 29, 2018, we completed the issuance and sale at par of $300,000 in aggregate principal amount of our Senior Notes in a private placement under Rule 144A and Regulation S under the Securities Act of 1933, as amended. The Senior Notes bear interest at a rate of 8.75% per year beginning June 29, 2018 (payable semi-annually in arrears on January 15 and July 15 of each year, beginning on January 15, 2019) and will mature on July 15, 2023.

The Senior Notes are the Company’s senior unsecured obligations and rank equal in right of payment with all of the Company’s existing and future senior indebtedness, senior to all of the Company’s existing and future subordinated indebtedness and effectively subordinated to all of the Company’s existing and future secured indebtedness, to the extent of the value of the collateral securing such indebtedness.

The Senior Notes contain customary covenants, certain callable provisions and events of default. Please see “Note 8: Debt” in “Item 8. Financial Statements and Supplementary Data” of our Annual Report on Form 10-K for the year ended December 31, 2018, for a discussion of the material provisions of our Senior Notes.

Note 5: Leases

In February 2016, the FASB established Accounting Standards Codification (“ASC”) Topic 842, Leases (“ASC 842”) which requires lessees to recognize leases on-balance sheet and disclose key information about leasing arrangements. ASC 842 was subsequently amended by Accounting Standards Update (“ASU”) No. 2018-01, Land Easement Practical Expedient for Transition to Topic 842; ASU No. 2018-10, Codification Improvements to Topic 842, Leases, ASU No. 2018-11, Targeted Improvements and ASU No 2019-01, Codification Improvements. The new standard establishes a right-of-use (“ROU”) model that requires a lessee to recognize a ROU asset and lease liability on the balance sheet for all leases except those with a term of 12 months or less. Leases will be classified as finance or operating, with classification affecting the pattern and classification of expense recognition in the income statement. We adopted the new standard on its effective date of January 1, 2019, which is also our date of initial application. Consequently, we have not updated financial information nor provided disclosures required under the new standard for dates and periods before January 1, 2019. Our disclosures for dates and periods before January 1, 2019, are provided in accordance with the requirements of ASC Topic 840, Leases (“ASC 840”).

We have elected the package of transition practical expedients, which permits us not to reassess under the new standard our prior conclusions about lease identification, lease classification and initial direct costs. Additionally, we have elected not to apply the recognition requirements of ASC Topic 842 to leases with durations of 12 months or less. Upon adoption of ASC 842, we carried over

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

our existing capital lease obligations (now “financing leases” under ASC 842) and capital lease asset (now “right of use asset” under ASC 842) at their previous carrying value.

Financing leases

We previously had lease financing agreements which were entered into during 2013 with U.S. Bank for $24,500 through the sale and subsequent leaseback of existing CO₂ compressors owned by us. The lease financing obligations were for terms of 84 months and included the option to purchase the equipment for a specified price at 72 months as well as an option to purchase the equipment at the end of the lease term for its then-current fair market value. There were no residual value guarantees and nonlease components under these leases. At the inception of the lease, our measurement of the lease liability assumed that the mid-term purchase option would be exercised. Since the lease contract had not been modified and there were no triggering events subsequent to our adoption of ASC 842, we did not perform any reassessment of the lease prior to its termination discussed below. Lease payments related to the equipment were recognized as principal and interest expense based on a weighted average implicit interest rate of 3.8%. Minimum lease payments were approximately $3,181 annually. In conjunction with the sale of our EOR assets in November 2017, these compressors were subleased to the buyer of those assets while we remained the primary obligor in relation to U.S. Bank. In September 2019, U.S. Bank entered into agreements with the sublessee which resulted in the discharge of the remaining obligations with respect to these compressor leases in the amount of $9,832.

During 2019, we entered into lease financing agreements for our fleet trucks for $1,643. The lease financing obligations are for 48-month terms with the option for us to purchase the vehicle at any time during the lease term by paying the lessor’s remaining unamortized cost in the vehicle. At the end of the lease term, the lessor’s remaining unamortized cost in the vehicle will be a de minimis amount and hence ownership of the vehicle can be transferred to us at minimal cost. There are no residual value guarantees or nonlease components under these leases.

Operating leases

We previously also had operating leases for CO₂ compressors deployed in our former EOR operations. The operating lease obligations, which we entered into in 2014 and 2016, were for terms of 84 months without any specified purchase options. There were no residual value guarantees or nonlease components under these leases. In conjunction with the sale of our EOR assets in November 2017, these compressors were subleased to the buyer of those assets although we remained the primary obligor in relation to U.S. Bank. Similar to the financing leases discussed above, all our obligations under these compressor leases were discharged by U.S. Bank in September 2019.

During the fourth quarter of 2018, we entered into 15-month leasing arrangements for two drilling rigs. These agreements specify a minimum daily rate on the rigs that we utilize to measure the lease liability upon adoption of ASC 842. The actual daily rate may vary from the minimum rate depending on whether the rig is being mobilized, demobilized, engaged in drilling or on standby. The daily rate includes a non-lease labor component that we have elected not to separate from the lease component for this asset class.

On August 30, 2019, in conjunction with the sale of the building housing our headquarters, we entered into a leaseback agreement with the buyer for a portion of the office space in the building for a period of two years with a renewal option that includes one-year extensions for up to two years. The office space lease includes typical non-lease components such as utilities, maintenance and janitorial services for that we have elected not to separate from the lease component.

Short term leases

Our short term leases are those with lease terms of 12 months or less and generally consist of wellhead compressors, generators and drilling rigs with terms ranging from one month to six months. As discussed above, we have elected not to recognize right of use assets or lease liabilities for leases with durations of 12 months or less.

Subleases

As discussed above, we previously had subleases consisting of CO₂ compressors that were utilized in our former EOR operations and leased as both financing and operating leases from U.S. Bank but subsequently subleased to the purchaser of our EOR assets (the “Sublessee”). Minimum payments under the subleases were equal to the original leases and as such we did not record any losses upon initiation of the subleases. All the subleases were classified as operating leases from a lessor’s standpoint. All payments received from the Sublessee were reflected as “Sublease revenue” on our statement of operations. Minimum payments made to U.S. Bank on the original operating leases were reflected as “Other” expense on our statement of operations. With respect to the financing leases, upon

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

executing the subleases, we reclassified the amount associated with these leases from the full cost amortization base to “Property and equipment, net” on our balance sheet, amortized the asset on a straight line basis prospectively while continuing to incur interest expense. In September 2019, U.S. Bank entered into agreements with the sublessee which resulted in the discharge of all our obligations with respect to the originating leases and to the subleases.

Lease assets and liabilities

Our operating lease and financing lease assets and liabilities are recorded on our balance sheet as of September 30, 2019 as follows:



	As of September 30, 2019
	Operating leases		Financing leases
Right of use asset:
Right of use assets from operating leases (1)	$	5,853	$	—
Plant, property and equipment, net (2)	—		1,478
Total lease assets	$	5,853	$	1,478
Lease liability:
Account payable and accrued liabilities	$	4,301	$	—
Long-term debt and financing leases, classified as current	—		381
Long-term debt and financing leases, less current maturities	—		1,106
Noncurrent operating lease obligations	1,239		—
Total lease liabilities	$	5,540	$	1,487

________________________________

(1) Consisted of leases on office space and drilling rigs.

(2) Consisted of leased fleet vehicles.

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

Our income, expenses and cash flows related to our leases is as follows for the three and nine months ended September 30, 2019:



	Three months ended			Nine months ended
	September 30, 2019			September 30, 2019
Lease cost
Finance lease cost:
Amortization of right-of-use assets	$	544		$	1,986
Interest on lease liabilities	87			317
Operating lease cost	205			821
Short-term lease cost	180			463
Variable lease cost	63			253
Sublease income	(799		)	(3,195		)
Total lease cost	$	280		$	645

Capitalized operating lease cost (1)	$	3,409		$	10,115

Other information
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows for finance leases	$	(87	)	$	(317	)
Operating cash flows for operating leases	(205		)	(821		)
Investing cash flows for operating leases	(3,510		)	(7,498		)
Financing cash flows for finance leases	(557		)	(2,002		)
Right-of-use assets obtained in exchange for new finance lease liabilities	256			1,643

________________________________


(1)	The operating lease cost are related to drilling rigs and are capitalized as part of oil and natural gas properties on our balance sheets.



	As of
	September 30, 2019
Weighted-average remaining lease term - finance leases	3.6 years
Weighted-average remaining lease term - operating leases	1.0 year
Weighted-average discount rate - finance leases	6.29	%
Weighted-average discount rate - operating leases	10.97	%

Our rent expense for the three months and nine months ended September 30, 2018, was $918 and $2,984, respectively.

Discount rate

Whenever possible, we utilize the implied rate in our lease agreements to measure our lease liabilities. In the absence of a readily available implied rate, we utilize our incremental borrowing rate. The incremental borrowing rate is the rate of interest that a lessee would have to pay to borrow on a collateralized basis over a similar term an amount equal to the lease payments in a similar economic environment. The lease liabilities we recorded on our balance sheet on the effective date of ASC 842 were measured utilizing an incremental borrowing rate derived from the yield on our unsecured Senior Notes and adjusted to a collateralized basis utilizing a recovery rate model that uses observed recovery rates on defaulted debt instruments.

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

Lease maturities

Our lease payments for each of the next five years and thereafter are as follows:



	As of September 30, 2019				As of December 31, 2018 (1)
	Operating leases		Financing leases		Operating leases		Financing leases
2019	$	3,475	$	116	$	13,890	$	12,332
2020	1,389		464		1,330		—
2021	941		464		1,297		—
2022	—		464		278		—
2023	—		160		205		—
Thereafter	—		—		—		—
Total minimum lease payments	5,805		1,668		17,000		12,332
Less: imputed interest	265		181		*		*
Total lease liability	5,540		1,487		*		*
Less: current maturities of lease obligations	4,301		381		*		*
Noncurrent lease obligations	$	1,239	$	1,106	*		*

________________________________


(1)	Represents undiscounted firm commitments as of December 31, 2018

* Disclosure not required under ASC 840.

Method of adoption

We adopted ASC 842 effective January 1, 2019, using the modified retrospective approach. Based on an assessment of our leasing contracts, we did not record a cumulative effect adjustment to the opening balance of accumulated deficit.

Reconciliation of Balance Sheet Statement

In accordance with ASC 842, the disclosure of the impact of adoption on our balance statement is as follows:



	As of January 1, 2019
	Balances upon adoption		Balances without adoption of ASC 842		Effect of change
Assets
Right of use asset from operating leases, net	$	14,999	$	—	$	14,999
Liabilities
Accounts payable and accrued liabilities	12,467		—		12,467
Noncurrent operating lease obligation	2,532		—		2,532

Note 6: Derivative instruments

Overview

Our results of operations, financial condition and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil, natural gas and natural gas liquids. These commodity prices are subject to wide fluctuations and market uncertainties. To mitigate a portion of this exposure, we enter into various types of derivative instruments, including commodity price swaps, collars, and basis protection swaps.

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

The following table summarizes our crude oil derivatives outstanding as of September 30, 2019:



		Weighted average fixed price per Bbl
Period and type of contract	Volume MBbls	Swaps		Purchased Puts		Sold Calls
2019
Oil swaps	688	$	55.90	$	—	$	—
Oil roll swaps	120	$	0.46	$	—	$	—
2020
Oil swaps	2,274	$	51.01	$	—	$	—
Oil roll swaps	410	$	0.38	$	—	$	—
Oil collars	195	$	—	$	55.00	$	66.42
2021
Oil swaps	689	$	46.24	$	—	$	—
Oil roll swaps	150	$	0.30	$	—	$	—

The following table summarizes our natural gas derivatives outstanding as of September 30, 2019:



Period and type of contract	Volume BBtu	Weighted average fixed price per MMBtu
2019
Natural gas swaps	3,977	$	2.85
Natural gas basis swaps	3,977	$	(0.51	)
2020
Natural gas swaps	7,680	$	2.70
Natural gas basis swaps	7,080	$	(0.46	)

The following table summarizes our natural gas liquid derivatives outstanding as of September 30, 2019:



Period and type of contract	Volume Thousands of Gallons	Weighted average fixed price per gallon
2019
Natural gasoline swaps	4,200	$	1.13
Propane swaps	9,156	$	0.61
Butane swaps	2,394	$	0.71
2020
Natural gasoline swaps	6,508	$	1.15
Propane swaps	14,872	$	0.57
Butane swaps	2,849	$	0.68

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

Effect of derivative instruments on the consolidated balance sheets

All derivative financial instruments are recorded on the balance sheet at fair value. See “Note 7: Fair value measurements” for additional information regarding fair value measurements. The estimated fair values of derivative instruments are provided below. The carrying amounts of these instruments are equal to the estimated fair values.



	As of September 30, 2019									As of December 31, 2018
	Assets			Liabilities			Net value			Assets			Liabilities			Net value
Natural gas derivative contracts	$	5,055		$	(40	)	$	5,015		$	833		$	(488	)	$	345
Crude oil derivative contracts	5,174			(6,164		)	(990		)	24,208			(4,452		)	19,756
NGL derivative contracts	5,871			(431		)	5,440			4,581			—			4,581
Total derivative instruments	16,100			(6,635		)	9,465			29,622			(4,940		)	24,682
Less:
Netting adjustments (1)	(3,543		)	3,543			—			(3,398		)	3,398			—
Derivative instruments - current	11,446			(70		)	11,376			24,025			—			24,025
Derivative instruments - long-term	$	1,111		$	(3,022	)	$	(1,911	)	$	2,199		$	(1,542	)	$	657

________________________________


(1)	Amounts represent the impact of master netting agreements that allow us to net settle positive and negative positions with the same counterparty. Positive and negative positions with counterparties are netted only to the extent that they relate to the same current versus noncurrent classification on the balance sheet.

Effect of derivative instruments on the consolidated statements of operations

“Derivative gains (losses)” in the consolidated statements of operations consist of the following:



	Three months ended September 30,					Nine months ended September 30,
	2019		2018			2019			2018
Change in fair value of commodity price derivatives	$	18,718	$	(16,804	)	$	(15,217	)	$	(55,822	)
Settlements received (paid) on commodity price derivatives	4,883		(6,873		)	5,536			(16,642		)
Total derivative gains (losses)	$	23,601	$	(23,677	)	$	(9,681	)	$	(72,464	)

Note 7: Fair value measurements

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, valuation models are applied. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for the instruments or market and the instruments’ complexity.

We categorize fair value measurements based upon the level of judgment associated with the inputs used to measure the fair value of the assets and liabilities as follows:

•Level 1 inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date.

•Level 2 inputs include quoted prices for identical or similar instruments in markets that are not active and inputs other than

quoted prices that are observable for the asset or liability.

•Level 3 inputs are unobservable inputs for the asset or liability, and include situations where there is little, if any, market

activity for the asset or liability.

In certain cases, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. In such cases, the asset or liability is categorized based on the lowest level input that is significant to the fair value measurement in its entirety. Our

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment, and may affect the placement of assets and liabilities within the levels of the fair value hierarchy.

Recurring fair value measurements

As of September 30, 2019, and December 31, 2018, our financial instruments recorded at fair value on a recurring basis consisted of commodity derivative contracts (see “Note 6: Derivative instruments”). We had no Level 1 assets or liabilities. Our derivative contracts classified as Level 2 consisted of commodity price swaps and oil roll swaps which are valued using an income approach. Future cash flows from the commodity price swaps are estimated based on the difference between the fixed contract price and the underlying published forward market price. Our derivative contracts classified as Level 3 consisted of collars and natural gas basis swaps. The fair value of these contracts is developed by a third-party pricing service using a proprietary valuation model, which we believe incorporates the assumptions that market participants would have made at the end of each period. Observable inputs include contractual terms, published forward pricing curves, and yield curves. Significant unobservable inputs are implied volatilities and proprietary pricing curves. Significant increases (decreases) in implied volatilities in isolation would result in a significantly higher (lower) fair value measurement. We review these valuations and the changes in the fair value measurements for reasonableness. All derivative instruments are recorded at fair value and include a measure of our own nonperformance risk for derivative liabilities or our counterparty credit risk for derivative assets.

The fair value hierarchy for our financial assets and liabilities is shown by the following table:



	As of September 30, 2019								As of December 31, 2018
	Derivative assets			Derivative liabilities			Net assets (liabilities)		Derivative assets			Derivative liabilities			Net assets (liabilities)
Significant other observable inputs (Level 2)	$	14,006		$	(6,635	)	$	7,371	$	29,370		$	(4,718	)	$	24,652
Significant unobservable inputs (Level 3)	2,094			—			2,094		252			(222		)	30
Netting adjustments (1)	(3,543		)	3,543			—		(3,398		)	3,398			—
	$	12,557		$	(3,092	)	9,465		$	26,224		$	(1,542	)	$	24,682

________________________________


(1)	Amounts represent the impact of master netting agreements that allow us to net settle positive and negative positions with the same counterparty. Positive and negative positions with counterparties are netted on the balance sheet only to the extent that they relate to the same current versus noncurrent classification.

Changes in the fair value of our derivative instruments, classified as Level 3 in the fair value hierarchy, were as follows for the periods presented:



	Nine months ended September 30,
Net derivative assets (liabilities)	2019			2018
Beginning balance	$	30		$	(295	)
Realized and unrealized gains (losses) included in derivative losses	2,371			(1,069		)
Settlements (received) paid	(307		)	959
Ending balance	$	2,094		$	(405	)
Gains (losses) relating to instruments still held at the reporting date included in derivative gains (losses) for the period	$	2,094		$	(342	)

Nonrecurring fair value measurements

Asset retirement obligations. Additions to the asset and liability associated with our asset retirement obligations are measured at fair value on a nonrecurring basis. Our asset retirement obligations consist of the estimated present value of future costs to plug and abandon or otherwise dispose of our oil and natural gas properties and related facilities. Significant inputs used in determining such obligations include estimates of plugging and abandonment costs, inflation rates, discount rates, and well life, all of which are Level 3 inputs according to the fair value hierarchy. The table below discloses the inflation and discount rate assumptions for the periods presented:

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)



	Nine months ended September 30, 2019				Nine months ended September 30, 2018
	Low		High		Low		High
Inflation rate (1)	2.25	%	2.25	%	2.26	%	2.26	%
Credit-adjusted risk-free discount rate	12.35	%	21.79	%	6.92	%	8.77	%

________________________________


(1)	The inflation rate is measured as a single rate on an annual basis.

These estimates may change based upon future inflation rates and changes in statutory remediation rules. See “Note 8: Asset retirement obligations” for additional information regarding our asset retirement obligations.

Fair value of other financial instruments

Our significant financial instruments, other than derivatives, consist primarily of cash and cash equivalents, accounts receivable, accounts payable, and debt. We believe the carrying values of cash and cash equivalents, accounts receivable, and accounts payable approximate fair values due to the short-term maturities of these instruments.

The carrying value and estimated fair value of our debt were as follows:



	September 30, 2019				December 31, 2018
Level 2	Carrying value (1)		Estimated fair value		Carrying value (1)		Estimated fair value
8.75% Senior Notes due 2023	$	300,000	$	124,389	$	300,000	$	213,618
Credit facility	110,000		110,000		—		—
Other secured debt (2)	433		433		8,942		8,942

________________________________


(1)	The carrying value excludes deductions for debt issuance costs.


(2)	The balance on September 30, 2019, consisted of only equipment installment notes while the balance on December 31, 2018, consisted of real estate and equipment installment notes.

The carrying value of our credit facility and other secured long-term debt approximates fair value because the rates are comparable to those at which we could currently borrow under similar terms, are variable and incorporate a measure of our credit risk. The fair value of our Senior Notes was estimated based on quoted market prices.

Counterparty credit risk

Our derivative contracts are executed with institutions, or affiliates of institutions, that are parties to our credit facilities at the time of execution, and we believe the credit risks associated with all of these institutions are acceptable. We do not require collateral or other security from counterparties to support derivative instruments. Master agreements are in place with each of our derivative counterparties which provide for net settlement in the event of default or termination of the contracts under each respective agreement. As a result of the netting provisions, our maximum amount of loss under derivative transactions due to credit risk is limited to the net amounts due from the counterparties under the derivatives. Our loss is further limited as any amounts due from a defaulting counterparty that is a Lender, or an affiliate of a Lender, under our credit facilities can be offset against amounts owed to such counterparty Lender. As of September 30, 2019, the counterparties to our open derivative contracts consisted of eight financial institutions, all of which were lenders under our credit facility.

The following table summarizes our derivative assets and liabilities which are offset in the consolidated balance sheets under our master netting agreements. It also reflects the amounts outstanding under our credit facilities that are available to offset our net derivative assets due from counterparties that are lenders under our credit facilities.

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)



	Offset in the consolidated balance sheets									Gross amounts not offset in the consolidated balance sheets
	Gross assets (liabilities)			Offsetting assets (liabilities)			Net assets (liabilities)			Derivatives (1)			Amounts outstanding under credit facilities (2)			Net amount
September 30, 2019
Derivative assets	$	16,100		$	(3,543	)	$	12,557		$	(1,757	)	$	(10,800	)	$	—
Derivative liabilities	(6,635		)	3,543			(3,092		)	1,757			—			(1,335		)
	$	9,465		$	—		$	9,465		$	—		$	(10,800	)	$	(1,335	)
December 31, 2018
Derivative assets	$	29,622		$	(3,398	)	$	26,224		$	(1,542	)	$	—		$	24,682
Derivative liabilities	(4,940		)	3,398			(1,542		)	1,542			—			—
	$	24,682		$	—		$	24,682		$	—		$	—		$	24,682

________________________________


(1)	Since positive and negative positions with a counterparty are netted on the balance sheet only to the extent that they relate to the same current versus noncurrent classification, these represent remaining amounts that could have been offset under our master netting agreements.


(2)	The amount outstanding under our credit facility that is available to offset our net derivative assets due from counterparties that are lenders under our credit facility.

We did not post additional collateral under any of these contracts as all of our counterparties are secured by the collateral under our credit facilities. Payment on our derivative contracts could be accelerated in the event of a default under our Credit Agreement. The aggregate fair value of our derivative liabilities subject to acceleration in the event of default was $6,635 before offsets at September 30, 2019.

Note 8: Asset retirement obligations

The following table provides a summary of our asset retirement obligation activity:



Balance at January 1, 2019	$	23,147
Liabilities incurred in current period	429
Liabilities settled or disposed in current period	(739		)
Revisions in estimated cash flows	200
Accretion expense	1,089
Balance at September 30, 2019	$	24,126
Less current portion included in accounts payable and accrued liabilities	1,742
Asset retirement obligations, long-term	$	22,384

See “Note 7: Fair value measurements” for additional information regarding fair value assumptions associated with our asset retirement obligations.

Note 9: Deferred compensation

Our deferred compensation includes cash awards and equity-based awards which are either settled in cash or in stock.

Cash Awards

From time to time, we have granted cash awards with long term vesting requirements. During 2015 and 2017, we granted long term cash awards to certain employees of the Company, which vest in equal annual increments over a four-year period. In August 2019, we granted cash awards, which vest in one year. Since the cash awards do not vary according to the value of the Company’s equity, the awards are not considered “stock-based compensation” under accounting guidance. We accrue for the cost of each annual increment over the period service is required to vest. A summary of compensation expense for our cash awards is presented below:

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)



	Three months ended September 30,					Nine months ended September 30,
	2019			2018		2019		2018
Cash LTIP expense (net of amounts capitalized)	$	(11	)	$	185	$	147	$	473
Cash LTIP awarded	775			127		775		174
Cash LTIP payments	955			1,166		955		1,183

The negative expense for the three months ended September 30, 2019, was a result of forfeitures. As of September 30, 2019, the outstanding liability accrued for our Cash LTIP, based on requisite service provided, was $732.

Equity Awards

The Company’s outstanding equity based awards have been granted under the 2017 Chaparral Energy, Inc. Management Incentive Plan (the “MIP”) and the Chaparral Energy, Inc. 2019 Long-Term Incentive Plan (the “LTIP”), which replaced the MIP in June 2019. The LTIP provides for the following types of awards: options, stock appreciation rights, restricted stock, restricted stock units, performance awards and other incentive awards. The aggregate number of shares of Class A common stock, par value $0.01 per share, reserved for issuance pursuant to the LTIP is set at 3,500,000. Generally, and to the extent not provided otherwise in an award agreement, (i) in the event of a Change in Control (as defined in the LTIP) in which the acquiring or surviving entity does not assume an outstanding award, the award will fully vest, and (ii) in the event of termination by the Company of a participant’s employment or service without cause or by the participant for Good Reason (as defined in the LTIP), in each case, within one year following the occurrence of a Change in Control, the award will fully vest. These accelerated vesting provisions are in addition to the service, performance or market based vesting provisions described below.

Restricted Stock Awards (“RSAs”)

Pursuant to the MIP, we have granted RSAs to our executive employees and members of our Board of Directors (the “Board”). Grants awarded to executives generally consist of shares for which 75% are subject to service vesting conditions (the “Time Shares”) and 25% are subject to performance or market-based vesting conditions (the “Performance Shares”). All grants to members of our Board were Time Shares.

Both the Time Shares and the Performance Shares are classified as equity-based awards. The Time Shares vest in equal annual installments over the three-year vesting period. The Performance Shares vest in three tranches annually according to performance or market-based conditions established each year which generally relate to profitability, stock returns, drilling results and other strategic goals.

Vesting conditions for Performance Shares vesting in 2019 were established and approved by our Board in March 2019 and we began recognizing expense for the related shares in the first quarter of 2019. Our Board established that all Performance Shares scheduled to vest in 2019 shall be subject to a market condition that is based on our stock return relative to a group of peer companies. See “Valuation of Awards” below for a discussion of grant date fair values of our market condition awards.

A summary of our restricted stock activity pursuant to our MIP is presented below:



	Time Shares						Performance Shares
	Weighted average award date fair value		Restricted shares		Vest date fair value		Weighted average award date fair value		Restricted shares
	($ per share)						($ per share)
Unvested and outstanding at January 1, 2019	$	20.06	818,206				$	20.12	125,528
Granted	$	6.94	198,378				$	6.74	55,000
Vested	$	20.00	(393,178	)	$	2,319	$	—	—
Forfeited	$	20.05	(95,684	)			$	20.05	(28,098	)
Unvested and outstanding at September 30, 2019	$	15.17	527,722				$	15.30	152,430

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

Restricted Stock Units (“RSUs”)

In 2018, we issued RSUs under our MIP to certain non-executive employees in lieu of cash awards. Certain RSUs are to be settled in stock upon vesting while others are to be settled in cash. The stock-settled RSUs are classified as equity awards while the cash-settled RSUs are classified as liability awards. These awards, which are service-based, will vest in equal installments over a three-year period.

In August 2019, we issued RSUs under our LTIP to executive employees, non-executive employees and members of our Board with the following provisions:

Executive employee awards: Grants consisted of RSUs for which 50% are subject to service vesting conditions and 50% are subject to market-based vesting conditions. Service-based RSUs vest in equal annual installments over a three-year period. Market condition RSUs vest in three annual tranches according to our stock return performance relative to a group of peers. The stock return performance is measured over three separate twelve month periods associated with each of the tranches. Both types of awards were classified as equity awards.

Non-executive employee awards: Grants consisted of RSUs with service vesting conditions and vest in equal annual installments over a three-year period. These awards were classified as equity awards.

Board awards: Grants consisted of RSUs with service vesting conditions and which vest in its entirety on the earlier of (a) the first anniversary of the grant date or (b) the date of the next Company ensuing annual meeting. These awards were classified as liability awards.

A summary of our RSU activity is presented below:



	Equity classified RSUs
	Service-condition RSUs						Market condition RSUs
	Weighted average award date fair value		Restricted units		Vest date fair value		Weighted average award date fair value		Restricted units
	($ per share)						($ per share)
Unvested and outstanding at January 1, 2019	$	17.66	89,633				$	—	—
Granted	$	1.33	788,323				$	1.36	565,000
Vested	$	17.66	(25,099	)	$	33	$	—	—
Forfeited	$	17.66	(14,305	)			$	—	—
Unvested and outstanding at September 30, 2019	$	2.31	838,552				$	1.36	565,000

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)



	Liability classified RSUs (1)
	Weighted average award date fair value		Restricted units		Vest date fair value
	($ per share)
Unvested and outstanding at January 1, 2019	$	17.66	37,196
Granted	$	1.44	71,570
Vested	$	17.09	(10,302	)	$	14
Forfeited	$	17.66	(7,836	)
Unvested and outstanding at September 30, 2019	$	4.92	90,628

Valuation of Awards

Compensation cost is generally recognized and measured according to the grant date fair value of the awards. For awards with service and performance conditions, the fair value is based on the market price of our Class A common stock on the grant date. For awards with a market condition, expense is based on a grant date fair value that incorporates the probability of vesting and the potential value of the award at vesting. We utilize Monte Carlo simulations to estimate the fair value our market based awards. The fair value and associated assumptions, which are considered to be Level 3 inputs within the fair value hierarchy, for each RSA or RSU granted in 2019 with a market condition is as follows:



	Grant Date of Market Condition Award
	August 30, 2019			April 22, 2019			March 11, 2019
Grant date fair value	$	1.41		$	8.59		$	4.66
Risk free rate	1.75		%	2.52		%	2.52		%
Volatility	90.0		%	64.1		%	64.1		%

Company-wide stock award

Historically, new employees were eligible for a grant of 100 shares of our Class A common stock subsequent to being employed for a certain period of time. There are no vesting requirements for these awards and thus compensation is recognized in full on the award date based on the closing price of our Class A common stock on that date. During the nine months ended September 30, 2019, 1,100 shares of Class A common stock were awarded to new employees under this program.

Stock-based compensation cost

Compensation cost is calculated net of forfeitures. We recognize the impact of forfeitures due to employee terminations in expense as those forfeitures occur instead of incorporating an estimate of such forfeitures. For awards with performance conditions, we will assess the probability that a performance condition will be achieved at each reporting period to determine whether and when to recognize compensation cost. For awards with market conditions, expense is recognized on the entire value of the award regardless of the vesting outcome so long as the participant remains employed.

A portion of stock-based compensation cost associated with employees involved in our acquisition, exploration, and development activities has been capitalized as part of our oil and natural gas properties. The remaining cost is reflected in lease operating and general and administrative expenses in the consolidated statements of operations. Stock-based compensation expense is as follows for the periods indicated:

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)



	Three months ended September 30,						Nine months ended September 30,
	2019			2018			2019			2018
Stock-based compensation cost	$	883		$	3,112		$	3,603		$	11,027
Less: stock-based compensation cost capitalized	(222		)	(807		)	(1,247		)	(2,428		)
Stock-based compensation expense	$	661		$	2,305		$	2,356		$	8,599
Number of vested shares repurchased or settled in cash	17,889			—			224,542			256,895
Payments for stock-based compensation	24			—			1,195			4,872

Based on a quarter end market price of $1.34 per share of our Class A common stock, the aggregate intrinsic value of all restricted shares and stock settled RSUs outstanding was $2,914 as of September 30, 2019. The repurchases or cash settlements and associated payments disclosed above were primarily for tax withholding. As of September 30, 2019, and December 31, 2018, accrued payroll and benefits payable included for stock-based compensation costs expected to be settled within the next twelve months were $17 and $17, respectively, all of which relates to our cash-settled RSUs. Unrecognized stock-based compensation cost of approximately $4,296 as of September 30, 2019, is expected to be recognized over a weighted-average period of 1.2 years.

Note 10: Commitments and contingencies

Standby letters of credit (“Letters”) available under our credit facility are used in lieu of surety bonds with various organizations for liabilities relating to the operation of oil and natural gas properties. We had Letters outstanding totaling $0 as of September 30, 2019 and $869 as of December 31, 2018. When amounts under the Letters are paid by the lenders, interest accrues on the amount paid at the same interest rate applicable to borrowings under the credit facility. No amounts were paid by the lenders under the Letters; therefore, we paid no interest on the Letters during the nine months ended September 30, 2019 or 2018.

Litigation and Claims

Chapter 11 Proceedings. Commencement of the Chapter 11 Cases automatically stayed many of the proceedings and actions against us noted below as well as other claims and actions that were or could have been brought prior to May 9, 2016 (“Petition Date”), and the claims remain subject to Bankruptcy Court jurisdiction. With respect to the proofs of claim asserted in the Chapter 11 Cases arising from the proceedings or actions below that were initiated prior to the Petition Date, we are unable to estimate the amount of such claims that will be allowed by the Bankruptcy Court due to, among other things, the complexity and number of legal and factual issues which are necessary to determine the amount of such claims and uncertainties related to the nature of defenses asserted in connection with the claims, the potential size of the putative classes, and the types of the properties and scope of agreements related to such claims. As a result, no reserves were established in respect of such proofs of claims or any of the proceedings or actions described below. To the extent that any of the legal proceedings were filed and relate to one or more claims accruing prior to the Petition Date and result in a claim being allowed against us, pursuant to the terms of the Reorganization Plan, such claims will be satisfied through the issuance of new stock in the Company or, if the amount of such claim is below the convenience class threshold, through cash settlement. Of the total alleged dollar amount of claims still unresolved, the large majority, as measured by the alleged amount of such claims, consists of claims from the Naylor Farms case described below. If the Bankruptcy Court were to allow the remaining unresolved proofs of claims from any of these cases, the Company, pursuant to the Plan of Reorganization, would be required to issue additional shares to the holders of such allowed proofs of claim that are in excess of a convenience class threshold, which would result in dilution to existing stockholders.

Naylor Farms, Inc., individually and as class representative on behalf of all similarly situated persons v. Chaparral Energy, L.L.C (the “Naylor Farms case”). On June 7, 2011, an alleged class action was filed against us in the United States District Court for the Western District of Oklahoma (“Naylor Trial Court”) alleging that we improperly deducted post-production costs from royalties paid to plaintiffs and other non-governmental Royalty Interest owners from crude oil and natural gas wells we operate in Oklahoma. The plaintiffs have alleged a number of claims, including breach of contract, fraud, breach of fiduciary duty, unjust enrichment, and other claims and seek termination of leases, recovery of compensatory damages, interest, punitive damages and attorney fees on behalf of the alleged class. Plaintiffs indicated they seek damages in excess of $5,000, the majority of which would consist of interest and may increase with the passage of time.

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

The Naylor Trial Court certified a class of plaintiffs with oil and gas leases containing specific language with claims beginning June 1, 2006 through present and our appeal of that class certification was subsequently denied by the United States Court of Appeals for the Tenth Circuit.

In addition to filing claims on behalf of the named plaintiffs and putative class members, plaintiffs' attorneys, on behalf of the putative class, filed amended proofs of claims in our Chapter 11 Cases in excess of $90,000 inclusive of actual and punitive damages, statutory interest and attorney fees. The Company's objection to treatment of the claims on a class basis is the subject of an appeal pending with the United States Court of Appeals for the Third Circuit.

We continue to dispute the plaintiffs’ allegations and are objecting to the claims both individually and on a class-wide basis. To the extent that any claims are allowed, determined or settled in favor of plaintiffs and they accrued prior to the Petition Date, pursuant to the terms of the Reorganization Plan, such claims will be satisfied through the issuance of new shares of common stock in the Company.

Lacheverjuan Bennett et al. v. Chaparral Energy, L.L.C., et al. On March 26, 2018, a group of twenty-seven individual plaintiffs filed a lawsuit in the District Court of Logan County, State of Oklahoma against twenty-three named defendants, including us, and twenty-five unnamed defendants. Plaintiffs all claim to be property owners and residents of Logan County, Oklahoma, and allege the defendants, all oil and gas companies which have engaged in injection well operations, induced earthquakes which have caused damage to real and personal property, and caused emotional damages. Plaintiffs claim absolute liability for ultra-hazardous activities, negligence, gross negligence, public and private nuisance, and trespass, and ask for compensatory and punitive damages, and attorney fees and costs. On November 1, 2019, we were dismissed from the case.

Hallco Petroleum, Inc. v. Chaparral Energy, L.L.C. On November 7, 2017, Hallco Production, LLC (“Hallco”) filed a lawsuit against us in the District Court of Kay County, State of Oklahoma. Plaintiffs alleged carbon dioxide which was injected for enhanced oil recovery in wells operated by us in the North Burbank Unit migrated to wells operated by Hallco, damaging its salt water disposal well and therefore preventing operation of, and production from, all wells on Hallco’s lease. Plaintiffs allege the migration of carbon dioxide constituted trespass, and further allege negligence and nuisance. Plaintiff seeks actual damages in excess of $75, plus punitive damages in an unspecified amount. Because we sold the EOR wells on November 17, 2017, Hallco filed an amended petition on March 6, 2018 to add the purchaser, Perdure Petroleum, LLC, as an additional defendant in the lawsuit. Plaintiff claims the damage is ongoing. While we dispute the plaintiff’s claims, dispute the remedies requested are available under Oklahoma law, and have been vigorously defending the case, we have reached an agreement in principle to settle the claims within insurance policy limits.

We are involved in various other legal proceedings including, but not limited to, commercial disputes, claims from royalty and surface owners (including those alleging damages from induced earthquakes), property damage claims, quiet title actions, personal injury claims, employment claims, and other matters which arise in the ordinary course of business. In addition, other proofs of claim have been filed in our bankruptcy case which we anticipate repudiating. While the outcome of these legal proceedings cannot be predicted with certainty, we do not expect any of them individually to have a material effect on our financial condition, results of operations or cash flows.

Contractual obligations

We have numerous contractual commitments in the ordinary course of business including debt service requirements, operating leases, financing leases, well drilling obligations and purchase obligations. Our operating leases currently consist of an office space lease at our headquarters, which we entered into in August 2019, and leases for drilling rigs, which have remaining terms of up to 3 months. Our financing leases consist of leases on our fleet vehicles. We previously had operating leases and financing leases on CO₂ recycle compressors with terms of seven years which were terminated in September 2019 (see “Note 5 - Leases”). As of September 30, 2019, other than additional borrowings under our credit facility, the repayment of the mortgage on our headquarters, the termination of our CO₂ recycle compressor leases and our new leases for fleet vehicles, we did not have material changes to our contractual commitments since December 31, 2018.



ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis is intended to assist in understanding our financial condition and results of operations for the three and nine months ended September 30, 2019 and 2018. The information should be read in conjunction with our unaudited consolidated financial statements and the notes thereto included in this quarterly report as well as the information included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2018.

Statements in our discussion may be forward-looking statements. These forward-looking statements involve risks and uncertainties. We caution that a number of factors could cause future production, revenues and expenses to differ materially from our expectations. For more information, see “Cautionary Note Regarding Forward-Looking Statements.”

Overview

As an independent oil and natural gas exploration and production company headquartered in Oklahoma City, we are a pure-play operator focused in Oklahoma’s hydrocarbon-rich STACK play, where we have approximately 129,000 net acres primarily in Kingfisher, Canadian and Garfield counties and approximately 218,000 net surface acres in the Mid-Continent region. Beginning in the early 1990s, our operations in the area later to become known as the STACK were focused on vertical wells and waterfloods. Since late 2013, however, we have concentrated on the horizontal development of the Mississippian-age Osage and Meramec formations, the Devonian-age Woodford Shale formation and the Pennsylvanian-age Oswego formation.

Reserves and Production. Our December 31, 2018, reserve estimates reflect that our production rate on current proved developed properties will decline at annual rates of approximately 25%, 17%, and 13% for the next three years. To grow our production and cash flow, we must find, develop and acquire new oil and natural gas reserves to replace those being depleted by production. Substantial capital expenditures are required to find, develop and acquire oil and natural gas reserves.

Strengthening Operations and Technical Teams. Since emerging from our Chapter 11 restructuring in early 2017, our strategy has been to divest non-core assets and focus on de-risking and growing our STACK assets. At the same time, we have concentrated on enhancing our operational and technical teams with proven industry leaders to strengthen our execution track record as we strive to create long-term stockholder value. Each of these industry veterans plays an integral role in furthering our geological understanding of our acreage, uncovering additional upside, and improving our operational results.

Developing our Inventory. Our development design seeks the optimal balance of individual well rates of return and total net present value. Our goal is to effectively develop our assets in way that efficiently converts them into cash flow, while at the same time increasing long-term value for our stockholders. We utilize an earth model derived from 3-D seismic to help identify our well locations, target intervals and well density. We design our fractures in a way that enhances near-wellbore stimulated reservoir volume and manages parent well communication risk. We are continuously evaluating and applying learning from one project to the next to enhance our return on the capital we invest in our operations.

We continue to test the most efficient spacing and operating strategies in order to minimize depletion, parent/child issues and other communication issues between geologic targets. As we drill our inventory, we learn more about each of our geologic targets. We may, after consolidating our learning regarding the variability and complexity of relevant geology as well as spacing within a reservoir, and particularly in light of commodity prices pertaining at that time as well as those projected in the near future, elect to sacrifice a portion of our drilling locations to both mitigate near term operational risk and address financial goals such as cash flow neutrality.

Cash Flow Neutrality. During 2019, we have made a concerted effort to position ourselves for operational cash flow neutrality in 2020, especially in light of the currently challenging capital markets environment. As we attempt to be maximally efficient in the use of our capital, we may not co-develop certain geologic benches at the same time other benches are drilled because the benches we are forgoing do not meet our return on investment criteria in today’s pricing environment. Benches not simultaneously developed as other benches within the same drilling unit may not be economic to drill in the future absent significant improvement in commodity prices.

Impact of Commodity Prices. In this regard, it is important to note that oil and NGL prices have a direct impact on which wells we drill and which benches we target at any given time. For example, from the third quarter of 2018 to the third quarter of 2019, West Texas Intermediate (“WTI”) has fallen from an average of $69.76 per barrel of oil to $56.37. Perhaps just as significantly, our realized

price on NGLs has fallen from 37% of WTI to 22% over that same time period. Of course, since WTI itself has fallen during that period, there is a compound effect.

Reduction of G&A and Operating Costs. In this commodity price environment, it is even more important to manage costs. Reductions in LOE and G&A costs have a direct impact on which wells and targets are economic. Since the beginning of 2019, the Company has reduced its corporate workforce and implemented cost reduction initiatives that will result in significant annualized G&A savings. The full impact of these reductions will be realized in 2020, with initial savings flowing through in the second half of 2019. As described in more detail below, we also sold the office building in which our corporate headquarters are located. As for capital and LOE reductions, we have focused on capturing savings from current weakness in the sector, optimized water handling costs, and taken a data-driven approach to improve fixed costs and to reduce workover expenses.

Highlights

Our financial and operating performance in the third quarter of 2019 includes the following highlights and notable developments:


•	We incurred a net loss for the three months ended September 30, 2019, of $130.9 million driven primarily by a ceiling impairment of $147.7 million, which was partially offset by $18.7 million in non-cash mark-to-market gains on our commodity derivative instruments.

•

We grew net production from our STACK play to 1,980 MBoe and 5,579 MBoe for the three and nine months ended September 30, 2019, respectively, representing increases of 37% and 49% from the prior year periods. Total net production was 2,409 MBoe and 6,857 MBoe for the three and nine months ended September 30, 2019, respectively, representing increases of 23% and 25%, compared to net production for the prior year periods.


•	We lowered our lease operating expense from $6.36/Boe to $5.14/Boe, a decrease of 19% from the prior year quarter, primarily driven by production growth in our lower-cost STACK play, where we have lowered water hauling costs, and divestitures of certain non-core assets in 2018, which were assets characterized by higher operating costs compared to our STACK assets.


•	We brought online 53 new gross operated wells during the nine months ended September 30, 2019, seven of which were part of our joint drilling program discussed below.


•	Our oil and natural gas capital expenditures for the nine months ended September 30, 2019, was $218.8 million, with $186.4 million incurred for drilling and completions and $7.6 million on acquisitions.


•	On September 27, 2019, we completed our regularly scheduled fall borrowing base redetermination at which time our bank group reaffirmed our borrowing base at $325.0 million.


•	In August 2019, we sold the building housing our headquarters along with adjacent land, furniture and fixtures net proceeds of $11.5 million. The proceeds from the sale were utilized to pay off the outstanding balance of the real estate mortgage note on the property.

Capital development

We incurred capital expenditures of $218.8 million for the nine months ended September 30, 2019, of which $186.4 million was for drilling and completions, which included completing and producing seven wells drilled in the prior year, drilling, completing and producing 39 wells, drilling five wells scheduled to be completed subsequent to September 30, 2019, and participating in wells operated by others. The $186.4 million of expenditures for drilling and completions includes $6.8 million for participating in wells operated by others. These wells do not include wells under our joint development agreement which we discuss below. in “Note 1: Nature of operations and summary of significant accounting policies” in “Item 1. Financial Statements” of this report.

We were operating four horizontal drilling rigs in the STACK early in the year, reduced to three rigs by the end of March 2019 and two rigs by October 2019, which we expect to maintain for the remainder of the year. Our capital expenditures for the nine months ended September 30, 2019 also includes $7.6 million on acquisitions, of which $0.6 million were for nonmonetary acreage trades. We currently expect capital expenditures to be in the range of $260 million to $280 million for the full year 2019. Our 2019 capital expenditures may be adjusted as business conditions warrant and the amount, timing and allocation of such expenditures is largely discretionary and within our control. The aggregate amount of capital that we will expend may fluctuate materially based on market conditions, the actual costs to drill, complete and place on production operated wells, our drilling results, the financial covenants contained in our debt instruments, other opportunities that may become available to us and our ability to obtain capital.

Results of operations

Production

Production volumes by area were as follows (MBoe):



	Three months ended September 30,		Nine months ended September 30,
	2019	2018	2019	2018
STACK Areas:
STACK - Kingfisher County	695	470	1,946	1,680
STACK - Canadian County	943	494	2,544	1,090
STACK - Garfield County	299	373	938	778
STACK - Other	43	104	151	201
Total STACK	1,980	1,441	5,579	3,749
Other	429	523	1,278	1,747
Total	2,409	1,964	6,857	5,496

For the three months ended September 30, 2019, production increased in Kingfisher County and Canadian County compared to the prior year quarter, but decreased in Garfield County. Our total net production of 2,409 MBoe and 6,857 MBoe for the three and nine months ended September 30, 2019, respectively, increased approximately 23% and 25%, compared to net production for the prior year periods. We accomplished this growth despite our divestitures of various non-core properties during 2018 which collectively contributed approximately 1,700 Boe/day of net production prior to their disposal. The increases were primarily a result of our production growth in the STACK. Net production from our STACK play was 1,980 MBoe and 5,579 MBoe for the three and nine months ended September 30, 2019, respectively, an increase of 37% and 49% from the prior year periods. This pattern of growth underscores our focus on developing the STACK which includes bringing online 66 gross (51 net) operated new wells in the area in the last 12 months.

As a result of our development strategy that includes utilizing larger pads and the timing of future wells coming online, the overall timing of our production growth may be uneven from quarter to quarter.

Revenues and transportation and processing

Our commodity sales are derived from the production and sale of oil, natural gas and natural gas liquids. These revenues do not include the effects of derivative instruments and may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices. For example, from the third quarter of 2018 to the third quarter of 2019, WTI has fallen from an average of $69.76 per barrel of oil to $56.37 while our realized price on NGLs has fallen from 37% of WTI to 22% over that same time period.

The following table presents information about our production and commodity sales before the effects of commodity derivative settlements:



	Three months ended September 30,						Nine months ended September 30,
	2019			2018			2019			2018
Commodity sales (in thousands):
Oil	$	40,459		$	46,576		$	124,251		$	132,378
Natural gas	8,745			9,458			30,427			26,584
Natural gas liquids	8,801			14,078			29,043			34,789
Gross commodity sales	$	58,005		$	70,112		$	183,721		$	193,751
Transportation and processing	(6,167		)	(4,593		)	(16,557		)	(11,916		)
Net commodity sales	$	51,838		$	65,519		$	167,164		$	181,835
Production:
Oil (MBbls)	738			664			2,229			2,006
Natural gas (MMcf)	5,823			4,539			16,012			12,491
Natural gas liquids (MBbls)	700			543			1,959			1,408
MBoe	2,409			1,964			6,857			5,496
Average daily production (Boe/d)	26,179			21,342			25,116			20,131
Average sales prices (excluding derivative settlements):
Oil per Bbl	$	54.82		$	70.14		$	55.74		$	65.99
Natural gas per Mcf	$	1.50		$	2.08		$	1.90		$	2.13
NGLs per Bbl	$	12.57		$	25.93		$	14.83		$	24.71
Transportation and processing per Boe	$	(2.56	)	$	(2.34	)	$	(2.41	)	$	(2.17	)
Average sales price per Boe	$	21.52		$	33.37		$	24.38		$	33.09

Our gross commodity sales (excluding transportation and processing deductions) of $58.0 million and $183.7 million for the three and nine months ended September 30, 2019, respectively, decreased approximately 17% and 5% compared to gross commodity sales for the prior year periods. The decreases for both the three months and nine months ended September 30, 2019, compared to the prior year periods are due to price decreases on all three commodities partially offset by production increases on all three commodities. The table below discloses the impact of price and production volume changes on our revenues.



	Three months ended September 30, 2019 vs. 2018					Nine months ended September 30, 2019 vs. 2018
(in thousands)	Sales change			Percentage change in sales		Sales change			Percentage change in sales
Change in oil sales due to:
Prices	$	(11,307	)	(24.3	)%	$	(22,843	)	(17.3	)%
Production	5,190			11.2	%	14,716			11.1	%
Total change in oil sales	$	(6,117	)	(13.1	)%	$	(8,127	)	(6.1	)%
Change in natural gas sales due to:
Prices	$	(3,384	)	(35.8	)%	$	(3,657	)	(13.8	)%
Production	2,671			28.2	%	7,500			28.2	%
Total change in natural gas sales	$	(713	)	(7.5	)%	$	3,843		14.5	%
Change in natural gas liquids sales due to:
Prices	$	(9,348	)	(66.5	)%	$	(19,361	)	(55.7	)%
Production	4,071			28.9	%	13,615			39.1	%
Total change in natural gas liquids sales	$	(5,277	)	(37.5	)%	$	(5,746	)	(16.5	)%

Transportation and processing revenue deductions principally consist of deductions by our customers for costs to prepare and transport production from the wellhead to a specified sales point and processing costs of gas into natural gas liquids. Transportation and processing deductions of $6.2 million and $16.6 million for the three and nine months ended September 30, 2019, respectively, were 34% and 39% higher than the prior year periods due to increases in natural gas and natural gas liquids production as well as driven by our production growth in the STACK where we have experienced higher transportation and processing costs compared to our other operating areas. Transportation and processing contracts related to our recent development in the STACK are fee-based and we are experiencing a larger proportion of gas production subject to fee based processing arrangements as opposed to percentage of proceeds arrangements more commonly associated with our legacy properties.

Derivative activities

Our results of operations, financial condition and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties. To mitigate a portion of this exposure, we have entered into various types of derivative instruments, including commodity price swaps and costless collars.

We closely monitor the fair value of our derivative contracts and may elect to settle a contract prior to its scheduled maturity date in order to lock in a gain or loss.

Our realized prices are impacted by realized gains and losses resulting from commodity derivatives contracts. The following table presents information about the effects of derivative settlements on realized prices:



	Three months ended September 30,						Nine months ended September 30,
	2019			2018			2019			2018
Oil (per Bbl):
Before derivative settlements	$	54.82		$	70.14		$	55.74		$	65.99
After derivative settlements	$	54.47		$	60.65		$	55.19		$	58.07
Post-settlement to pre-settlement price	99.4		%	86.5		%	99.0		%	88.0		%
Natural gas liquids (per Bbl):
Before derivative settlements	$	12.57		$	25.93		$	14.83		$	24.71
After derivative settlements	$	15.90		$	25.20		$	16.82		$	24.45
Post-settlement to pre-settlement price	126.5		%	97.2		%	113.4		%	98.9		%
Natural gas (per Mcf):
Before derivative settlements	$	1.50		$	2.08		$	1.90		$	2.13
After derivative settlements	$	1.99		$	2.05		$	2.08		$	2.10
Post-settlement to pre-settlement price	132.7		%	98.6		%	109.5		%	98.6		%

The estimated fair values of our oil, natural gas, and NGL derivative instruments are provided below. The associated carrying values of these instruments are equal to the estimated fair values.



(in thousands)	September 30, 2019			December 31, 2018
Derivative (liabilities) assets:
Crude oil derivatives	$	(990	)	$	19,756
Natural gas derivatives	5,015			345
NGL derivatives	5,440			4,581
Net derivative assets	$	9,465		$	24,682

The effects of derivative activities on our results of operations and cash flows were as follows:



	Three months ended September 30,
	2019						2018
(in thousands)	Non-cash fair value adjustment			Settlements (paid) received			Non-cash fair value adjustment			Settlements (paid) received
Derivative gains (losses):
Crude oil derivatives	$	16,457		$	(261	)	$	(14,026	)	$	(6,307	)
Natural gas derivatives	(80		)	2,816			357			(174		)
NGL derivatives	2,341			2,328			(3,135		)	(392		)
Derivative gains (losses)	$	18,718		$	4,883		$	(16,804	)	$	(6,873	)



	Nine months ended September 30,
	2019						2018
(in thousands)	Non-cash fair value adjustment			Settlements (paid) received			Non-cash fair value adjustment			Settlements (paid) received
Derivative (losses) gains:
Crude oil derivatives	$	(20,746	)	$	(1,241	)	$	(50,802	)	$	(15,889	)
Natural gas derivatives	4,670			2,868			108			(396		)
NGL derivatives	859			3,909			(5,128		)	(357		)
Derivative (losses) gains	$	(15,217	)	$	5,536		$	(55,822	)	$	(16,642	)

We do not apply hedge accounting to any of our derivative instruments. As a result, all gains and losses associated with our derivative contracts are recognized immediately as “Derivative losses” in our consolidated statements of operations. The fluctuation in derivative (losses) gains from period to period is due primarily to the significant volatility of oil, NGL and natural gas prices and to changes in our outstanding derivative contracts during these periods.

Lease operating expenses



	Three months ended September 30,				Nine months ended September 30,
(in thousands, except per Boe data)	2019		2018		2019		2018
Lease operating expenses:
STACK	$	7,907	$	6,251	$	23,466	$	18,569
Other	4,465		6,242		14,571		23,476
Total lease operating expenses	$	12,372	$	12,493	$	38,037	$	42,045
Lease operating expenses per Boe:
STACK	$	3.99	$	4.34	$	4.21	$	4.95
Other	$	10.41	$	11.93	$	11.40	$	13.44
Lease operating expenses per Boe	$	5.14	$	6.36	$	5.55	$	7.65

Lease operating expenses (“LOE”) are sensitive to changes in demand for field equipment, services, and qualified operational personnel, which is driven by demand for oil and natural gas. However, the timing of changes in operating costs may lag behind changes in commodity prices.

LOE for the three months ended September 30, 2019, was $12.4 million, which was flat compared to the prior year quarter. Although the change in LOE on a dollar basis for the quarter was flat, LOE on a per Boe basis of $3.99 in the STACK and $10.41 in our Other areas were 8% and 13% lower compared to the prior year quarter. The quarter over quarter decline in LOE per Boe in the STACK was primarily due to increased production and a decrease in water hauling costs in certain areas of the STACK as pipeline infrastructure is expanded into the area and contract rates are locked in. The quarter over quarter decline in LOE per Boe in our Other areas was due to divestiture of high-cost non-core assets in 2018.

LOE for the nine months ended September 30, 2019 was $38.0 million, a decrease of 10% compared to the prior year period. This decrease was due to the divestiture of high-cost non-core assets in 2018 partially offset by LOE increases in the STACK where we are growing production. The 2018 divestitures were the primary driver behind a 15% decline in LOE per Boe in our Other areas to $11.40. LOE per Boe in the STACK decreased 15% to $4.21 due to increased production and cost reductions in water hauling, discussed above, as well as reduced costs for well maintenance.

Production taxes (which include severance and ad valorem taxes)



	Three months ended September 30,						Nine months ended September 30,
	2019			2018			2019			2018
Production taxes (in thousands)	$	2,925		$	4,028		$	9,607		$	9,473
Production taxes per Boe	$	1.21		$	2.05		$	1.40		$	1.72
Production taxes as % of commodity sales	5.0		%	5.7		%	5.2		%	4.9		%

Production taxes for the three and nine months ended September 30, 2019, of $2.9 million and $9.6 million, respectively, were 27% lower and 1% higher than the prior year periods. The quarter over quarter decrease on a dollar basis and on a per Boe basis was primarily a result of lower revenues driven by a decline in commodity pricing. The year over year change on a dollar basis was approximately flat as a decrease in taxes attributable to lower revenues was offset by legislative tax increases discussed below.

In March 2018, the Oklahoma legislature approved a production tax increase from 2% to 5% during the first three years of production on horizontal wells spudded after July 1, 2015. The production tax rate on any new well is currently 5% of commodity revenues for the first 36 months and 7% thereafter.

Depreciation, depletion and amortization (“DD&A”)



	Three months ended September 30,				Nine months ended September 30,
	2019		2018		2019		2018
DD&A (in thousands):
Oil and natural gas properties (1)	$	26,627	$	20,234	$	76,996	$	56,875
Property and equipment	1,394		2,018		5,022		6,890
Total DD&A	$	28,021	$	22,252	$	82,018	$	63,765
DD&A per Boe:
Oil and natural gas properties (1)	$	11.05	$	10.30	$	11.23	$	10.35
Other fixed assets	0.57		1.03		0.73		1.25
Total DD&A per Boe	$	11.63	$	11.33	$	11.96	$	11.60

_________________________________________


(1)	Includes accretion of asset retirement obligations

We adjust our DD&A rate on oil and natural gas properties each quarter for changes in our estimates of oil and natural gas reserves and costs. Oil and natural gas DD&A for the three and nine months ended September 30, 2019, of $26.6 million and $77.0 million, respectively, was 32% and 35% higher than the prior year periods due to higher production and a higher DD&A rate.

General and administrative expenses (“G&A”)



	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2019			2018			2019			2018
G&A:
Gross G&A expenses	$	9,898		$	12,202		$	30,769		$	37,187
Capitalized exploration and development costs	(2,089		)	(3,181		)	(7,332		)	(8,469		)
Net G&A expenses	7,809			9,021			23,437			28,718
Net G&A expense per Boe	$	3.24		$	4.59		$	3.42		$	5.23

Net G&A of $7.8 million and $23.4 million for the three and nine months ended September 30, 2019, respectively, decreased 13% and 18% from the prior year periods primarily due to lower compensation and benefits, which included a reduction in stock based compensation. Compensation and benefits were lower as a result of a reduction in headcount. Stock compensation expense was lower for the three and nine months ended September 30, 2019, compared to the prior year periods because our executive stock grants awarded in 2017 were front loaded for three-year periods and subject to accelerated cost recognition which results in higher expense early during the life of a grant with graded vesting. The cost savings were partially offset by severance costs in 2019 for employees impacted by our reductions in force during the year, and increases in professional fees and insurance costs. The table below discloses our stock based compensation expense and our employee severance costs included in G&A.



	Three months ended September 30,				Nine months ended September 30,
(in thousands)	2019		2018		2019		2018
Employee severance costs	$	1,057	$	135	$	2,115	$	135
Stock compensation, gross	873		3,112		3,520		11,027
	$	1,930	$	3,247	$	5,635	$	11,162

Other expense

Other expense consists of the following:



	Three months ended September 30,				Nine months ended September 30,
(in thousands)	2019		2018		2019		2018
Restructuring	$	—	$	—	$	—	$	425
Subleases	269		402		1,075		1,208
Total other expense	$	269	$	402	$	1,075	$	1,633

Restructuring expense. We previously incurred exit costs in conjunction with our EOR asset divestiture which predominantly consist of one-time severance and termination benefits for the affected employees. The expense recorded in 2018 is a result of termination benefits for the final slate of employees terminated as a result of the divestiture.

Subleases. Our subleases consist of CO₂ compressors that were previously utilized in our EOR operations and leased as both financing and operating leases from U.S. Bank but were subsequently subleased to the purchaser of our EOR assets (the “Sublessee”). As discussed in “Note 5: Leases” in “Item 1. Financial Statements” of this report, the subleases were terminated in September 2019.

Full-cost ceiling impairment

Energy commodity prices are volatile and a decline in commodity prices negatively impacts our revenues, profitability, cash flows, liquidity (including our borrowing base availability), and reserves, which could lead us to consider reductions in our capital program, asset sales or organizational changes. Prices we receive are determined by prevailing market conditions, regional and worldwide economic and geopolitical activity, supply versus demand, weather, seasonality and other factors that influence market conditions and often result in significant volatility in commodity prices. We mitigate the effects of volatility in commodity prices primarily by hedging a substantial portion of our expected production, focusing on a competitive cost structure and maintaining flexibility in our capital investment program with limited long-term commitments.

Price volatility also impacts our business through the full cost ceiling test calculation. The ceiling test calculation dictates that we use the unweighted arithmetic average price of crude oil and natural gas as of the first day of each month for the 12-month period ending on the balance sheet date. Since the prices used in the cost ceiling are based on a trailing 12-month period, the full impact of price changes on our financial statements may not be recognized immediately but could be spread over several reporting periods.

We recorded a ceiling test impairment on our oil and natural gas properties of $147.7 million and $261.0 million for the three and nine months ended September 30, 2019 primarily due to a decrease in the price used to estimate our reserves, as disclosed in the table below, and due to impairments of unevaluated non-producing leasehold. We have previously and may in the future impair and/or relinquish certain undeveloped leases due to expirations or prior to expiration based upon changes in exploration plans, timing and extent of development activity, availability of capital and suitable rig and drilling equipment, resource potential, comparative economics, changing regulations and/or other factors. Such impairments result in a transfer of amounts from unevaluated oil and natural gas properties to the full cost amortization base. Impairments of non-producing leasehold of $55.9 million and $76.9 million were recorded for the three and nine months ended September 30, 2019, respectively, which directly increased the amount of ceiling test impairment. Substantially all of the non-producing leasehold impairment recorded in the third quarter was related to our STACK acreage in Garfield County, Oklahoma as a result of our decision to suspend development of the area pending additional analysis of recent results. The non-producing leasehold impairment recognized in the current year includes impairment of our fresh start step-up adjustments recorded upon our exit from bankruptcy. At the time of our bankruptcy emergence in March 2017, the carrying value of our non-producing leasehold was increased to reflect fair value in accordance with fresh start accounting. Included in the impairment amounts for the three and nine months ended September 30, 2019, disclosed above were $31.6 million and $48.1 million associated with these fresh start step up adjustments.



Benchmark prices utilized in ceiling test	September 30, 2019		June 30, 2019		March 31, 2019		December 31, 2018
Oil (per Bbl)	$	57.77	$	61.39	$	63.06	$	65.56
Natural gas (per MMbtu)	$	2.87	$	3.02	$	3.07	$	3.10
Natural gas liquids (per Bbl)	$	21.37	$	22.71	$	24.60	$	25.56

If commodity prices remain at their current level or decline, we expect the trailing 12-month average price to decline by the end of 2019 and we believe that it is probable that we would record further ceiling test impairment losses in 2019. In addition to commodity prices, our production rates, levels of proved reserves, estimated future operating expenses, estimated future development costs, transfers of unevaluated properties and other factors will determine our actual ceiling test calculation and impairment analyses in future periods. Please see “Note 1: Nature of operations and summary of significant accounting policies” in “Item 1. Financial Statements” of this report for further discussion of our ceiling test.

Impairment of other assets and extinguishment of debt

During the second quarter of 2019, we commenced efforts to locate a buyer for our headquarters building. In conjunction with these efforts, we obtained a third party valuation on the fair value of the property. The valuation appraised the property at an amount lower than its net book value at the time. Based on this market appraisal and our expectations that, more likely than not, the headquarters building will be sold before the end of its useful life, we determined that the net book value of the property would not be recoverable. As a result, we recorded an impairment of $6.4 million in June 2019 to write down the net book value of the property to its fair value based on its market appraisal.

On August 5, 2019, we entered into a real estate purchase and sale agreement for the sale of the building housing our headquarters along with adjacent land, furniture and fixtures. Conditioned upon closing of this sale, we entered into a leaseback agreement with the buyer for a portion of the office space in our headquarters building for a period of two years. We closed the sale on August 29, 2019, for net proceeds of $11.5 million while recognizing an immaterial loss on disposal. The proceeds from the sale were utilized to pay off the outstanding balance of the real estate mortgage note on the property. We incurred a prepayment penalty of $1.6 million on the mortgage payoff which we recorded as a “Loss on extinguishment of debt” on our consolidated statements of operations.

Income taxes

We did not record any net deferred tax benefit for the three months ended September 30, 2019, as any deferred tax asset arising from the benefit is reduced by a valuation allowance as utilization of the loss carryforwards and realization of other deferred tax assets cannot be reasonably assured. Please see “Note 12: Income Taxes” in “Item 8. Financial Statement and Supplementary Data” of our Annual Report on Form 10-K for the year ended December 31, 2018, which contains additional information about our income taxes.

As a result of the Chapter 11 reorganization and related transactions, upon emergence from bankruptcy, we experienced an ownership change within the meaning of IRC Section 382 which subjected certain of the Company’s tax attributes, including our federal net operating loss carryforwards, to an IRC Section 382 limitation. If we were to experience an additional “ownership change,” our ability to offset taxable income arising after the ownership change with NOLs generated prior to the ownership change would be limited, possibly substantially. See “Note 1: Nature of operations and summary of significant accounting policies” in “Item 1. Financial Statements” of this report for our discussion of the Section 382 limitation.

Other income and expenses

Interest expense. The following table presents interest expense for the periods indicated:



	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2019			2018			2019			2018
Credit facility	$	1,044		$	—		$	2,032		$	5,118
Senior Notes	6,563			6,562			19,688			6,708
Bank fees, other interest and amortization of issuance costs	1,206			1,283			3,841			2,644
Interest expense, gross	8,813			7,845			25,561			14,470
Capitalized interest	(2,819		)	(3,640		)	(9,432		)	(7,155		)
Total interest expense	$	5,994		$	4,205		$	16,129		$	7,315
Average borrowings	$	402,163		$	321,752		$	375,759		$	261,001

Interest expense for the three and nine months ended September 30, 2019, was $6.0 million and $16.1 million, respectively, which was higher than the prior year periods, primarily due to an increase in gross interest expense. Gross interest expense was higher for the

three months ended September 30, 2019, compared to the prior year quarter primarily due to a larger balance of outstanding debt, as disclosed in the average borrowings in the table above. Gross interest expense was higher for the nine months ended September 30, 2019, compared to the prior year period due to a larger balance of outstanding debt, coupled with an increase in the effective interest rate on our indebtedness. Our Senior Notes, which were issued in June 2018, and constituted the majority of our debt during 2019 and during the latter half of 2018, carries a significantly higher interest rate compared to the interest rate on our credit facility, which constituted the majority of our debt during the first half of 2018.

We capitalize interest based on the carrying value of our unevaluated non-producing leasehold excluding any amounts that are the result of our fresh start fair value adjustment. Capitalized interest for the three months ended September 30, 2019 of $2.8 million was lower than the prior year period due to a lower average carrying balance on unevaluated non-producing leasehold. Capitalized interest for the nine months ended September 30, 2019, of $9.4 million, increased compared to the prior year period due the aforementioned higher effective interest rate and a larger average balance in unevaluated non-producing leasehold.

Reorganization items



	Three months ended September 30,				Nine months ended September 30,
(in thousands)	2019		2018		2019		2018
Loss on the settlement of liabilities subject to compromise	$	—	$	—	$	—	$	48
Professional fees	530		493		1,306		1,962
Total reorganization items	$	530	$	493	$	1,306	$	2,010

“Professional fees” in the table above consisted of legal fees for continuing work to resolve outstanding bankruptcy claims and fees to the U.S. Bankruptcy Trustee, which we will continue to incur until our bankruptcy case is closed.

Liquidity and capital resources

Our primary sources of liquidity have historically been cash flows generated from operating activities, financing provided by our revolving credit facility or issuance of debt and proceeds from hedge settlements. Additionally, in recent years, asset dispositions and our joint development arrangement have provided a source of cash flow for enhancing liquidity. Our business strategy and, in certain circumstances, the financial covenants contained in our debt instruments require that we continuously commit substantial investment to drill and develop our oil and natural gas properties such that production from new wells can offset the natural production decline from existing wells.

As of September 30, 2019, our cash balance was $21.5 million and the amount outstanding under our credit facility was $110.0 million. Availability under our credit facility is subject to financial covenants, discussed below, and borrowing base redeterminations conducted semi-annually on or around May 1 and November 1, or upon occurrence of certain specified events. We continuously monitor our liquidity needs, coordinate our capital expenditure program with our expected cash flows, and evaluate our available alternative sources of liquidity. We believe that we have sufficient liquidity to fund our capital expenditures and day to day operations at a minimum for the next 12 months.

Approximately 55% of our 2019 drilling and completion capital is dedicated to our Canadian County position, while 35% is for continued development in Kingfisher County, and 10% is expected to have been allocated to Garfield County. With respect to Garfield County, our initial results were quite strong in 2017 and during much of 2018; since then, they have become less consistent. Therefore, given the recent and current commodity price environment, we are prioritizing our capital spend in Canadian and Kingfisher Counties in the second half of 2019 and in 2020. At the same time, we are continuing to analyze the data from our wells in Garfield County in order to better understand its complex geology. We have recently reduced our rig count to two. While we expect to begin 2020 with two rigs, we could reduce activity further as warranted. This strategic approach will allow us to lower our capital budget as compared to 2019 while still maintaining production and providing opportunities to mature our learning of the basin’s characteristics.

Sources and uses of cash

Our net change in cash is summarized as follows:



	Nine months ended September 30,
(in thousands)	2019			2018
Cash flows provided by operating activities	$	70,536		$	96,267
Cash flows used in investing activities	(182,961		)	(233,038		)
Cash flows provided by financing activities	96,513			157,999
Net (decrease) increase in cash during the period	$	(15,912	)	$	21,228

Our cash flows from operating activities are derived substantially from the production and sale of oil and natural gas. Cash flows from operating activities for the nine months ended September 30, 2019, of $70.5 million was lower compared to the prior year. The decrease was primarily due to higher cash interest paid as well as lower revenues driven by the decline in commodity prices. Cash interest payments increased due to the timing of coupon payments on our Senior Notes, a higher average higher debt balance and a higher weighted average effective interest rate.

We use the net cash provided by operations to partially fund our acquisition, exploration and development activities. During 2019, we also relied on borrowings from our credit facility and cash on hand to fund our capital expenditures.

Our cash flows from investing activities typically consist of cash outflows for capital expenditures, cash inflows from asset dispositions and derivative settlement payments or receipts.

Our actual costs incurred, including costs that we have accrued for during the nine months ended September 30, 2019, are summarized in the table below.



	Nine months ended September 30, 2019
(in thousands)	STACK		Other		Total
Acquisitions (1)	$	7,637	$	—	$	7,637
Drilling (2)	186,384		—		186,384
Enhancements	5,952		2,704		8,656
Operational capital expenditures incurred	199,973		2,704		202,677
Other (3)	—		—		16,077
Total capital expenditures incurred	$	199,973	$	2,704	$	218,754

______________________________________________________


(1)	Includes $0.6 million of nonmonetary acreage trades.


(2)	Includes $6.8 million on development of wells operated by others and $12.5 million on our joint development agreement. Of the $12.5 million incurred on our joint development program, $4.0 million was incurred on costs that were in excess of the well cost caps specified under the agreement as a result of inflation and $8.6 million was incurred to acquire additional working interests.


(3)	For the nine months ended September 30, 2019, this amount includes $7.2 million for capitalized general and administrative expenses, and $9.4 million for capitalized interest.

Net cash used in investing activities during the nine months ended September 30, 2019 consisted of cash outflows for capital expenditure of $202.8 million partially offset by receipts for derivative settlements of $5.5 million and proceeds from asset sales of $14.3 million. The asset sale proceeds primarily consisted of proceeds from the sale of our headquarters building of $11.5 million. Net cash used in investing activities during the nine months ended September 30, 2018, consisted of cash outflows for capital expenditure of $252.7 million and payments for derivative settlements of $16.6 million partially offset by proceeds from asset divestitures of $36.3 million. Capital expenditures during the nine months ended September 30, 2018, included the closing payment of $54.8 million on our 7,000 acre leasehold purchase in January 2018.

Net cash from financing activities during the nine months ended September 30, 2019, consisted of borrowings on our credit facility of $110.0 million partially offset by cash outflows for repayment of debt and financing leases of $10.7 million and for treasury stock repurchases of $1.2 million. Our debt repayment included paying off the outstanding balance on our real estate mortgage note upon the sale of our headquarters building. In conjunction with the extinguishment of the mortgage, we incurred a $1.6 million cash

prepayment penalty. Net cash from financing activities during the nine months ended September 30, 2018, consisted of cash inflows from proceeds from issuing Senior Notes of $300.0 million and from borrowings on our credit facility of $116.0 million partially offset by cash outflows for repayment of debt and capital leases of $245.6 million, for debt financing costs of $7.6 million and for treasury stock repurchases of $4.9 million.

Indebtedness

Debt consists of the following as of the dates indicated:



(in thousands)	September 30, 2019			December 31, 2018
8.75% Senior Notes due 2023	$	300,000		$	300,000
Credit facility	110,000			—
Real estate mortgage notes	—			8,588
Financing lease obligations	1,487			11,677
Installment note payable	433			354
Unamortized issuance costs	(10,816		)	(13,148		)
Total debt, net	$	401,104		$	307,471

As discussed previously, upon the divestiture of our headquarters building in August 2019, we utilized the sale proceeds to pay off the outstanding balance of our real estate mortgage note which was $8.2 million at the time of the repayment.

Until recently, we had financing leases for CO₂ compressors that were subleased to the buyer of our former EOR oil and natural gas properties. In September 2019, the originating lessor entered into agreements with the sublessee which resulted in the discharge of all our obligations with respect to these compressor leases and the removal of the associated debt from our consolidated balance sheet in the amount of $9.8 million. Our remaining finance leases consist entirely of leases on our fleet vehicles.

Credit facility

Pursuant to our Credit Agreement (the “Credit Agreement”) with Royal Bank of Canada, as administrative agent and issuing bank, and the additional lenders party thereto, we have a $750.0 million credit facility collateralized by our oil and natural gas properties and is scheduled to mature on December 21, 2022. Availability under our credit facility is subject to financial covenants (see “Note 4: Debt” in “Item 1. Financial Statements” of this report) and a borrowing base predicated on the value of our oil and natural gas properties and set by the banks semi-annually on or around May 1 and November 1 of each year. As of September 30, 2019, our borrowing base on the credit facility was $325.0 million.

The Credit Agreement contains covenants and events of default customary for oil and natural gas reserve-based lending facilities. Please see “Note 8: Debt” in “Item 8 Financial Statements and Supplementary Data” of our Annual Report on Form 10-K for the year ended December 31, 2018, for a discussion of the material provisions of our Credit Agreement.

On September 27, 2019, we entered into the Fourth Amendment (the “Amendment”) to the Credit Agreement. The Amendment, among other things, (i) reaffirmed the borrowing base at $325.0 million ; (ii) amended the definition of EBITDAX to, among other things, (a) added back losses related to or resulting from the full or partial extinguishment of debt, (b) expanded the add-back of amounts associated with retirements, severance or departure to apply to all employees or former employees, and (c) clarified that gains related to or resulting from the full or partial extinguishment of debt are excluded; and (iii) revised certain negative covenants to provide that the Company, under certain circumstances, may prepay or otherwise redeem certain Permitted Senior Additional Debt (as defined in the Credit Agreement) in an aggregate amount not to exceed $30.0 million.

8.75% Senior Notes

On June 29, 2018, we issued at par $300.0 million in aggregate principal amount of our 8.75% Senior Notes maturing in July 15, 2023 in a private placement under Rule 144A and Regulation S of the Securities Act of 1933, as amended. The estimated offering costs were $7.3 million resulting in net proceeds of $292.7 million, which we used to repay the credit facility and for general corporate purposes.

Please see “Note 8: Debt” in “Item 8 Financial Statements and Supplementary Data” of our Annual Report on Form 10-K for the year ended December 31, 2018, for a discussion of the material provisions of our Senior Notes.

Finance leases

During 2019, we entered into lease financing agreements for our fleet trucks for $1.6 million. The lease financing obligations are for 48-month terms with the option for us to purchase the vehicle at any time during the lease term by paying the lessor’s remaining unamortized cost in the vehicle. At the end of the lease term, the lessor’s remaining unamortized cost in the vehicle will be a de minimis amount and hence title to the vehicle can be transferred to us at minimal cost.

Contractual obligations

We have numerous contractual commitments in the ordinary course of business including debt service requirements, operating leases, financing leases, well drilling obligations and purchase obligations. Our operating leases currently consist of an office space lease at our headquarters which we entered into in August 2019 and leases for drilling rigs, which have remaining terms of up to 3 months. Our financing leases consist of leases on our fleet vehicles. We previously had operating leases and financing leases on CO₂ recycle compressors with terms of seven years which were terminated in September 2019 (see “Note 5: Leases” in “Item 1. Financial Statements”). As of September 30, 2019, other than additional borrowings under our credit facility, the repayment of the mortgage on our headquarters, the termination of our CO₂ recycle compressor leases and our new leases for fleet vehicles, we did not have material changes to our contractual commitments since December 31, 2018.

Financial position

We believe that the following discussion of material changes in our balance sheet may be useful:



(in thousands)	September 30, 2019		December 31, 2018		Change
Assets
Right of use asset from operating leases	$	5,853	$	—	$	5,853
Accounts receivable, net	45,145		66,087		(20,942		)
Derivative instrument assets, net	9,465		24,682		(15,217		)
Liabilities
Accounts payable and accrued liabilities	$	81,269	$	73,779	$	7,490
Long-term debt and financing leases	401,104		307,471		93,633
Noncurrent operating lease obligations	1,239		—		1,239


•	Right of use asset on operating leases: We recognized assets for our drilling rig and headquarters office space leases pursuant to our adoption of the new lease accounting standard.

•

Accounts receivable, net: The decrease is due to a reduction in amounts billed to other working interest owners as a result of an increase in our working interest on recently drilled wells, receipts from other working interest owners on certain overdue joint interest billings that were previously in dispute but have now been resolved and lower commodity sales in the month prior to quarter end, resulting in a decline in trade receivables.


•	Derivative instrument assets, net: The decrease is primarily due to an increase in forward commodity prices.

•

Accounts payable and accrued liabilities: The balance as of September 30, 2019, includes $4.3 million for our current obligations on operating leases pursuant to the adoption of the new lease accounting standard in 2019. The table above also discloses the noncurrent portion of these obligations totaling $1.2 million. The operating lease liabilities reflect our obligations on drilling rigs and office space leases as of September 30, 2019.


•	Long-term debt and financing leases: Debt was higher in total primarily due to $110.0 million in borrowings on our credit facility partially offset by the repayment of our real estate mortgage note and the discharge of our CO₂ compressor financing leases.

Non-GAAP financial measure and reconciliation

Management uses adjusted EBITDA (as defined below) as a supplemental financial measurement to evaluate our operational trends. Items excluded generally represent non-cash and/or non-recurring adjustments, the timing and amount of which cannot be reasonably estimated and are not considered by management when measuring our overall operating performance. In addition, Adjusted

EBITDA is generally consistent with the EBITDAX calculation that is used in the Ratio of Total Debt to EBITDAX covenant under our credit facility. We consider compliance with this covenant to be material.

Adjusted EBITDA is used as a supplemental financial measurement in the evaluation of our business and should not be considered as an alternative to net income, as an indicator of our operating performance, as an alternative to cash flows from operating activities, or as a measure of liquidity. Adjusted EBITDA is not defined under GAAP and, accordingly, it may not be a comparable measurement to those used by other companies.

We define adjusted EBITDA as net income, adjusted to exclude (1) asset impairments, (2) interest and other financing costs, net of capitalized interest, (3) income taxes, (4) depreciation, depletion and amortization, (5) non-cash change in fair value of non-hedge derivative instruments, (6) interest income, (7) stock-based compensation expense, (8) gain or loss on disposed assets, (9) impairment charges, (10) other significant, unusual non-cash charges and (11) certain expenses related to our restructuring, cost reduction initiatives, reorganization, severance costs and fresh start accounting activities for which our lenders have permitted us to exclude when calculating covenant compliance.

The following tables provide a reconciliation of net loss to adjusted EBITDA for the specified periods:



	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2019			2018			2019			2018
Net loss	(130,935		)	(12,068		)	(279,704		)	(45,503		)
Interest expense	5,994			4,205			16,129			7,315
Depreciation, depletion, and amortization	28,021			22,252			82,018			63,765
Non-cash change in fair value of derivative instruments	(18,718		)	16,804			15,217			55,822
Impact of derivative repricing	—			(1,698		)	—			(3,950		)
Loss on settlement of liabilities subject to compromise	—			—			—			48
Interest income	(2		)	(7		)	(4		)	(9		)
Stock-based compensation expense	705			2,304			2,359			8,598
(Gain) loss on sale of assets	(141		)	2,024			(631		)	2,599
Loss on impairment of oil and gas assets	147,686			—			261,001			—
Loss on impairment of other assets	—			—			6,407			—
Loss on extinguishment of debt	1,624			—			1,624			—
Restructuring, reorganization and other	1,587			493			3,420			1,962
Adjusted EBITDA	$	35,821		$	34,309		$	107,836		$	90,647

Our credit facility requires us to maintain a current ratio (as defined in Credit Agreement) of not less than 1.0 to 1.0. The definition of current assets and current liabilities used for determination of the current ratio computed for loan compliance purposes differs from current assets and current liabilities determined in compliance with GAAP. Since compliance with financial covenants is a material requirement under our Credit Agreement, we consider the current ratio calculated under our Credit Agreement to be a useful measure of our liquidity because it includes the funds available to us under our Credit Agreement and is not affected by the volatility in working capital caused by changes in the fair value of derivatives. The following table discloses the current ratio for our loan compliance compared to the ratio calculated per GAAP:



(dollars in thousands)	September 30, 2019			December 31, 2018
Current assets per GAAP	$	84,240		$	134,431
Plus—Availability under Credit Agreement	180,282			208,355
Less—Short term derivative instruments	(11,446		)	(24,025		)
Current assets as adjusted	$	253,076		$	318,761
Current liabilities per GAAP	110,843			136,710
Less—Current derivative instruments	(70		)	—
Less—Current operating lease obligation	(4,301		)	—
Less—Current asset retirement obligation	(1,742		)	(1,057		)
Less—Current maturities of long term debt	(586		)	(12,371		)
Current liabilities as adjusted	$	104,144		$	123,282
Current ratio per GAAP	0.76			0.98
Current ratio for loan compliance	2.43			2.59

Off-Balance Sheet Arrangements

At September 30, 2019, we did not have any off-balance sheet arrangements.

Critical accounting policies

For a discussion of our critical accounting policies, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2018.

Also see the footnote disclosures included in “Note 1: Nature of operations and summary of significant accounting policies” and “Note 5: Leases” in “Item 1. Financial Statements” of this report.

Recent accounting pronouncements

See recently adopted and issued accounting standards in “Note 1: Nature of operations and summary of significant accounting policies” in “Item 1. Financial Statements” of this report.



ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity prices

Our financial condition, results of operations, capital resources and inventory of drillable locations are highly dependent upon the prevailing market prices of, and demand for, oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. For example, from the third quarter of 2018 to the third quarter of 2019, West Texas Intermediate (“WTI”) has fallen from an average of $69.76 per barrel of oil to $56.37. Perhaps just as significantly, our realized price on NGLs has fallen from 37% of WTI to 22% over that same time period. Of course, since WTI itself has fallen during that period, there is a compound effect.

We cannot predict future oil and natural gas prices with any degree of certainty. Sustained declines in oil and natural gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of net oil and natural gas reserves that we can produce economically. Any reduction in reserves, including reductions due to price fluctuations, can reduce our borrowing base under our Credit Agreement and adversely affect our liquidity and our ability to obtain capital for our acquisition, exploration and development activities. Based on our production for the nine months ended September 30, 2019, our gross revenues from oil and natural gas sales would change approximately $4.2 million for each $1.00 change in oil and natural gas liquid prices and $1.6 million for each $0.10 change in natural gas prices.

To mitigate a portion of our exposure to fluctuations in commodity prices, we enter into various types of derivative instruments, which in the past have included commodity price swaps, collars, put options, enhanced swaps and basis protection swaps. We do not apply hedge accounting to any of our derivative instruments. As a result, all gains and losses associated with our derivative contracts are recognized immediately as “Derivative (losses) gains” in the consolidated statements of operations. This can have a significant impact on our results of operations due to the volatility of the underlying commodity prices. Please see “Note 6: Derivative instruments” in “Item 1. Financial Statements” of this report for further discussion of our derivative instruments.

Derivative positions are adjusted in response to changes in prices and market conditions as part of an ongoing dynamic process. We review our derivative positions continuously and if future market conditions change, we may execute a cash settlement with our counterparty, restructure the position, or enter into a new swap that effectively reverses the current position (a counter-swap). The factors we consider in closing or restructuring a position before the settlement date are identical to those reviewed when deciding to enter into the original derivative position.

The fair value of our outstanding derivative instruments at September 30, 2019 was a net asset of $9.5 million. Based on our outstanding derivative instruments as of September 30, 2019, summarized below, a 10% increase in the September 30, 2019, forward curves used to mark-to-market our derivative instruments would have increased our net liability position to $14.5 million, while a 10% decrease would have reverted our net liability to a net asset position of $33.2 million.

Our outstanding oil derivative instruments as of September 30, 2019, are summarized below:



Period and type of contract	Volume MBbls	Weighted average fixed price per Bbl
October - December 2019		Swaps		Purchased Puts		Sold Calls
Oil swaps	688	$	55.90	$	—	$	—
Oil roll swaps	120	$	0.46	$	—	$	—
January - March 2020
Oil swaps	504	$	50.47	$	—	$	—
Oil roll swaps	120	$	0.46	$	—	$	—
Oil collars	195	$	—	$	55.00	$	66.42
April - June 2020
Oil swaps	744	$	51.99	$	—	$	—
Oil roll swaps	110	$	0.42	$	—	$	—
July - September 2020
Oil swaps	495	$	50.63	$	—	$	—
Oil roll swaps	90	$	0.30	$	—	$	—
October - December 2020
Oil swaps	531	$	50.49	$	—	$	—
Oil roll swaps	90	$	0.30	$	—	$	—
January - March 2021
Oil swaps	170	$	46.24	$	—	$	—
Oil roll swaps	90	$	0.30	$	—	$	—
April - June 2021
Oil swaps	165	$	45.97	$	—	$	—
Oil roll swaps	60	$	0.30	$	—	$	—
July - September 2021
Oil swaps	183	$	46.64	$	—	$	—
October - December 2021
Oil swaps	171	$	46.07	$	—	$	—

Our outstanding natural gas derivative instruments as of September 30, 2019, are summarized below:



Period and type of contract	Volume BBtu	Weighted average fixed price per MMBtu
October - December 2019		Swaps
Natural gas swaps	3,977	$	2.85
Natural gas basis swaps	3,977	$	(0.51	)
January - March 2020
Natural gas swaps	2,340	$	2.67
Natural gas basis swaps	2,040	$	(0.46	)
April - June 2020
Natural gas swaps	2,340	$	2.67
Natural gas basis swaps	2,040	$	(0.46	)
July - September 2020
Natural gas swaps	1,500	$	2.75
Natural gas basis swaps	1,500	$	(0.46	)
October - December 2020
Natural gas swaps	1,500	$	2.75
Natural gas basis swaps	1,500	$	(0.46	)

Our outstanding natural gas liquid derivative instruments as of September 30, 2019 are summarized below:



Period and type of contract	Volume Thousands of Gallons	Weighted average fixed price per gallon
October - December 2019		Swaps
Natural gasoline swaps	4,200	$	1.13
Propane swaps	9,156	$	0.61
Butane swaps	2,394	$	0.71
January - March 2020
Natural gasoline swaps	4,032	$	1.13
Propane swaps	8,988	$	0.61
Butane swaps	2,352	$	0.71
April - June 2020
Natural gasoline swaps	2,476	$	1.17
Propane swaps	5,884	$	0.51
Butane swaps	497	$	0.53

Interest rates. All of the outstanding borrowings under our Credit Agreement as of September 30, 2019 are subject to market rates of interest as determined from time to time by the banks. As of September 30, 2019, borrowings bear interest at the adjusted LIBO Rate, as defined under the Credit Agreement, plus the applicable margin, which resulted in a weighted average interest rate of 4.34% on the amount outstanding. Any increases in these rates can have an adverse impact on our results of operations and cash flow. Assuming a constant debt level under our Credit Agreement of $325.0 million, equal to our borrowing base at September 30, 2019, the cash flow impact for a 12-month period resulting from a 100 basis point change in interest rates would be $3.3 million.



ITEM 4.	CONTROLS AND PROCEDURES

Disclosure Controls and procedures

As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Form 10-Q. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of September 30, 2019, at the reasonable assurance level.

Changes in Internal control over financial reporting

There have been no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. We may make changes in our internal control procedures from time to time.

PART II—OTHER INFORMATION



ITEM 1.	LEGAL PROCEEDINGS

Please see “Note 10: Commitments and contingencies” in “Item 1. Financial Statements” of this report for a discussion of our material legal proceedings. In our opinion, there are no other material pending legal proceedings to which we are a party or of which any of our property is the subject. However, due to the nature of our business, certain legal or administrative proceedings may arise from time to time in the ordinary course of business. While the outcome of these legal matters cannot be predicted with certainty, we do not expect them to have a material adverse effect on our financial condition, results of operations or cash flows.



ITEM 1A.	RISK FACTORS

Security holders and potential investors in our securities should carefully consider the risk factors in our Annual Report on Form 10-K filed with the SEC on March 14, 2019, together with the information set forth in our subsequent Quarterly Reports on Form 10-Q, current reports on Form 8-K and other materials we file with the SEC.

Except for the risk factor discussed below, there have been no material changes to the Risk Factors previously disclosed in our Annual Report for the year ended December 31, 2018.

We may not be able to maintain our listing on the NYSE, which could have a material adverse effect on us and our stockholders.

Our common stock is listed on the New York Stock Exchange (the “NYSE”). There are a number of continued listing requirements that we must satisfy in order to maintain our listing on the NYSE. If we fail to maintain compliance with all applicable continued listing requirements and the NYSE determines to delist our common stock, the delisting could adversely affect the market liquidity of our common stock, our ability to obtain financing and our ability to fund our operations.

The NYSE’s standards for continued listing include, among other things, that if the average closing price of a security as reported on the NYSE consolidated tape is less than $1.00 over a consecutive 30 trading-day period. On November 11, 2019, we were notified by the NYSE that, for the last 30 trading days, the closing price for our common stock had closed below the minimum $1.00 per share requirement. In accordance with the NYSE’s listed company manual rules, we have been provided a period of six months, or until May 11, 2020 (the “Compliance Date”), to regain compliance with the closing price requirement.

If, at any time before the Compliance Date, we have a closing share price of at least $1.00 on the last trading day of any calendar month and an average closing share price of at least $1.00 over the 30 trading-day period ending on the last trading day of that month, then we would regain compliance with the closing price requirement. One action we may consider in order to regain compliance prior to the Compliance Date would be to implement a reverse stock split.

If we do not regain compliance with the closing price requirement by the Compliance Date, and are not eligible for an additional compliance period at that time, the NYSE’s staff will provide written notification to us that our common stock may be delisted. At that time, we may appeal the NYSE’s staff’s delisting determination to a committee of the NYSE’s board of directors.

Any such delisting could result in our stock becoming ineligible to be included in one or more or held in or by one or more funds and otherwise adversely affect the market liquidity of our common shares, and, accordingly, the market price of our common shares could decrease. A delisting could adversely affect our ability to obtain financing for our operations or result in a loss of confidence by investors, customers, suppliers or employees.



ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None



ITEM 5.	OTHER INFORMATION

Not applicable.



ITEM 6.	EXHIBITS



Exhibit No.		Description

3.1*		Third Amended and Restated Certificate of Incorporation of Chaparral Energy, Inc., dated as of March 21, 2017 (Incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K filed on March 27, 2017).

3.2*		Certificate of Retirement of 7,869,929 shares of Class B Common Stock (Incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K filed on December 19, 2018).

3.3*		Amended and Restated Bylaws of Chaparral Energy, Inc., dated as of March 21, 2017 (Incorporated by reference to Exhibit 3.2 of the Company’s Current Report on Form 8-K filed on March 27, 2017).

4.1*		Registration Rights Agreement, dated as of March 21, 2017, by and among Chaparral Energy, Inc. and the Stockholders named therein (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K filed on March 27, 2017).

4.2*		Stockholders Agreement, dated as of March 21, 2017, by and among Chaparral Energy, Inc. and the Stockholders named therein (Incorporated by reference to Exhibit 10.4 of the Company’s Current Report on Form 8-K filed on March 27, 2017).

4.3*		First Amendment to Stockholders Agreement, dated as of March 6, 2018, by and among Chaparral Energy, Inc. and the Stockholders named therein (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K filed on March 9, 2018).

4.4*		Indenture dated June 29, 2018, among the Company, the Guarantors party thereto, and UMB Bank, N.A., as Trustee (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K filed on July 2, 2018).

4.5*		Form of 8.750% Senior Note due 2023 (Incorporated by reference to Exhibit A of Exhibit 4.1 of the Company’s Current Report on Form 8-K filed on July 2, 2018).

10.1 † *		Employment Agreement, dated as of April 22, 2019, by and between the Company and Scott Pittman. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K/A filed on April 23, 2019).

10.2 *		Third Amendment to Tenth Restated Credit Agreement, dated as of May 2, 2019, among Chaparral Energy, Inc., as borrower, Royal Bank of Canada, as administrative agent and issuing bank, and the additional lenders party thereto. (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 10-Q filed on May 9, 2019).

10.3 *		Fourth Amendment to Tenth Restated Credit Agreement, dated as of September 27, 2019, among Chaparral Energy, Inc., as borrower, Royal Bank of Canada, as administrative agent and issuing bank, and the additional lenders party thereto. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on October 2, 2019).

10.4 † *		Chaparral Energy, Inc. 2019 Long-Term Incentive Plan, effective June 28, 2019. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on July 2, 2019).

31.1		Certification by Principal Executive Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act.



31.2		Certification by Principal Financial Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act.

32.1		Certification by Principal Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2		Certification by Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS		XBRL Instance Document.

101.SCH		XBRL Taxonomy Extension Schema Document.

101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF		XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB		XBRL Taxonomy Extension Label Linkbase Document.

101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document.



*	Incorporated by reference
†	Management contract or compensatory plan or arrangement

SIGNATURES

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



CHAPARRAL ENERGY, INC.

By:		/s/ K. Earl Reynolds
Name:		K. Earl Reynolds
Title:		Chief Executive Officer
		(Principal Executive Officer)

By:		/s/ Scott Pittman
Name:		Scott Pittman
Title:		Chief Financial Officer and Senior Vice President
		(Principal Financial Officer and Principal Accounting Officer)

Date: November 12, 2019

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