10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended June 30, 2020

or

☐ 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 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	☒
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 August 17, 2020: 47,790,146 shares of Class A Common Stock, par value $0.01 per share.

CHAPARRAL ENERGY, INC.

Index to Form 10-Q

	Page
Part I. FINANCIAL INFORMATION
Item 1. Financial Statements (Unaudited)	8
Consolidated Balance Sheets	8
Consolidated Statements of Operations	9
Consolidated Statement of Stockholders’ Equity	10
Consolidated Statements of Cash Flows	11
Condensed Notes to Consolidated Financial Statements	12
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	36
Overview	36
Results of Operations	41
Liquidity and Capital Resources	37
Non-GAAP Financial Measure and Reconciliation	50
Critical Accounting Policies	51
Recent Accounting Pronouncements	51
Item 3. Quantitative and Qualitative Disclosures about Market Risk	51
Item 4. Controls and Procedures	53
Part II. OTHER INFORMATION
Item 1. Legal Proceedings	53
Item 1A. Risk Factors	53
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	59
Item 5. Other Information	59
Item 6. Exhibits	60
Signatures	63

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:

•the Chapter 11 Cases;

•the effects of the Chapter 11 Cases on our liquidity or results of operations or business prospects;

•the expected terms of a proposed plan of reorganization;

•our ability to confirm and consummate a Chapter 11 plan of reorganization;

•our ability to continue to operate in the ordinary course while the Chapter 11 Cases are pending;

•the treatment of our creditors and other stakeholders (including, without limitation, holders of our common stock) under a plan of reorganization;

•the potential impact of any epidemics or pandemics, including COVID-19;

•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;

•takeaway constraints and storage capacity for oil and natural gas; 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, 2019, the risks and uncertainties include or relate to:

•risks and uncertainties regarding the Company’s ability to complete a reorganization process under Chapter 11 of the Bankruptcy Code, including consummation of the restructuring in accordance with the terms of our restructuring support agreement;

•the Company’s ability to obtain timely approval by the Bankruptcy Court regarding the motions filed in the Chapter 11 Cases;

•the time that the Company will operate under Chapter 11 protection and the continued availability of operating capital during the pendency of the Chapter 11 Cases;

•the effects of the Chapter 11 Cases on our liquidity or results of operations or business prospects;

•the effects of the Chapter 11 Cases on our business and the interests of various constituents, including our stockholders;

•employee attrition and the Company’s ability to retain senior management and other key personnel due to the distractions and uncertainties, including the Company’s ability to provide adequate compensation and benefits during the Chapter 11 Cases;

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•the Company’s ability to maintain relationships with suppliers, customers, employees and other third parties and regulatory authorities because of the Chapter 11 filing;

•the effects of the Chapter 11 Cases on the market price of the Company’s common stock and on the Company’s ability to access the capital markets;

•risks associated with third party motions in the Chapter 11 Cases, which may interfere with the Company’s ability to consummate the restructuring or an alternative restructuring;

•increased administrative and legal costs related to the Chapter 11 process;

•potential delays in the Chapter 11 process due to the effects of COVID-19;

•other litigation and inherent risks involved in a bankruptcy process;

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

•worldwide supply of and demand for oil and natural gas, including to the extent affected by the COVID-19 pandemic and the recovery therefrom;

•volatility and declines in oil and natural gas prices, including to the extent affected by the COVID-19 pandemic and the recovery therefrom;

•geopolitical events affecting oil and natural gas prices;

•the impact of COVID-19 on the health of our key personnel;

•risks related to the geographic concentration of our assets;

•our ability to develop, explore for, acquire and replace oil and natural gas reserves and sustain production;

•drilling plans (including scheduled and budgeted wells);

•the extent to which we are able to continue to reduce lease operating expense and G&A costs;

•geologic and reservoir complexity and variability;

•uncertainties in estimating our oil and gas reserves and the present values of those reserves;

•the number, timing or results of any wells;

•changes in wells operated and in reserve estimates;

•activities on properties we do not operate;

•availability and cost of drilling and production equipment, facilities, field service providers, gathering, processing and transportation;

•takeaway constraints and storage capacity for oil and natural gas;

•competition in the oil and natural gas industry;

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

•weather, including its impact on oil and natural gas demand and weather-related delays on operations;

•the impact of natural disasters on our present and future operations;

•the operating hazards attendant to the oil and natural gas business;

•effectiveness and extent of our risk management activities;

•effectiveness of orders from the Oklahoma Corporation Commission and other regulatory bodies in mitigating the risk of lease cancellation actions associated with the voluntary shut-in of production;

•current borrowings, capital resources and liquidity;

•covenant compliance under instruments governing any of our existing or future indebtedness, including our ability to comply with financial covenants under our Credit Agreement;

•the effects of government regulation and permitting and other legal requirements;

•the impact of legislative, tax and regulatory initiatives, including in response to the COVID-19 pandemic;

•volatility in the price of our common stock;

•integration of existing and new technologies into operations;

•future exploration;

•changes in strategy and business discipline; 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

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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.

5

GLOSSARY OF CERTAIN DEFINED TERMS

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

Bankruptcy Code	Title 11 of the United States Code.
Bankruptcy Court	United States Bankruptcy Court for the District of Delaware.
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	One barrel of crude oil equivalent, determined 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 one-pound of water from 58.5 to 59.5 degrees Fahrenheit.
Chapter 11 Cases	Voluntary petitions seeking relief under the Bankruptcy Code in the Bankruptcy Court for relief under Chapter 11 of the Bankruptcy Code filed on August 16, 2020, 2020, by Chaparral Energy, Inc. and its subsidiaries, including Chaparral Resources, L.L.C., Chaparral Real Estate, L.L.C., Chaparral CO2, L.L.C., CEI Pipeline, L.L.C., Chaparral Energy, L.L.C., CEI Acquisition, L.L.C., Green Country Supply, Inc., Chaparral Biofuels, L.L.C., Chaparral Exploration, L.L.C., Roadrunner Drilling, L.L.C., Trabajo Energy, L.L.C., Charles Energy, L.L.C. and Chestnut Energy, L.L.C.
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.
COVID-19	An infectious disease caused by severe acute respiratory syndrome coronavirus 2 (SARS-CoV-2). It was first identified in late 2019 and has since spread globally, resulting in a sustained pandemic.
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.
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.
Limited Forbearance Agreement	Forbearance Agreement dated as of July 15, 2020, by and among Chaparral Energy, Inc., the subsidiary guarantors party thereto, certain Lenders identified therein, and Royal Bank of Canada, as Administrative Agent and Issuing Bank.
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.

6

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.
NYSE	The New York Stock Exchange.
Plan of Reorganization	Plan of Reorganization contemplated by the RSA.
Play	A term describing an area of land following the identification by geologists and geophysicists of reservoirs with potential oil and natural gas reserves.
Prior Chapter 11 Cases	Voluntary petitions seeking relief under the Bankruptcy Code in the Bankruptcy Court for relief under Chapter 11 of the Bankruptcy Code filed on May 9, 2016, by Chaparral Energy, Inc. and its subsidiaries including Chaparral Energy, L.L.C., Chaparral Resources, L.L.C., Chaparral Real Estate, L.L.C., Chaparral CO2 , L.L.C., CEI Pipeline, L.L.C., CEI Acquisition, L.L.C., Green Country Supply, Inc., Chaparral Biofuels, L.L.C., Chaparral Exploration, L.L.C., Roadrunner Drilling, L.L.C.
Prior Effective Date	March 21, 2017, the date of the Company’s emergence from the Prior Chapter 11 Cases.
Prior Reorganization Plan	First Amended Joint Plan of Reorganization under the Prior Chapter 11 Cases, dated as of January 25, 2017.
Proved developed reserves	Reserves that can be expected to be recovered (i) 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 and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a 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, regardless of whether deterministic or probabilistic methods are used for estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. For additional information, see the SEC’s definition in Rule 1-10(a)(22) of Regulation S-X, a link for which is available at the SEC’s website.
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%.
RSA	Restructuring Support Agreement, dated as of August 15, 2020, by and among Chaparral Energy, Inc., certain of its subsidiaries and the Consenting Creditors (as defined therein).
SEC	The Securities and Exchange Commission.
Senior Notes	Our 8.75% senior notes due 2023.
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.

7

Chaparral Energy, Inc. and Subsidiaries

Consolidated Balance Sheets

(Unaudited) 

PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

(dollars in thousands, except share data)	June 30, 2020		December 31, 2019
Assets
Current assets:
Cash and cash equivalents	$	56,137	$	22,595
Accounts receivable:
Accounts receivable, gross	43,197		50,744
Allowance for credit losses	(4,215)		(1,097)
Accounts receivable, net	38,982		49,647
Inventories, net	2,456		3,730
Prepaid expenses	4,034		3,471
Derivative instruments	15,197		947
Total current assets	116,806		80,390
Property and equipment, net	7,948		9,217
Right of use assets from operating leases	1,744		2,444
Oil and natural gas properties, using the full cost method:
Proved	1,569,627		1,276,036
Unevaluated (excluded from the amortization base)	142,295		371,229
Accumulated depreciation, depletion, amortization and impairment	(1,246,703)		(754,379)
Total oil and natural gas properties	465,219		892,886
Held for sale assets	111		2,860
Derivative instruments	1,990		—
Other assets	1,349		635
Total assets	$	595,167	$	988,432
Liabilities and stockholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	39,272	$	64,558
Accrued payroll and benefits payable	5,970		10,963
Accrued interest payable	12,309		12,227
Revenue distribution payable	9,322		22,370
Long-term debt and financing leases, classified as current	521,292		594
Derivative instruments	—		11,957
Total current liabilities	588,165		122,669
Long-term debt and financing leases, less current maturities	996		421,392
Derivative instruments	—		5,075
Noncurrent operating lease obligations	234		917
Deferred compensation	419		165
Asset retirement obligations	21,412		21,073
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; 48,297,606 issued and 47,790,146 outstanding at June 30, 2020 and 48,413,185 issued and 47,942,230 outstanding at December 31, 2019	483		485
Additional paid in capital	977,957		977,174
Treasury stock, at cost, 507,460 and 470,955 shares as of June 30, 2020, and December 31, 2019	(6,128)		(6,110)
Accumulated deficit	(988,371)		(554,408)
Total stockholders’ equity	(16,059)		417,141
Total liabilities and stockholders’ equity	$	595,167	$	988,432

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

8

Chaparral Energy, Inc. and Subsidiaries

Consolidated Statements of Operations

(Unaudited)

	Three months ended				Six months ended
(in thousands, except share and per share data)	June 30, 2020		June 30, 2019		June 30, 2020		June 30, 2019
Revenues:
Net commodity sales	$	15,880	$	66,707	$	64,731	$	115,326
Sublease revenue	—		1,198		—		2,396
Total revenues	15,880		67,905		64,731		117,722
Costs and expenses:
Lease operating	5,971		13,371		16,059		25,665
Production taxes	823		3,802		3,573		6,682
Depreciation, depletion and amortization	14,821		30,282		37,833		53,997
Impairment of oil and gas assets	384,639		63,593		456,010		113,315
Impairment of other assets	310		6,407		463		6,407
General and administrative	9,488		7,315		17,556		15,628
Liability management	8,047		—		8,047		—
Litigation loss	4,359		—		4,359		—
Subleases	—		403		—		806
Total costs and expenses	428,458		125,173		543,900		222,500
Operating loss	(412,578)		(57,268)		(479,169)		(104,778)
Non-operating income (expense):
Interest expense	(8,047)		(5,571)		(14,683)		(10,135)
Write-off of Senior Note issuance costs	(4,420)		—		(4,420)		—
Derivative (losses) gains	(13,019)		17,734		65,361		(33,282)
(Loss) gain on sale of assets	(261)		491		(159)		490
Other income (expense), net	35		(302)		281		(288)
Net non-operating income (expense)	(25,712)		12,352		46,380		(43,215)
Reorganization items, net	(436)		(313)		(1,020)		(776)
Loss before income taxes	(438,726)		(45,229)		(433,809)		(148,769)
Income tax expense	—		—		—		—
Net loss	$	(438,726)	$	(45,229)	$	(433,809)	$	(148,769)
Loss per share:
Basic	$	(9.55)	$	(0.99)	$	(9.45)	$	(3.27)
Diluted	$	(9.55)	$	(0.99)	$	(9.45)	$	(3.27)
Weighted average shares used to compute earnings per share:
Basic	45,949,797		45,641,797		45,890,041		45,549,518
Diluted	45,949,797		45,641,797		45,890,041		45,549,518

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

9

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, 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
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

	Common stock
(dollars in thousands)	Shares outstanding	Amount		Additional paid in capital		Treasury stock		Accumulated deficit		Total
As of December 31, 2019	47,942,230	$	485	$	977,174	$	(6,110)	$	(554,408)	$	417,141
Cumulative effect of accounting standard adoption	—	—		—		—		(154)		(154)
Stock-based compensation	—	—		705		—		—		705
Restricted stock forfeited or canceled	(22,494)	(1)		—		—		—		(1)
Repurchase of common stock	(3,856)	—		—		(6)		—		(6)
Net income	—	—		—		—		4,917		4,917
Balance at March 31, 2020	47,915,880	$	484	$	977,879	$	(6,116)	$	(549,645)	$	422,602
Stock-based compensation	—	—		78		—		—		78
Restricted stock forfeited	(93,085)	(1)		—		—		—		(1)
Repurchase of common stock	(32,649)	—		—		(12)		—		(12)
Net loss	—	—		—		—		(438,726)		(438,726)
Balance at June 30, 2020	47,790,146	$	483	$	977,957	$	(6,128)	$	(988,371)	$	(16,059)

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

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Chaparral Energy, Inc. and Subsidiaries

Consolidated Statements of Cash Flows

(Unaudited)

	Six months ended
(in thousands)	June 30, 2020		June 30, 2019
Cash flows from operating activities
Net loss	$	(433,809)	$	(148,769)
Adjustments to reconcile net loss to net cash (used in) provided by operating activities
Depreciation, depletion and amortization	37,833		53,997
Derivative (gains) losses	(65,361)		33,282
Impairment of oil and gas assets	456,010		113,315
Impairment of other assets	463		6,407
Write-off of Senior Note issuance costs	4,420		—
Loss (gain) on sale of assets	159		(490)
Other	4,612		1,621
Change in assets and liabilities
Accounts receivable	6,206		13,584
Inventories	747		40
Prepaid expenses and other assets	(1,277)		1,055
Accounts payable and accrued liabilities	(7,217)		(18,389)
Revenue distribution payable	(13,049)		600
Deferred compensation	844		1,852
Net cash (used in) provided by operating activities	(9,419)		58,105
Cash flows from investing activities
Expenditures for property, plant, and equipment and oil and natural gas properties	(86,862)		(146,434)
Proceeds from asset dispositions	3,370		857
Proceeds from derivative instruments, net	32,089		653
Net cash used in investing activities	(51,403)		(144,924)
Cash flows from financing activities
Proceeds from long-term debt	120,000		85,000
Repayment of long-term debt	(25,313)		(343)
Principal payments under financing lease obligations	(212)		(1,445)
Payment of debt issuance costs and other financing fees	(93)		(20)
Treasury stock purchased	(18)		(1,171)
Net cash provided by financing activities	94,364		82,021
Net increase (decrease) in cash and cash equivalents	33,542		(4,798)
Cash and cash equivalents, at beginning of period	22,595		37,446
Cash and cash equivalents, at end of period	$	56,137	$	32,648

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

11

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 and going concern

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, 2019.

The financial information as of June 30, 2020, and for the three and six months ended June 30, 2020 and 2019, is unaudited. The financial information as of December 31, 2019 has been derived from the audited financial statements contained in our Annual Report on Form 10-K for the year ended December 31, 2019. 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 six months ended June 30, 2020 are not necessarily indicative of the results of operations that will be realized for the year ended December 31, 2020.

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.

Chapter 11 Cases and going concern

On August 16, 2020 (the “Petition Date”), Chaparral Energy, Inc. and its consolidated subsidiaries, including Chaparral Resources, L.L.C., Chaparral Real Estate, L.L.C., Chaparral CO2, L.L.C., CEI Pipeline, L.L.C., Chaparral Energy, L.L.C., CEI Acquisition, L.L.C., Green Country Supply, Inc., Chaparral Biofuels, L.L.C., Chaparral Exploration, L.L.C., Roadrunner Drilling, L.L.C., Trabajo Energy, L.L.C., Charles Energy, L.L.C. and Chestnut Energy, L.L.C. (collectively, the “Debtors”) filed voluntary petitions commencing the Chapter 11 Cases, seeking relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. The Company has requested court approval for the joint administration of the Chapter 11 Cases under the caption In re Chaparral Energy, Inc. We are currently operating our business as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court, in accordance with the applicable provisions of the Bankruptcy Code.

To maintain and continue uninterrupted ordinary course operations during the bankruptcy proceedings, the Debtors filed a variety of “first day” motions seeking approval from the Bankruptcy Court for various forms of customary relief designed to minimize the effect of bankruptcy on the Debtors’ operations, customers and employees. Upon entry by the Bankruptcy Court of the orders approving all requested “first day” relief, we will be able to conduct normal business activities and pay all associated obligations for the period following our bankruptcy filing and (subject to caps applicable to payments of certain pre-petition obligations) pre-petition employee wages and benefits, pre-petition amounts owed to certain lienholders and vendors, royalty interest and working interest holders, and partners. During the pendency of the Chapter 11 Cases, all transactions outside the ordinary course of our business require the prior approval of the Bankruptcy Court.

The commencement, through the Chapter 11 Cases, of a voluntary proceeding in bankruptcy constituted an immediate event of default under our Credit Agreement and the indenture governing our Senior Notes (the “Indenture”), resulting in the automatic and immediate acceleration of all outstanding amounts under those financing arrangements. Accordingly, we have classified the outstanding balances under our Credit Agreement and Senior Notes as current liabilities on our condensed consolidated balance sheet as of June 30, 2020.

Please see “Note 11: Subsequent events” for a discussion of the restructuring support agreement and the related proposed plan of reorganization.

Ability to continue as a going concern—The accompanying condensed consolidated financial statements are prepared in accordance with generally accepted accounting principles applicable to a going concern, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business. The filing of the Chapter 11 Cases constituted an event of default

12

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

under the Indenture and the Credit Agreement, resulting in the automatic and immediate acceleration of outstanding balances under those financing arrangements. The Company projects that it will not have sufficient cash on hand or available liquidity to repay all of such debt. These conditions along with the significant risks and uncertainties related to the Company’s liquidity and the Chapter 11 Cases raise substantial doubt about the Company’s ability to continue as a going concern. The condensed consolidated financial statements do not include any adjustments relating to the recoverability and classification of recorded asset amounts or the amounts and classification of liabilities that might result from the outcome of this uncertainty. If the Company cannot continue as a going concern, adjustments to the carrying values and classification of its assets and liabilities and the reported amounts of income and expenses could be required and could be material.

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 June 30, 2020, cash with a recorded balance totaling approximately $55,445 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

In June 2016, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) 2016–13, Financial Instruments–Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments (“ASU 2016–13”), which changes the recognition model for the impairment of financial instruments, including accounts receivable, loans and held-to-maturity debt securities, among others. We adopted ASU 2016–13 using the modified retrospective method effective January 1, 2020. In contrast to previous guidance, which considered current information and events, and only recognized losses when they became probable (an “incurred loss” model), ASU 2016–13 mandates an “expected loss” model. The expected loss model: (i) estimates the risk of loss even when risk is remote, (ii) estimates losses over the contractual life, (iii) considers past events, current conditions and reasonable supported forecasts and (iv) has no recognition threshold. ASU 2016–13 is applicable to our accounts receivable portfolio, particularly those receivables attributable to our joint interest partners which have a higher credit risk than those associated with our traditional customer receivables.

Basis of accounting. Our accounts receivable are carried at gross cost, representing amounts due, less an allowance for expected credit losses. We write off accounts receivable when they are determined to be uncollectible. When we recover amounts that were previously written off, those amounts are offset against the allowance and reduce expense in the year of recovery.

The Company has four portfolio segments constituting its total accounts receivables: (i) joint interest receivables; (ii) commodity sales receivables; (iii) derivative settlement receivables and (iv) other receivables. The table below discloses balances related to these four segments and the allowance:

	June 30, 2020		December 31, 2019
Joint interests	$	9,992	$	16,664
Commodity sales	14,416		30,819
Derivative settlements	15,540		717
Other	3,249		2,544
Allowance for credit losses	(4,215)		(1,097)
	$	38,982	$	49,647

Commodity sales receivables. The Company sells its commodity products primarily to oil and natural gas midstream entities including crude oil refineries and natural gas processing plants. We also sell a small percentage of our natural gas and natural gas liquids to energy marketing entities. Payment is generally due within 30 days of sales and amounts outstanding longer than 90 days are considered past due. Based on 2019 commodity sales, our 10 largest purchasers account for over 75% of our commodity sales. Based on our history of collections from our purchasers, we believe the probability of credit losses from uncollectible receivables to be low. We perform annual credit evaluations on purchasers representing approximately 80% or more of our commodity revenues. The evaluations include (i) an assessment of external credit ratings; (ii) performing internal risk evaluations when external ratings are not available; (iii) assessing the need for guarantor letters or letters of credit. We estimate the expected losses on uncollectible receivables by applying a uniform allowance rate on the total outstanding balance taking into consideration general industry conditions and more specifically, factors impacting the midstream energy segment. We may make further adjustments to our allowance for credit losses according to any specific news we may receive regarding individual purchasers.

13

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

Joint interest receivables. Our joint interest receivables represent amounts owed to us by other working interest owners on wells that we operate. We have numerous joint interest counterparties which are the result of combining all or portions of multiple oil and gas leases to form units for the drilling of wells under pooling or a joint interest agreements. The counterparties in this segment are diverse, ranging from large public company upstream operators to individual mineral leaseholders. Amounts billed to our joint interest owners generally consist of drilling and completion costs, in the early stages of a well, and lease operating expenses and costs for workovers and remediation work once a well in online. Payment is generally due within 60 days of billing and amount outstanding longer than 90 days are considered past due. Our historical losses on uncollectible receivables have predominantly been attributable to this portfolio segment, although losses in prior years have not been material. In the event of nonpayment, we may be able to mitigate our losses by netting the outstanding amount against any revenues payable to the joint interest owner and if still insufficient, by assuming the joint interest owner’s working interest in the well. The fair value of the working interest, which represents collateral for the outstanding receivable, will depend on the fair value of the remaining oil and natural gas reserves of the well. We monitor the ongoing collectability of these receivables by focusing on past due accounts with material balances. We estimate the expected losses on uncollectible joint interest receivables by applying varying allowance rates to outstanding balances based on aging of the balances. We also factor in current industry conditions, outstanding revenues payable to the accountholder, the fair value of the accountholder’s working interest in the property and the accountholder’s previous loss history in assessing the appropriate allowance. This method is augmented with a specific identification approach that includes directly communicating with certain joint interest owners that have material outstanding balances and consideration of specific information or circumstances regarding the account, such as bankruptcy, litigation or ongoing negotiations.

Derivative settlement receivables. Our derivative receivables relate to net settlements due from counterparties to our derivative contracts. Since derivative settlements fluctuate depending on commodity price changes, which are volatile, the associated amounts can result in a net payable or a net receivable position in any given month. Our derivative contracts generally require payment within 60 days of the fixing date. We have a limited number of counterparties to our derivative contracts, all of whom are large financial institutions and are also lenders under our credit agreement. These financial institution counterparties bear investment grade credit ratings. We have never incurred credit losses from our derivative receivables and believe the probability of such losses to be highly remote. Furthermore, to the extent that a balance is uncollectible, we believe that we have offset rights against amounts owed to the counterparty under our credit facility. Based on these circumstances, we have not recorded any allowance for credit losses related to these receivables. As discussed in “Note 11: Subsequent events,” we terminated all our outstanding derivatives in July 2020.

Other receivables. These receivables are of a nonrecurring discrete nature and generally immaterial with respect to our total receivables. Outstanding amounts may include receivables from taxing authorities and post-closing adjustments from acquisitions and divestitures.

Response to current industry conditions. We are in the midst of an unprecedented decline in crude oil prices brought about by the COVID-19 pandemic and other macroeconomic factors, which has drastically reduced demand for crude oil. The price decline has been exacerbated by episodic storage constraints. We have incorporated the prevailing industry crisis into our forecast of credit losses by increasing the allowance rates that we apply to our receivables, and for certain accounts where we have applied specific identification measures, recognizing an allowance sooner than would be typical under normal conditions.

Accrued interest, discount and premiums. We do not accrue interest on the outstanding balances of our receivables. There are no discounts or premiums associated with our receivables.

Presentation of credit loss expense. Our credit loss expense is included as a component of “General and administrative expenses” on our consolidated statement of operations and is as follows:

	Three months ended June 30,				Six months ended June 30,
	2020		2019		2020		2019
Credit losses on receivables	$	1,447	$	(18)	$	2,964	$	(276)

Credit quality disclosures. We are exempted under ASU 2016-13 from disclosing credit quality disclosures on our commodity sales receivables. Since all the financial institution counterparties to our derivative contracts bear investment grade credit ratings, we do not believe further decomposition by credit rating is necessary for this segment of receivables. The table below segregates our joint interest receivables based on the amount of revenues payable which can be utilized to offset the receivable balance. We consider this segregation to be a reasonable indicator of credit quality.

14

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

Joint interest receivables, gross	June 30, 2020
Accounts which have sufficient related revenue distributions payable to offset entire receivable balance	$	258
Accounts which have related revenue distributions payable but not sufficient to offset entire receivable balance	3,711
Accounts without related revenue distributions payable	6,023
Total	$	9,992

Allowance for credit losses. The table below discloses activity on our receivables allowance account:

	Six months ended June 30, 2020
	Commodity sales		Joint interest		Derivatives		Other		Total
Balance at January 1, 2020	$	—	$	1,097	$	—	$	—	$	1,097
Cumulative effect of accounting standard adoption	154		—		—		—		154
Credit losses	59		2,905		—		—		2,964
Write-offs	—		—		—		—		—
Recoveries	—		—		—		—		—
Balance at June 30, 2020	$	213	$	4,002	$	—	$	—	$	4,215

Inventories

Inventories consisted of the following:

	June 30, 2020		December 31, 2019
Equipment inventory	$	2,673	$	3,435
Commodities	425		474
Inventory valuation allowance	(642)		(179)
	$	2,456	$	3,730

During the three and six months ended June 30, 2020, we recorded an adjustment to net realizable value of $310 and $463 on our equipment inventory, which is reflected as “Impairment of other assets” on our consolidated statements of operations.

Property and equipment, net

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

	June 30, 2020		December 31, 2019
Machinery and equipment	$	3,229	$	3,543
Office and computer equipment	3,606		3,363
Automobiles and trucks	2,469		3,071
Building and improvements	664		693
Furniture and fixtures	8		8
	9,976		10,678
Less accumulated depreciation, amortization and impairment	3,963		3,459
	6,013		7,219
Land	1,935		1,998
	$	7,948	$	9,217

Held for sale.  In an effort to further streamline operations, during the fourth quarter of 2019, the Company began transitioning from an internally staffed and resourced oilfield services function to a third party provider solution. As a result, it began to actively market all related company-owned oilfield services machinery and equipment for eventual disposal. Accounting guidance requires us

15

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

to reflect the disposal group separately on the balance sheet as “Assets held for sale” at carrying value or fair value less cost to sell, whichever is less. The carrying value of assets held for sale is not included in the table above. Our held for sale assets are as follows:

	Carrying value at
	June 30, 2020		December 31, 2019
Equipment	$	—	$	1,572
Vehicles	111		488
Real estate	—		800
Total held for sale	$	111	$	2,860

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. Quarterly, 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. 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; 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 Prior Effective Date in 2017, 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 Focus Areas.

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

	June 30, 2020		December 31, 2019
Leasehold acreage	$	135,059	$	334,083
Capitalized interest	6,317		16,785
Wells and facilities in progress of completion	919		20,361
Total unevaluated oil and natural gas properties excluded from amortization	$	142,295	$	371,229

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 June 30, 2020, 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. These losses are reflected in “Impairment of oil and gas assets” in our consolidated statements of operations. The ceiling test impairment we recorded in the current year was driven in part by our impairment of unevaluated leasehold in the amount $216,173 and $218,741 for the three and six month periods ending June 30, 2020, respectively. Impairments of leasehold result in a transfer of amounts from unevaluated oil and natural gas properties to the full cost amortization base subsequently impacting the ceiling test.

16

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

	Three months ended June 30,			Six months ended June 30,
	2020	2019		2020		2019
Impairment of oil and gas assets	384,639	$	63,593	$	456,010	$	113,315

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 June 30, 2020, and December 31, 2019, were immaterial.

Revenue recognition

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

	Three months ended June 30,				Six months ended June 30,
	2020		2019		2020		2019
Revenues:
Oil	$	10,384	$	50,990	$	47,410	$	83,792
Natural gas	5,679		10,476		14,334		21,682
Natural gas liquids	3,903		11,025		13,585		20,242
Gross commodity sales	19,966		72,491		75,329		125,716
Transportation and processing	(4,086)		(5,784)		(10,598)		(10,390)
Net commodity sales	$	15,880	$	66,707	$	64,731	$	115,326

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, 2019, 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.

Income taxes

On March 27, 2020, the President of the U.S. signed into law the Coronavirus Aid, Relief, and Economic Security (“CARES”) Act. The CARES Act provides relief to corporate taxpayers by permitting a five-year carryback of 2018-2020 net operating losses (“NOLs”), removing the 80% limitation on the carryback of those NOLs, increasing the Section 163(j) 30% limitation on interest expense deductibility to 50% of adjusted taxable income for 2019 and 2020, and accelerates refunds for minimum tax credit carryforwards, along with a few other provisions. During the three and six months ended June 30, 2020, no material adjustments were made to provision amounts recorded as a result of the enactment of the CARES Act.

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.  The consistent effective tax rate, as disclosed below, is a result of maintaining a valuation allowance against substantially all of our net deferred tax asset.

	Three months ended June 30,				Six months ended June 30,
	2020		2019		2020		2019
Effective income tax rate	0.0	%	0.0	%	0.0	%	0.0	%

Despite the Company’s net loss for the six month period ended June 30, 2020, we did not record any net deferred tax benefit due to the Company’s projected taxable loss for the year ending December 31, 2020. Nor did the Company record a 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 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

17

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

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 June 30, 2020, or December 31, 2019.

As a result of the Prior Reorganization Plan and related transactions, the Company experienced an ownership change within the meaning of Internal Revenue Code (“IRC”) Section 382 on the Prior Effective Date. 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 six month period ended June 30, 2020, or any intervening period since the Prior Effective Date. Since the Prior Effective Date ownership change, the Company has generated additional NOLs and other tax attributes that are not currently subject to an IRC Section 382 limitation. The Company’s ability to use NOLs and other tax attributes to reduce taxable income and income taxes could be materially impacted by a future IRC 382 ownership change. Future transactions involving the Company’s stock, including those outside of the Company’s control, could cause an IRC 382 ownership change resulting in a limitation on tax attributes currently not limited and a more restrictive limitation on tax attributes currently subject to the previous IRC 382 limitation.

Subleases expense

Subleases expense for the three months ended March 31, 2019, consisted of our expense on operating leases for CO₂ compressors that we subleased to another operator in 2019. Please see “Note 1: Nature of operations and summary of significant accounting policies” and “Note 17: Leases” in “Item 8. Financial Statements and Supplementary Data” of our Annual Report on Form 10-K for the year ended December 31, 2019, for a discussion of the subleases.

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 resulting from the Prior Chapter 11 Cases and Prior Reorganization Plan. The reorganization items disclosed in our consolidated statement of operations consist of professional fees for continuing legal work to resolve outstanding claims and fees to the U.S. Bankruptcy Trustee, which we will continue to incur until both the Prior Chapter 11 Cases and the Chapter 11 Cases are closed.

Liability management expenses

Liability management expense includes third party legal and professional service fees incurred from our activities to restructure our debt and in preparation for our Chapter 11 Cases.

Litigation loss

The expense consists of our estimate of the settlement costs for the Naylor Farms Case as discussed in “Note 10: Commitments and Contingencies.”

18

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

Recently issued accounting pronouncements

In December 2019, the FASB issued ASU 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes. This standard eliminates certain exceptions in the existing guidance related to the approach for intraperiod tax allocation, the methodology for calculating income taxes in an interim period, and the recognition of deferred tax liabilities for outside basis differences. The new guidance also clarifies certain aspects of the existing guidance, among other things. The standard is effective for interim and annual periods beginning after December 15, 2020 and shall be applied on either a prospective basis, a retrospective basis for all periods presented, or a modified retrospective basis through a cumulative-effect adjustment to retained earnings depending on which aspects of the new standard are applicable to an entity. The Company is in the process of evaluating the new standard and is unable to estimate its financial impact, if any, at this time.

Note 2: Earnings per share

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

	Three months ended June 30,				Six months ended June 30,
(in thousands, except share and per share data)	2020		2019		2020		2019
Numerator for basic and diluted loss per share
Net loss	$	(438,726)	$	(45,229)	$	(433,809)	$	(148,769)
Denominator for basic loss per share
Weighted average common shares	45,949,797		45,641,797		45,890,041		45,549,518
Denominator for diluted loss per share
Weighted average common shares	45,949,797		45,641,797		45,890,041		45,549,518
Loss per share
Basic	$	(9.55)	$	(0.99)	$	(9.45)	$	(3.27)
Diluted	$	(9.55)	$	(0.99)	$	(9.45)	$	(3.27)
Participating securities excluded from loss per share calculations
Unvested restricted stock units - stock settled	604,789		81,119		604,789		81,119
Unvested restricted stock awards	1,839,381		706,821		1,839,381		706,821

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

	Six months ended June 30,
	2020		2019
Net cash provided by operating activities included:
Cash payments for interest	$	16,942	$	16,328
Interest capitalized	(3,900)		(6,613)
Cash payments for reorganization items	1,189		857
Non-cash investing activities included:
Asset retirement obligation additions and revisions	133		386
Financing lease right of use asset additions (see Note 5: Leases)	—		1,387
Change in accrued oil and gas capital expenditures	(22,418)		7,024

19

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

Note 4: Debt

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

	June 30, 2020		December 31, 2019
8.75% Senior Notes due 2023	$	300,000	$	300,000
Credit facility	225,000		130,000
Installment note payable	—		371
Financing lease obligations	1,442		1,653
Unamortized debt issuance costs	(4,154)		(10,038)
Total debt, net	522,288		421,986
Less current portion	521,292		594
Total long-term debt, net	$	996	$	421,392

Chapter 11 Cases and Effect of Automatic Stay. On August 16, 2020, 2020, the Debtors filed for relief under the Bankruptcy Code. The commencement, through the Chapter 11 Cases, of a voluntary proceeding in bankruptcy constituted an immediate event of default under the Credit Agreement and the Indenture, resulting in immediate acceleration of outstanding amounts under these financing arrangements. Any efforts to enforce payment obligations related to the Company’s debt, including the acceleration thereof, have been automatically stayed as a result of the Chapter 11 Cases, and the creditors’ rights of enforcement are subject to the applicable provisions of the Bankruptcy Code. As a result of the acceleration, we have classified the amounts outstanding under the Credit Agreement and Senior Notes as current liabilities on our condensed consolidated balance sheet as of June 30, 2020. For more information on the Chapter 11 Cases and related matters, refer to the “Note 1: Nature of operations and summary of significant accounting policies” and “Note 11: Subsequent events.”

Credit Agreement

Pursuant to our 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 that is 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 June 30, 2020, was $175,000 with no availability (see discussion of Borrowing Base Deficiency below).

As of June 30, 2020, 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 3.19%.

The Credit Agreement contains financial covenants that require, for each fiscal quarter, us to maintain: (1) a Current Ratio (as defined in the Credit Agreement) of no less than 1.0 to 1.0, 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.

The Credit Agreement contains covenants and events of default customary for oil and natural gas reserve-based lending facilities. Our Credit Agreement and Senior Notes include cross default provisions wherein a default on one instrument may cause default on the other. 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, 2019, for a discussion of the material provisions of our Credit Agreement.

On April 1, 2020, we borrowed $15,000, and on April 2, 2020, we provided notice to our lenders to borrow an additional $90,000 (the latter herein referred to as the “Borrowing”) which increased the total amount outstanding under the Credit Agreement to $250,000. The Borrowing was made by the Company as a precautionary measure in order to increase its cash position and thereby provide for flexibility in the current challenging business environment and associated uncertainties. Subsequent to the Borrowing, we were notified that our lenders had exercised their right to make an interim redetermination of the Company’s borrowing base. The lenders’ redetermination notice stated that the Company’s borrowing base was decreased from $325,000 to $175,000, effective April 3, 2020. Our lenders subsequently reaffirmed the borrowing base at the same level on May 5, 2020, in conjunction with our scheduled semi-annual redetermination process. As a result of the April 3, 2020 borrowing base redetermination, the Borrowing, once funded, created a borrowing base deficiency in the amount of $75,000 under the Credit Agreement (the “Borrowing Base Deficiency”). In accordance with the Credit Agreement the Company is allowed to eliminate such Borrowing Base Deficiency by repaying the amount of the Borrowing

20

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

Base Deficiency in six equal monthly installments. During the second quarter, we made two such payments totaling $25,000 plus interest between May 1 to June 1, 2020. A third payment of $12,500 was made in early July 2020. No premium or penalty was charged with respect to those repayments. We did not make the fourth installment payment of $12,500 that was due on August 3, 2020 (the “August Deficiency Payment”), which subsequently resulted in an event of default under the Credit Agreement and under the Indenture, as discussed further below.

On July 15, 2020, the Company entered into a Limited Forbearance Agreement with the lenders under its Credit Agreement (the “Lenders”). The Limited Forbearance Agreement included, among other things, a requirement that the Company terminate all of its outstanding commodity hedges and to apply a certain portion of the proceeds thereof toward partial repayment of the outstanding amount under the Credit Agreement. The Limited Forbearance Agreement was amended effective as of July 24, 2020, by the First Amendment to Limited Forbearance Agreement (the “First Amendment”) and was further amended effective July 29, 2020 by a Second Amendment (the “Second Amendment” and, as amended, such Limited Forbearance Agreement, the “Lender Forbearance Agreement”).

The forbearance period under the Lender Forbearance Agreement began on July 15, 2020 and was scheduled to expire on July 29, 2020, unless terminated earlier in accordance with the terms thereof. The Second Amendment extended the scheduled termination date to August 9, 2020, unless terminated earlier in accordance with the terms of the Forbearance Agreement. However, the Second Amendment permitted an extension of the scheduled termination date by mutual agreement of the Administrative Agent and the Company to any date up to and including August 14, 2020. The Administrative Agent and the Company agreed to extend the termination date to August 14, 2020. Subsequently, on August 14, 2020, the Lender Forbearance Agreement was further amended by a Third Amendment (the “Third Amendment” and, as amended, such Lender Forbearance Agreement, the “Final Lender Forbearance Agreement”), which, among other things, extended the scheduled termination date to August 17, 2020, unless terminated earlier in accordance with the terms of the Final Lender Forbearance Agreement.

Pursuant to the Final Lender Forbearance Agreement, the Lenders agreed, during the forbearance period, to forbear from exercising any remedies under the Credit Agreement for any default or event of default resulting from any failure by the Company or any of its subsidiaries to make all or any part of the required interest payment due on July 15, 2020 with respect to the Company’s Senior Notes (including the failure to make such payment during the 30-day grace period therefor), as discussed further below. Even though the indenture for the Senior Notes provides for a 30-day grace period before an event of default occurs under the indenture, the failure to make the interest payment on the due date constituted an event of default under the cross-default provisions of the Credit Agreement. The Company did not make the required interest payment of $13,125 on the due date or within the 30-day grace period. The Final Lender Forbearance Agreement also includes forbearance for the Company’s failure to timely pay the August Deficiency Payment under the Credit Agreement and the failure to timely deliver the quarterly financial statements for the period ended June 30, 2020 and the required accompanying officer’s certificate.

Pursuant to the Limited Forbearance Agreement with the lenders under our Credit Agreement, we terminated all our outstanding derivatives contracts on July 27, 2020 and applied a certain portion of the proceeds thereof toward partial repayment of the outstanding amount under the Credit Agreement, which we discuss in “Note 11: Subsequent events.”

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 Indenture contains customary covenants, certain mandatory redemption 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, 2019, for a discussion of the material provisions of our Senior Notes.

On July 15, 2020, the Company elected not to make the $13,125 interest payment on the Senior Notes due on that day. Under the Indenture, the Company has a 30-day grace period to make the interest payment before that non-payment constitutes an event of default. The 30-day grace period expires on August 14, 2020. However, as discussed above, the failure to make that interest payment on the Senior Notes constituted an event of default under cross-default provisions of the Credit Agreement.

21

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

Effective as of July 30, 2020, the Company and the holders of at least 75% of the principal amount of outstanding Senior Notes (the “Initial Consenting Noteholders”) entered into a Forbearance and Waiver Agreement (the “Noteholder Forbearance Agreement”). Pursuant to the Noteholder Forbearance Agreement, the Initial Consenting Noteholders agreed, during the forbearance period, to forbear from exercising certain remedies under the Indenture (including acceleration) for any default or event of default resulting from any failure by the Company to pay the August Deficiency Payment under the Credit Agreement on or before August 3, 2020. In addition, under the Noteholder Forbearance Agreement, subject to the occurrence of such an event of default, the Initial Consenting Noteholders have waived any such event of default and the consequences thereof under the Indenture. The forbearance period under the Noteholder Forbearance Agreement began on July 30, 2020 and was scheduled to expire on August 14, 2020. On August 14, 2020, the Company and the Initial Consenting Noteholders amended and restated the Noteholder Forbearance Agreement (such amendment and restatement, the “Amended and Restated Noteholder Forbearance Agreement”). Pursuant to the Amended and Restated Noteholder Forbearance Agreement, the Initial Consenting Noteholders agreed to extend the forbearance period to August 17, 2020 and to additionally forbear from exercising certain remedies under the Indenture (including acceleration) for any default or event of default resulting from any failure by the Company to make the required interest payment of $13,125 within the 30-day grace period described above.

Please see “Note 11: Subsequent events” for a discussion of the restructuring support agreement and the related proposed plan of reorganization.

As discussed above, our filing of the Chapter 11 Cases triggered an event of default on our Senior Notes. The event of default effectively allows the lender to demand immediate repayment, thus shortening the life of our Senior Notes to the current period. As a result, we wrote off the remaining balance of unamortized issuance costs in the amount of $4,420.

22

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

Note 5: Leases

We currently have financing leases that consist of fleet trucks and office equipment and an operating lease for the office space housing our headquarters. Please see “Note 17: Leases” in “Item 8. Financial Statements and Supplementary Data” of our Annual Report on Form 10-K for the year ended December 31, 2019, for a discussion of these leases. We also have short term leases, which are those with lease terms of 12 months or less, and generally consist of wellhead compressors and drilling rigs with terms ranging from one month to six months. We do not recognize right of use assets or lease liabilities for leases with durations of 12 months or less.

Lease assets and liabilities

Our operating lease and financing lease assets and liabilities are recorded on our balance sheet as of June 30, 2020 as:

	As of June 30, 2020
	Operating leases		Financing leases
Right of use asset:
Right of use assets from operating leases	$	1,744	$	—
Plant, property and equipment, net	—		1,428
Total lease assets	$	1,744	$	1,428
Lease liability:
Account payable and accrued liabilities	$	1,331	$	—
Long-term debt and financing leases, classified as current	—		446
Long-term debt and financing leases, less current maturities	—		996
Noncurrent operating lease obligations	234		—
Total lease liabilities	$	1,565	$	1,442

23

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:

	Three months ended June 30,				Six months ended June 30,
	2020		2019		2020		2019
Lease cost
Finance lease cost:
Amortization of right-of-use assets	$	114	$	749	$	231	$	1,442
Interest on lease liabilities	26		117		53		230
Operating lease cost	389		308		779		616
Short-term lease cost	92		154		310		283
Variable lease cost	—		95		—		190
Sublease income	—		(1,198)		—		(2,396)
Total lease cost	$	621	$	225	$	1,373	$	365
Capitalized operating lease cost (1)	$	—	$	3,371	$	—	$	6,706
Other information
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows for finance leases	$	(26)	$	(117)	$	(53)	$	(230)
Operating cash flows for operating leases	(344)		(308)		(689)		(616)
Investing cash flows for operating leases	—		(2,965)		—		(3,988)
Financing cash flows for finance leases	(107)		(746)		(212)		(1,445)
Right-of-use assets obtained in exchange for new finance lease liabilities	—		717		—		1,387

________________________________

(1)The operating lease cost is related to drilling rigs with terms longer than 30 days and is capitalized as part of oil and natural gas properties on our balance sheets.

Note 6: Derivative instruments

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.

The following table summarizes our crude oil derivatives outstanding as of June 30, 2020:

		Weighted average fixed price per Bbl
Period and type of contract	Volume MBbls	Swaps
2020
Oil swaps	1,026	$	50.56
Oil roll swaps	180	$	0.30
2021
Oil swaps	689	$	46.24
Oil roll swaps	150	$	0.30

24

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

The following table summarizes our natural gas derivatives outstanding as of June 30, 2020:

Period and type of contract	Volume BBtu	Weighted average fixed price per MMBtu
2020
Natural gas swaps	3,000	$	2.75
Natural gas basis swaps	3,000	$	(0.46)

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 June 30, 2020						As of December 31, 2019
	Assets		Liabilities		Net value		Assets		Liabilities		Net value
Natural gas derivative contracts	$	2,288	$	(500)	$	1,788	$	3,552	$	(1)	$	3,551
Crude oil derivative contracts	15,399		—		15,399		391		(22,196)		(21,805)
NGL derivative contracts	—		—		—		2,868		(699)		2,169
Total derivative instruments	17,687		(500)		17,187		6,811		(22,896)		(16,085)
Less:
Netting adjustments (1)	(500)		500		—		(5,864)		5,864		—
Derivative instruments - current	15,197		—		15,197		947		(11,957)		(11,010)
Derivative instruments - long-term	$	1,990	$	—	$	1,990	$	—	$	(5,075)	$	(5,075)

________________________________

(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

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 gains (losses)” in the consolidated statements of operations.

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

	Three months ended June 30,				Six months ended June 30,
	2020		2019		2020		2019
Change in fair value of commodity price derivatives	$	(35,934)	$	17,596	$	33,272	$	(33,935)
Net settlements received on commodity price derivatives	22,915		138		32,089		653
Total derivative gains (losses)	$	(13,019)	$	17,734	$	65,361	$	(33,282)

Pursuant to the Limited Forbearance Agreement with the lenders under our Credit Agreement, we terminated all our outstanding derivatives contracts on July 27, 2020 and applied a certain portion of the proceeds thereof toward partial repayment of the outstanding amount under the Credit Agreement, which we discuss in “Note 11: Subsequent events.”

25

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

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 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 June 30, 2020, and December 31, 2019, 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 during the current year consisted of natural gas basis swaps and collars. 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 June 30, 2020						As of December 31, 2019
	Derivative assets		Derivative liabilities		Net assets (liabilities)		Derivative assets		Derivative liabilities		Net assets (liabilities)
Significant other observable inputs (Level 2)	$	17,687	$	—	$	17,687	$	6,576	$	(22,895)	$	(16,319)
Significant unobservable inputs (Level 3)	—		(500)		(500)		235		(1)		234
Netting adjustments (1)	(500)		500		—		(5,864)		5,864		—
	$	17,187	$	—	17,187		$	947	$	(17,032)	$	(16,085)

________________________________

(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:

26

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

	Six months ended June 30,
Net derivative assets (liabilities)	2020		2019
Beginning balance	$	234	$	30
Realized and unrealized gains included in derivative losses	1,033		441
Settlements (received) paid	(1,767)		116
Ending balance	$	(500)	$	587
(Losses) gains relating to instruments still held at the reporting date included in derivative gains (losses) for the period	$	(430)	$	742

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:

	Six months ended June 30,
	2020		2019
Inflation rate	2.21	%	2.25	%
Credit-adjusted risk-free discount rate (low)	25.00	%	12.35	%
Credit-adjusted risk-free discount rate (high)	25.00	%	14.60	%

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:

	June 30, 2020				December 31, 2019
Level 2	Carrying value (1)		Estimated fair value		Carrying value (1)		Estimated fair value
8.75% Senior Notes due 2023	$	300,000	$	30,000	$	300,000	$	133,050
Credit facility	225,000		225,000		130,000		130,000
Other secured debt (2)	—		—		371		371

________________________________

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

(2)The balance December 31, 2019, consisted of only 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.

27

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

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 June 30, 2020, the counterparties to our open derivative contracts consisted of five 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. 

	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
June 30, 2020
Derivative assets	$	17,687	$	(500)	$	17,187	$	—	$	(17,187)	$	—
Derivative liabilities	(500)		500		—		—		—		—
	$	17,187	$	—	$	17,187	$	—	$	(17,187)	$	—
December 31, 2019
Derivative assets	$	6,811	$	(5,864)	$	947	$	—	$	(947)	$	—
Derivative liabilities	(22,896)		5,864		(17,032)		—		947		(16,085)
	$	(16,085)	$	—	$	(16,085)	$	—	$	—	$	(16,085)

________________________________

(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 $500 before offsets at June 30, 2020.

Pursuant to the Limited Forbearance Agreement with the lenders under our Credit Agreement, we terminated all our outstanding derivatives contracts on July 27, 2020 and applied a certain portion of the proceeds thereof toward partial repayment of the outstanding amount under the Credit Agreement, which we discuss in “Note 11: Subsequent events.”

Note 8: Asset retirement obligations

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

Balance at January 1, 2020	$	23,156
Liabilities incurred in current period	84
Liabilities settled or disposed in current period	(419)
Revisions in estimated cash flows	49
Accretion expense	649
Balance at June 30, 2020	$	23,519
Less current portion included in accounts payable and accrued liabilities	2,107
Asset retirement obligations, long-term	$	21,412

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

28

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

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. Our cash awards, which are generally service-based, vest either in one year, in annual increments over a three year period or in annual increments over a four-year period. We accrue for the cost of each annual increment over the period that service is required to vest. A summary of compensation expense for our cash awards is presented below:

	Three months ended June 30,				Six months ended June 30,
	2020		2019		2020		2019
Cash LTIP expense (net of amounts capitalized)	$	187	$	67	$	354	$	158

As of June 30, 2020, the outstanding liability accrued for our Cash LTIP, based on requisite service provided, was $1,366.

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. Our equity grants have been in the form or restricted stock awards (“restricted shares”) and restricted stock units (“RSUs”). In December 2019, we also granted restricted shares to our recently appointed chief executive officer under an inducement equity grant that is exempted from the general requirement of the NYSE rules that require equity-based compensation plans and arrangements to be approved by stockholders. 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. Please see “Note 13: Deferred Compensation” in “Item 8. Financial Statements and Supplementary Data” of our Annual Report on Form 10-K for the year ended December 31, 2019, for further details on the MIP, the LTIP as well as the nature and vesting requirements for our restricted shares and RSUs.

A summary of our restricted share activity 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, 2020	$	5.41	1,069,505			$	1.53	1,089,343
Granted	$	—	—			$	—	—
Vested	$	15.71	(203,888)	$	130	$	—	—
Forfeited	$	8.87	(82,658)			$	6.94	(20,833)
Cancelled	$	20.05	(12,088)			$	—	—
Unvested and outstanding at June 30, 2020	$	2.09	770,871			$	1.33	1,068,510

29

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

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, 2020	$	2.41	638,383			$	1.36	390,000
Granted	$	1.95	4,500			$	—	—
Vested	$	—	—	$	—	$	—	—
Forfeited	$	1.56	(228,094)			$	1.36	(200,000)
Unvested and outstanding at June 30, 2020	$	2.87	414,789			$	1.36	190,000

	Liability classified RSUs
	Weighted average award date fair value		Restricted units	Vest date fair value
	($ per share)
Unvested and outstanding at January 1, 2020	$	4.57	75,779
Granted	$	—	—
Vested	$	1.33	(60,000)	$	41
Forfeited	$	17.66	(1,515)
Unvested and outstanding at June 30, 2020	$	16.83	14,264

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:

	Three months ended June 30,				Six months ended June 30,
	2020		2019		2020		2019
Stock-based compensation cost	$	101	$	1,260	$	771	$	2,720
Less: stock-based compensation cost capitalized	(7)		(399)		(281)		(1,025)
Stock-based compensation expense	$	94	$	861	$	490	$	1,695
Number of vested shares repurchased or settled in cash	92,649		126,231		96,505		206,653
Payments for stock-based compensation	53		708		59		1,171

Based on a quarter end market price of $0.65 per share of our Class A common stock, the aggregate intrinsic value of all restricted shares and RSUs outstanding was $1,593 as of June 30, 2020. Payments for restricted shares and the associated number of shares repurchased are reflected as treasury stock transactions in our consolidated statements of equity. As of June 30, 2020, and December 31, 2019, accrued payroll and benefits payable included for stock-based compensation costs expected to be settled within the next

30

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

twelve months were $45 and $52, respectively, all of which relates to our cash-settled RSUs. Unrecognized stock-based compensation cost of approximately $1,357 as of June 30, 2020, is expected to be recognized over a weighted-average period of 1.3 years.

Note 10: Commitments and contingencies

Standby letters of credit (“Letters”) available under our credit facility may be 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 nil as of June 30, 2020 and nil as of December 31, 2019. 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 six months ended June 30, 2020 or 2019.

Surety bonds totaling $2,121 were posted on our behalf as of June 30, 2020. We pay premiums for such bonds and, under normal circumstances, are not required to post collateral of any kind to support their issuance. However, as a result of the current extraordinary macroeconomic situation and the Borrowing Base Deficiency discussed above, we have been required to post cash collateral in respect of the bonds totaling $950.

Litigation and Claims

Prior Chapter 11 Cases.  Commencement of the Prior 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 (the “Prior Petition Date”), and the claims remain subject to Bankruptcy Court jurisdiction. With respect to the proofs of claim asserted in the Prior Chapter 11 Cases arising from the proceedings or actions below that were initiated prior to the Prior 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 that relate to one or more claims accruing prior to the Prior Petition Date and that result in a claim being allowed against us, pursuant to the terms of the Prior Reorganization Plan, such claims would 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, in each case subject to their further treatment prescribed by the Plan of Reorganization, assuming its ultimate approval.

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 consist of interest and may increase with the passage of time. We responded to the Naylor Farms petition, denied the allegations and raised arguments and defenses. Plaintiffs filed a motion for class certification in October 2015.  In addition, the plaintiffs filed a motion for summary judgment asking the Naylor Trial Court to determine as a matter of law that natural gas is not marketable until it is in the condition and location to enter an interstate pipeline. On May 20, 2016, we filed a Notice of Suggestion of Bankruptcy with the Naylor Trial Court. Subsequently the bankruptcy stay was lifted for the limited purpose of determining the class certification issue.

On January 17, 2017, the Naylor Trial Court certified a modified class of plaintiffs with oil and gas leases containing specific language. The modified class constitutes less than 60% of the leases the plaintiffs originally sought to certify. After additional briefing on the subject, on April 18, 2017, the Naylor Trial Court issued an order certifying the class to include only claims relating back to June 1, 2006. On May 3, 2019, our appeal of that class certification was denied by the Tenth Circuit Court of Appeals.

In addition to filing claims on behalf of the named and putative plaintiffs, on August 15, 2016, plaintiffs’ attorneys filed a proof of claim on behalf of the putative class claiming damages in excess of $150,000 in our Prior Chapter 11 Cases. The Company objected to treatment of the claim on a class basis, asserting the claim should be addressed on an individual basis. On April 20, 2017, plaintiffs filed an amended proof of claim reducing the claim to an amount in excess of $90,000 inclusive of actual and punitive damages, statutory interest and attorney fees. On May 24, 2017, the Bankruptcy Court denied the Company’s objection, ruling the plaintiffs

31

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

may file a claim on behalf of the class. This order did not establish liability or otherwise address the merits of the plaintiffs’ claims. The Bankruptcy Court order was affirmed by the United States District Court for the District of Delaware on September 24, 2019. On October 24, 2019, the Company filed its notice of appeal to the United States Court of Appeals for the Third Circuit.

During the period leading up to the commencement of the Chapter 11 Case, the Company engaged in settlement negotiations with counsel to the plaintiffs in the Naylor Farms case. On July 6, 2020, after multiple rounds of negotiations, the Company and the class representatives reached an agreement in principle on the terms of a settlement and, on August 15, 2020, the Company and the class representatives entered into a settlement agreement (the “Settlement Agreement”) to settle all claims related to the Naylor Farms case, including, for the avoidance of doubt, all alleged claims arising prior to the petition date in the Prior Chapter 11 Cases and all alleged claims arising thereafter.

Pursuant to the Settlement Agreement, the Company has agreed to:

•pay $2,500 to the settlement class;

•pay $850 to counsel to the settlement class for attorney fees, in exchange for a release of all liens or claims asserted by all counsel related to the Naylor Farms case;

•pay $150 to the class representative for services rendered as class representative; and

•allow the class proof of claim filed in the Prior Chapter 11 Case in an aggregate amount of $45,000 (provided that all other individual proofs of claims filed for similar claims are withdrawn).

The effectiveness of the settlement is subject to numerous conditions precedent, including approval by the Bankruptcy Court. Upon the Bankruptcy Court’s final approval of the Settlement Agreement, the members of the class who do not opt out of the settlement will provide the Company with a release of all past and present claims with respect to the allegations in the Naylor Farms case, and the Naylor Farms case and the Third Circuit appeal will be dismissed with prejudice.

Upon the final approval of the Settlement Agreement and the effectiveness of the settlement, the plaintiffs, in full satisfaction, settlement, discharge, and release of their claims asserted in the Prior Chapter 11 Cases, shall be deemed to hold 1,432,300 shares of Class A common stock in Chaparral Energy, Inc. as of the Petition Date on account of the $45,000 allowed class proof of claim and shall be entitled to receive any distribution under the Plan provided to holders of equity interests who do not hold through the Depository Trust Corporation (the “DTC”) or whose interests arise in connection with claims pending in the Prior Chapter 11 Cases, subject to a cap.

W.H. Davis Family Limited Partnership Claims in the Company’s Prior Chapter 11 Cases (the “W. H. Davis case”). The W. H. Davis Family Limited Partnership and affiliates (collectively, “Davis”) filed Proofs of Claim in the Company’s Prior Chapter 11 Cases. Davis claimed that Chaparral owed Davis $17,262 as the result of Chaparral’s alleged diversion of CO₂ from the Camrick Unit and the North Perryton Unit to the Farnsworth Unit. All these units were divested by the Company as part of its EOR asset sale in November 2017. While the Company denies all claims asserted by Davis, the Company determined it was prudent to explore settlement of the claims. Accordingly, the Company and Davis agreed at mediation to settle Davis’ claims for an allowed claim of $2,650 in Class 6 under the Prior Reorganization Plan, which agreement was memorialized in a settlement term sheet executed by both parties on the day of the mediation, a settlement agreement executed by both parties thereafter, and a settlement stipulation executed by both parties that was filed with the Bankruptcy Court. Davis subsequently contested the enforcement of the settlement under its terms, claiming that Davis was mistaken in its understanding of the terms of the Prior Reorganization Plan as relate to Class 6 claims. On August 14, 2020, Davis stipulated to the termination of such contest without payment by the Company of any consideration therefor.

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 and our financing leases consist of leases on our fleet vehicles and office equipment. We have a well drilling commitment under the terms of leasehold purchase agreements which we entered into in 2017. The drilling commitment requires the

32

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

Company to drill and complete 10 wells on such leasehold in each of 2019, 2020, and 2021 and 15 wells in 2022. To the extent the Company does not drill and complete the minimum number of wells in a given year, it is required to pay the sellers of the acreage $250 for each deficient well. The Company has paid the deficiency amount related to its 2019 drilling commitment and recorded an accrual of $2,500 in March 2020 for the deficiency on its 2020 drilling commitment and recorded an additional accrual of $6,250 in June 2020 for the remaining obligation as it does not intend to drill any further wells on the subject acreage.

Other than additional borrowings under our credit facility and the Borrowing Base Deficiency described in “Note 4: Debt” and the termination of our derivative contracts discussed below, we did not have material changes to our contractual commitments since December 31, 2019.

Note 11: Subsequent events

As discussed in “Note 4: Debt”, the Lender Forbearance Agreement required us to terminate all our outstanding derivative contracts and to apply a certain portion of the proceeds thereof toward partial repayment of the outstanding amount under the Credit Agreement. Pursuant to this requirement, on July 27, 2020, the Company terminated all its outstanding derivative contracts. Proceeds from the early termination along with amounts owed to the Company from previously settled positions totaled $28,237. Of this amount, $24,000 was applied toward repayment on outstanding credit facility borrowings and the remainder was retained by the Company. The amount applied toward debt repayment versus the amount retained by the Company was determined under the terms of the Lender Forbearance Agreement.

On August 15, 2020, the Debtors entered into a restructuring support agreement (the “RSA”) with (i) certain lenders under our Credit Agreement and (ii) certain holders of our Senior Notes (the “Restructuring Support Parties”). Pursuant to the RSA, the Restructuring Support Parties agreed, subject to the terms and conditions of the RSA, to vote to accept the Debtors’ prepackaged Joint Chapter 11 Plan of Reorganization (as proposed, our “Plan of Reorganization”). Our Plan of Reorganization and the related disclosure statement (the “Disclosure Statement”) were each filed with the Bankruptcy Court on August 16, 2020. Below is a summary of certain material terms of the RSA and the treatment that the stakeholders of the Company would receive under the Plan of Reorganization:


•The RSA includes certain milestones for the progress of the Chapter 11 Cases, which include the dates by which the Company is required to, among other things, obtain certain court orders and consummate the transactions contemplated therein. Failure to meet these milestones allows the RSA to be terminated by the non-Company signatories thereto. In addition, the signatories to the RSA will have the right to terminate the RSA under certain circumstances, including if the board of directors of the Company determines in good faith that performance under the RSA would be inconsistent with its fiduciary duties as set forth therein. The Plan of Reorganization remains subject to approval by the Bankruptcy Court and the satisfaction of certain conditions precedent.


•The Company will emerge from Chapter 11 with a $300,000 exit credit facility (the “Exit Facility”). The Exit Facility will include (A) second out term loans (the “Second Out Term Loans”) in an amount to be determined, which will have a maturity date that is one year and 91 days following the Revolving Maturity Date (defined below) and (B) a revolving facility (the maturity date of which will be the earlier of May 31, 2024 or 40 months after emergence (the “Revolving Maturity Date”)) that has an initial borrowing base equal to (i) the lesser of (a) $175,000 or (b) the Company’s proved developed producing reserves on a PV-15 basis, plus hedges, on 6-month roll-forward basis minus (ii) the aggregate amount of the Second Out Term Loans. There must be a minimum of $20,000 of availability under the Exit Facility at emergence.


•The Company will raise $35,000 through a fully backstopped new money rights offering (the “Rights Offering”) of second-lien senior notes convertible into New Common Stock (as defined below) (the “2L Convertible Notes”) issued at par. The Convertible Notes will be convertible into shares of New Common Stock equal to 50% of the New Common Stock outstanding upon the reorganized Company’s emergence from bankruptcy (subject to certain anti-dilution protection) and will have the following terms:

◦they will have a maturity date of May 31, 2025 or 52 months after emergence, whichever is earlier;

◦they will bear interest at a rate of 9% per annum (if paid in cash), or 13% per annum (if paid in kind with additional principal);

◦interest must be paid in kind with additional principal if the Company’s liquidity is less than $20,000 at the time of such payment.


•On August 15, 2020, the Debtors entered into a Backstop Purchase Agreement (the “Backstop Purchase Agreement”) with the backstop parties named therein (the “Backstop Parties”). The Backstop Parties are obligated to fund, if necessary, the

33

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

entirety of the initial $35,000 principal amount. In exchange for that commitment, such holders will receive a put option premium (the “Put Option Premium”) equal to 10% of the total issued and outstanding shares of new common stock of the reorganized Company (the “New Common Stock”) prior to dilution by the Management Incentive Plan (as defined below), the Warrants (as defined below) and the conversion of the 2L Convertible Notes. The Convertible Notes will be convertible into shares of New Common Stock equal to 50% of New Common Stock outstanding upon the reorganized Company’s emergence from bankruptcy (subject to certain anti-dilution protection). If the Backstop Purchase Agreement is terminated (subject to certain exceptions, including a termination of the Backstop Purchase Agreement by the Company as a result of a breach by the Backstop Parties), the Debtors will be required to pay the Put Option Premium in a cash amount equal to $2,625 in lieu of New Common Stock. The transactions contemplated by the Backstop Purchase Agreement are conditioned upon the satisfaction or waiver of customary conditions for transactions of this nature, including among other things that (i) the Bankruptcy Court shall have confirmed the Plan and (ii) all Convertible Notes have been, or concurrently with the Closing will be, subscribed for or purchased pursuant to the Backstop Purchase Agreement.


•The reorganized Company will adopt a management incentive plan (the “Management Incentive Plan”), which will provide for the issuance of equity and/or equity based awards for up to 7% of the new common equity issued by the reorganized Company, the terms and conditions of which will be determined by the reorganized Company’s new board members within 30 days after emergence.

•Holders of Credit Agreement Claims

◦Lenders under the Credit Agreement will receive, on account of their prepetition loans, (i) their pro rata share of cash in the amount of the difference between their outstanding loans as of the effective date of the Plan of Reorganization and the initial borrowing base under the Exit Facility and (ii) with respect to lenders who agree to provide revolving commitments under the Exit Facility, their pro rata share of an additional amount of cash in excess of $5,000 (less cash payments scheduled to be made as severance payments to former officers and employees at or around emergence in accordance with the terms of the severance settlement agreements in an amount not to exceed $1,220 and less other cash payments required to be made at or around exit pursuant to the Plan of Reorganization) and new first-lien first-out revolving loans on account of their remaining prepetition loans and, with respect to lenders electing not to provide revolving commitments under the Exit Facility, new first-lien second-out term loans on account of their remaining prepetition loans.

•Holders of Senior Notes

◦At emergence, each holder of Senior Notes will receive its pro rata share of (i) 100% of the New Common Stock, subject to dilution by any New Common Stock issued in connection with the Management Incentive Plan, Warrants (as defined below), conversion of the 2L Convertible Notes and the Put Option Premium, and obligations in respect of the Senior Notes would be extinguished and (ii) rights to participate pro rata in the Rights Offering of the 2L Convertible Notes.


•Holders of Other Claims

◦Except as otherwise provided in the Plan of Reorganization, all other claims, including general unsecured claims, will receive treatment that renders them unimpaired under the Bankruptcy Code.

•Existing Equityholders

◦All of the Company's existing common stock and other equity interests will be cancelled without any distribution to the holders of such common stock and other equity interests on account thereof.

◦However, holders of the Company's existing common stock and certain other equity interests that do not object to the Plan of Reorganization or opt out of the releases contained in the Plan of Reorganization (the “Eligible Common Stockholders”) are entitled to receive their ratable share of $1,200 in cash and the package of cashless exercise warrants described below (or in the case of certain holders of equity interests who do not hold through the DTC, cash in an amount equal to $0.01508 per share in lieu of such warrants). As of the date hereof, the Company has 47,790,146 shares of common stock outstanding.

◦The cashless exercise warrants distributable pro rata to the Eligible Common Stockholders (the “Warrants”) will be exercisable for (i) 5% of the New Common Stock issued by the reorganized Company at emergence, with a $300,000 equity value strike price and 4-year term and (ii) 5% of the New Common Stock issued by the reorganized Company at emergence with a $350,000 equity value strike price and 5-year term. The Warrants will be subject to dilution by New Common Stock issued in connection with the Management Incentive Plan, the Put Option Premium, and any conversion of the 2L Convertible Notes.




34

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

•Claimants in the Prior Chapter 11 Cases

◦Holders of claims in the Prior Chapter 11 Cases that are classified in Class 6 or Class 8 in the Prior Reorganization Plan, if and when their claims are allowed, that do not object to the Plan of Reorganization or opt out of the releases contained in the Plan of Reorganization will receive an equivalent amount of cash as such Eligible Common Stockholders who do not hold through the DTC. Distributions to holders of such claims in the Prior Chapter 11 Cases after the effective date of the Plan of Reorganization will be capped at $150.


35

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

Chaparral Energy, Inc. (NYSE: CHAP) is an independent oil and natural gas exploration and production company headquartered in Oklahoma City. Founded in 1988, Chaparral has over 212,000 net surface acres in the Mid-Continent region.  The Company is focused in the oil window of the Anadarko Basin in the heart of Oklahoma, where it has approximately 114,000 net acres (our “Focus Areas”). 

The following discussion and analysis is intended to assist in understanding our financial condition and results of operations for the three and six months ended June 30, 2020 and 2019, as well as the current trends and uncertainties relevant to the Company’s future financial and operational performance. 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, 2019.

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.”

Early 2020 Activity

Early in the first quarter of 2020, Chaparral management began a comprehensive cash improvement effort. The initiative, which involves the formation and collaboration of multiple working teams, was intended to identify, validate and implement opportunities to improve the Company’s cash flow across all parts of its business: drilling and completions capital expenditures, lease operating expenses, production uptime and efficiency, development planning, and general and administrative expenses. Many of the measures identified by the teams were implemented and expanded cash flow at the project level. However, because of the extraordinary and unprecedented events affecting the oil and gas industry discussed below, the benefits – which are scale-dependent – were not able to achieve their full potential.

Macroeconomic Developments and Their Impact on the Oil and Gas Industry

The energy industry has recently experienced two significant external forces that have impacted, and are anticipated to continue impacting, both day-to-day operations and the macro environment. The COVID-19 outbreak and voluntary and mandatory quarantines, travel restrictions and other restrictions throughout the United States and other parts of the world have resulted in decreased demand for crude oil, NGLs and natural gas. Additionally, in March 2020, the group of oil producing nations known as OPEC+ failed to reach an agreement over proposed oil production cuts due to the decrease in global demand for oil stemming from the COVID-19 pandemic (the oil price war). Although the members of OPEC+ eventually reached an agreement to reduce their oil production beginning in May 2020 and continuing through April 2022, there remains significant uncertainty regarding the future actions of OPEC+, its members and other state-controlled oil companies related to oil price and production controls, including anticipated increases in supply from Russia and other members of OPEC+, particularly Saudi Arabia.

In addition, the COVID-19 pandemic has increased volatility and caused negative pressure in the capital and credit markets. As a result, we have not had the sort of access to the capital and credit markets that was once available to us. That lack of access to financing compounded the impact of the depressed commodity price environment triggered by COVID-19 and the oil price war.

Chaparral’s Response and 2020 Outlook

In response to the depressed commodity price environment, Chaparral has taken material and unusual actions to maximize the value of its assets and improve its financial position. Because the Company had (a) a strong hedge position for crude oil in 2020, the terms of which did not require the physical delivery of any oil or gas and (b) no material volume commitments or other contractual obligations to produce oil or gas, we determined that it was not prudent or necessary to continue developing our inventory or to sell all of our products at the prevailing low market prices.

Shut-ins and Drilling Suspension. We suspended all drilling and stimulation operations in early April 2020, deferring completions of recently drilled wells. Further, the Company shut in the six-well Greenback pad that came online in early March even though it

36

was performing above expectations. The Company subsequently shut in operated production that is not associated with waterfloods or exposed to well-specific mechanical or other risks during the months of May and June 2020.

In order to facilitate a swift restart of sales, we took steps in April to increase crude storage in the tank batteries at our operated lease locations. As tank batteries filled, the majority of our operated production was curtailed. Furthermore, as part of the April 2020 shut-in, we implemented procedures and precautions to protect mechanical and reservoir integrity and to minimize the cost and timing of resuming production. We wanted to ensure that production could be resumed efficiently on these shut-in wells once commodity prices recover sufficiently. With improved crude prices in June 2020, the Company began a phased restart to the curtailed production and by the end of the month nearly all our operated wells had returned to production.

Hedging. The Company entered 2020 with a strong hedge position for crude oil in 2020. As prices declined sharply due to COVID-19 and the initial lack of a coordinated response from OPEC+ to cut production, we generated $22.9 million and $32.1 million in realized derivative gains for the three and six months ended June 30, 2020, respectively. However, we were unable to enter into new hedges during the second quarter of 2020 as a result of a restriction imposed on us by our hedging counterparties (who are also lenders under our Credit Agreement) while our Borrowing Base Deficiency (as described below) remained uncured. In July 2020, we terminated all our outstanding derivatives, which we discuss further below.

Liquidity and capital resources

Effect of Shut-ins and Drilling Suspension on Cash Flow from Operations. 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. As a result of shutting in a substantial number of our producing wells and suspending drilling and stimulation operations, cash flows generated from our operating activities declined significantly. This decline was partially offset by (a) the related reductions in expenses and capital expenditures and (b) proceeds from hedge settlements.

Proceeds from Revolving Credit Facility and Senior Notes Interest Payment. In order to address the net reduction in cash flows discussed above, we significantly increased our cash balance by borrowing an additional $105 million at the beginning of April 2020. These borrowings were made as a precautionary measure to increase our cash position and provide operational flexibility in the current challenging business environment. The April 2020 borrowings increased the total amount outstanding under our Credit Agreement to $250.0 million.

Borrowing Base Deficiency and Past Due August Deficiency Payment. Shortly after we made these borrowings in April 2020, our lenders made an interim redetermination of the Company’s borrowing base, reducing the borrowing base from $325.0 million to $175.0 million, effective April 3, 2020. The combination of the borrowing base reduction and our April 2020 borrowings created a $75.0 million borrowing base deficiency under the Credit Agreement (the “Borrowing Base Deficiency”). In accordance with the Credit Agreement, we elected to follow a procedure that permitted the Company to repay the $75.0 million deficiency in six equal monthly installments of $12.5 million, beginning in early May 2020. Since making that election, we have made three deficiency payments, for a total of $37.5 million. However, we did not make the fourth installment payment of $12.5 million that was due on August 3, 2020 (the “August Deficiency Payment”). The failure to make that payment on time resulted in an immediate event of default under the Credit Agreement, as well as under the cross-default provisions of the Indenture.

Past Due Interest Payment on the Senior Notes. On July 15, 2020, the Company elected not to make the $13.125 million interest payment on the Senior Notes due on that day (the “Past Due Interest Payment”). Under the Indenture, the Company has a 30-day grace period to make the Past Due Interest Payment before that non-payment becomes an event of default. The Company subsequently did not make the Past Due Interest payment upon expiration of the 30-day grace period on August 14, 2020. Even though the Indenture provides for a 30-day grace period to make the Past Due Interest Payment, the failure to make that interest payment on its due date of July 15, 2020 constituted an immediate event of default under cross-default provisions of the Credit Agreement. The subsequent failure to make that interest payment upon expiration of the 30-day grace period on August 14, 2020 constituted an event of default under the indenture governing our Senior Notes (the “Indenture”).

Lender Forbearance Agreement. On July 15, 2020, in order to address the cross-default that resulted under the Credit Agreement from the failure to timely pay the Past Due Interest Payment, the Company entered into a Limited Forbearance Agreement with the lenders under its Credit Agreement. The Limited Forbearance Agreement was amended effective as of July 24, 2020, by the First

37

Amendment to Limited Forbearance Agreement (the “First Amendment”) and was further amended effective July 29, 2020 by a

Second Amendment (the “Second Amendment” and, as amended, such Limited Forbearance Agreement, the “Lender Forbearance

Agreement”). On August 14, 2020, the Lender Forbearance Agreement was further amended by a Third Amendment (the “Third Amendment” and, as amended, such Lender Forbearance Agreement, the “Final Lender Forbearance Agreement”).

Pursuant to the Final Lender Forbearance Agreement, the Lenders agreed, during the forbearance period, to forbear from exercising any remedies under the Credit Agreement for any default or event of default resulting from any failure by the Company or any of its subsidiaries to make all or any part of the Past Due Interest Payment (including the failure to make such payment during the 30-day grace period therefor). The Final Lender Forbearance Agreement also includes forbearance for the Company’s failure to timely pay the August Deficiency Payment under the Credit Agreement and the failure to timely deliver the quarterly financial statements for the period ended June 30, 2020 and the required accompanying officer’s certificate.

The forbearance period under the Final Lender Forbearance Agreement began on July 15, 2020 and was scheduled to expire on July 29, 2020, unless terminated earlier in accordance with its terms. The scheduled expiration of the forbearance period was later extended to August 9, 2020 and, by mutual agreement between the Company the administrative bank for the credit facility, extended further to August 14, 2020. The Third Amendment resulted in an final extension of the forbearance period to August 17, 2020.

Required Termination of Hedges and Partial Paydown of Credit Agreement. The Final Lender Forbearance Agreement required the Company to terminate all of its outstanding commodity hedges or before July 31, 2020 and to apply a certain portion of the proceeds thereof toward partial repayment of the outstanding amount under the Credit Agreement. To comply with this requirement, the Company unwound all of its hedge positions, resulting in total proceeds of $28.2 million (taking into account previously-settled hedge positions). Of this amount, $24.0 million was applied toward repayment on outstanding credit facility borrowings and the remainder was retained by the Company.

Noteholder Forbearance Agreement. Effective as of July 30, 2020, to address the Company’s expected cross-default under the Indenture resulting from the failure to timely pay the August Deficiency Payment under the Credit Agreement, the Company and the holders of at least 75% of the principal amount of outstanding Senior Notes (the “Initial Consenting Noteholders”) entered into a Forbearance and Waiver Agreement (the “Noteholder Forbearance Agreement”). The forbearance period under the Noteholder Forbearance Agreement began on July 30, 2020 and was scheduled to expire on August 14, 2020.

Pursuant to the Noteholder Forbearance Agreement, the Initial Consenting Noteholders agreed, during the forbearance period, to forbear from exercising certain remedies under the Indenture (including acceleration) for any default or event of default resulting from any failure by the Company to pay the August Deficiency Payment under the Credit Agreement on or before August 3, 2020.

On August 14, 2020, the Company and the Initial Consenting Noteholders amended and restated the Noteholder Forbearance Agreement (such amendment and restatement, the “Amended and Restated Noteholder Forbearance Agreement”). Pursuant to the Amended and Restated Noteholder Forbearance Agreement, the Initial Consenting Noteholders agreed to extend the forbearance period to August 17, 2020 and to additionally forbear from exercising certain remedies under the Indenture (including acceleration) for any default or event of default resulting from any failure by the Company to make the required interest payment of $13.125 million within the 30-day grace period described above.

Impact of Impending Expiration of Forbearance Periods. Both the Final Lender Forbearance Agreement and the Amended and Restated Noteholder Forbearance Agreement are scheduled to expire on August 17, 2020. Therefore, before either of those forbearance agreements expired, the Company was effectively required to either (i) make a voluntary bankruptcy filing to take advantage of the automatic stay under Chapter 11 or (ii) make both the $12.5 million August Deficiency Payment and the $13.125 million Past Due Interest Payment.

Restructuring Support Agreement and the Chapter 11 Cases. On August 15, 2020, we entered into a restructuring support agreement (the “RSA”) with (i) the lenders under our Credit Agreement and (ii) certain holders of our Senior Notes (the “Restructuring Support Parties”). Pursuant to the RSA, the Restructuring Support Parties agreed, subject to the terms and conditions of the RSA, to vote to accept our prepackaged Joint Chapter 11 Plan of Reorganization (as proposed, our “Plan of Reorganization”). Our Plan of Reorganization and the related disclosure statement (the “Disclosure Statement”) were each filed with the Bankruptcy Court on August 16, 2020. For more information on the RSA, see “Note 11: Subsequent events” in “Item 1: Financial Information” of this Quarterly Report on Form 10-Q.

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The commencement of a voluntary proceeding in bankruptcy through our filing of the Chapter 11 Cases constitutes an immediate event of default under the Credit Agreement and the Senior Notes, resulting in immediate acceleration of outstanding amounts under these debt instruments. Any efforts to enforce payment obligations related to the Company’s debt, including the acceleration thereof, have been automatically stayed as a result of the Chapter 11 Cases, and the creditors’ rights of enforcement are subject to the applicable provisions of the Bankruptcy Code. Furthermore, the filing of the Chapter 11 Cases caused the immediate termination of the Final Lender Forbearance Agreement and the Amended and Restated Noteholder Forbearance Agreement.

To maintain and continue uninterrupted ordinary course operations during the bankruptcy proceedings, the we filed a variety of “first day” motions seeking approval from the Bankruptcy Court for various forms of customary relief designed to minimize the effect of bankruptcy on our operations, customers and employees. Upon entry by the Bankruptcy Court of the orders approving all requested “first day” relief, we will be able to conduct normal business activities and pay all associated obligations for the period following our bankruptcy filing and (subject to caps applicable to payments of certain pre-petition obligations) pre-petition employee wages and benefits, pre-petition amounts owed to certain lienholders and vendors, royalty interest and working interest holders, and partners. During the pendency of the Chapter 11 Cases, all transactions outside the ordinary course of our business require the prior approval of the Bankruptcy Court.

Ability to Continue as a Going Concern

The Company projects that it will not have sufficient cash on hand or available liquidity to repay all debt that was accelerated through the filing of the Chapter 11 Cases. These conditions along with the significant risks and uncertainties related to the Company’s liquidity and the Chapter 11 Cases raise substantial doubt about the Company’s ability to continue as a going concern.

Exit Facility

Pursuant to the RSA, on the effective date of our Plan of Reorganization, the remaining borrowings under the Credit Agreement will constitute outstanding amounts under a $300,000 exit credit facility (the “Exit Facility”). The Exit Facility will include (A) second out term loans (the “Second Out Term Loans”) in an amount to be determined, which will have a maturity date that is one year and 91 days following the Revolving Maturity Date (defined below) and (B) a revolving facility (the maturity date of which will be the earlier of May 31, 2024 or 40 months after emergence (the “Revolving Maturity Date”)) that has an initial borrowing base equal to (i) the lesser of (a) $175,000 or (b) the Company’s proved developed producing reserves on a PV-15 basis, plus hedges, on 6-month roll-forward basis minus (ii) the aggregate amount of the Second Out Term Loans. There must be a minimum of $20,000 of availability under the Exit Facility at emergence.

Indebtedness

Debt consists of the following as of the dates indicated:

(in thousands)	June 30, 2020		December 31, 2019
8.75% Senior Notes due 2023	$	300,000	$	300,000
Credit facility	225,000		130,000
Financing lease obligations	1,442		1,653
Installment note payable	—		371
Unamortized issuance costs	(4,154)		(10,038)
Total debt, net	$	522,288	$	421,986

Finance leases

We currently have financing leases that consist of fleet trucks and office equipment. Please see “Note 17: Leases” in “Item 8. Financial Statements and Supplementary Data” of our Annual Report on Form 10-K for the year ended December 31, 2019, for a discussion of these leases.

Sources and uses of cash

Our net change in cash is summarized as follows:

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	Six months ended June 30,
(in thousands)	2020		2019
Cash flows (used in) provided by operating activities	$	(9,419)	$	58,105
Cash flows used in investing activities	(51,403)		(144,924)
Cash flows provided by financing activities	94,364		82,021
Net increase (decrease) in cash during the period	$	33,542	$	(4,798)

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 six months ended June 30, 2020, which was an outflow of $9.4 million, decreased compared to the prior year period primarily due to a reduction in gross revenues, liability management expenses that we incurred and working capital changes. These cash flow decreases were partially offset by lower lease operating expenses and production taxes.

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. During 2020, we relied on borrowings from our credit facility, derivative receipts and cash on hand to fund our capital expenditures.

Our actual costs incurred, including costs that we have accrued for during the six months ended June 30, 2020, are summarized in the table below.

(in thousands)	Six months ended June 30, 2020
Acquisitions (1)	$	11,080
Drilling (2)	42,750
Enhancements	4,069
Operational capital expenditures incurred	57,899
Other (3)	6,952
Total capital expenditures incurred	$	64,851

 ______________________________________________________

(1)Includes $8.8 million recorded to unproved leasehold related to the drilling commitment obligation discussed above under “Contractual obligations.”

(2)Includes $0.7 million on development of wells operated by others.

(3)For the six months ended June 30, 2020, this amount includes $2.9 million for capitalized general and administrative expenses, and $3.9 million for capitalized interest.

Net cash used in investing activities during the six months ended June 30, 2020 consisted of cash outflows for capital expenditure of $86.9 million partially offset by receipts for derivative settlements of $32.1 million and proceeds from asset sales of $3.4 million. Our cash outflows for capital expenditure are greater than our actual costs incurred for the period, disclosed in the table above, as a result of payments in the current period for expenditures accrued at the end of the prior year. Our asset sale proceeds primarily consisted of proceeds from equipment, vehicles and real estate previously classified as held-for-sale on our balance sheet. Net cash used in investing activities during the six months ended June 30, 2019 consisted of cash outflows for capital expenditure of $146.4 million partially offset by receipts for derivative settlements of $0.7 million and proceeds from asset sales of $0.9 million.

Net cash from financing activities during the six months ended June 30, 2020, consisted of borrowings on our credit facility of $120.0 million partially offset by cash outflows of $25.5 million for repayment of debt, including financing leases, and $0.1 million for debt financing fees. Net cash from financing activities during the six months ended June 30, 2019, consisted of borrowings on our credit facility of $85.0 million partially offset by cash outflows for repayment of debt and financing leases of $1.8 million and for treasury stock repurchases of $1.2 million.

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 and our financing leases consist of leases on our fleet vehicles and office equipment. We have a well drilling commitment under the terms of leasehold purchase agreements which we entered into in 2017. The drilling commitment requires the Company to drill and complete 10 wells on such leasehold in each of 2019, 2020, and 2021 and 15 wells in 2022. To the extent the

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Company does not drill and complete the minimum number of wells in a given year, it is required to pay the sellers of the acreage $250,000 for each deficient well. The Company has paid the deficiency amount related to its 2019 drilling commitment and recorded accruals of $2.5 million in March 2020 and $6.3 million in June 2020 for the remaining obligation as it does not intend to drill any further wells on the subject acreage.

Surety bonds totaling $2.1 million were posted on our behalf as of March 31, 2020. We pay premiums for such bonds and, under normal circumstances, are not required to post collateral of any kind to support their issuance. However, as a result of the current extraordinary macroeconomic situation and the Borrowing Base Deficiency discussed above, we have been required to post cash collateral in respect of the bonds totaling $1.0 million as of June 30, 2020.

Other than additional borrowings under our credit facility and the Borrowing Base Deficiency described in “Note 4: Debt” in “Item 1: Financial Information” of this Quarterly Report on Form 10-Q and the termination of our derivative contracts in July 2020, we have not had material changes to our contractual commitments since December 31, 2019.

Results of operations

Highlights

Our financial and operating performance in the second quarter of 2020 includes the following highlights and comparisons to the prior year quarter:

•We generated a net loss for the three months ended June 30, 2020, of $438.7 million. Included in our loss was a ceiling impairment of $384.6 million.

•Our loss on commodity derivatives for the three months ended June 30, 2020, of $13.0 million was attributable to $35.9 million of noncash mark-to-market losses partially offset by $22.9 million in realized settlement gains.

•Our net sales volume decreased 34% to 1,689 MBoe for the three months ended June 30, 2020, compared to the prior year quarter as we curtailed capital development and shut-in wells for a portion of the quarter in response to low commodity prices.

•We lowered our lease operating expense by 55% to $6.0 million for the three months ended June 30, 2020, compared to the prior year quarter. The corresponding change on a per Boe basis was a decrease of 32% to $3.58/Boe.

•We incurred liability management expenses of $8.0 million from our activities to restructure our debt and in preparation for our Chapter 11 Case.

•Our oil and natural gas capital expenditures for the six months ended June 30, 2020, were $64.9 million, with $42.8 million incurred for drilling and completions and $11.1 million on acquisitions. Our capital activity during the first half of the year included completing and bringing online 15 wells, of which nine were drilled in the current year and six in the prior year. We also drilled three wells scheduled to be completed subsequent to quarter end.

•As a result of the defaults on our Senior Notes and Credit Agreement, we classified the entire outstanding amounts on those facilities as current liabilities on our condensed consolidated balance sheet.

Sales

Sales volumes by area were as follows (MBoe)

	Three months ended June 30,		Increase/	Percent
	2020	2019	(Decrease)	Change
Focus Areas:
Kingfisher County	462	646	(184)	(28.5)	%
Canadian County	732	1,125	(393)	(34.9)	%
Garfield County	169	343	(174)	(50.7)	%
Other	18	51	(33)	(64.7)	%
Total Focus Areas	1,381	2,165	(784)	(36.2)	%
Other	308	409	(101)	(24.7)	%
Total	1,689	2,574	(885)	(34.4)	%

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	Six months ended June 30,		Increase/	Percent
	2020	2019	(Decrease)	Change
Focus Areas:
Kingfisher County	1,212	1,251	(39)	(3.1)	%
Canadian County	2,114	1,601	513	32.0	%
Garfield County	405	639	(234)	(36.6)	%
Other	54	108	(54)	(50.0)	%
Total Focus Areas	3,785	3,599	186	5.2	%
Other	697	849	(152)	(17.9)	%
Total	4,482	4,448	34	0.8	%

For the three months ended June 30, 2020, our total net sales decreased compared to the prior year quarter. The decreases were primarily due to our shut in of wells for a portion of the quarter as a result the low pricing environment, our suspension of capital development in late April 2020, and natural decline. The previously mentioned measures were taken as a response to the drastic commodity price declines we have experienced recently as a result of COVID-19. For the six months ended June 30, 2020, our total sales was approximately flat compared to the prior year period as the sales decline in the second quarter discussed above was offset by sales increases primarily due to 38 operated wells that were brought online since the second quarter of 2019.

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.

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

	Three months ended June 30,				Increase/		Percent
	2020		2019		(Decrease)		Change
Commodity sales (in thousands):
Oil	$	10,384	$	50,990	$	(40,606)	(79.6)		%
Natural gas	5,679		10,476		(4,797)		(45.8)		%
Natural gas liquids	3,903		11,025		(7,122)		(64.6)		%
Gross commodity sales	$	19,966	$	72,491	$	(52,525)	(72.5)		%
Transportation and processing	(4,086)		(5,784)		1,698		(29.4)		%
Net commodity sales	$	15,880	$	66,707	$	(50,827)	(76.2)		%
Production:
Oil (MBbls)	453		873		(420)		(48.1)		%
Natural gas (MMcf)	4,621		5,715		(1,094)		(19.1)		%
Natural gas liquids (MBbls)	466		749		(283)		(37.8)		%
MBoe	1,689		2,574		(885)		(34.4)		%
Average daily production (Boe/d)	18,562		28,286		(9,724)		(34.4)		%
Average sales prices (excluding derivative settlements):
Oil per Bbl	$	22.92	$	58.41	$	(35.49)	(60.8)		%
Natural gas per Mcf	$	1.23	$	1.83	$	(0.60)	(32.8)		%
NGLs per Bbl	$	8.38	$	14.72	$	(6.34)	(43.1)		%
Transportation and processing per Boe	$	(2.42)	$	(2.25)	$	(0.17)	7.6		%
Average sales price per Boe	$	9.40	$	25.92	$	(16.52)	$	(0.64)

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	Six months ended June 30,				Increase/		Percent
	2020		2019		(Decrease)		Change
Commodity sales (in thousands):
Oil	$	47,410	$	83,792	$	(36,382)	(43.4)	%
Natural gas	14,334		21,682		(7,348)		(33.9)	%
Natural gas liquids	13,585		20,242		(6,657)		(32.9)	%
Gross commodity sales	$	75,329	$	125,716	$	(50,387)	(40.1)	%
Transportation and processing	(10,598)		(10,390)		(208)		2.0	%
Net commodity sales	$	64,731	$	115,326	$	(50,595)	(43.9)	%
Production:
Oil (MBbls)	1,293		1,491		(198)		(13.3)	%
Natural gas (MMcf)	11,071		10,189		882		8.7	%
Natural gas liquids (MBbls)	1,344		1,259		85		6.8	%
MBoe	4,482		4,448		34		0.8	%
Average daily production (Boe/d)	24,627		24,576		51		0.2	%
Average sales prices (excluding derivative settlements):
Oil per Bbl	$	36.67	$	56.20	$	(19.53)	(34.8)	%
Natural gas per Mcf	$	1.29	$	2.13	$	(0.84)	(39.4)	%
NGLs per Bbl	$	10.11	$	16.08	$	(5.97)	(37.1)	%
Transportation and processing per Boe	$	(2.36)	$	(2.34)	$	(0.02)	0.9	%
Average sales price per Boe	$	14.44	$	25.93	$	(11.49)	(44.3)	%

Our gross commodity sales (excluding transportation and processing deductions) decreased for the three months ended June 30, 2020, compared to the prior year quarter due to volume and price decreases across all commodities. Our commodity sales for the six months ended June 30, 2020, decreased compared to the prior year period due to price decreases across all commodities and a decrease in crude oil volumes partially offset by volume increases for natural gas and NGLs. The table below discloses the impact of price and production volume changes on our revenues.

	Three months ended June 30, 2020 vs. 2019				Six months ended June 30, 2020 vs. 2019
(in thousands)	Sales change		Percentage change in sales		Sales change		Percentage change in sales
Change in oil sales due to:
Prices	$	(16,074)	(31.5)	%	$	(25,254)	(30.1)	%
Volume	(24,532)		(48.0)	%	(11,128)		(13.3)	%
Total change in oil sales	$	(40,606)	(79.6)	%	$	(36,382)	(43.4)	%
Change in natural gas sales due to:
Prices	$	(2,795)	(26.7)	%	$	(9,227)	(42.6)	%
Volume	(2,002)		(19.1)	%	1,879		8.7	%
Total change in natural gas sales	$	(4,797)	(45.8)	%	$	(7,348)	(33.9)	%
Change in natural gas liquids sales due to:
Prices	$	(2,956)	(26.9)	%	$	(8,024)	(39.6)	%
Volume	(4,166)		(37.8)	%	1,367		6.8	%
Total change in natural gas liquids sales	$	(7,122)	(64.6)	%	$	(6,657)	(32.9)	%

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 for the three months ended June 30, 2020, were lower than the prior year quarter due primarily to decreases in natural gas and natural gas liquids volumes sold. Transportation and processing deductions for the six months ended June 30, 2020,

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were relatively flat compared to the prior year quarter due primarily to natural gas and natural gas liquids volumes remaining relatively flat over the two periods.

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.

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 June 30,						Six months ended June 30,
	2020			2019			2020			2019
Oil (per Bbl):
Before derivative settlements	$	22.92		$	58.41		$	36.67		$	56.20
After derivative settlements	$	63.55		$	56.13		$	54.12		$	55.54
Post-settlement to pre-settlement price	277.3		%	96.1		%	147.6		%	98.8		%
Natural gas liquids (per Bbl):
Before derivative settlements	$	8.38		$	14.72		$	10.11		$	16.08
After derivative settlements	$	13.73		$	16.08		$	14.44		$	17.33
Post-settlement to pre-settlement price	163.8		%	109.2		%	142.8		%	107.8		%
Natural gas (per Mcf):
Before derivative settlements	$	1.23		$	1.83		$	1.29		$	2.13
After derivative settlements	$	1.67		$	2.03		$	1.63		$	2.13
Post-settlement to pre-settlement price	135.8		%	110.9		%	126.4		%	100.0		%

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)	June 30, 2020		December 31, 2019
Derivative assets (liabilities):
Crude oil derivatives	$	15,399	$	(21,805)
Natural gas derivatives	1,788		3,551
NGL derivatives	—		2,169
Net derivative assets (liabilities)	$	17,187	$	(16,085)

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Our derivative portfolio, which was in a net liability position at the end of 2019, reverted to a net asset of $17.2 million as of June 30, 2020. The change, which also corresponds to the non-cash fair value adjustment gain of $33.3 million in the table below, is primarily due to the steep decline in crude oil forward prices brought on by the COVID-19 pandemic.

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

	Three months ended June 30,
	2020				2019
(in thousands)	Non-cash fair value adjustment		Settlements (paid) received		Non-cash fair value adjustment		Settlements (paid) received
Derivative gains (losses):
Crude oil derivatives	$	(30,036)	$	18,405	$	11,466	$	(1,991)
Natural gas derivatives	(2,468)		2,017		4,889		1,113
NGL derivatives	(3,430)		2,493		1,241		1,016
Derivative gains (losses)	$	(35,934)	$	22,915	$	17,596	$	138
	Six months ended June 30,
	2020				2019
(in thousands)	Non-cash fair value adjustment		Settlements (paid) received		Non-cash fair value adjustment		Settlements (paid) received
Derivative gains (losses):
Crude oil derivatives	$	37,204	$	22,561	$	(37,203)	$	(980)
Natural gas derivatives	(1,763)		3,705		4,750		52
NGL derivatives	(2,169)		5,823		(1,482)		1,581
Derivative gains (losses)	$	33,272	$	32,089	$	(33,935)	$	653

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 gains (losses)” in our consolidated statements of operations. The fluctuation in derivative gains (losses) 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.

Pursuant to the requirements of the Lender Forbearance Agreement, on July 27, 2020, the Company terminated all its outstanding derivative contracts. Proceeds from the early termination along with amounts owed to the Company from previously settled positions totaled $28.2 million.

Lease operating expenses

	Three months ended June 30,				Increase/		Percent
(in thousands, except per Boe data)	2020		2019		(Decrease)		Change
Lease operating expenses:
Focus Areas	$	3,082	$	8,445	$	(5,363)	(63.5)	%
Other	2,889		4,926		(2,037)		(41.4)	%
Total lease operating expenses	$	5,971	$	13,371	$	(7,400)	(55.3)	%
Lease operating expenses per Boe:
Focus Areas	$	2.23	$	3.90	$	(1.67)	(42.8)	%
Other	$	9.38	$	12.04	$	(2.66)	(22.1)	%
Lease operating expenses per Boe	$	3.54	$	5.19	$	(1.65)	(31.8)	%

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	Six months ended June 30,				Increase/		Percent
(in thousands, except per Boe data)	2020		2019		(Decrease)		Change
Lease operating expenses:
Focus Areas	$	8,691	$	15,559	$	(6,868)	(44.1)	%
Other	7,368		10,106		(2,738)		(27.1)	%
Total lease operating expenses	$	16,059	$	25,665	$	(9,606)	(37.4)	%
Lease operating expenses per Boe:
Focus Areas	$	2.30	$	4.32	$	(2.02)	(46.8)	%
Other	$	10.57	$	11.90	$	(1.33)	(11.2)	%
Lease operating expenses per Boe	$	3.58	$	5.77	$	(2.19)	(38.0)	%

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 June 30, 2020 was lower on a total dollar basis and on a per Boe basis compared to the prior year quarter. The quarter over quarter decline in total LOE was primarily due to a decrease in water hauling costs and reduced costs for well maintenance. Our reduced well maintenance costs were primarily attributable to our shut-ins of wells as part of our response to low commodity pricing. In addition to these factors, LOE on a per Boe basis was also lower because of increased production in areas with lower per Boe costs. LOE for the six months ended June 30, 2020 was lower on a total dollar basis and on a per Boe basis due to the same factors described above.

Production taxes (which include severance and ad valorem taxes)

	Three months ended June 30,						Increase/		Percent
	2020			2019			(Decrease)		Change
Production taxes (in thousands)	$	823		$	3,802		$	(2,979)	(78.4)	%
Production taxes per Boe	$	0.49		$	1.48		$	(0.99)	(66.9)	%
Production taxes as % of commodity sales	4.1		%	5.2		%
	Six months ended June 30,						Increase/		Percent
	2020			2019			(Decrease)		Change
Production taxes (in thousands)	$	3,573		$	6,682		$	(3,109)	(46.5)	%
Production taxes per Boe	$	0.80		$	1.50		$	(0.70)	(46.7)	%
Production taxes as % of commodity sales	4.7		%	5.3		%

Production taxes for the three months and six months ended June 30, 2020 were lower than the prior year periods due to a decrease in commodity revenues driven by volume and price declines as discussed above. The corresponding decreases on a per Boe basis were primarily a result of lower commodity prices and a greater percentage of revenues being derived from gas volumes, which yield a lower revenue per Boe compared to crude oil and NGLs.

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

	Three months ended June 30,				Increase/		Percent
	2020		2019		(Decrease)		Change
DD&A (in thousands):
Oil and natural gas properties (1)	$	14,388	$	28,488	$	(14,100)	(49.5)	%
Property and equipment	433		1,794		(1,361)		(75.9)	%
Total DD&A	$	14,821	$	30,282	$	(15,461)	(51.1)	%
DD&A per Boe:
Oil and natural gas properties (1)	$	8.52	$	11.07	$	(2.55)	(23.0)	%
Other fixed assets	0.25		0.69		(0.44)		(63.8)	%
Total DD&A per Boe	$	8.77	$	11.76	$	(2.99)	(25.4)	%

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	Six months ended June 30,				Increase/		Percent
	2020		2019		(Decrease)		Change
DD&A (in thousands):
Oil and natural gas properties (1)	$	36,963	$	50,369	$	(13,406)	(26.6)	%
Property and equipment	870		3,628		(2,758)		(76.0)	%
Total DD&A	$	37,833	$	53,997	$	(16,164)	(29.9)	%
DD&A per Boe:
Oil and natural gas properties (1)	$	8.25	$	11.32	$	(3.07)	(27.1)	%
Other fixed assets	0.19		0.82		(0.63)		(76.8)	%
Total DD&A per Boe	$	8.44	$	12.14	$	(3.70)	(30.5)	%

_________________________________________

(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 six months ended June 30, 2020 decreased compared to the prior year periods due to lower production and a lower DD&A rate. The DD&A rate declined due to prior ceiling test write-offs, which lowered the full cost amortization base, and a reduction in future development costs as certain undeveloped reserves have been dropped from the amortization base as a result of being uneconomic in the current price environment.

General and administrative expenses (“G&A”)

	Three months ended June 30,				Increase/		Percent
(in thousands)	2020		2019		(Decrease)		Change
G&A:
Gross G&A expenses	$	10,187	$	9,836	$	351	3.6	%
Capitalized exploration and development costs	(699)		(2,521)		1,822		(72.3)	%
Net G&A expenses	9,488		7,315		2,173		29.7	%
Net G&A expense per Boe	$	5.62	$	2.84	$	2.78	97.9	%

	Six months ended June 30,				Increase/		Percent
(in thousands)	2020		2019		(Decrease)		Change
G&A:
Gross G&A expenses	$	20,480	$	20,871	$	(391)	(1.9)	%
Capitalized exploration and development costs	(2,924)		(5,243)		2,319		(44.2)	%
Net G&A expenses	17,556		15,628		1,928		12.3	%
Net G&A expense per Boe	$	3.92	$	3.51	$	0.41	11.7	%

Net G&A for the three months ended June 30, 2020, increased from the prior year quarter primarily due to credit losses, severance for terminated employees, sales tax interest and penalties, partially offset by a decrease in payroll and benefits and stock compensation expense. Payroll and benefits were lower as a result of a reduction in headcount. Stock compensation expense was lower because our executive stock grants awarded prior to August 2019 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. In addition, stock compensation expense was also lower due to recent forfeitures. Our credit losses were recorded as we increased our allowance for uncollectible receivables pursuant to new accounting guidance that requires us to forecast uncollectible amounts under an “expected loss” model as well as in consideration of current industry conditions that have been adversely impacted by COVID-19. We incurred interest and penalties due to a nonpayment of sales tax in connection with the divestiture of our enhanced oil recovery business in 2017.

Net G&A for the six months ended June 30, 2020, increased from the prior year period due to the same factors discussed above.

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Capitalized G&A for the three and six months ended June 30, 2020, was lower than the prior year periods as we reduced our capitalization rates to reflect our reduction of capital activity in response to the current price environment.

The table below discloses amounts related to the items discussed above.

	Three months ended June 30,				Six months ended June 30,
(in thousands)	2020		2019		2020		2019
Employee severance costs	$	901	$	—	$	1,634	$	1,058
Stock compensation, gross	108		1,228		768		2,647
Sales tax interest and penalties	777		—		777		—
Credit losses on receivables	1,447		(18)		2,964		(276)
	$	3,233	$	1,210	$	6,143	$	3,429

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 portion of our expected production when permitted, 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.

	Three months ended June 30,				Six months ended June 30,
(in thousands)	2020		2019		2020		2019
Ceiling impairment	$	384,639	$	63,593	$	456,010	$	113,315

We recorded a ceiling test impairment on our oil and natural gas properties for the three months ended June 30, 2020, due to a write-off of the value of non-producing acreage in Garfield and Kingfisher counties, in Oklahoma, and a decrease in the prices of all commodities used to estimate our reserves. Our ceiling test impairment for the six months ended June 30, 2020, was driven largely by the same factors.

The commodity prices used to estimate our reserves are as follows:

Benchmark prices utilized in ceiling test	June 30, 2020		March 31, 2020		December 31, 2019
Oil (per Bbl)	$	47.17	$	55.77	$	55.69
Natural gas (per MMBtu)	$	2.07	$	2.30	$	2.58
Natural gas liquids (per Bbl)	$	11.29	$	14.97	$	16.21

As discussed above, our ceiling test impairment during the second quarter of 2020 was impacted by the write-off of the value of non-producing acreage in Garfield and Kingfisher counties, Oklahoma, that we no longer intend to develop as a result of poor drilling economics based on our outlook on long term commodity pricing and historical well performance. Impairments of leasehold result in a transfer of amounts from unevaluated oil and natural gas properties to the full cost amortization base subsequently impacting the ceiling test. During the three and six month periods ending June 30, 2020, impairments of non-producing leasehold, which include expirations, were $216.2 million and $218.7 million, respectively.

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The precipitous crude oil price decline caused by COVD-19 has resulted in a first of the month price in April and May 2020 of $20.31/Bbl and $19.78/Bbl, respectively with a modest recovery to $40.83/Bbl in August 2020. If commodity prices remain at their current level, decline, or do not recover to a level above $47.00/Bbl, we expect the trailing 12-month average price to decline as 2020 progresses and we believe that it is probable that we would record further ceiling test impairment losses in 2020. 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 and going concern” in “Item 1. Financial Statements” of this report for further discussion of our ceiling test.

Income taxes

We did not record any net deferred tax benefit for the three and six months ended June 30, 2020, 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, 2019, which contains additional information about our income taxes.

As a result of the Prior Reorganization Plan and related transactions, upon emergence from bankruptcy, we experienced an ownership change within the meaning of Internal Revenue Code (“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 net operating losses (“NOLs”) generated prior to the ownership change would be limited, possibly substantially. See “Note 1: Nature of operations and summary of significant accounting policies and going concern” 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 June 30,				Six months ended June 30,
(in thousands)	2020		2019		2020		2019
Credit facility	$	2,224	$	838	$	3,613	$	988
Senior Notes	6,562		6,562		13,125		13,125
Bank fees, other interest and amortization of issuance costs	843		1,292		1,845		2,635
Interest expense, gross	9,629		8,692		18,583		16,748
Capitalized interest	(1,582)		(3,121)		(3,900)		(6,613)
Total interest expense	$	8,047	$	5,571	$	14,683	$	10,135
Average borrowings	$	539,012	$	391,405	$	492,926	$	362,557

Interest expense for the three and six months ended June 30, 2020, was higher than the prior year quarter due to both an increase in gross interest expense as well as a reduction in capitalized interest. Gross interest was higher due to increased borrowings on our credit facility as reflected in the average borrowings disclosed in the table above. 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 June 30, 2020, was lower than the prior year period due to a lower average carrying balance on unevaluated non-producing leasehold, for which a large portion was written off recently.

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 resulting from the Prior Chapter 11 Cases and Prior Reorganization Plan. The reorganization items disclosed in our consolidated statement of operations consist of professional fees for continuing legal work to resolve outstanding claims and fees to the U.S. Bankruptcy Trustee, which we will continue to incur until both the Prior Chapter 11 Cases and the Chapter 11 Cases are closed.

Liability management expenses. Liability management expense includes third party legal and professional service fees incurred from our activities to restructure our debt and in preparation for our Chapter 11 Cases.

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Litigation loss. The expense consists of our estimate of the settlement costs for the Naylor Farms Case as discussed (and defined) in “Note 10: Commitments and Contingencies” in “Item 1. Financial Statements” of this report.

Subleases expenses. The expense consisted of our expense on operating leases for CO₂ compressors that we subleased to another operator. Both originating leases and subleases were terminated during the third quarter of 2019.

Write off Senior Note issuance costs. Our filing of the Chapter 11 Cases triggered an event of default on our Senior Notes. The event of default effectively allows the lender to demand immediate repayment, thus shortening the life of our Senior Notes to the current period. As a result, we wrote off the remaining balance of unamortized issuance costs.

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 generally accepted accounting principles (“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, some or all of 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 June 30,				Six months ended June 30,
(in thousands)	2020		2019		2020		2019
Net loss	(438,726)		(45,229)		$	(433,809)	$	(148,769)
Interest expense	8,047		5,571		14,683		10,135
Depreciation, depletion, and amortization	14,821		30,282		37,833		53,997
Non-cash change in fair value of derivative instruments	35,934		(17,596)		(33,272)		33,935
Impact of derivative repricing	702		—		1,404		—
Interest income	—		(2)		—		(2)
Stock-based compensation expense	90		852		496		1,654
Loss (gain) on sale of assets	261		(491)		159		(490)
Loss on impairment of oil and gas assets	384,639		63,593		456,010		113,315
Loss on impairment of other assets	310		6,407		463		6,407
Credit loss on uncollectible receivables	1,447		(18)		2,964		(276)
Write-off of Senior Note issuance costs	4,420		—		4,420		—
Restructuring, reorganization and other	1,337		313		2,654		1,833
Adjusted EBITDA	$	13,282	$	43,682	$	54,005	$	71,739

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

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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)	June 30, 2020		December 31, 2019
Current assets per GAAP	$	116,806	$	80,390
Plus—Availability under Credit Agreement	—		194,406
Less—Short term derivative instruments	(15,197)		(947)
Current assets as adjusted	$	101,609	$	273,849
Current liabilities per GAAP	588,165		122,669
Less—Current derivative instruments	—		(11,957)
Less—Current operating lease obligation	(1,331)		(1,259)
Less—Current asset retirement obligation	(2,107)		(2,083)
Less—Current maturities of long term debt	(521,292)		(594)
Current liabilities as adjusted	$	63,435	$	106,776
Current ratio per GAAP	0.20		0.66
Current ratio for loan compliance	1.60		2.56

Off-Balance Sheet Arrangements

At June 30, 2020, 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, 2019.

Also see the footnote disclosures included in “Note 1: Nature of operations and summary of significant accounting policies and going concern” 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 and going concern” 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. 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 six months ended June 30, 2020, our gross revenues from oil and natural gas sales would change approximately $2.6 million for each $1.00 change in oil and natural gas liquid prices and $1.1 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

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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. See our discussion in “Results of operations” above regarding the termination of all our derivative positions in July 2020.

The fair value of our outstanding derivative instruments at June 30, 2020 was a net asset of $17.2 million. Based on our outstanding derivative instruments as of June 30, 2020, summarized below, a 10% increase in the June 30, 2020, forward curves used to mark-to-market our derivative instruments would have decreased our net asset position to $9.9 million, while a 10% decrease would have increased our net asset position to $24.5 million.

Our outstanding oil derivative instruments as of June 30, 2020, are summarized below:

Period and type of contract	Volume MBbls	Weighted average fixed price per Bbl
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 June 30, 2020, are summarized below:

Period and type of contract	Volume BBtu	Weighted average fixed price per MMBtu
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)

As described above in “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Going concern, liquidity and capital resources,” pursuant to the requirements of the Lender Forbearance Agreement, on July 27, 2020, the Company terminated all its outstanding derivative contracts. Proceeds from the early termination along with amounts owed to the Company from previously settled positions totaled $28.2 million.

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Interest rates.  All of the outstanding borrowings under our Credit Agreement as of June 30, 2020 are subject to market rates of interest as determined from time to time by the banks. As of June 30, 2020, 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 3.19% 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 $175.0 million, equal to our borrowing base at June 30, 2020, the cash flow impact for a 12-month period resulting from a 100 basis point change in interest rates would be $1.8 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 June 30, 2020, 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 12, 2020, 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 factors discussed below, there have been no material changes to the Risk Factors previously disclosed in our Annual Report for the year ended December 31, 2019.

We are subject to the risks and uncertainties associated with proceedings under Chapter 11 of the Bankruptcy Code.

For the duration of our Chapter 11 Cases, our operations and our ability to develop and execute our business plan, and our continuation as a going concern, are subject to the risks and uncertainties associated with bankruptcy. These risks include the following:

•our ability to execute, confirm and consummate the Plan of Reorganization as contemplated by the RSA with respect to the Chapter 11 Cases;

•the high costs of bankruptcy proceedings and related fees;

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•our ability to obtain sufficient financing to allow us to emerge from bankruptcy and execute our business plan post-emergence;

•our ability to obtain Bankruptcy Court approval with respect to motions filed in the Chapter 11 Cases from time to time;

•our ability to maintain our relationships with our suppliers, service providers, customers, employees, and other third parties;

•our ability to maintain contracts that are critical to our operations;

•our ability to fund and execute our business plan;

•the ability of third parties to seek and obtain Bankruptcy Court approval to terminate contracts and other agreements with us;

•the ability of third parties to seek and obtain Bankruptcy Court approval to terminate or shorten the exclusivity period for us to propose and confirm a Chapter 11 plan, to appoint a Chapter 11 trustee, or to convert the Chapter 11 Cases to proceedings under Chapter 7 of the Bankruptcy Code;

•the actions and decisions of our creditors and other third parties who have interests in our Chapter 11 Cases that may be inconsistent with the RSA or our plans; and

•Delays in our Chapter 11 Cases increase the risks of us being unable to reorganize our business and emerge from bankruptcy and increase our costs associated with the bankruptcy process.

These risks and uncertainties could affect our business and operations in various ways. For example, negative events associated with our Chapter 11 Cases could adversely affect our relationships with our suppliers, service providers, customers, employees, and other third parties, which in turn could adversely affect our operations and financial condition. Also, we need the prior approval of the Bankruptcy Court for transactions outside the ordinary course of business, which may limit our ability to respond timely to certain events or take advantage of certain opportunities. We also need Bankruptcy Court confirmation of the Plan of Reorganization as contemplated by the RSA. Because of the risks and uncertainties associated with our Chapter 11 Cases, we cannot accurately predict or quantify the ultimate impact that events that occur during our Chapter 11 Cases will have on our business, financial condition and results of operations.

Even if our Plan of Reorganization is consummated, we will continue to face a number of risks, including our ability to reduce expenses, implement any strategic initiatives and generally maintain favorable relationships with and secure the confidence of our counterparties. Accordingly, we cannot guarantee that the proposed financial restructuring will achieve our stated goals nor can we give any assurance of our ability to continue as a going concern.

Our shares may have limited or no value under the Chapter 11 Plan of Reorganization.

Our Chapter 11 plan of reorganization provides for limited cash payments to be made and Warrants issued in respect of certain shares of our common stock, as described under “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and capital resources—Restructuring Support Agreement and the Chapter 11 Cases.” Such Warrants will not include Black-Scholes protection or similar protections in the event of a sale, merger or similar transaction prior to exercise; therefore, the occurrence of certain transactions, including certain sales or mergers, likely would negatively impact, and could even eliminate, the value of the Warrants. The Debtors’ investment banker, Intrepid Partners, LLC, has prepared an independent valuation analysis, which is attached to an exhibit to the Disclosure Statement, and estimates the implied plan equity value of the Company at emergence to be $70 million to $160 million, which is below the equity value strike prices described above. Accordingly, trading in our common stock during the pendency of the Chapter 11 Cases is highly speculative and poses substantial risks. Trading prices for our common stock may bear little or no relationship to the actual recovery, if any, by holders of our common stock in the Chapter 11 Cases. We expect that holders of our common stock could experience a significant or complete loss on their investment, depending on the outcome of the Chapter 11 Cases.

Operating under the Bankruptcy Court protection for a long period of time may harm our business.

Our future results are dependent upon the successful confirmation and implementation of a plan of reorganization. A long period of operations under Bankruptcy Court protection could have a material adverse effect on our business, financial condition, results of operations and liquidity. A prolonged period of operating under Bankruptcy Court protection may make it more difficult to retain management and other key personnel necessary to the success and growth of our business. In addition, the longer the proceedings related to the Chapter 11 Cases continue, the more likely it is that our customers and suppliers will lose confidence in our ability to reorganize our businesses successfully and will seek to establish alternative commercial relationships.

Furthermore, so long as the proceedings related to the Chapter 11 Cases continue, we will be required to incur substantial costs for professional fees and other expenses associated with the administration of the Chapter 11 proceedings. Although no such financing has been sought to date, and we do not currently anticipate seeking such financing, the Chapter 11 proceedings may also require us to seek debtor-in-possession financing to fund operations. If we are unable to obtain such financing on favorable terms or at all, our

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chances of successfully reorganizing our business may be seriously jeopardized, the likelihood that we instead will be required to liquidate our assets may be enhanced, and, as a result, our securities could become further devalued or become worthless.

Furthermore, we cannot predict the ultimate amount of all settlement terms for the liabilities that will be subject to a plan of reorganization. Even once a plan of reorganization is approved and implemented, our operating results may be adversely affected by the possible reluctance of prospective lenders and other counterparties to do business with a company that recently emerged from Chapter 11 proceedings.

We may not be able to obtain confirmation of a Chapter 11 Plan of Reorganization.

To emerge successfully from Bankruptcy Court protection as a viable entity, we must meet certain statutory requirements with respect to adequacy of disclosure with respect to a plan of reorganization, solicit and obtain the requisite acceptances of such a plan and fulfill other statutory conditions for confirmation of such a plan, which have not occurred to date. The confirmation process is subject to numerous, unanticipated potential delays, including a delay in the Bankruptcy Court’s commencement of the confirmation hearing regarding our plan.

The terms of a plan of reorganization have been proposed under our RSA, however, there is no assurance a plan of reorganization consistent with the terms set forth in the RSA will be confirmed, or that any plan of reorganization that is confirmed will not have terms materially different from the Plan of Reorganization contemplated in the RSA. We may not receive the requisite acceptances of constituencies in the proceedings related to the Chapter 11 Cases to confirm our Plan of Reorganization. Even if the requisite acceptances of our Plan of Reorganization are received, the Bankruptcy Court, which can exercise substantial discretion, may not confirm our Plan of Reorganization. The precise requirements and evidentiary showing for confirming a plan, notwithstanding its rejection by one or more impaired classes of claims or equity interests, depends upon a number of factors including, without limitation, the status and seniority of the claims or equity interests in the rejecting class (e.g., secured claims or unsecured claims, subordinated or senior claims).

If our Plan of Reorganization is not confirmed by the Bankruptcy Court, it is unclear whether we would be able to reorganize our business and what, if anything, holders of claims against us would ultimately receive with respect to their claims.

We have substantial liquidity needs and may not be able to obtain sufficient liquidity for the duration of the Chapter 11 Cases or to confirm a plan of reorganization or liquidation.

Although we have lowered our capital budget and reduced the scale of our operations significantly, our business remains capital intensive. Our principal sources of liquidity historically have been cash flow from operations and borrowings under our Credit Agreement. If our cash flow from operations remains depressed or decreases as a result of lower commodity prices or otherwise, our ability to expend the capital necessary to replace our proved reserves, maintain our leasehold acreage or maintain current production may be limited, resulting in decreased production and proved reserves over time. In addition to the cash requirements necessary to fund ongoing operations, we have incurred, and expect to continue to incur, significant professional fees and other costs in connection with the Chapter 11 Cases. As of August 14, 2020, our total available liquidity, consisting of cash on hand, was $32.1 million. We expect to continue using additional cash that will further reduce this liquidity.

We believe that we will have sufficient liquidity, including cash on hand and funds generated from ongoing operations, to fund anticipated cash requirements through the Chapter 11 Cases. As such, we expect to pay vendor and royalty obligations on a go-forward basis according to the terms of our current contracts and consistent with applicable court orders, if any, approving such payments. However, our ability to maintain adequate liquidity depends in part upon industry conditions and general economic, financial, competitive, regulatory and other factors beyond our control, and there can be no assurance that our current liquidity will be sufficient to allow us to satisfy our obligations related to the Chapter 11 Cases or to pursue confirmation of our Plan of Reorganization. We can provide no assurance that additional financing would be available or, if available, offered to us on acceptable terms. Our access to additional financing is, and for the foreseeable future will likely continue to be, extremely limited if it is available at all. Our long-term liquidity requirements and the adequacy of our capital resources are difficult to predict at this time.

As a result of the Chapter 11 Cases, our financial results may be volatile and may not reflect historical trends.

During the Chapter 11 Cases, we expect our financial results to continue to be volatile as restructuring activities and expenses, contract terminations and rejections and claims assessments significantly impact our financial results. As a result, our historical financial performance is likely not indicative of financial performance after the date of the bankruptcy filing.

In addition, if we emerge from Chapter 11, the amounts reported in subsequent periods may materially change relative to historical results, including as a result of revisions to our operating plans pursuant to our Plan of Reorganization or any other

55

confirmed Chapter 11 plan of reorganization. We also may be required to adopt fresh start accounting, in which case our assets and liabilities will be recorded at fair value as of the fresh start reporting date, which may differ materially from the recorded values of assets and liabilities prior to seeking bankruptcy protection. Our financial results after the application of fresh start accounting also may be different from historical trends.

We may be subject to claims that will not be discharged in the Chapter 11 Cases, which could have a material adverse effect on our financial condition and results of operations.

The Bankruptcy Code provides that the confirmation of a plan of reorganization discharges a debtor from substantially all debts arising prior to confirmation. With few exceptions, all claims that arose before confirmation of the plan or reorganization (i) would be subject to compromise and/or treatment under the plan or reorganization and/or (ii) would be discharged in accordance with the terms of the plan of reorganization. Any claims not ultimately discharged through the plan of reorganization could be asserted against the reorganized entities and may have an adverse effect on their financial condition and results of operations on a post-reorganization basis.

The pursuit of the Chapter 11 Cases has consumed and will continue to consume a substantial portion of the time and attention of our management, which may have an adverse effect on our business and results of operations, and we may face increased levels of employee attrition.

While the Chapter 11 Cases continue, our management will be required to spend a significant amount of time and effort focusing on the Chapter 11 Cases instead of focusing exclusively on our business operations. This diversion of attention may materially adversely affect the conduct of our business, and, as a result, our financial condition and results of operations, particularly if the Chapter 11 Cases are protracted.

During the duration of the Chapter 11 Cases, our employees will face considerable distraction and uncertainty and we may experience increased levels of employee attrition. A loss of key personnel or material erosion of employee morale could have a material adverse effect on the conduct of our business, thereby adversely affecting our business and results of operations. The failure to retain or attract members of our management team and other key personnel could impair our ability to execute our strategy and implement operational initiatives, thereby having a material adverse effect on our financial condition and results of operations.

In certain instances, a Chapter 11 case may be converted to a case under Chapter 7 of the Bankruptcy Code.

Upon a showing of cause, the Bankruptcy Court may convert our Chapter 11 Cases to cases under Chapter 7 of the Bankruptcy Code. In such event, a Chapter 7 trustee would be appointed or elected to liquidate our assets and the assets of our subsidiaries for distribution in accordance with the priorities established by the Bankruptcy Code. We believe that liquidation under Chapter 7 would result in significantly smaller distributions being made to our creditors than those provided for in a plan of reorganization because of (i) the likelihood that the assets would have to be sold or otherwise disposed of in a distressed fashion over a short period of time rather than in a controlled manner and as a going concern, (ii) additional administrative expenses involved in the appointment of a Chapter 7 trustee, and (iii) additional expenses and claims, some of which would be entitled to priority, that would be generated during the liquidation and from the rejection of leases and other executory contracts in connection with a cessation of operations.

Any plan of reorganization that we may implement will be based in large part upon assumptions and analyses developed by us. If these assumptions and analyses prove to be incorrect, our plan may be unsuccessful in its execution.

Any plan of reorganization that we may implement could affect both our capital structure and the ownership, structure and operation of our business and will reflect assumptions and analyses based on our experience and perception of historical trends, current conditions and expected future developments, as well as other factors that we consider appropriate under the circumstances. In addition, any plan of reorganization will rely upon financial projections, including with respect to revenues, capital expenditures, debt service and cash flow. Financial forecasts are necessarily speculative, and it is likely that one or more of the assumptions and estimates that are the basis of these financial forecasts will not be accurate. Whether actual future results and developments will be consistent with our expectations and assumptions depends on a number of factors, including but not limited to (i) our ability to substantially change our capital structure, (ii) our ability to obtain adequate liquidity and financing sources, (iii) our ability to retain key employees, and (iv) the overall strength and stability of general economic conditions of the financial and oil and gas industries, both in the U.S. and in global markets. The failure of any of these factors could materially adversely affect the successful reorganization of our businesses. Consequently, there can be no assurance that the results or developments contemplated by any plan of reorganization we may implement will occur or, even if they do occur, that they will have the anticipated effects on us and our subsidiaries or our businesses or operations. The failure of any such results or developments to materialize as anticipated could materially adversely affect the successful execution of any plan of reorganization.

56

Even if a Chapter 11 plan of reorganization is consummated, we may not be able to achieve our stated goals or continue as a going concern.

Even if a Chapter 11 plan of reorganization is consummated, we will continue to face a number of risks, including certain risks that are beyond our control, such as further deterioration or other changes in economic conditions, changes in our industry, potential revaluing of our assets due to Chapter 11 proceeding, changes in consumer demand for, and acceptance of, our oil and gas and increasing expenses. Some of these concerns and effects typically become more acute when a case under the Bankruptcy Code continues for a protracted period without indication of how or when the case may be completed. As a result of these risks and others, there is no guaranty that our Plan of Reorganization or any other confirmed Chapter 11 plan of reorganization will achieve our stated goals.

Furthermore, even if our debts are reduced or discharged through our Plan of Reorganization, we may need to raise additional funds through public or private debt or equity financing or other various means to fund our business after the completion of the proceedings related to the Chapter 11 Cases. Our access to additional financing is, and for the foreseeable future will likely continue to be, extremely limited, if it is available at all. Therefore, adequate funds may not be available when needed or may not be available on favorable terms, if they are available at all.

Our ability to continue as a going concern is dependent upon our ability to raise additional capital. As a result, we cannot give any assurance of our ability to continue as a going concern, even if a Chapter 11 plan of reorganization is confirmed.

Transfers of our equity, or issuances of equity in connection with our Chapter 11 Cases, may impair our ability to utilize our federal income tax net operating loss carryforwards in future years.

Under federal income tax law, a corporation is generally permitted to deduct from taxable income net operating losses carried forward from prior years. We have NOLs of approximately $1.3 billion estimated through December 31, 2020. Our ability to utilize our NOLs to offset future taxable income and to reduce federal income tax liability is subject to certain requirements and restrictions. If we experience an “ownership change,” as defined in Section 382 of the U.S. Internal Revenue Code, then our ability to use our net operating loss carryforwards may be substantially limited, which could have a negative impact on our financial position and results of operations. Generally, there is an “ownership change” if one or more shareholders owning five percent or more of a corporation’s common stock ("Substantial Shareholder") have aggregate increases in their ownership of such stock of more than 50 percentage points over the prior three-year period.

Following the implementation of a plan of reorganization, it is possible that an “ownership change” may be deemed to occur. Under Section 382 of the U.S. Internal Revenue Code, absent an application exception, if a corporation undergoes an “ownership change,” the amount of its net operating losses that may be utilized to offset future taxable income generally is subject to an annual limitation. If an ownership change occurs and our NOLs are subject to the Section 382 limitation, this could adversely impact our future cash flows if we have taxable income and are not able to offset it through the utilization of our NOLs.

The RSA is subject to significant conditions and milestones that may be difficult for us to satisfy.

There are certain material conditions we must satisfy under the RSA. These include, but are not limited to, the timely satisfaction of certain milestones in the anticipated Chapter 11 Cases, such as the confirmation and effectiveness of the Plan. Our ability to timely complete such milestones is subject to risks and uncertainties that may be beyond our control.

If the RSA is terminated, our ability to confirm and consummate a Chapter 11 plan of reorganization could be materially and adversely affected.

The RSA contains a number of termination events. The occurrence of any of these termination events would enable certain parties to the RSA to terminate that agreement. Any such termination could result in the loss of support for the Plan by the parties to the RSA, which could adversely affect our ability to confirm and consummate the Plan. If the Plan is not consummated, there can be no assurance that any new plan of reorganization would be as favorable to holders of claims as the current Plan.

The combination of the COVID-19 pandemic and the related significant decline in global oil prices raises substantial doubt about our ability to continue as a going concern within one year.

The rapid, global spread of COVID-19 in the first quarter of 2020 and the resulting economic repercussions created significant volatility in the oil and gas industry. Stay-at-home and similar protective measures that were enacted by federal, foreign, state and local governments to slow the spread of the virus contributed to a significant deterioration in the domestic and global demand for oil and gas. Compounding the impact of COVID-19, the oil production output alliance between Russia, Saudi Arabia and other oil

57

producing nations (“OPEC+”) broke down as both sides were unable to reach agreement in early March 2020 over how much to restrict production in order to stabilize crude oil prices. As a result, Saudi Arabia and Russia both initiated efforts to increase production, driving down oil prices. OPEC+ was later able to agree on approximately 9.7 million barrels of oil per day of production cuts, but that announcement has done little to aid in oil price recovery because of the significant drop in global demand. Even though the price for oil in the commodities futures markets currently reflect some price improvement (although still less than pre-March 2020 prices), the current cash prices have deteriorated significantly. On April 20, 2020, the front-month futures contract for WTI prices dipped into the negative, and as of the time of this filing were less than $45.00 per barrel. The front-month contract is used to calculate our settlement price for crude sales in the current month as well as a price adjustment for the following month. This combination of events has led to an unprecedented supply-demand oil imbalance and has created a great deal of uncertainty in the oil and gas industry as producers make adjustments to their capital and budget strategies in reaction to these changes.

As a result, our cash flow outlook from low pricing has resulted in a situation that raises substantial doubt about our ability to continue as a going concern within one year of the issuance date of the financial statements contained in this quarterly report.

Global oil prices may not return to pre-COVID-19 levels for several months or years, if ever.

There can be no assurance that demand for oil and gas will return to pre-COVID-19 levels or, if it does, that it will return to those levels at any time in the foreseeable future. In addition, even if that demand increases, the significant amount of oil currently in storage, combined with the stated oil price strategy of Saudi Arabia and Russia, could result in the continuation of low commodity prices for a significant period of time. In addition, the COVID-19 pandemic has increased volatility and caused negative pressure in the capital and credit markets. As a result, we do not expect to have access in the current environment to the capital markets or financing on terms we would find favorable, if at all. The continuation of the current price environment for a sustained period would have a significant negative impact on the Company and its operations.

The combination of the COVID-19 pandemic and the related significant decline in global oil prices have significantly hampered the Company’s ability to access the capital markets or obtain financing.

The COVID-19 pandemic and global oil price decline described above has increased volatility and caused negative pressure in the capital and credit markets. As a result, and in light of our debt incurrence restrictions in our existing debt documents, we do not expect to have access in the current environment to the capital markets or financing on terms we would find favorable, if at all.

The actions taken by the Company to address the COVID-19 pandemic and the related significant decline in global oil prices may not have the intended result.

In response to the COVID-19 pandemic and the related significant decline in global oil prices, the Company is taking several proactive steps to address that decline, including, among other things:

•suspending all drilling and stimulation operations in early April 2020 and deferring completions of recently drilled wells;

•shutting-in production that is not associated with waterfloods, or exposed to well specific mechanical or other risks;

•increasing crude storage at our lease locations; and

•significantly increasing our cash balance by making additional borrowings under our credit facility.

There can be no assurance that these steps will be sufficient for us to weather the COVID-19 pandemic until energy commodity prices recover to levels that can sustain our ongoing business and enable us to meet our financial covenants and day-to-day obligations in the long term. These proactive steps may not have the intended result and could cause the Company’s revenues to decline more than any intended cost savings. Furthermore, shutting-in production could result in damage to the wells and/or target formations, and that damage could be permanent.

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

Period	Total number of shares purchased (1)	Average price paid per share	Total number of shares purchased as part of publicly announced plans or programs	Maximum number of shares that may yet be purchased under the plans or programs
April 1 - 30, 2020	32,649	0.35	N/A	N/A
May 1 - 30, 2020	—	—	N/A	N/A
June 1 - 30, 2020	—	—	N/A	N/A
Total	32,649	0.35	N/A	N/A

_________________________

(1)  All shares purchases relate to tax withholding and the payment of taxes in connection with vesting of restricted shares issued under our equity incentive plan.

ITEM 5. OTHER INFORMATION

Not applicable.

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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*	Second Amended and Restated Bylaws of Chaparral Energy, Inc., dated as of December 20, 2019 (Incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K filed on December 27, 2019).
4.1*	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).
4.2*	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).
4.3*	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).
10.1*	Restructuring Support Agreement, dated as of August 15, 2020, by and among Chaparral Energy, Inc., certain of its subsidiaries and the Consenting Creditors (as defined therein) (Incorporated by reference to Exhibit 99.1 to the Company’s Current Report on Form 8-K filed on August 17, 2020).
10.2*	Backstop Purchase Agreement, dated as of August 15, 2020, by and among Chaparral Energy, Inc., certain of its subsidiaries and the Backstop Parties (as defined therein) (Incorporated by reference to Exhibit 99.2 to the Company’s Current Report on Form 8-K filed on August 17, 2020).
10.3*	SVP Letter Agreement, dated as of August 14, 2020, by and among Strategic Value Partners, LLC, certain investment funds directly and indirectly managed by Strategic Value Partners, LLC, and Chaparral Energy, Inc. (Incorporated by reference to Exhibit 99.7 to the Company’s Current Report on Form 8-K filed on August 17, 2020).
10.4*	Forbearance Agreement dated as of July 15, 2020, by and among the Company, the subsidiary guarantors party thereto, certain Lenders identified therein, and Royal Bank of Canada, as Administrative Agent and Issuing Bank (Incorporated by reference to Exhibit 99.1 to the Company’s Current Report on Form 8-K filed on July 15, 2020).
10.5*	First Amendment to Forbearance Agreement dated as of July 24, 2020, by and among the Company, the subsidiary guarantors party thereto, certain Lenders identified therein, Royal Bank of Canada, as Administrative Agent and Issuing Bank, and the hedge counterparties party thereto (Incorporated by reference to Exhibit 99.1 to the Company’s Current Report on Form 8-K filed on July 27, 2020).
10.6*	Second Amendment to Forbearance Agreement dated as of July 29, 2020, by and among the Chaparral Energy, Inc., the subsidiary guarantors party thereto, certain Lenders identified therein, and Royal Bank of Canada, as Administrative Agent and Issuing Bank (Incorporated by reference to Exhibit 99.1 to the Company’s Current Report on Form 8-K filed on July 31, 2020).
10.7*	Third Amendment to Limited Forbearance Agreement dated as of August 14, 2020, by and among the Chaparral Energy, Inc., the subsidiary guarantors party thereto, certain Lenders identified therein, and Royal Bank of Canada, as Administrative Agent and Issuing Bank (Incorporated by reference to Exhibit 99.8 to the Company’s Current Report on Form 8-K filed on August 17, 2020).

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10.8 *	Forbearance and Waiver Agreement dated as of July 30, 2020, by and among Chaparral Energy, Inc., the subsidiary guarantors party thereto, and certain noteholders identified therein (Incorporated by reference to Exhibit 99.2 to the Company’s Current Report on Form 8-K filed on July 31, 2020).
10.9 *	Amended and Restated Forbearance and Waiver Agreement dated as of August 14, 2020, by and among Chaparral Energy, Inc., the subsidiary guarantors party thereto, and certain noteholders identified therein (Incorporated by reference to Exhibit 99.9 to the Company’s Current Report on Form 8-K filed on August 17, 2020).
10.10 †*	Chaparral Energy, Inc. 2020 Key Executive Incentive Plan dated April 24, 2020 (Incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q filed on May 11, 2020).
10.11 †*	Form of Award Notice under Chaparral Energy, Inc. 2020 Key Executive Incentive Plan dated April 24, 2020 (Incorporated by reference to Exhibit 10.2 of the Company’s Quarterly Report on Form 10-Q filed on May 11, 2020).
10.12 †*	Chaparral Energy, Inc. 2020 Key Executive Retention Plan dated April 24, 2020 (Incorporated by reference to Exhibit 10.3 of the Company’s Quarterly Report on Form 10-Q filed on May 11, 2020).
10.13 †*	Form of Award Notice under Chaparral Energy, Inc. 2020 Key Executive Retention Plan dated April 24, 2020 (Incorporated by reference to Exhibit 10.4 of the Company’s Quarterly Report on Form 10-Q filed on May 11, 2020).
10.14 †*	Amendment to the Separation and Release Agreement between the Company, Chaparral Energy, L.L.C. and K. Earl Reynolds dated August 13, 2020 (Incorporated by reference to Exhibit 99.6 to the Company’s Current Report on Form 8-K filed on August 17, 2020).
10.15 †*	Amendment and Release Agreement between the Company, Chaparral Energy, L.L.C. and Scott Pittman dated August 13, 2020 (Incorporated by reference to Exhibit 99.5 to the Company’s Current Report on Form 8-K filed on August 17, 2020).
10.16 †*	Amendment and Release Agreement between the Company, Chaparral Energy, L.L.C. and James M. Miller dated August 13, 2020 (Incorporated by reference to Exhibit 99.3 to the Company’s Current Report on Form 8-K filed on August 17, 2020).
10.17 †*	Amendment and Release Agreement between the Company, Chaparral Energy, L.L.C. and Mark Ver Hoeve dated August 13, 2020 (Incorporated by reference to Exhibit 99.4 to the Company’s Current Report on Form 8-K filed on August 17, 2020).
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.

61

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

62

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/ Charles Duginski
Name:	Charles Duginski
Title:	Chief Executive Officer
	(Principal Executive Officer)
By:	/s/ Stephanie Carnes
Name:	Stephanie Carnes
Title:	Vice President and Controller
	(Principal Financial Officer and Principal Accounting Officer)

Date: August 17, 2020

63

EX-31.1

EXHIBIT 31.1

CERTIFICATION

I, Charles Duginski, Chief Executive Officer of Chaparral Energy, Inc., certify that:

1.I have reviewed this Quarterly Report on Form 10-Q of Chaparral Energy, Inc.;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation;

d)disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

6.all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

7.any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	August 17, 2020
		/s/ Charles Duginski
		Charles Duginski
		Chief Executive Officer

EX-31.2

EXHIBIT 31.2

CERTIFICATION

I, Stephanie Carnes, Controller and Principal Financial Officer of Chaparral Energy, Inc., certify that:

1.I have reviewed this Quarterly Report on Form 10-Q of Chaparral Energy, Inc.;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation;

d)disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

6.all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

7.any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	August 17, 2020
		/s/ Stephanie Carnes
		Stephanie Carnes
		Controller and Vice President

EX-32.1

EXHIBIT 32.1

CERTIFICATION OF PERIODIC REPORT

I, Charles Duginski, Chief Executive Officer of Chaparral Energy Inc. (the “Company”), certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, that, to the best of my knowledge:

(1)the Quarterly Report on Form 10-Q of the Company for the period ended June 30, 2020 (the “Report”) fully complies with the requirements of Section 13 (a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m(a) or 78o(d)); and

(2)the information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.

Date:	August 17, 2020
		/s/ Charles Duginski
		Charles Duginski
		Chief Executive Officer

EX-32.2

EXHIBIT 32.2

CERTIFICATION OF PERIODIC REPORT

I, Stephanie Carnes, Controller and Principal Financial Officer of Chaparral Energy Inc. (the “Company”), certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, that, to the best of my knowledge:

(1)the Quarterly Report on Form 10-Q of the Company for the period ended June 30, 2020 (the “Report”) fully complies with the requirements of Section 13 (a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m(a) or 78o(d)); and

(2)the information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.

Date:	August 17, 2020
		/s/ Stephanie Carnes
		Stephanie Carnes
		Controller and Vice President

XML

Cover - shares	6 Months Ended
	Jun. 30, 2020	Aug. 17, 2020
Cover [Abstract]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Jun. 30, 2020
Document Transition Report	false
Entity File Number	001-38602
Entity Registrant Name	Chaparral Energy, Inc.
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	73-1590941
Entity Address, Address Line One	701 Cedar Lake Boulevard
Entity Address, City or Town	Oklahoma City
Entity Address, State or Province	OK
Entity Address, Postal Zip Code	73114
City Area Code	405
Local Phone Number	478-8770
Title of 12(b) Security	Class A common stock, par value, $0.01 per share
Trading Symbol	CHAP
Security Exchange Name	NYSE
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		47,790,146
Entity Central Index Key	0001346980
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	Q2
Amendment Flag	false

XML

Consolidated Balance Sheets (Unaudited) - USD ($) $ in Thousands	Jun. 30, 2020	Dec. 31, 2019
Current assets:
Cash and cash equivalents	$ 56,137	$ 22,595
Accounts receivable:
Accounts receivable, gross	43,197	50,744
Allowance for credit losses	(4,215)	(1,097)
Accounts receivable, net	38,982	49,647
Inventories, net	2,456	3,730
Prepaid expenses	4,034	3,471
Derivative instruments	15,197	947
Total current assets	116,806	80,390
Property and equipment, net	7,948	9,217
Right of use assets from operating leases	1,744	2,444
Oil and natural gas properties, using the full cost method:
Proved	1,569,627	1,276,036
Unevaluated (excluded from the amortization base)	142,295	371,229
Accumulated depreciation, depletion, amortization and impairment	(1,246,703)	(754,379)
Total oil and natural gas properties	465,219	892,886
Held for sale assets	111	2,860
Derivative instruments	1,990	0
Other assets	1,349	635
Total assets	595,167	988,432
Current liabilities:
Accounts payable and accrued liabilities	39,272	64,558
Accrued payroll and benefits payable	5,970	10,963
Accrued interest payable	12,309	12,227
Revenue distribution payable	9,322	22,370
Long-term debt and financing leases, classified as current	521,292	594
Derivative instruments	0	11,957
Total current liabilities	588,165	122,669
Long-term debt and financing leases, less current maturities	996	421,392
Derivative instruments	0	5,075
Noncurrent operating lease obligations	234	917
Deferred compensation	419	165
Asset retirement obligations	21,412	21,073
Commitments and contingencies (Note 10)
Stockholders’ equity:
Preferred stock, 5,000,000 shares authorized, none issued and outstanding	0	0
Common stock, $0.01 par value, 192,130,071 shares authorized; 48,297,606 issued and 47,790,146 outstanding at June 30, 2020 and 48,413,185 issued and 47,942,230 outstanding at December 31, 2019	483	485
Additional paid in capital	977,957	977,174
Treasury stock, at cost, 507,460 and 470,955 shares as of June 30, 2020, and December 31, 2019	(6,128)	(6,110)
Accumulated deficit	(988,371)	(554,408)
Total stockholders’ equity	(16,059)	417,141
Total liabilities and stockholders’ equity	$ 595,167	$ 988,432

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Consolidated Balance Sheets (Unaudited) (Parenthetical) - $ / shares	Jun. 30, 2020	Dec. 31, 2019
Statement of Financial Position [Abstract]
Preferred stock, shares authorized (in shares)	5,000,000	5,000,000
Preferred stock, shares issued (in shares)	0	0
Preferred stock, shares outstanding (in shares)	0	0
Treasury stock, shares (in shares)	507,460	470,955
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	192,130,071	192,130,071
Common stock, shares issued (in shares)	48,297,606	48,413,185
Common stock, shares outstanding (in shares)	47,790,146	47,942,230

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Consolidated Statements of Operations (Unaudited) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
Revenues:
Net commodity sales	$ 15,880	$ 66,707	$ 64,731	$ 115,326
Sublease revenue	0	1,198	0	2,396
Total revenues	15,880	67,905	64,731	117,722
Costs and expenses:
Lease operating	5,971	13,371	16,059	25,665
Production taxes	823	3,802	3,573	6,682
Depreciation, depletion and amortization	14,821	30,282	37,833	53,997
Impairment of oil and gas assets	384,639	63,593	456,010	113,315
Impairment of other assets	310	6,407	463	6,407
General and administrative	9,488	7,315	17,556	15,628
Liability management	8,047	0	8,047	0
Litigation loss	4,359	0	4,359	0
Subleases	0	403	0	806
Total costs and expenses	428,458	125,173	543,900	222,500
Operating loss	(412,578)	(57,268)	(479,169)	(104,778)
Non-operating income (expense):
Interest expense	(8,047)	(5,571)	(14,683)	(10,135)
Write-off of Senior Note issuance costs	(4,420)	0	(4,420)	0
Derivative (losses) gains	(13,019)	17,734	65,361	(33,282)
(Loss) gain on sale of assets	(261)	491	(159)	490
Other income (expense), net	35	(302)	281	(288)
Net non-operating income (expense)	(25,712)	12,352	46,380	(43,215)
Reorganization items, net	(436)	(313)	(1,020)	(776)
Loss before income taxes	(438,726)	(45,229)	(433,809)	(148,769)
Income tax expense	0	0	0	0
Net loss	$ (438,726)	$ (45,229)	$ (433,809)	$ (148,769)
Loss per share:
Basic (in dollars per share)	$ (9.55)	$ (0.99)	$ (9.45)	$ (3.27)
Diluted (in dollars per share)	$ (9.55)	$ (0.99)	$ (9.45)	$ (3.27)
Weighted average shares used to compute earnings per share:
Basic (in shares)	45,949,797	45,641,797	45,890,041	45,549,518
Diluted (in shares)	45,949,797	45,641,797	45,890,041	45,549,518

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Consolidated Statement of Stockholders' Equity (Unaudited) - USD ($) $ in Thousands	Total	Cumulative Effect, Period of Adoption, Adjustment	Common stock	Additional paid in capital	Treasury stock	Accumulated deficit	Accumulated deficit Cumulative Effect, Period of Adoption, Adjustment
Balance at beginning of period (in shares) at Dec. 31, 2018			46,390,513
Balance at beginning of period at Dec. 31, 2018	$ 884,687		$ 467	$ 974,616	$ (4,936)	$ (85,460)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stock-based compensation (in shares)			94,078
Stock-based compensation	1,424		$ 1	1,423
Restricted stock forfeited or canceled (in shares)			(97,113)
Restricted stock forfeited or canceled	(1)		$ (1)
Repurchase of common stock (in shares)			(80,422)
Repurchase of common stock	(463)				(463)
Net loss	(103,540)					(103,540)
Balance at end of period (in shares) at Mar. 31, 2019			46,307,056
Balance at end of period at Mar. 31, 2019	782,107		$ 467	976,039	(5,399)	(189,000)
Balance at beginning of period (in shares) at Dec. 31, 2018			46,390,513
Balance at beginning of period at Dec. 31, 2018	$ 884,687		$ 467	974,616	(4,936)	(85,460)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Repurchase of common stock (in shares)	(206,653)
Net loss	$ (148,769)
Balance at end of period (in shares) at Jun. 30, 2019			46,417,442
Balance at end of period at Jun. 30, 2019	737,744		$ 469	977,611	(6,107)	(234,229)
Balance at beginning of period (in shares) at Mar. 31, 2019			46,307,056
Balance at beginning of period at Mar. 31, 2019	782,107		$ 467	976,039	(5,399)	(189,000)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stock-based compensation (in shares)			160,400
Stock-based compensation	$ 1,250		$ 1	1,249
Repurchase of common stock (in shares)	(126,231)		(126,231)
Repurchase of common stock	$ (708)				(708)
Issuance of common stock - litigation settlement (in shares)			76,217
Issuance of common stock - litigation settlement	324		$ 1	323
Net loss	(45,229)					(45,229)
Balance at end of period (in shares) at Jun. 30, 2019			46,417,442
Balance at end of period at Jun. 30, 2019	$ 737,744		$ 469	977,611	(6,107)	(234,229)
Balance at beginning of period (in shares) at Dec. 31, 2019	47,942,230		47,942,230
Balance at beginning of period at Dec. 31, 2019	$ 417,141	$ (154)	$ 485	977,174	(6,110)	(554,408)	$ (154)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stock-based compensation	705			705
Restricted stock forfeited or canceled (in shares)			(22,494)
Restricted stock forfeited or canceled	(1)		$ (1)
Repurchase of common stock (in shares)			(3,856)
Repurchase of common stock	(6)				(6)
Net loss	4,917					4,917
Balance at end of period (in shares) at Mar. 31, 2020			47,915,880
Balance at end of period at Mar. 31, 2020	$ 422,602		$ 484	977,879	(6,116)	(549,645)
Balance at beginning of period (in shares) at Dec. 31, 2019	47,942,230		47,942,230
Balance at beginning of period at Dec. 31, 2019	$ 417,141	$ (154)	$ 485	977,174	(6,110)	(554,408)	$ (154)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Repurchase of common stock (in shares)	(96,505)
Net loss	$ (433,809)
Balance at end of period (in shares) at Jun. 30, 2020	47,790,146		47,790,146
Balance at end of period at Jun. 30, 2020	$ (16,059)		$ 483	977,957	(6,128)	(988,371)
Balance at beginning of period (in shares) at Mar. 31, 2020			47,915,880
Balance at beginning of period at Mar. 31, 2020	422,602		$ 484	977,879	(6,116)	(549,645)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stock-based compensation	78			78
Restricted stock forfeited or canceled (in shares)			(93,085)
Restricted stock forfeited or canceled	$ (1)		$ (1)
Repurchase of common stock (in shares)	(92,649)		(32,649)
Repurchase of common stock	$ (12)				(12)
Net loss	$ (438,726)					(438,726)
Balance at end of period (in shares) at Jun. 30, 2020	47,790,146		47,790,146
Balance at end of period at Jun. 30, 2020	$ (16,059)		$ 483	$ 977,957	$ (6,128)	$ (988,371)

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Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
Cash flows from operating activities
Net loss	$ (438,726)	$ (45,229)	$ (433,809)	$ (148,769)
Adjustments to reconcile net loss to net cash (used in) provided by operating activities
Depreciation, depletion and amortization	14,821	30,282	37,833	53,997
Derivative (gains) losses	13,019	(17,734)	(65,361)	33,282
Impairment of oil and gas assets	384,639	63,593	456,010	113,315
Impairment of other assets	310	6,407	463	6,407
Write-off of Senior Note issuance costs	4,420	0	4,420	0
Loss (gain) on sale of assets	261	(491)	159	(490)
Other			4,612	1,621
Change in assets and liabilities
Accounts receivable			6,206	13,584
Inventories			747	40
Prepaid expenses and other assets			(1,277)	1,055
Accounts payable and accrued liabilities			(7,217)	(18,389)
Revenue distribution payable			(13,049)	600
Deferred compensation			844	1,852
Net cash (used in) provided by operating activities			(9,419)	58,105
Cash flows from investing activities
Expenditures for property, plant, and equipment and oil and natural gas properties			(86,862)	(146,434)
Proceeds from asset dispositions			3,370	857
Proceeds from derivative instruments, net			32,089	653
Net cash used in investing activities			(51,403)	(144,924)
Cash flows from financing activities
Proceeds from long-term debt			120,000	85,000
Repayment of long-term debt			(25,313)	(343)
Principal payments under financing lease obligations	(107)	(746)	(212)	(1,445)
Payment of debt issuance costs and other financing fees			(93)	(20)
Treasury stock purchased			(18)	(1,171)
Net cash provided by financing activities			94,364	82,021
Net increase (decrease) in cash and cash equivalents			33,542	(4,798)
Cash and cash equivalents, at beginning of period			22,595	37,446
Cash and cash equivalents, at end of period	$ 56,137	$ 32,648	$ 56,137	$ 32,648

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Nature of operations and summary of significant accounting policies and going concern

6 Months Ended

Jun. 30, 2020

Accounting Policies [Abstract]

Nature of operations and summary of significant accounting policies and going concern

Nature of operations and summary of significant accounting policies and going concern

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, 2019.

The financial information as of June 30, 2020, and for the three and six months ended June 30, 2020 and 2019, is unaudited. The financial information as of December 31, 2019 has been derived from the audited financial statements contained in our Annual Report on Form 10-K for the year ended December 31, 2019. 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 six months ended June 30, 2020 are not necessarily indicative of the results of operations that will be realized for the year ended December 31, 2020.

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.

Chapter 11 Cases and going concern

On August 16, 2020 (the “Petition Date”), Chaparral Energy, Inc. and its consolidated subsidiaries, including Chaparral Resources, L.L.C., Chaparral Real Estate, L.L.C., Chaparral CO2, L.L.C., CEI Pipeline, L.L.C., Chaparral Energy, L.L.C., CEI Acquisition, L.L.C., Green Country Supply, Inc., Chaparral Biofuels, L.L.C., Chaparral Exploration, L.L.C., Roadrunner Drilling, L.L.C., Trabajo Energy, L.L.C., Charles Energy, L.L.C. and Chestnut Energy, L.L.C. (collectively, the “Debtors”) filed voluntary petitions commencing the Chapter 11 Cases, seeking relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. The Company has requested court approval for the joint administration of the Chapter 11 Cases under the caption In re Chaparral Energy, Inc. We are currently operating our business as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court, in accordance with the applicable provisions of the Bankruptcy Code.

To maintain and continue uninterrupted ordinary course operations during the bankruptcy proceedings, the Debtors filed a variety of “first day” motions seeking approval from the Bankruptcy Court for various forms of customary relief designed to minimize the effect of bankruptcy on the Debtors’ operations, customers and employees. Upon entry by the Bankruptcy Court of the orders approving all requested “first day” relief, we will be able to conduct normal business activities and pay all associated obligations for the period following our bankruptcy filing and (subject to caps applicable to payments of certain pre-petition obligations) pre-petition employee wages and benefits, pre-petition amounts owed to certain lienholders and vendors, royalty interest and working interest holders, and partners. During the pendency of the Chapter 11 Cases, all transactions outside the ordinary course of our business require the prior approval of the Bankruptcy Court.

The commencement, through the Chapter 11 Cases, of a voluntary proceeding in bankruptcy constituted an immediate event of default under our Credit Agreement and the indenture governing our Senior Notes (the “Indenture”), resulting in the automatic and immediate acceleration of all outstanding amounts under those financing arrangements. Accordingly, we have classified the outstanding balances under our Credit Agreement and Senior Notes as current liabilities on our condensed consolidated balance sheet as of June 30, 2020.

Please see “Note 11: Subsequent events” for a discussion of the restructuring support agreement and the related proposed plan of reorganization.

Ability to continue as a going concern—The accompanying condensed consolidated financial statements are prepared in accordance with generally accepted accounting principles applicable to a going concern, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business. The filing of the Chapter 11 Cases constituted an event of default

under the Indenture and the Credit Agreement, resulting in the automatic and immediate acceleration of outstanding balances under those financing arrangements. The Company projects that it will not have sufficient cash on hand or available liquidity to repay all of such debt. These conditions along with the significant risks and uncertainties related to the Company’s liquidity and the Chapter 11 Cases raise substantial doubt about the Company’s ability to continue as a going concern. The condensed consolidated financial statements do not include any adjustments relating to the recoverability and classification of recorded asset amounts or the amounts and classification of liabilities that might result from the outcome of this uncertainty. If the Company cannot continue as a going concern, adjustments to the carrying values and classification of its assets and liabilities and the reported amounts of income and expenses could be required and could be material.

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 June 30, 2020, cash with a recorded balance totaling approximately $55,445 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

In June 2016, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) 2016–13, Financial Instruments–Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments (“ASU 2016–13”), which changes the recognition model for the impairment of financial instruments, including accounts receivable, loans and held-to-maturity debt securities, among others. We adopted ASU 2016–13 using the modified retrospective method effective January 1, 2020. In contrast to previous guidance, which considered current information and events, and only recognized losses when they became probable (an “incurred loss” model), ASU 2016–13 mandates an “expected loss” model. The expected loss model: (i) estimates the risk of loss even when risk is remote, (ii) estimates losses over the contractual life, (iii) considers past events, current conditions and reasonable supported forecasts and (iv) has no recognition threshold. ASU 2016–13 is applicable to our accounts receivable portfolio, particularly those receivables attributable to our joint interest partners which have a higher credit risk than those associated with our traditional customer receivables.

Basis of accounting. Our accounts receivable are carried at gross cost, representing amounts due, less an allowance for expected credit losses. We write off accounts receivable when they are determined to be uncollectible. When we recover amounts that were previously written off, those amounts are offset against the allowance and reduce expense in the year of recovery.

The Company has four portfolio segments constituting its total accounts receivables: (i) joint interest receivables; (ii) commodity sales receivables; (iii) derivative settlement receivables and (iv) other receivables. The table below discloses balances related to these four segments and the allowance:

	June 30, 2020		December 31, 2019
Joint interests	$	9,992	$	16,664
Commodity sales	14,416		30,819
Derivative settlements	15,540		717
Other	3,249		2,544
Allowance for credit losses	(4,215)		(1,097)
	$	38,982	$	49,647

Commodity sales receivables. The Company sells its commodity products primarily to oil and natural gas midstream entities including crude oil refineries and natural gas processing plants. We also sell a small percentage of our natural gas and natural gas liquids to energy marketing entities. Payment is generally due within 30 days of sales and amounts outstanding longer than 90 days are considered past due. Based on 2019 commodity sales, our 10 largest purchasers account for over 75% of our commodity sales. Based on our history of collections from our purchasers, we believe the probability of credit losses from uncollectible receivables to be low. We perform annual credit evaluations on purchasers representing approximately 80% or more of our commodity revenues. The evaluations include (i) an assessment of external credit ratings; (ii) performing internal risk evaluations when external ratings are not available; (iii) assessing the need for guarantor letters or letters of credit. We estimate the expected losses on uncollectible receivables by applying a uniform allowance rate on the total outstanding balance taking into consideration general industry conditions and more specifically, factors impacting the midstream energy segment. We may make further adjustments to our allowance for credit losses according to any specific news we may receive regarding individual purchasers.

Joint interest receivables. Our joint interest receivables represent amounts owed to us by other working interest owners on wells that we operate. We have numerous joint interest counterparties which are the result of combining all or portions of multiple oil and gas leases to form units for the drilling of wells under pooling or a joint interest agreements. The counterparties in this segment are diverse, ranging from large public company upstream operators to individual mineral leaseholders. Amounts billed to our joint interest owners generally consist of drilling and completion costs, in the early stages of a well, and lease operating expenses and costs for workovers and remediation work once a well in online. Payment is generally due within 60 days of billing and amount outstanding longer than 90 days are considered past due. Our historical losses on uncollectible receivables have predominantly been attributable to this portfolio segment, although losses in prior years have not been material. In the event of nonpayment, we may be able to mitigate our losses by netting the outstanding amount against any revenues payable to the joint interest owner and if still insufficient, by assuming the joint interest owner’s working interest in the well. The fair value of the working interest, which represents collateral for the outstanding receivable, will depend on the fair value of the remaining oil and natural gas reserves of the well. We monitor the ongoing collectability of these receivables by focusing on past due accounts with material balances. We estimate the expected losses on uncollectible joint interest receivables by applying varying allowance rates to outstanding balances based on aging of the balances. We also factor in current industry conditions, outstanding revenues payable to the accountholder, the fair value of the accountholder’s working interest in the property and the accountholder’s previous loss history in assessing the appropriate allowance. This method is augmented with a specific identification approach that includes directly communicating with certain joint interest owners that have material outstanding balances and consideration of specific information or circumstances regarding the account, such as bankruptcy, litigation or ongoing negotiations.

Derivative settlement receivables. Our derivative receivables relate to net settlements due from counterparties to our derivative contracts. Since derivative settlements fluctuate depending on commodity price changes, which are volatile, the associated amounts can result in a net payable or a net receivable position in any given month. Our derivative contracts generally require payment within 60 days of the fixing date. We have a limited number of counterparties to our derivative contracts, all of whom are large financial institutions and are also lenders under our credit agreement. These financial institution counterparties bear investment grade credit ratings. We have never incurred credit losses from our derivative receivables and believe the probability of such losses to be highly remote. Furthermore, to the extent that a balance is uncollectible, we believe that we have offset rights against amounts owed to the counterparty under our credit facility. Based on these circumstances, we have not recorded any allowance for credit losses related to these receivables. As discussed in “Note 11: Subsequent events,” we terminated all our outstanding derivatives in July 2020.

Other receivables. These receivables are of a nonrecurring discrete nature and generally immaterial with respect to our total receivables. Outstanding amounts may include receivables from taxing authorities and post-closing adjustments from acquisitions and divestitures.

Response to current industry conditions. We are in the midst of an unprecedented decline in crude oil prices brought about by the COVID-19 pandemic and other macroeconomic factors, which has drastically reduced demand for crude oil. The price decline has been exacerbated by episodic storage constraints. We have incorporated the prevailing industry crisis into our forecast of credit losses by increasing the allowance rates that we apply to our receivables, and for certain accounts where we have applied specific identification measures, recognizing an allowance sooner than would be typical under normal conditions.

Accrued interest, discount and premiums. We do not accrue interest on the outstanding balances of our receivables. There are no discounts or premiums associated with our receivables.

Presentation of credit loss expense. Our credit loss expense is included as a component of “General and administrative expenses” on our consolidated statement of operations and is as follows:

	Three months ended June 30,				Six months ended June 30,
	2020		2019		2020		2019
Credit losses on receivables	$	1,447	$	(18)	$	2,964	$	(276)

Credit quality disclosures. We are exempted under ASU 2016-13 from disclosing credit quality disclosures on our commodity sales receivables. Since all the financial institution counterparties to our derivative contracts bear investment grade credit ratings, we do not believe further decomposition by credit rating is necessary for this segment of receivables. The table below segregates our joint interest receivables based on the amount of revenues payable which can be utilized to offset the receivable balance. We consider this segregation to be a reasonable indicator of credit quality.

Joint interest receivables, gross	June 30, 2020
Accounts which have sufficient related revenue distributions payable to offset entire receivable balance	$	258
Accounts which have related revenue distributions payable but not sufficient to offset entire receivable balance	3,711
Accounts without related revenue distributions payable	6,023
Total	$	9,992

Allowance for credit losses. The table below discloses activity on our receivables allowance account:

	Six months ended June 30, 2020
	Commodity sales		Joint interest		Derivatives		Other		Total
Balance at January 1, 2020	$	—	$	1,097	$	—	$	—	$	1,097
Cumulative effect of accounting standard adoption	154		—		—		—		154
Credit losses	59		2,905		—		—		2,964
Write-offs	—		—		—		—		—
Recoveries	—		—		—		—		—
Balance at June 30, 2020	$	213	$	4,002	$	—	$	—	$	4,215

Inventories

Inventories consisted of the following:

	June 30, 2020		December 31, 2019
Equipment inventory	$	2,673	$	3,435
Commodities	425		474
Inventory valuation allowance	(642)		(179)
	$	2,456	$	3,730

During the three and six months ended June 30, 2020, we recorded an adjustment to net realizable value of $310 and $463 on our equipment inventory, which is reflected as “Impairment of other assets” on our consolidated statements of operations.

Property and equipment, net

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

	June 30, 2020		December 31, 2019
Machinery and equipment	$	3,229	$	3,543
Office and computer equipment	3,606		3,363
Automobiles and trucks	2,469		3,071
Building and improvements	664		693
Furniture and fixtures	8		8
	9,976		10,678
Less accumulated depreciation, amortization and impairment	3,963		3,459
	6,013		7,219
Land	1,935		1,998
	$	7,948	$	9,217

Held for sale.  In an effort to further streamline operations, during the fourth quarter of 2019, the Company began transitioning from an internally staffed and resourced oilfield services function to a third party provider solution. As a result, it began to actively market all related company-owned oilfield services machinery and equipment for eventual disposal. Accounting guidance requires us

to reflect the disposal group separately on the balance sheet as “Assets held for sale” at carrying value or fair value less cost to sell, whichever is less. The carrying value of assets held for sale is not included in the table above. Our held for sale assets are as follows:

	Carrying value at
	June 30, 2020		December 31, 2019
Equipment	$	—	$	1,572
Vehicles	111		488
Real estate	—		800
Total held for sale	$	111	$	2,860

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. Quarterly, 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. 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; 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 Prior Effective Date in 2017, 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 Focus Areas.

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

	June 30, 2020		December 31, 2019
Leasehold acreage	$	135,059	$	334,083
Capitalized interest	6,317		16,785
Wells and facilities in progress of completion	919		20,361
Total unevaluated oil and natural gas properties excluded from amortization	$	142,295	$	371,229

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 June 30, 2020, 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. These losses are reflected in “Impairment of oil and gas assets” in our consolidated statements of operations. The ceiling test impairment we recorded in the current year was driven in part by our impairment of unevaluated leasehold in the amount $216,173 and $218,741 for the three and six month periods ending June 30, 2020, respectively. Impairments of leasehold result in a transfer of amounts from unevaluated oil and natural gas properties to the full cost amortization base subsequently impacting the ceiling test.

	Three months ended June 30,			Six months ended June 30,
	2020	2019		2020		2019
Impairment of oil and gas assets	384,639	$	63,593	$	456,010	$	113,315

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 June 30, 2020, and December 31, 2019, were immaterial.

Revenue recognition

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

	Three months ended June 30,				Six months ended June 30,
	2020		2019		2020		2019
Revenues:
Oil	$	10,384	$	50,990	$	47,410	$	83,792
Natural gas	5,679		10,476		14,334		21,682
Natural gas liquids	3,903		11,025		13,585		20,242
Gross commodity sales	19,966		72,491		75,329		125,716
Transportation and processing	(4,086)		(5,784)		(10,598)		(10,390)
Net commodity sales	$	15,880	$	66,707	$	64,731	$	115,326

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, 2019, 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.

Income taxes

On March 27, 2020, the President of the U.S. signed into law the Coronavirus Aid, Relief, and Economic Security (“CARES”) Act. The CARES Act provides relief to corporate taxpayers by permitting a five-year carryback of 2018-2020 net operating losses (“NOLs”), removing the 80% limitation on the carryback of those NOLs, increasing the Section 163(j) 30% limitation on interest expense deductibility to 50% of adjusted taxable income for 2019 and 2020, and accelerates refunds for minimum tax credit carryforwards, along with a few other provisions. During the three and six months ended June 30, 2020, no material adjustments were made to provision amounts recorded as a result of the enactment of the CARES Act.

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.  The consistent effective tax rate, as disclosed below, is a result of maintaining a valuation allowance against substantially all of our net deferred tax asset.

	Three months ended June 30,				Six months ended June 30,
	2020		2019		2020		2019
Effective income tax rate	0.0	%	0.0	%	0.0	%	0.0	%

Despite the Company’s net loss for the six month period ended June 30, 2020, we did not record any net deferred tax benefit due to the Company’s projected taxable loss for the year ending December 31, 2020. Nor did the Company record a 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 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 June 30, 2020, or December 31, 2019.

As a result of the Prior Reorganization Plan and related transactions, the Company experienced an ownership change within the meaning of Internal Revenue Code (“IRC”) Section 382 on the Prior Effective Date. 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 six month period ended June 30, 2020, or any intervening period since the Prior Effective Date. Since the Prior Effective Date ownership change, the Company has generated additional NOLs and other tax attributes that are not currently subject to an IRC Section 382 limitation. The Company’s ability to use NOLs and other tax attributes to reduce taxable income and income taxes could be materially impacted by a future IRC 382 ownership change. Future transactions involving the Company’s stock, including those outside of the Company’s control, could cause an IRC 382 ownership change resulting in a limitation on tax attributes currently not limited and a more restrictive limitation on tax attributes currently subject to the previous IRC 382 limitation.

Subleases expense

Subleases expense for the three months ended March 31, 2019, consisted of our expense on operating leases for CO₂ compressors that we subleased to another operator in 2019. Please see “Note 1: Nature of operations and summary of significant accounting policies” and “Note 17: Leases” in “Item 8. Financial Statements and Supplementary Data” of our Annual Report on Form 10-K for the year ended December 31, 2019, for a discussion of the subleases.

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 resulting from the Prior Chapter 11 Cases and Prior Reorganization Plan. The reorganization items disclosed in our consolidated statement of operations consist of professional fees for continuing legal work to resolve outstanding claims and fees to the U.S. Bankruptcy Trustee, which we will continue to incur until both the Prior Chapter 11 Cases and the Chapter 11 Cases are closed.

Liability management expenses

Liability management expense includes third party legal and professional service fees incurred from our activities to restructure our debt and in preparation for our Chapter 11 Cases.

Litigation loss

The expense consists of our estimate of the settlement costs for the Naylor Farms Case as discussed in “Note 10: Commitments and Contingencies.”

Recently issued accounting pronouncementsIn December 2019, the FASB issued ASU 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes. This standard eliminates certain exceptions in the existing guidance related to the approach for intraperiod tax allocation, the methodology for calculating income taxes in an interim period, and the recognition of deferred tax liabilities for outside basis differences. The new guidance also clarifies certain aspects of the existing guidance, among other things. The standard is effective for interim and annual periods beginning after December 15, 2020 and shall be applied on either a prospective basis, a retrospective basis for all periods presented, or a modified retrospective basis through a cumulative-effect adjustment to retained earnings depending on which aspects of the new standard are applicable to an entity. The Company is in the process of evaluating the new standard and is unable to estimate its financial impact, if any, at this time.

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Earnings per share

6 Months Ended

Jun. 30, 2020

Earnings Per Share [Abstract]

Earnings per share

Earnings per share

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

	Three months ended June 30,				Six months ended June 30,
(in thousands, except share and per share data)	2020		2019		2020		2019
Numerator for basic and diluted loss per share
Net loss	$	(438,726)	$	(45,229)	$	(433,809)	$	(148,769)
Denominator for basic loss per share
Weighted average common shares	45,949,797		45,641,797		45,890,041		45,549,518
Denominator for diluted loss per share
Weighted average common shares	45,949,797		45,641,797		45,890,041		45,549,518
Loss per share
Basic	$	(9.55)	$	(0.99)	$	(9.45)	$	(3.27)
Diluted	$	(9.55)	$	(0.99)	$	(9.45)	$	(3.27)
Participating securities excluded from loss per share calculations
Unvested restricted stock units - stock settled	604,789		81,119		604,789		81,119
Unvested restricted stock awards	1,839,381		706,821		1,839,381		706,821

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Supplemental disclosures to the consolidated statements of cash flows

6 Months Ended

Jun. 30, 2020

Supplemental Cash Flow Elements [Abstract]

Supplemental disclosures to the consolidated statements of cash flows

Supplemental disclosures to the consolidated statements of cash flows

	Six months ended June 30,
	2020		2019
Net cash provided by operating activities included:
Cash payments for interest	$	16,942	$	16,328
Interest capitalized	(3,900)		(6,613)
Cash payments for reorganization items	1,189		857
Non-cash investing activities included:
Asset retirement obligation additions and revisions	133		386
Financing lease right of use asset additions (see Note 5: Leases)	—		1,387
Change in accrued oil and gas capital expenditures	(22,418)		7,024

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Debt

6 Months Ended

Jun. 30, 2020

Debt Disclosure [Abstract]

Debt

Debt

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

	June 30, 2020		December 31, 2019
8.75% Senior Notes due 2023	$	300,000	$	300,000
Credit facility	225,000		130,000
Installment note payable	—		371
Financing lease obligations	1,442		1,653
Unamortized debt issuance costs	(4,154)		(10,038)
Total debt, net	522,288		421,986
Less current portion	521,292		594
Total long-term debt, net	$	996	$	421,392

Chapter 11 Cases and Effect of Automatic Stay. On August 16, 2020, 2020, the Debtors filed for relief under the Bankruptcy Code. The commencement, through the Chapter 11 Cases, of a voluntary proceeding in bankruptcy constituted an immediate event of default under the Credit Agreement and the Indenture, resulting in immediate acceleration of outstanding amounts under these financing arrangements. Any efforts to enforce payment obligations related to the Company’s debt, including the acceleration thereof, have been automatically stayed as a result of the Chapter 11 Cases, and the creditors’ rights of enforcement are subject to the applicable provisions of the Bankruptcy Code. As a result of the acceleration, we have classified the amounts outstanding under the Credit Agreement and Senior Notes as current liabilities on our condensed consolidated balance sheet as of June 30, 2020. For more information on the Chapter 11 Cases and related matters, refer to the “Note 1: Nature of operations and summary of significant accounting policies” and “Note 11: Subsequent events.”

Credit Agreement

Pursuant to our 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 that is 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 June 30, 2020, was $175,000 with no availability (see discussion of Borrowing Base Deficiency below).

As of June 30, 2020, 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 3.19%.

The Credit Agreement contains financial covenants that require, for each fiscal quarter, us to maintain: (1) a Current Ratio (as defined in the Credit Agreement) of no less than 1.0 to 1.0, 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.

The Credit Agreement contains covenants and events of default customary for oil and natural gas reserve-based lending facilities. Our Credit Agreement and Senior Notes include cross default provisions wherein a default on one instrument may cause default on the other. 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, 2019, for a discussion of the material provisions of our Credit Agreement.

On April 1, 2020, we borrowed $15,000, and on April 2, 2020, we provided notice to our lenders to borrow an additional $90,000 (the latter herein referred to as the “Borrowing”) which increased the total amount outstanding under the Credit Agreement to $250,000. The Borrowing was made by the Company as a precautionary measure in order to increase its cash position and thereby provide for flexibility in the current challenging business environment and associated uncertainties. Subsequent to the Borrowing, we were notified that our lenders had exercised their right to make an interim redetermination of the Company’s borrowing base. The lenders’ redetermination notice stated that the Company’s borrowing base was decreased from $325,000 to $175,000, effective April 3, 2020. Our lenders subsequently reaffirmed the borrowing base at the same level on May 5, 2020, in conjunction with our scheduled semi-annual redetermination process. As a result of the April 3, 2020 borrowing base redetermination, the Borrowing, once funded, created a borrowing base deficiency in the amount of $75,000 under the Credit Agreement (the “Borrowing Base Deficiency”). In accordance with the Credit Agreement the Company is allowed to eliminate such Borrowing Base Deficiency by repaying the amount of the Borrowing

Base Deficiency in six equal monthly installments. During the second quarter, we made two such payments totaling $25,000 plus interest between May 1 to June 1, 2020. A third payment of $12,500 was made in early July 2020. No premium or penalty was charged with respect to those repayments. We did not make the fourth installment payment of $12,500 that was due on August 3, 2020 (the “August Deficiency Payment”), which subsequently resulted in an event of default under the Credit Agreement and under the Indenture, as discussed further below.

On July 15, 2020, the Company entered into a Limited Forbearance Agreement with the lenders under its Credit Agreement (the “Lenders”). The Limited Forbearance Agreement included, among other things, a requirement that the Company terminate all of its outstanding commodity hedges and to apply a certain portion of the proceeds thereof toward partial repayment of the outstanding amount under the Credit Agreement. The Limited Forbearance Agreement was amended effective as of July 24, 2020, by the First Amendment to Limited Forbearance Agreement (the “First Amendment”) and was further amended effective July 29, 2020 by a Second Amendment (the “Second Amendment” and, as amended, such Limited Forbearance Agreement, the “Lender Forbearance Agreement”).

The forbearance period under the Lender Forbearance Agreement began on July 15, 2020 and was scheduled to expire on July 29, 2020, unless terminated earlier in accordance with the terms thereof. The Second Amendment extended the scheduled termination date to August 9, 2020, unless terminated earlier in accordance with the terms of the Forbearance Agreement. However, the Second Amendment permitted an extension of the scheduled termination date by mutual agreement of the Administrative Agent and the Company to any date up to and including August 14, 2020. The Administrative Agent and the Company agreed to extend the termination date to August 14, 2020. Subsequently, on August 14, 2020, the Lender Forbearance Agreement was further amended by a Third Amendment (the “Third Amendment” and, as amended, such Lender Forbearance Agreement, the “Final Lender Forbearance Agreement”), which, among other things, extended the scheduled termination date to August 17, 2020, unless terminated earlier in accordance with the terms of the Final Lender Forbearance Agreement.

Pursuant to the Final Lender Forbearance Agreement, the Lenders agreed, during the forbearance period, to forbear from exercising any remedies under the Credit Agreement for any default or event of default resulting from any failure by the Company or any of its subsidiaries to make all or any part of the required interest payment due on July 15, 2020 with respect to the Company’s Senior Notes (including the failure to make such payment during the 30-day grace period therefor), as discussed further below. Even though the indenture for the Senior Notes provides for a 30-day grace period before an event of default occurs under the indenture, the failure to make the interest payment on the due date constituted an event of default under the cross-default provisions of the Credit Agreement. The Company did not make the required interest payment of $13,125 on the due date or within the 30-day grace period. The Final Lender Forbearance Agreement also includes forbearance for the Company’s failure to timely pay the August Deficiency Payment under the Credit Agreement and the failure to timely deliver the quarterly financial statements for the period ended June 30, 2020 and the required accompanying officer’s certificate.

Pursuant to the Limited Forbearance Agreement with the lenders under our Credit Agreement, we terminated all our outstanding derivatives contracts on July 27, 2020 and applied a certain portion of the proceeds thereof toward partial repayment of the outstanding amount under the Credit Agreement, which we discuss in “Note 11: Subsequent events.”

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 Indenture contains customary covenants, certain mandatory redemption 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, 2019, for a discussion of the material provisions of our Senior Notes.

On July 15, 2020, the Company elected not to make the $13,125 interest payment on the Senior Notes due on that day. Under the Indenture, the Company has a 30-day grace period to make the interest payment before that non-payment constitutes an event of default. The 30-day grace period expires on August 14, 2020. However, as discussed above, the failure to make that interest payment on the Senior Notes constituted an event of default under cross-default provisions of the Credit Agreement.

Effective as of July 30, 2020, the Company and the holders of at least 75% of the principal amount of outstanding Senior Notes (the “Initial Consenting Noteholders”) entered into a Forbearance and Waiver Agreement (the “Noteholder Forbearance Agreement”). Pursuant to the Noteholder Forbearance Agreement, the Initial Consenting Noteholders agreed, during the forbearance period, to forbear from exercising certain remedies under the Indenture (including acceleration) for any default or event of default resulting from any failure by the Company to pay the August Deficiency Payment under the Credit Agreement on or before August 3, 2020. In addition, under the Noteholder Forbearance Agreement, subject to the occurrence of such an event of default, the Initial Consenting Noteholders have waived any such event of default and the consequences thereof under the Indenture. The forbearance period under the Noteholder Forbearance Agreement began on July 30, 2020 and was scheduled to expire on August 14, 2020. On August 14, 2020, the Company and the Initial Consenting Noteholders amended and restated the Noteholder Forbearance Agreement (such amendment and restatement, the “Amended and Restated Noteholder Forbearance Agreement”). Pursuant to the Amended and Restated Noteholder Forbearance Agreement, the Initial Consenting Noteholders agreed to extend the forbearance period to August 17, 2020 and to additionally forbear from exercising certain remedies under the Indenture (including acceleration) for any default or event of default resulting from any failure by the Company to make the required interest payment of $13,125 within the 30-day grace period described above.

Please see “Note 11: Subsequent events” for a discussion of the restructuring support agreement and the related proposed plan of reorganization.

As discussed above, our filing of the Chapter 11 Cases triggered an event of default on our Senior Notes. The event of default effectively allows the lender to demand immediate repayment, thus shortening the life of our Senior Notes to the current period. As a result, we wrote off the remaining balance of unamortized issuance costs in the amount of $4,420.

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Leases

6 Months Ended

Jun. 30, 2020

Leases [Abstract]

Leases

Leases

We currently have financing leases that consist of fleet trucks and office equipment and an operating lease for the office space housing our headquarters. Please see “Note 17: Leases” in “Item 8. Financial Statements and Supplementary Data” of our Annual Report on Form 10-K for the year ended December 31, 2019, for a discussion of these leases. We also have short term leases, which are those with lease terms of 12 months or less, and generally consist of wellhead compressors and drilling rigs with terms ranging from one month to six months. We do not recognize right of use assets or lease liabilities for leases with durations of 12 months or less.

Lease assets and liabilities

Our operating lease and financing lease assets and liabilities are recorded on our balance sheet as of June 30, 2020 as:

	As of June 30, 2020
	Operating leases		Financing leases
Right of use asset:
Right of use assets from operating leases	$	1,744	$	—
Plant, property and equipment, net	—		1,428
Total lease assets	$	1,744	$	1,428
Lease liability:
Account payable and accrued liabilities	$	1,331	$	—
Long-term debt and financing leases, classified as current	—		446
Long-term debt and financing leases, less current maturities	—		996
Noncurrent operating lease obligations	234		—
Total lease liabilities	$	1,565	$	1,442

Our income, expenses and cash flows related to our leases is as follows:

	Three months ended June 30,				Six months ended June 30,
	2020		2019		2020		2019
Lease cost
Finance lease cost:
Amortization of right-of-use assets	$	114	$	749	$	231	$	1,442
Interest on lease liabilities	26		117		53		230
Operating lease cost	389		308		779		616
Short-term lease cost	92		154		310		283
Variable lease cost	—		95		—		190
Sublease income	—		(1,198)		—		(2,396)
Total lease cost	$	621	$	225	$	1,373	$	365
Capitalized operating lease cost (1)	$	—	$	3,371	$	—	$	6,706
Other information
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows for finance leases	$	(26)	$	(117)	$	(53)	$	(230)
Operating cash flows for operating leases	(344)		(308)		(689)		(616)
Investing cash flows for operating leases	—		(2,965)		—		(3,988)
Financing cash flows for finance leases	(107)		(746)		(212)		(1,445)
Right-of-use assets obtained in exchange for new finance lease liabilities	—		717		—		1,387

________________________________

(1)The operating lease cost is related to drilling rigs with terms longer than 30 days and is capitalized as part of oil and natural gas properties on our balance sheets.

Leases

Leases

We currently have financing leases that consist of fleet trucks and office equipment and an operating lease for the office space housing our headquarters. Please see “Note 17: Leases” in “Item 8. Financial Statements and Supplementary Data” of our Annual Report on Form 10-K for the year ended December 31, 2019, for a discussion of these leases. We also have short term leases, which are those with lease terms of 12 months or less, and generally consist of wellhead compressors and drilling rigs with terms ranging from one month to six months. We do not recognize right of use assets or lease liabilities for leases with durations of 12 months or less.

Lease assets and liabilities

Our operating lease and financing lease assets and liabilities are recorded on our balance sheet as of June 30, 2020 as:

	As of June 30, 2020
	Operating leases		Financing leases
Right of use asset:
Right of use assets from operating leases	$	1,744	$	—
Plant, property and equipment, net	—		1,428
Total lease assets	$	1,744	$	1,428
Lease liability:
Account payable and accrued liabilities	$	1,331	$	—
Long-term debt and financing leases, classified as current	—		446
Long-term debt and financing leases, less current maturities	—		996
Noncurrent operating lease obligations	234		—
Total lease liabilities	$	1,565	$	1,442

Our income, expenses and cash flows related to our leases is as follows:

	Three months ended June 30,				Six months ended June 30,
	2020		2019		2020		2019
Lease cost
Finance lease cost:
Amortization of right-of-use assets	$	114	$	749	$	231	$	1,442
Interest on lease liabilities	26		117		53		230
Operating lease cost	389		308		779		616
Short-term lease cost	92		154		310		283
Variable lease cost	—		95		—		190
Sublease income	—		(1,198)		—		(2,396)
Total lease cost	$	621	$	225	$	1,373	$	365
Capitalized operating lease cost (1)	$	—	$	3,371	$	—	$	6,706
Other information
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows for finance leases	$	(26)	$	(117)	$	(53)	$	(230)
Operating cash flows for operating leases	(344)		(308)		(689)		(616)
Investing cash flows for operating leases	—		(2,965)		—		(3,988)
Financing cash flows for finance leases	(107)		(746)		(212)		(1,445)
Right-of-use assets obtained in exchange for new finance lease liabilities	—		717		—		1,387

________________________________

(1)The operating lease cost is related to drilling rigs with terms longer than 30 days and is capitalized as part of oil and natural gas properties on our balance sheets.

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Derivative instruments

6 Months Ended

Jun. 30, 2020

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative instruments

Derivative instruments

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.

The following table summarizes our crude oil derivatives outstanding as of June 30, 2020:

		Weighted average fixed price per Bbl
Period and type of contract	Volume MBbls	Swaps
2020
Oil swaps	1,026	$	50.56
Oil roll swaps	180	$	0.30
2021
Oil swaps	689	$	46.24
Oil roll swaps	150	$	0.30

The following table summarizes our natural gas derivatives outstanding as of June 30, 2020:

Period and type of contract	Volume BBtu	Weighted average fixed price per MMBtu
2020
Natural gas swaps	3,000	$	2.75
Natural gas basis swaps	3,000	$	(0.46)

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 June 30, 2020						As of December 31, 2019
	Assets		Liabilities		Net value		Assets		Liabilities		Net value
Natural gas derivative contracts	$	2,288	$	(500)	$	1,788	$	3,552	$	(1)	$	3,551
Crude oil derivative contracts	15,399		—		15,399		391		(22,196)		(21,805)
NGL derivative contracts	—		—		—		2,868		(699)		2,169
Total derivative instruments	17,687		(500)		17,187		6,811		(22,896)		(16,085)
Less:
Netting adjustments (1)	(500)		500		—		(5,864)		5,864		—
Derivative instruments - current	15,197		—		15,197		947		(11,957)		(11,010)
Derivative instruments - long-term	$	1,990	$	—	$	1,990	$	—	$	(5,075)	$	(5,075)

________________________________

(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

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 gains (losses)” in the consolidated statements of operations.

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

	Three months ended June 30,				Six months ended June 30,
	2020		2019		2020		2019
Change in fair value of commodity price derivatives	$	(35,934)	$	17,596	$	33,272	$	(33,935)
Net settlements received on commodity price derivatives	22,915		138		32,089		653
Total derivative gains (losses)	$	(13,019)	$	17,734	$	65,361	$	(33,282)

Pursuant to the Limited Forbearance Agreement with the lenders under our Credit Agreement, we terminated all our outstanding derivatives contracts on July 27, 2020 and applied a certain portion of the proceeds thereof toward partial repayment of the outstanding amount under the Credit Agreement, which we discuss in “Note 11: Subsequent events.”

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Fair value measurements

6 Months Ended

Jun. 30, 2020

Fair Value Disclosures [Abstract]

Fair value measurements

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 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 June 30, 2020, and December 31, 2019, 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 during the current year consisted of natural gas basis swaps and collars. 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 June 30, 2020						As of December 31, 2019
	Derivative assets		Derivative liabilities		Net assets (liabilities)		Derivative assets		Derivative liabilities		Net assets (liabilities)
Significant other observable inputs (Level 2)	$	17,687	$	—	$	17,687	$	6,576	$	(22,895)	$	(16,319)
Significant unobservable inputs (Level 3)	—		(500)		(500)		235		(1)		234
Netting adjustments (1)	(500)		500		—		(5,864)		5,864		—
	$	17,187	$	—	17,187		$	947	$	(17,032)	$	(16,085)

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(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:

	Six months ended June 30,
Net derivative assets (liabilities)	2020		2019
Beginning balance	$	234	$	30
Realized and unrealized gains included in derivative losses	1,033		441
Settlements (received) paid	(1,767)		116
Ending balance	$	(500)	$	587
(Losses) gains relating to instruments still held at the reporting date included in derivative gains (losses) for the period	$	(430)	$	742

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:

	Six months ended June 30,
	2020		2019
Inflation rate	2.21	%	2.25	%
Credit-adjusted risk-free discount rate (low)	25.00	%	12.35	%
Credit-adjusted risk-free discount rate (high)	25.00	%	14.60	%

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:

	June 30, 2020				December 31, 2019
Level 2	Carrying value (1)		Estimated fair value		Carrying value (1)		Estimated fair value
8.75% Senior Notes due 2023	$	300,000	$	30,000	$	300,000	$	133,050
Credit facility	225,000		225,000		130,000		130,000
Other secured debt (2)	—		—		371		371

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

(2)The balance December 31, 2019, consisted of only 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 June 30, 2020, the counterparties to our open derivative contracts consisted of five 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. 

	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
June 30, 2020
Derivative assets	$	17,687	$	(500)	$	17,187	$	—	$	(17,187)	$	—
Derivative liabilities	(500)		500		—		—		—		—
	$	17,187	$	—	$	17,187	$	—	$	(17,187)	$	—
December 31, 2019
Derivative assets	$	6,811	$	(5,864)	$	947	$	—	$	(947)	$	—
Derivative liabilities	(22,896)		5,864		(17,032)		—		947		(16,085)
	$	(16,085)	$	—	$	(16,085)	$	—	$	—	$	(16,085)

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(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 $500 before offsets at June 30, 2020.

Pursuant to the Limited Forbearance Agreement with the lenders under our Credit Agreement, we terminated all our outstanding derivatives contracts on July 27, 2020 and applied a certain portion of the proceeds thereof toward partial repayment of the outstanding amount under the Credit Agreement, which we discuss in “Note 11: Subsequent events.”

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Asset retirement obligations

6 Months Ended

Jun. 30, 2020

Asset Retirement Obligation Disclosure [Abstract]

Asset retirement obligations

Asset retirement obligations

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

Balance at January 1, 2020	$	23,156
Liabilities incurred in current period	84
Liabilities settled or disposed in current period	(419)
Revisions in estimated cash flows	49
Accretion expense	649
Balance at June 30, 2020	$	23,519
Less current portion included in accounts payable and accrued liabilities	2,107
Asset retirement obligations, long-term	$	21,412

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

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Deferred compensation

6 Months Ended

Jun. 30, 2020

Share-based Payment Arrangement, Noncash Expense [Abstract]

Deferred compensation

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. Our cash awards, which are generally service-based, vest either in one year, in annual increments over a three year period or in annual increments over a four-year period. We accrue for the cost of each annual increment over the period that service is required to vest. A summary of compensation expense for our cash awards is presented below:

	Three months ended June 30,				Six months ended June 30,
	2020		2019		2020		2019
Cash LTIP expense (net of amounts capitalized)	$	187	$	67	$	354	$	158

As of June 30, 2020, the outstanding liability accrued for our Cash LTIP, based on requisite service provided, was $1,366.

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. Our equity grants have been in the form or restricted stock awards (“restricted shares”) and restricted stock units (“RSUs”). In December 2019, we also granted restricted shares to our recently appointed chief executive officer under an inducement equity grant that is exempted from the general requirement of the NYSE rules that require equity-based compensation plans and arrangements to be approved by stockholders. 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. Please see “Note 13: Deferred Compensation” in “Item 8. Financial Statements and Supplementary Data” of our Annual Report on Form 10-K for the year ended December 31, 2019, for further details on the MIP, the LTIP as well as the nature and vesting requirements for our restricted shares and RSUs.

A summary of our restricted share activity 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, 2020	$	5.41	1,069,505			$	1.53	1,089,343
Granted	$	—	—			$	—	—
Vested	$	15.71	(203,888)	$	130	$	—	—
Forfeited	$	8.87	(82,658)			$	6.94	(20,833)
Cancelled	$	20.05	(12,088)			$	—	—
Unvested and outstanding at June 30, 2020	$	2.09	770,871			$	1.33	1,068,510

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, 2020	$	2.41	638,383			$	1.36	390,000
Granted	$	1.95	4,500			$	—	—
Vested	$	—	—	$	—	$	—	—
Forfeited	$	1.56	(228,094)			$	1.36	(200,000)
Unvested and outstanding at June 30, 2020	$	2.87	414,789			$	1.36	190,000

	Liability classified RSUs
	Weighted average award date fair value		Restricted units	Vest date fair value
	($ per share)
Unvested and outstanding at January 1, 2020	$	4.57	75,779
Granted	$	—	—
Vested	$	1.33	(60,000)	$	41
Forfeited	$	17.66	(1,515)
Unvested and outstanding at June 30, 2020	$	16.83	14,264

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:

	Three months ended June 30,				Six months ended June 30,
	2020		2019		2020		2019
Stock-based compensation cost	$	101	$	1,260	$	771	$	2,720
Less: stock-based compensation cost capitalized	(7)		(399)		(281)		(1,025)
Stock-based compensation expense	$	94	$	861	$	490	$	1,695
Number of vested shares repurchased or settled in cash	92,649		126,231		96,505		206,653
Payments for stock-based compensation	53		708		59		1,171

Based on a quarter end market price of $0.65 per share of our Class A common stock, the aggregate intrinsic value of all restricted shares and RSUs outstanding was $1,593 as of June 30, 2020. Payments for restricted shares and the associated number of shares repurchased are reflected as treasury stock transactions in our consolidated statements of equity. As of June 30, 2020, and December 31, 2019, accrued payroll and benefits payable included for stock-based compensation costs expected to be settled within the next

twelve months were $45 and $52, respectively, all of which relates to our cash-settled RSUs. Unrecognized stock-based compensation cost of approximately $1,357 as of June 30, 2020, is expected to be recognized over a weighted-average period of 1.3 years.

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Commitments and contingencies

6 Months Ended

Jun. 30, 2020

Commitments and Contingencies Disclosure [Abstract]

Commitments and contingencies

Commitments and contingencies

Standby letters of credit (“Letters”) available under our credit facility may be 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 nil as of June 30, 2020 and nil as of December 31, 2019. 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 six months ended June 30, 2020 or 2019.

Surety bonds totaling $2,121 were posted on our behalf as of June 30, 2020. We pay premiums for such bonds and, under normal circumstances, are not required to post collateral of any kind to support their issuance. However, as a result of the current extraordinary macroeconomic situation and the Borrowing Base Deficiency discussed above, we have been required to post cash collateral in respect of the bonds totaling $950.

Litigation and Claims

Prior Chapter 11 Cases.  Commencement of the Prior 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 (the “Prior Petition Date”), and the claims remain subject to Bankruptcy Court jurisdiction. With respect to the proofs of claim asserted in the Prior Chapter 11 Cases arising from the proceedings or actions below that were initiated prior to the Prior 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 that relate to one or more claims accruing prior to the Prior Petition Date and that result in a claim being allowed against us, pursuant to the terms of the Prior Reorganization Plan, such claims would 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, in each case subject to their further treatment prescribed by the Plan of Reorganization, assuming its ultimate approval.

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 consist of interest and may increase with the passage of time. We responded to the Naylor Farms petition, denied the allegations and raised arguments and defenses. Plaintiffs filed a motion for class certification in October 2015.  In addition, the plaintiffs filed a motion for summary judgment asking the Naylor Trial Court to determine as a matter of law that natural gas is not marketable until it is in the condition and location to enter an interstate pipeline. On May 20, 2016, we filed a Notice of Suggestion of Bankruptcy with the Naylor Trial Court. Subsequently the bankruptcy stay was lifted for the limited purpose of determining the class certification issue.

On January 17, 2017, the Naylor Trial Court certified a modified class of plaintiffs with oil and gas leases containing specific language. The modified class constitutes less than 60% of the leases the plaintiffs originally sought to certify. After additional briefing on the subject, on April 18, 2017, the Naylor Trial Court issued an order certifying the class to include only claims relating back to June 1, 2006. On May 3, 2019, our appeal of that class certification was denied by the Tenth Circuit Court of Appeals.

In addition to filing claims on behalf of the named and putative plaintiffs, on August 15, 2016, plaintiffs’ attorneys filed a proof of claim on behalf of the putative class claiming damages in excess of $150,000 in our Prior Chapter 11 Cases. The Company objected to treatment of the claim on a class basis, asserting the claim should be addressed on an individual basis. On April 20, 2017, plaintiffs filed an amended proof of claim reducing the claim to an amount in excess of $90,000 inclusive of actual and punitive damages, statutory interest and attorney fees. On May 24, 2017, the Bankruptcy Court denied the Company’s objection, ruling the plaintiffs

may file a claim on behalf of the class. This order did not establish liability or otherwise address the merits of the plaintiffs’ claims. The Bankruptcy Court order was affirmed by the United States District Court for the District of Delaware on September 24, 2019. On October 24, 2019, the Company filed its notice of appeal to the United States Court of Appeals for the Third Circuit.

During the period leading up to the commencement of the Chapter 11 Case, the Company engaged in settlement negotiations with counsel to the plaintiffs in the Naylor Farms case. On July 6, 2020, after multiple rounds of negotiations, the Company and the class representatives reached an agreement in principle on the terms of a settlement and, on August 15, 2020, the Company and the class representatives entered into a settlement agreement (the “Settlement Agreement”) to settle all claims related to the Naylor Farms case, including, for the avoidance of doubt, all alleged claims arising prior to the petition date in the Prior Chapter 11 Cases and all alleged claims arising thereafter.

Pursuant to the Settlement Agreement, the Company has agreed to:

•pay $2,500 to the settlement class;

•pay $850 to counsel to the settlement class for attorney fees, in exchange for a release of all liens or claims asserted by all counsel related to the Naylor Farms case;

•pay $150 to the class representative for services rendered as class representative; and

•allow the class proof of claim filed in the Prior Chapter 11 Case in an aggregate amount of $45,000 (provided that all other individual proofs of claims filed for similar claims are withdrawn).

The effectiveness of the settlement is subject to numerous conditions precedent, including approval by the Bankruptcy Court. Upon the Bankruptcy Court’s final approval of the Settlement Agreement, the members of the class who do not opt out of the settlement will provide the Company with a release of all past and present claims with respect to the allegations in the Naylor Farms case, and the Naylor Farms case and the Third Circuit appeal will be dismissed with prejudice.

Upon the final approval of the Settlement Agreement and the effectiveness of the settlement, the plaintiffs, in full satisfaction, settlement, discharge, and release of their claims asserted in the Prior Chapter 11 Cases, shall be deemed to hold 1,432,300 shares of Class A common stock in Chaparral Energy, Inc. as of the Petition Date on account of the $45,000 allowed class proof of claim and shall be entitled to receive any distribution under the Plan provided to holders of equity interests who do not hold through the Depository Trust Corporation (the “DTC”) or whose interests arise in connection with claims pending in the Prior Chapter 11 Cases, subject to a cap.

W.H. Davis Family Limited Partnership Claims in the Company’s Prior Chapter 11 Cases (the “W. H. Davis case”). The W. H. Davis Family Limited Partnership and affiliates (collectively, “Davis”) filed Proofs of Claim in the Company’s Prior Chapter 11 Cases. Davis claimed that Chaparral owed Davis $17,262 as the result of Chaparral’s alleged diversion of CO₂ from the Camrick Unit and the North Perryton Unit to the Farnsworth Unit. All these units were divested by the Company as part of its EOR asset sale in November 2017. While the Company denies all claims asserted by Davis, the Company determined it was prudent to explore settlement of the claims. Accordingly, the Company and Davis agreed at mediation to settle Davis’ claims for an allowed claim of $2,650 in Class 6 under the Prior Reorganization Plan, which agreement was memorialized in a settlement term sheet executed by both parties on the day of the mediation, a settlement agreement executed by both parties thereafter, and a settlement stipulation executed by both parties that was filed with the Bankruptcy Court. Davis subsequently contested the enforcement of the settlement under its terms, claiming that Davis was mistaken in its understanding of the terms of the Prior Reorganization Plan as relate to Class 6 claims. On August 14, 2020, Davis stipulated to the termination of such contest without payment by the Company of any consideration therefor.

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 and our financing leases consist of leases on our fleet vehicles and office equipment. We have a well drilling commitment under the terms of leasehold purchase agreements which we entered into in 2017. The drilling commitment requires the

Company to drill and complete 10 wells on such leasehold in each of 2019, 2020, and 2021 and 15 wells in 2022. To the extent the Company does not drill and complete the minimum number of wells in a given year, it is required to pay the sellers of the acreage $250 for each deficient well. The Company has paid the deficiency amount related to its 2019 drilling commitment and recorded an accrual of $2,500 in March 2020 for the deficiency on its 2020 drilling commitment and recorded an additional accrual of $6,250 in June 2020 for the remaining obligation as it does not intend to drill any further wells on the subject acreage.

Other than additional borrowings under our credit facility and the Borrowing Base Deficiency described in “Note 4: Debt” and the termination of our derivative contracts discussed below, we did not have material changes to our contractual commitments since December 31, 2019.

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Subsequent events

6 Months Ended

Jun. 30, 2020

Subsequent Events [Abstract]

Subsequent events

Subsequent events

As discussed in “Note 4: Debt”, the Lender Forbearance Agreement required us to terminate all our outstanding derivative contracts and to apply a certain portion of the proceeds thereof toward partial repayment of the outstanding amount under the Credit Agreement. Pursuant to this requirement, on July 27, 2020, the Company terminated all its outstanding derivative contracts. Proceeds from the early termination along with amounts owed to the Company from previously settled positions totaled $28,237. Of this amount, $24,000 was applied toward repayment on outstanding credit facility borrowings and the remainder was retained by the Company. The amount applied toward debt repayment versus the amount retained by the Company was determined under the terms of the Lender Forbearance Agreement.

On August 15, 2020, the Debtors entered into a restructuring support agreement (the “RSA”) with (i) certain lenders under our Credit Agreement and (ii) certain holders of our Senior Notes (the “Restructuring Support Parties”). Pursuant to the RSA, the Restructuring Support Parties agreed, subject to the terms and conditions of the RSA, to vote to accept the Debtors’ prepackaged Joint Chapter 11 Plan of Reorganization (as proposed, our “Plan of Reorganization”). Our Plan of Reorganization and the related disclosure statement (the “Disclosure Statement”) were each filed with the Bankruptcy Court on August 16, 2020. Below is a summary of certain material terms of the RSA and the treatment that the stakeholders of the Company would receive under the Plan of Reorganization:


•The RSA includes certain milestones for the progress of the Chapter 11 Cases, which include the dates by which the Company is required to, among other things, obtain certain court orders and consummate the transactions contemplated therein. Failure to meet these milestones allows the RSA to be terminated by the non-Company signatories thereto. In addition, the signatories to the RSA will have the right to terminate the RSA under certain circumstances, including if the board of directors of the Company determines in good faith that performance under the RSA would be inconsistent with its fiduciary duties as set forth therein. The Plan of Reorganization remains subject to approval by the Bankruptcy Court and the satisfaction of certain conditions precedent.


•The Company will emerge from Chapter 11 with a $300,000 exit credit facility (the “Exit Facility”). The Exit Facility will include (A) second out term loans (the “Second Out Term Loans”) in an amount to be determined, which will have a maturity date that is one year and 91 days following the Revolving Maturity Date (defined below) and (B) a revolving facility (the maturity date of which will be the earlier of May 31, 2024 or 40 months after emergence (the “Revolving Maturity Date”)) that has an initial borrowing base equal to (i) the lesser of (a) $175,000 or (b) the Company’s proved developed producing reserves on a PV-15 basis, plus hedges, on 6-month roll-forward basis minus (ii) the aggregate amount of the Second Out Term Loans. There must be a minimum of $20,000 of availability under the Exit Facility at emergence.


•The Company will raise $35,000 through a fully backstopped new money rights offering (the “Rights Offering”) of second-lien senior notes convertible into New Common Stock (as defined below) (the “2L Convertible Notes”) issued at par. The Convertible Notes will be convertible into shares of New Common Stock equal to 50% of the New Common Stock outstanding upon the reorganized Company’s emergence from bankruptcy (subject to certain anti-dilution protection) and will have the following terms:

◦they will have a maturity date of May 31, 2025 or 52 months after emergence, whichever is earlier;

◦they will bear interest at a rate of 9% per annum (if paid in cash), or 13% per annum (if paid in kind with additional principal);

◦interest must be paid in kind with additional principal if the Company’s liquidity is less than $20,000 at the time of such payment.


•On August 15, 2020, the Debtors entered into a Backstop Purchase Agreement (the “Backstop Purchase Agreement”) with the backstop parties named therein (the “Backstop Parties”). The Backstop Parties are obligated to fund, if necessary, the

entirety of the initial $35,000 principal amount. In exchange for that commitment, such holders will receive a put option premium (the “Put Option Premium”) equal to 10% of the total issued and outstanding shares of new common stock of the reorganized Company (the “New Common Stock”) prior to dilution by the Management Incentive Plan (as defined below), the Warrants (as defined below) and the conversion of the 2L Convertible Notes. The Convertible Notes will be convertible into shares of New Common Stock equal to 50% of New Common Stock outstanding upon the reorganized Company’s emergence from bankruptcy (subject to certain anti-dilution protection). If the Backstop Purchase Agreement is terminated (subject to certain exceptions, including a termination of the Backstop Purchase Agreement by the Company as a result of a breach by the Backstop Parties), the Debtors will be required to pay the Put Option Premium in a cash amount equal to $2,625 in lieu of New Common Stock. The transactions contemplated by the Backstop Purchase Agreement are conditioned upon the satisfaction or waiver of customary conditions for transactions of this nature, including among other things that (i) the Bankruptcy Court shall have confirmed the Plan and (ii) all Convertible Notes have been, or concurrently with the Closing will be, subscribed for or purchased pursuant to the Backstop Purchase Agreement.


•The reorganized Company will adopt a management incentive plan (the “Management Incentive Plan”), which will provide for the issuance of equity and/or equity based awards for up to 7% of the new common equity issued by the reorganized Company, the terms and conditions of which will be determined by the reorganized Company’s new board members within 30 days after emergence.

•Holders of Credit Agreement Claims

◦Lenders under the Credit Agreement will receive, on account of their prepetition loans, (i) their pro rata share of cash in the amount of the difference between their outstanding loans as of the effective date of the Plan of Reorganization and the initial borrowing base under the Exit Facility and (ii) with respect to lenders who agree to provide revolving commitments under the Exit Facility, their pro rata share of an additional amount of cash in excess of $5,000 (less cash payments scheduled to be made as severance payments to former officers and employees at or around emergence in accordance with the terms of the severance settlement agreements in an amount not to exceed $1,220 and less other cash payments required to be made at or around exit pursuant to the Plan of Reorganization) and new first-lien first-out revolving loans on account of their remaining prepetition loans and, with respect to lenders electing not to provide revolving commitments under the Exit Facility, new first-lien second-out term loans on account of their remaining prepetition loans.

•Holders of Senior Notes

◦At emergence, each holder of Senior Notes will receive its pro rata share of (i) 100% of the New Common Stock, subject to dilution by any New Common Stock issued in connection with the Management Incentive Plan, Warrants (as defined below), conversion of the 2L Convertible Notes and the Put Option Premium, and obligations in respect of the Senior Notes would be extinguished and (ii) rights to participate pro rata in the Rights Offering of the 2L Convertible Notes.


•Holders of Other Claims

◦Except as otherwise provided in the Plan of Reorganization, all other claims, including general unsecured claims, will receive treatment that renders them unimpaired under the Bankruptcy Code.

•Existing Equityholders

◦All of the Company's existing common stock and other equity interests will be cancelled without any distribution to the holders of such common stock and other equity interests on account thereof.

◦However, holders of the Company's existing common stock and certain other equity interests that do not object to the Plan of Reorganization or opt out of the releases contained in the Plan of Reorganization (the “Eligible Common Stockholders”) are entitled to receive their ratable share of $1,200 in cash and the package of cashless exercise warrants described below (or in the case of certain holders of equity interests who do not hold through the DTC, cash in an amount equal to $0.01508 per share in lieu of such warrants). As of the date hereof, the Company has 47,790,146 shares of common stock outstanding.

◦The cashless exercise warrants distributable pro rata to the Eligible Common Stockholders (the “Warrants”) will be exercisable for (i) 5% of the New Common Stock issued by the reorganized Company at emergence, with a $300,000 equity value strike price and 4-year term and (ii) 5% of the New Common Stock issued by the reorganized Company at emergence with a $350,000 equity value strike price and 5-year term. The Warrants will be subject to dilution by New Common Stock issued in connection with the Management Incentive Plan, the Put Option Premium, and any conversion of the 2L Convertible Notes.




•Claimants in the Prior Chapter 11 Cases

◦Holders of claims in the Prior Chapter 11 Cases that are classified in Class 6 or Class 8 in the Prior Reorganization Plan, if and when their claims are allowed, that do not object to the Plan of Reorganization or opt out of the releases contained in the Plan of Reorganization will receive an equivalent amount of cash as such Eligible Common Stockholders who do not hold through the DTC. Distributions to holders of such claims in the Prior Chapter 11 Cases after the effective date of the Plan of Reorganization will be capped at $150.


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Nature of operations and summary of significant accounting policies and going concern (Policies)

6 Months Ended

Jun. 30, 2020

Accounting Policies [Abstract]

Nature of operations

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

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, 2019.

The financial information as of June 30, 2020, and for the three and six months ended June 30, 2020 and 2019, is unaudited. The financial information as of December 31, 2019 has been derived from the audited financial statements contained in our Annual Report on Form 10-K for the year ended December 31, 2019. 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 six months ended June 30, 2020 are not necessarily indicative of the results of operations that will be realized for the year ended December 31, 2020.

Reclassifications

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

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 June 30, 2020, cash with a recorded balance totaling approximately $55,445 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

Accounts receivable

In June 2016, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) 2016–13, Financial Instruments–Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments (“ASU 2016–13”), which changes the recognition model for the impairment of financial instruments, including accounts receivable, loans and held-to-maturity debt securities, among others. We adopted ASU 2016–13 using the modified retrospective method effective January 1, 2020. In contrast to previous guidance, which considered current information and events, and only recognized losses when they became probable (an “incurred loss” model), ASU 2016–13 mandates an “expected loss” model. The expected loss model: (i) estimates the risk of loss even when risk is remote, (ii) estimates losses over the contractual life, (iii) considers past events, current conditions and reasonable supported forecasts and (iv) has no recognition threshold. ASU 2016–13 is applicable to our accounts receivable portfolio, particularly those receivables attributable to our joint interest partners which have a higher credit risk than those associated with our traditional customer receivables.

Basis of accounting. Our accounts receivable are carried at gross cost, representing amounts due, less an allowance for expected credit losses. We write off accounts receivable when they are determined to be uncollectible. When we recover amounts that were previously written off, those amounts are offset against the allowance and reduce expense in the year of recovery.

The Company has four portfolio segments constituting its total accounts receivables: (i) joint interest receivables; (ii) commodity sales receivables; (iii) derivative settlement receivables and (iv) other receivables. The table below discloses balances related to these four segments and the allowance:

Oil and natural gas properties

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. Quarterly, 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. 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; 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 Prior Effective Date in 2017, 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 Focus Areas.

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 June 30, 2020, 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. These losses are reflected in “Impairment of oil and gas assets” in our consolidated statements of operations. The ceiling test impairment we recorded in the current year was driven in part by our impairment of unevaluated leasehold in the amount $216,173 and $218,741 for the three and six month periods ending June 30, 2020, respectively. Impairments of leasehold result in a transfer of amounts from unevaluated oil and natural gas properties to the full cost amortization base subsequently impacting the ceiling test.

	Three months ended June 30,			Six months ended June 30,
	2020	2019		2020		2019
Impairment of oil and gas assets	384,639	$	63,593	$	456,010	$	113,315

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 June 30, 2020, and December 31, 2019, were immaterial.

Income taxes

Income taxes

On March 27, 2020, the President of the U.S. signed into law the Coronavirus Aid, Relief, and Economic Security (“CARES”) Act. The CARES Act provides relief to corporate taxpayers by permitting a five-year carryback of 2018-2020 net operating losses (“NOLs”), removing the 80% limitation on the carryback of those NOLs, increasing the Section 163(j) 30% limitation on interest expense deductibility to 50% of adjusted taxable income for 2019 and 2020, and accelerates refunds for minimum tax credit carryforwards, along with a few other provisions. During the three and six months ended June 30, 2020, no material adjustments were made to provision amounts recorded as a result of the enactment of the CARES Act.

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.  The consistent effective tax rate, as disclosed below, is a result of maintaining a valuation allowance against substantially all of our net deferred tax asset.

	Three months ended June 30,				Six months ended June 30,
	2020		2019		2020		2019
Effective income tax rate	0.0	%	0.0	%	0.0	%	0.0	%

Despite the Company’s net loss for the six month period ended June 30, 2020, we did not record any net deferred tax benefit due to the Company’s projected taxable loss for the year ending December 31, 2020. Nor did the Company record a 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 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 June 30, 2020, or December 31, 2019.

As a result of the Prior Reorganization Plan and related transactions, the Company experienced an ownership change within the meaning of Internal Revenue Code (“IRC”) Section 382 on the Prior Effective Date. 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 six month period ended June 30, 2020, or any intervening period since the Prior Effective Date. Since the Prior Effective Date ownership change, the Company has generated additional NOLs and other tax attributes that are not currently subject to an IRC Section 382 limitation. The Company’s ability to use NOLs and other tax attributes to reduce taxable income and income taxes could be materially impacted by a future IRC 382 ownership change. Future transactions involving the Company’s stock, including those outside of the Company’s control, could cause an IRC 382 ownership change resulting in a limitation on tax attributes currently not limited and a more restrictive limitation on tax attributes currently subject to the previous IRC 382 limitation.

Reorganization items

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 resulting from the Prior Chapter 11 Cases and Prior Reorganization Plan. The reorganization items disclosed in our consolidated statement of operations consist of professional fees for continuing legal work to resolve outstanding claims and fees to the U.S. Bankruptcy Trustee, which we will continue to incur until both the Prior Chapter 11 Cases and the Chapter 11 Cases are closed.

Recently issued accounting pronouncements

Recently issued accounting pronouncementsIn December 2019, the FASB issued ASU 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes. This standard eliminates certain exceptions in the existing guidance related to the approach for intraperiod tax allocation, the methodology for calculating income taxes in an interim period, and the recognition of deferred tax liabilities for outside basis differences. The new guidance also clarifies certain aspects of the existing guidance, among other things. The standard is effective for interim and annual periods beginning after December 15, 2020 and shall be applied on either a prospective basis, a retrospective basis for all periods presented, or a modified retrospective basis through a cumulative-effect adjustment to retained earnings depending on which aspects of the new standard are applicable to an entity. The Company is in the process of evaluating the new standard and is unable to estimate its financial impact, if any, at this time.

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Nature of operations and summary of significant accounting policies and going concern (Tables)

6 Months Ended

Jun. 30, 2020

Accounting Policies [Abstract]

Schedule of accounts receivable

	June 30, 2020		December 31, 2019
Joint interests	$	9,992	$	16,664
Commodity sales	14,416		30,819
Derivative settlements	15,540		717
Other	3,249		2,544
Allowance for credit losses	(4,215)		(1,097)
	$	38,982	$	49,647

Schedule of accounts receivable, allowance for credit loss

Our credit loss expense is included as a component of “General and administrative expenses” on our consolidated statement of operations and is as follows:

	Three months ended June 30,				Six months ended June 30,
	2020		2019		2020		2019
Credit losses on receivables	$	1,447	$	(18)	$	2,964	$	(276)

The table below segregates our joint interest receivables based on the amount of revenues payable which can be utilized to offset the receivable balance. We consider this segregation to be a reasonable indicator of credit quality.

Joint interest receivables, gross	June 30, 2020
Accounts which have sufficient related revenue distributions payable to offset entire receivable balance	$	258
Accounts which have related revenue distributions payable but not sufficient to offset entire receivable balance	3,711
Accounts without related revenue distributions payable	6,023
Total	$	9,992

Allowance for credit losses. The table below discloses activity on our receivables allowance account:

	Six months ended June 30, 2020
	Commodity sales		Joint interest		Derivatives		Other		Total
Balance at January 1, 2020	$	—	$	1,097	$	—	$	—	$	1,097
Cumulative effect of accounting standard adoption	154		—		—		—		154
Credit losses	59		2,905		—		—		2,964
Write-offs	—		—		—		—		—
Recoveries	—		—		—		—		—
Balance at June 30, 2020	$	213	$	4,002	$	—	$	—	$	4,215

Schedule of inventories

Inventories consisted of the following:

	June 30, 2020		December 31, 2019
Equipment inventory	$	2,673	$	3,435
Commodities	425		474
Inventory valuation allowance	(642)		(179)
	$	2,456	$	3,730

Schedule of property and equipment, net

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

	June 30, 2020		December 31, 2019
Machinery and equipment	$	3,229	$	3,543
Office and computer equipment	3,606		3,363
Automobiles and trucks	2,469		3,071
Building and improvements	664		693
Furniture and fixtures	8		8
	9,976		10,678
Less accumulated depreciation, amortization and impairment	3,963		3,459
	6,013		7,219
Land	1,935		1,998
	$	7,948	$	9,217

Schedule of assets held for sale

Our held for sale assets are as follows:

	Carrying value at
	June 30, 2020		December 31, 2019
Equipment	$	—	$	1,572
Vehicles	111		488
Real estate	—		800
Total held for sale	$	111	$	2,860

Schedule of unevaluated oil and natural gas properties

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

	June 30, 2020		December 31, 2019
Leasehold acreage	$	135,059	$	334,083
Capitalized interest	6,317		16,785
Wells and facilities in progress of completion	919		20,361
Total unevaluated oil and natural gas properties excluded from amortization	$	142,295	$	371,229

Schedule of impairment of oil and gas properties

These losses are reflected in “Impairment of oil and gas assets” in our consolidated statements of operations. The ceiling test impairment we recorded in the current year was driven in part by our impairment of unevaluated leasehold in the amount $216,173 and $218,741 for the three and six month periods ending June 30, 2020, respectively. Impairments of leasehold result in a transfer of amounts from unevaluated oil and natural gas properties to the full cost amortization base subsequently impacting the ceiling test.

	Three months ended June 30,			Six months ended June 30,
	2020	2019		2020		2019
Impairment of oil and gas assets	384,639	$	63,593	$	456,010	$	113,315

Schedule of disaggregation of revenue

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

	Three months ended June 30,				Six months ended June 30,
	2020		2019		2020		2019
Revenues:
Oil	$	10,384	$	50,990	$	47,410	$	83,792
Natural gas	5,679		10,476		14,334		21,682
Natural gas liquids	3,903		11,025		13,585		20,242
Gross commodity sales	19,966		72,491		75,329		125,716
Transportation and processing	(4,086)		(5,784)		(10,598)		(10,390)
Net commodity sales	$	15,880	$	66,707	$	64,731	$	115,326

Schedule of effective income tax rate

The consistent effective tax rate, as disclosed below, is a result of maintaining a valuation allowance against substantially all of our net deferred tax asset.

	Three months ended June 30,				Six months ended June 30,
	2020		2019		2020		2019
Effective income tax rate	0.0	%	0.0	%	0.0	%	0.0	%

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Earnings per share (Tables)

6 Months Ended

Jun. 30, 2020

Earnings Per Share [Abstract]

Schedule of basic and diluted earnings per share

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

	Three months ended June 30,				Six months ended June 30,
(in thousands, except share and per share data)	2020		2019		2020		2019
Numerator for basic and diluted loss per share
Net loss	$	(438,726)	$	(45,229)	$	(433,809)	$	(148,769)
Denominator for basic loss per share
Weighted average common shares	45,949,797		45,641,797		45,890,041		45,549,518
Denominator for diluted loss per share
Weighted average common shares	45,949,797		45,641,797		45,890,041		45,549,518
Loss per share
Basic	$	(9.55)	$	(0.99)	$	(9.45)	$	(3.27)
Diluted	$	(9.55)	$	(0.99)	$	(9.45)	$	(3.27)
Participating securities excluded from loss per share calculations
Unvested restricted stock units - stock settled	604,789		81,119		604,789		81,119
Unvested restricted stock awards	1,839,381		706,821		1,839,381		706,821

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Supplemental disclosures to the consolidated statements of cash flows (Tables)

6 Months Ended

Jun. 30, 2020

Supplemental Cash Flow Elements [Abstract]

Schedule of supplemental disclosures to the consolidated statements of cash flows

	Six months ended June 30,
	2020		2019
Net cash provided by operating activities included:
Cash payments for interest	$	16,942	$	16,328
Interest capitalized	(3,900)		(6,613)
Cash payments for reorganization items	1,189		857
Non-cash investing activities included:
Asset retirement obligation additions and revisions	133		386
Financing lease right of use asset additions (see Note 5: Leases)	—		1,387
Change in accrued oil and gas capital expenditures	(22,418)		7,024

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Debt (Tables)

6 Months Ended

Jun. 30, 2020

Debt Disclosure [Abstract]

Schedule of debt

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

	June 30, 2020		December 31, 2019
8.75% Senior Notes due 2023	$	300,000	$	300,000
Credit facility	225,000		130,000
Installment note payable	—		371
Financing lease obligations	1,442		1,653
Unamortized debt issuance costs	(4,154)		(10,038)
Total debt, net	522,288		421,986
Less current portion	521,292		594
Total long-term debt, net	$	996	$	421,392

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Leases (Tables)

6 Months Ended

Jun. 30, 2020

Leases [Abstract]

Schedule of leases as presented on balance sheet

Our operating lease and financing lease assets and liabilities are recorded on our balance sheet as of June 30, 2020 as:

	As of June 30, 2020
	Operating leases		Financing leases
Right of use asset:
Right of use assets from operating leases	$	1,744	$	—
Plant, property and equipment, net	—		1,428
Total lease assets	$	1,744	$	1,428
Lease liability:
Account payable and accrued liabilities	$	1,331	$	—
Long-term debt and financing leases, classified as current	—		446
Long-term debt and financing leases, less current maturities	—		996
Noncurrent operating lease obligations	234		—
Total lease liabilities	$	1,565	$	1,442

Schedule of lease cost

Our income, expenses and cash flows related to our leases is as follows:

	Three months ended June 30,				Six months ended June 30,
	2020		2019		2020		2019
Lease cost
Finance lease cost:
Amortization of right-of-use assets	$	114	$	749	$	231	$	1,442
Interest on lease liabilities	26		117		53		230
Operating lease cost	389		308		779		616
Short-term lease cost	92		154		310		283
Variable lease cost	—		95		—		190
Sublease income	—		(1,198)		—		(2,396)
Total lease cost	$	621	$	225	$	1,373	$	365
Capitalized operating lease cost (1)	$	—	$	3,371	$	—	$	6,706
Other information
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows for finance leases	$	(26)	$	(117)	$	(53)	$	(230)
Operating cash flows for operating leases	(344)		(308)		(689)		(616)
Investing cash flows for operating leases	—		(2,965)		—		(3,988)
Financing cash flows for finance leases	(107)		(746)		(212)		(1,445)
Right-of-use assets obtained in exchange for new finance lease liabilities	—		717		—		1,387

________________________________

(1)The operating lease cost is related to drilling rigs with terms longer than 30 days and is capitalized as part of oil and natural gas properties on our balance sheets.

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Derivative instruments (Tables)

6 Months Ended

Jun. 30, 2020

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of derivatives outstanding

The following table summarizes our crude oil derivatives outstanding as of June 30, 2020:

		Weighted average fixed price per Bbl
Period and type of contract	Volume MBbls	Swaps
2020
Oil swaps	1,026	$	50.56
Oil roll swaps	180	$	0.30
2021
Oil swaps	689	$	46.24
Oil roll swaps	150	$	0.30

The following table summarizes our natural gas derivatives outstanding as of June 30, 2020:

Period and type of contract	Volume BBtu	Weighted average fixed price per MMBtu
2020
Natural gas swaps	3,000	$	2.75
Natural gas basis swaps	3,000	$	(0.46)

Schedule of derivative instruments recorded on the balance sheet at fair value

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 June 30, 2020						As of December 31, 2019
	Assets		Liabilities		Net value		Assets		Liabilities		Net value
Natural gas derivative contracts	$	2,288	$	(500)	$	1,788	$	3,552	$	(1)	$	3,551
Crude oil derivative contracts	15,399		—		15,399		391		(22,196)		(21,805)
NGL derivative contracts	—		—		—		2,868		(699)		2,169
Total derivative instruments	17,687		(500)		17,187		6,811		(22,896)		(16,085)
Less:
Netting adjustments (1)	(500)		500		—		(5,864)		5,864		—
Derivative instruments - current	15,197		—		15,197		947		(11,957)		(11,010)
Derivative instruments - long-term	$	1,990	$	—	$	1,990	$	—	$	(5,075)	$	(5,075)

________________________________

(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.

Schedule of derivative gains (losses) in the consolidated statements of operations

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

	Three months ended June 30,				Six months ended June 30,
	2020		2019		2020		2019
Change in fair value of commodity price derivatives	$	(35,934)	$	17,596	$	33,272	$	(33,935)
Net settlements received on commodity price derivatives	22,915		138		32,089		653
Total derivative gains (losses)	$	(13,019)	$	17,734	$	65,361	$	(33,282)

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Fair value measurements (Tables)

6 Months Ended

Jun. 30, 2020

Fair Value Disclosures [Abstract]

Schedule of fair value hierarchy for our financial assets and liabilities

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

	As of June 30, 2020						As of December 31, 2019
	Derivative assets		Derivative liabilities		Net assets (liabilities)		Derivative assets		Derivative liabilities		Net assets (liabilities)
Significant other observable inputs (Level 2)	$	17,687	$	—	$	17,687	$	6,576	$	(22,895)	$	(16,319)
Significant unobservable inputs (Level 3)	—		(500)		(500)		235		(1)		234
Netting adjustments (1)	(500)		500		—		(5,864)		5,864		—
	$	17,187	$	—	17,187		$	947	$	(17,032)	$	(16,085)

________________________________

(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.

Schedule of level 3 rollforward

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:

	Six months ended June 30,
Net derivative assets (liabilities)	2020		2019
Beginning balance	$	234	$	30
Realized and unrealized gains included in derivative losses	1,033		441
Settlements (received) paid	(1,767)		116
Ending balance	$	(500)	$	587
(Losses) gains relating to instruments still held at the reporting date included in derivative gains (losses) for the period	$	(430)	$	742

Schedule of inflation and discount rate assumptions

The table below discloses the inflation and discount rate assumptions for the periods presented:

	Six months ended June 30,
	2020		2019
Inflation rate	2.21	%	2.25	%
Credit-adjusted risk-free discount rate (low)	25.00	%	12.35	%
Credit-adjusted risk-free discount rate (high)	25.00	%	14.60	%

Schedule of carrying value and estimated fair value of debts

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

	June 30, 2020				December 31, 2019
Level 2	Carrying value (1)		Estimated fair value		Carrying value (1)		Estimated fair value
8.75% Senior Notes due 2023	$	300,000	$	30,000	$	300,000	$	133,050
Credit facility	225,000		225,000		130,000		130,000
Other secured debt (2)	—		—		371		371

________________________________

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

(2)The balance December 31, 2019, consisted of only equipment installment notes

Schedule of offsetting assets

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. 

	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
June 30, 2020
Derivative assets	$	17,687	$	(500)	$	17,187	$	—	$	(17,187)	$	—
Derivative liabilities	(500)		500		—		—		—		—
	$	17,187	$	—	$	17,187	$	—	$	(17,187)	$	—
December 31, 2019
Derivative assets	$	6,811	$	(5,864)	$	947	$	—	$	(947)	$	—
Derivative liabilities	(22,896)		5,864		(17,032)		—		947		(16,085)
	$	(16,085)	$	—	$	(16,085)	$	—	$	—	$	(16,085)

________________________________

(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.

Schedule of offsetting liabilities

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. 

	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
June 30, 2020
Derivative assets	$	17,687	$	(500)	$	17,187	$	—	$	(17,187)	$	—
Derivative liabilities	(500)		500		—		—		—		—
	$	17,187	$	—	$	17,187	$	—	$	(17,187)	$	—
December 31, 2019
Derivative assets	$	6,811	$	(5,864)	$	947	$	—	$	(947)	$	—
Derivative liabilities	(22,896)		5,864		(17,032)		—		947		(16,085)
	$	(16,085)	$	—	$	(16,085)	$	—	$	—	$	(16,085)

________________________________

(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.

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Asset retirement obligations (Tables)

6 Months Ended

Jun. 30, 2020

Asset Retirement Obligation Disclosure [Abstract]

Summary of asset retirement obligations

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

Balance at January 1, 2020	$	23,156
Liabilities incurred in current period	84
Liabilities settled or disposed in current period	(419)
Revisions in estimated cash flows	49
Accretion expense	649
Balance at June 30, 2020	$	23,519
Less current portion included in accounts payable and accrued liabilities	2,107
Asset retirement obligations, long-term	$	21,412

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Deferred compensation (Tables)

6 Months Ended

Jun. 30, 2020

Share-based Payment Arrangement, Noncash Expense [Abstract]

Schedule of amounts related to cash LTIP

A summary of compensation expense for our cash awards is presented below:

	Three months ended June 30,				Six months ended June 30,
	2020		2019		2020		2019
Cash LTIP expense (net of amounts capitalized)	$	187	$	67	$	354	$	158

Schedule of rollforward of unvested deferred compensation

A summary of our restricted share activity 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, 2020	$	5.41	1,069,505			$	1.53	1,089,343
Granted	$	—	—			$	—	—
Vested	$	15.71	(203,888)	$	130	$	—	—
Forfeited	$	8.87	(82,658)			$	6.94	(20,833)
Cancelled	$	20.05	(12,088)			$	—	—
Unvested and outstanding at June 30, 2020	$	2.09	770,871			$	1.33	1,068,510

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, 2020	$	2.41	638,383			$	1.36	390,000
Granted	$	1.95	4,500			$	—	—
Vested	$	—	—	$	—	$	—	—
Forfeited	$	1.56	(228,094)			$	1.36	(200,000)
Unvested and outstanding at June 30, 2020	$	2.87	414,789			$	1.36	190,000

	Liability classified RSUs
	Weighted average award date fair value		Restricted units	Vest date fair value
	($ per share)
Unvested and outstanding at January 1, 2020	$	4.57	75,779
Granted	$	—	—
Vested	$	1.33	(60,000)	$	41
Forfeited	$	17.66	(1,515)
Unvested and outstanding at June 30, 2020	$	16.83	14,264

Schedule of stock-based compensation cost

Stock-based compensation expense is as follows for the periods indicated:

	Three months ended June 30,				Six months ended June 30,
	2020		2019		2020		2019
Stock-based compensation cost	$	101	$	1,260	$	771	$	2,720
Less: stock-based compensation cost capitalized	(7)		(399)		(281)		(1,025)
Stock-based compensation expense	$	94	$	861	$	490	$	1,695
Number of vested shares repurchased or settled in cash	92,649		126,231		96,505		206,653
Payments for stock-based compensation	53		708		59		1,171

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Nature of operations and summary of significant accounting policies and going concern (Cash and Cash Equivalents and Accounts Receivable) (Details) $ in Thousands	6 Months Ended
	Jun. 30, 2020 USD ($) segment	Dec. 31, 2019 USD ($)
Segment Reporting Information [Line Items]
Cash held	$ 55,445
Number of portfolio segments | segment	4
Components of accounts receivable
Accounts receivable, gross	$ 43,197	$ 50,744
Allowance for credit losses	(4,215)	(1,097)
Accounts receivable, net	38,982	49,647
Joint interests
Components of accounts receivable
Accounts receivable, gross	9,992	16,664
Allowance for credit losses	(4,002)	(1,097)
Commodity sales
Components of accounts receivable
Accounts receivable, gross	14,416	30,819
Allowance for credit losses	$ (213)	0
Commodity sales | Customer Concentration Risk | Sales
Components of accounts receivable
Concentration risk, percentage	75.00%
Commodity sales | Credit evaluations | Sales
Components of accounts receivable
Concentration risk, percentage	80.00%
Derivative settlements
Components of accounts receivable
Accounts receivable, gross	$ 15,540	717
Allowance for credit losses	0	0
Other
Components of accounts receivable
Accounts receivable, gross	3,249	2,544
Allowance for credit losses	$ 0	$ 0

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Nature of operations and summary of significant accounting policies and going concern (Credit Loss) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Dec. 31, 2019
Segment Reporting Information [Line Items]
Total					$ 43,197	$ 50,744
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance at January 1, 2020	$ 4,215		$ 4,215		4,215	1,097
Credit losses	1,447	$ (18)	2,964	$ (276)
Write-offs			0
Recoveries			0
Balance at June 30, 2020	4,215		4,215
Cumulative Effect, Period of Adoption, Adjustment
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance at January 1, 2020						154
Commodity sales
Segment Reporting Information [Line Items]
Total					14,416	30,819
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance at January 1, 2020	213		213		213	0
Credit losses			59
Write-offs			0
Recoveries			0
Balance at June 30, 2020	213		213
Commodity sales | Cumulative Effect, Period of Adoption, Adjustment
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance at January 1, 2020						154
Joint interests
Segment Reporting Information [Line Items]
Accounts which have sufficient related revenue distributions payable to offset entire receivable balance					258
Accounts which have related revenue distributions payable but not sufficient to offset entire receivable balance					3,711
Accounts without related revenue distributions payable					6,023
Total					9,992	16,664
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance at January 1, 2020	4,002		4,002		4,002	1,097
Credit losses			2,905
Write-offs			0
Recoveries			0
Balance at June 30, 2020	4,002		4,002
Joint interests | Cumulative Effect, Period of Adoption, Adjustment
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance at January 1, 2020						0
Derivatives
Segment Reporting Information [Line Items]
Total					15,540	717
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance at January 1, 2020	0		0		0	0
Credit losses			0
Write-offs			0
Recoveries			0
Balance at June 30, 2020	0		0
Derivatives | Cumulative Effect, Period of Adoption, Adjustment
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance at January 1, 2020						0
Other
Segment Reporting Information [Line Items]
Total					3,249	2,544
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance at January 1, 2020	0		0		$ 0	0
Credit losses			0
Write-offs			0
Recoveries			0
Balance at June 30, 2020	$ 0		$ 0
Other | Cumulative Effect, Period of Adoption, Adjustment
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance at January 1, 2020						$ 0

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Nature of operations and summary of significant accounting policies and going concern (Inventories) (Details) - USD ($) $ in Thousands	3 Months Ended	6 Months Ended
	Jun. 30, 2020	Jun. 30, 2020	Dec. 31, 2019
Energy Related Inventory
Equipment inventory	$ 2,673	$ 2,673	$ 3,435
Commodities	425	425	474
Inventory valuation allowance	(642)	(642)	(179)
Inventories, net	2,456	2,456	$ 3,730
Inventory impairment	$ 310	$ 463

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Nature of operations and summary of significant accounting policies and going concern (Property and Equipment, Net) (Details) - USD ($) $ in Thousands	Jun. 30, 2020	Dec. 31, 2019
Property, Plant and Equipment [Line Items]
Property and equipment, excluding land, gross	$ 9,976	$ 10,678
Less accumulated depreciation, amortization and impairment	3,963	3,459
Property and equipment, excluding land, net	6,013	7,219
Land	1,935	1,998
Property and equipment, net	7,948	9,217
Machinery and equipment
Property, Plant and Equipment [Line Items]
Property and equipment, excluding land, gross	3,229	3,543
Office and computer equipment
Property, Plant and Equipment [Line Items]
Property and equipment, excluding land, gross	3,606	3,363
Automobiles and trucks
Property, Plant and Equipment [Line Items]
Property and equipment, excluding land, gross	2,469	3,071
Building and improvements
Property, Plant and Equipment [Line Items]
Property and equipment, excluding land, gross	664	693
Furniture and fixtures
Property, Plant and Equipment [Line Items]
Property and equipment, excluding land, gross	$ 8	$ 8

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Nature of operations and summary of significant accounting policies and going concern (Assets Held for Sale) (Details) - USD ($) $ in Thousands	Jun. 30, 2020	Dec. 31, 2019
Long Lived Assets Held-for-sale [Line Items]
Held for sale assets	$ 111	$ 2,860
Equipment
Long Lived Assets Held-for-sale [Line Items]
Held for sale assets	0	1,572
Vehicles
Long Lived Assets Held-for-sale [Line Items]
Held for sale assets	111	488
Real estate
Long Lived Assets Held-for-sale [Line Items]
Held for sale assets	$ 0	$ 800

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Nature of operations and summary of significant accounting policies and going concern (Unevaluated Oil and Natural Gas Properties) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019	Dec. 31, 2019
Capitalized Costs of Unproved Properties Excluded from Amortization, Cumulative [Abstract]
Leasehold acreage	$ 135,059		$ 135,059		$ 334,083
Capitalized interest	6,317		6,317		16,785
Wells and facilities in progress of completion	919		919		20,361
Total unevaluated oil and natural gas properties excluded from amortization	142,295		142,295		$ 371,229
Impairment of leasehold	216,173		218,741
Impairment of oil and gas assets	$ 384,639	$ 63,593	$ 456,010	$ 113,315

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Nature of operations and summary of significant accounting policies and going concern (Revenue Recognition) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
Disaggregation of Revenue [Line Items]
Gross commodity sales	$ 19,966	$ 72,491	$ 75,329	$ 125,716
Transportation and processing	(4,086)	(5,784)	(10,598)	(10,390)
Net commodity sales	15,880	66,707	64,731	115,326
Oil
Disaggregation of Revenue [Line Items]
Gross commodity sales	10,384	50,990	47,410	83,792
Natural gas
Disaggregation of Revenue [Line Items]
Gross commodity sales	5,679	10,476	14,334	21,682
Natural gas liquids
Disaggregation of Revenue [Line Items]
Gross commodity sales	$ 3,903	$ 11,025	$ 13,585	$ 20,242

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Nature of operations and summary of significant accounting policies and going concern (Income Taxes) (Details) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019	Dec. 31, 2019
Accounting Policies [Abstract]
Effective income tax rate	0.00%	0.00%	0.00%	0.00%
Deferred tax benefit			$ 0
Uncertain tax positions	$ 0		0		$ 0
Net operating loss carryforwards subject to limitation	$ 760,067,000		$ 760,067,000

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Earnings per share (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended				6 Months Ended
	Jun. 30, 2020	Mar. 31, 2020	Jun. 30, 2019	Mar. 31, 2019	Jun. 30, 2020	Jun. 30, 2019
Numerator for basic and diluted loss per share
Net loss	$ (438,726)	$ 4,917	$ (45,229)	$ (103,540)	$ (433,809)	$ (148,769)
Denominator for basic loss per share
Weighted average common shares - Basic for Class A and Class B (in shares)	45,949,797		45,641,797		45,890,041	45,549,518
Denominator for diluted loss per share
Weighted average common shares - Diluted for Class A and Class B (in shares)	45,949,797		45,641,797		45,890,041	45,549,518
Loss per share
Basic for Class A and Class B (in dollars per share)	$ (9.55)		$ (0.99)		$ (9.45)	$ (3.27)
Diluted for Class A and Class B (in dollars per share)	$ (9.55)		$ (0.99)		$ (9.45)	$ (3.27)
Unvested restricted stock units - stock settled
Loss per share
Participating securities excluded from earnings per share calculations (in shares)	604,789		81,119		604,789	81,119
Unvested restricted stock awards
Loss per share
Participating securities excluded from earnings per share calculations (in shares)	1,839,381		706,821		1,839,381	706,821

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Supplemental disclosures to the consolidated statements of cash flows (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019
Net cash provided by operating activities included:
Cash payments for interest	$ 16,942	$ 16,328
Interest capitalized	(3,900)	(6,613)
Cash payments for reorganization items	1,189	857
Non-cash investing activities included:
Asset retirement obligation additions and revisions	133	386
Financing lease right of use asset additions (see Note 5: Leases)	0	1,387
Change in accrued oil and gas capital expenditures	$ (22,418)	$ 7,024

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Debt (Components of Debt) (Details) - USD ($) $ in Thousands	Jun. 30, 2020	Apr. 02, 2020	Dec. 31, 2019	Jun. 29, 2018
Debt Instrument [Line Items]
8.75% Senior Notes due 2023	$ 300,000		$ 300,000
Credit facility	225,000	$ 250,000	130,000
Installment note payable	0		371
Financing lease obligations	1,442		1,653
Unamortized debt issuance costs	(4,154)		(10,038)
Total debt, net	522,288		421,986
Less current portion	521,292		594
Total long-term debt, net	$ 996		$ 421,392
8.75% Senior Notes due 2023
Debt Instrument [Line Items]
Debt instrument, interest rate stated percentage				8.75%

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Debt (Credit Agreement) (Details)				1 Months Ended		6 Months Ended
	Jul. 15, 2020	Apr. 02, 2020 USD ($)	Apr. 01, 2020 USD ($)	Jul. 31, 2020 USD ($)	Jun. 01, 2020 USD ($) payment	Jun. 30, 2020 USD ($) qtr	Aug. 03, 2020 USD ($)	Apr. 14, 2020 installment	Apr. 03, 2020 USD ($)	Dec. 31, 2019 USD ($)
Line of Credit Facility [Line Items]
Credit facility maximum borrowing amount						$ 750,000,000
Current borrowing capacity		$ 325,000,000				175,000,000			$ 175,000,000
Additional borrowings under Credit Agreement		90,000,000	$ 15,000,000
Credit facility		$ 250,000,000				$ 225,000,000				$ 130,000,000
Borrowing base deficiency, Credit Agreement									$ 75,000,000
Number of installment payments to eliminate borrowing base deficiency | installment								6
Number of payment for borrowing base deficiency | payment					2
Payment for borrowing base deficiency, amount					$ 25,000,000
Subsequent event
Line of Credit Facility [Line Items]
Payment for borrowing base deficiency, amount				$ 12,500,000
Debt interest payment, default amount							$ 12,500,000
Debt Instrument, debt default, grace period	30 days
Credit agreement
Line of Credit Facility [Line Items]
Number of consecutive quarters | qtr						4
Minimum | Credit agreement
Line of Credit Facility [Line Items]
Current Ratio covenant						1.0
Maximum | Credit agreement
Line of Credit Facility [Line Items]
Ratio of debt to EBITDAX						4.0
Adjusted LIBO Rate | Credit agreement
Line of Credit Facility [Line Items]
Weighted average interest rate						3.19%

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Debt (Senior Notes) (Details) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019	Aug. 03, 2020	Jul. 30, 2020	Jul. 15, 2020	Jun. 29, 2018
Debt Instrument [Line Items]
Write-off of Senior Note issuance costs	$ 4,420,000	$ 0	$ 4,420,000	$ 0
Subsequent event
Debt Instrument [Line Items]
Debt interest payment, default amount					$ 12,500,000
8.75% Senior Notes due 2023
Debt Instrument [Line Items]
Aggregate principal amount								$ 300,000,000
Debt instrument, interest rate								8.75%
8.75% Senior Notes due 2023 | Subsequent event
Debt Instrument [Line Items]
Debt interest payment, default amount							$ 13,125,000
Initial Consenting Noteholders, percentage of principle amount of outstanding Senior Notes						75.00%

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Leases (Short Term Leases) (Details)	6 Months Ended
	Jun. 30, 2020
Minimum
Lessee, Lease, Description [Line Items]
Short term leases, term	1 month
Maximum
Lessee, Lease, Description [Line Items]
Short term leases, term	6 months

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Leases (Balance Sheet Disclosures) (Details) - USD ($) $ in Thousands	Jun. 30, 2020	Dec. 31, 2019
Operating leases
Right of use assets from operating leases	$ 1,744	$ 2,444
Account payable and accrued liabilities	1,331
Noncurrent operating lease obligations	234	917
Total lease liabilities	1,565
Financing leases
Plant, property and equipment, net	1,428
Long-term debt and financing leases, classified as current	446
Long-term debt and financing leases, less current maturities	996
Total lease liabilities	$ 1,442	$ 1,653
Finance Lease, Right-of-Use Asset, Statement of Financial Position [Extensible List]	us-gaap:PropertyPlantAndEquipmentAndFinanceLeaseRightOfUseAssetAfterAccumulatedDepreciationAndAmortization	us-gaap:PropertyPlantAndEquipmentAndFinanceLeaseRightOfUseAssetAfterAccumulatedDepreciationAndAmortization
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List]	us-gaap:AccountsPayableAndOtherAccruedLiabilitiesCurrent	us-gaap:AccountsPayableAndOtherAccruedLiabilitiesCurrent
Finance Lease, Liability, Current, Statement of Financial Position [Extensible List]	us-gaap:LongTermDebtAndCapitalLeaseObligationsCurrent	us-gaap:LongTermDebtAndCapitalLeaseObligationsCurrent
Finance Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]	us-gaap:LongTermDebtAndCapitalLeaseObligations	us-gaap:LongTermDebtAndCapitalLeaseObligations

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Leases (Lease Assets and Liabilities) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
Finance lease cost:
Amortization of right-of-use assets	$ 114	$ 749	$ 231	$ 1,442
Interest on lease liabilities	26	117	53	230
Operating lease cost	389	308	779	616
Short-term lease cost	92	154	310	283
Variable lease cost	0	95	0	190
Sublease income	0	(1,198)	0	(2,396)
Total lease cost	621	225	1,373	365
Capitalized operating lease cost	0	3,371	0	6,706
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows for finance leases	(26)	(117)	(53)	(230)
Operating cash flows for operating leases	(344)	(308)	(689)	(616)
Investing cash flows for operating leases	0	(2,965)	0	(3,988)
Financing cash flows for finance leases	(107)	(746)	(212)	(1,445)
Right-of-use assets obtained in exchange for new finance lease liabilities	$ 0	$ 717	$ 0	$ 1,387
Operating lease cost, drilling rigs, minimum term			30 days

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Derivative instruments (Summary of Derivatives Outstanding) (Details)	Jun. 30, 2020 bbl MMBTU $ / bbl $ / BTU
Oil swaps | Derivative Maturing In 2020 | Crude oil derivatives
Derivative [Line Items]
Volume (in MBbl, MMBtu, or Gallon) | bbl	1,026
Weighted average fixed price (in usd per unit) | $ / bbl	50.56
Oil swaps | Derivative Maturing In 2021 | Crude oil derivatives
Derivative [Line Items]
Volume (in MBbl, MMBtu, or Gallon) | bbl	689
Weighted average fixed price (in usd per unit) | $ / bbl	46.24
Oil roll swaps | Derivative Maturing In 2020 | Crude oil derivatives
Derivative [Line Items]
Volume (in MBbl, MMBtu, or Gallon) | bbl	180
Weighted average fixed price (in usd per unit) | $ / bbl	0.30
Oil roll swaps | Derivative Maturing In 2021 | Crude oil derivatives
Derivative [Line Items]
Volume (in MBbl, MMBtu, or Gallon) | bbl	150
Weighted average fixed price (in usd per unit) | $ / bbl	0.30
Natural gas swaps | Derivative Maturing In 2020 | Natural gas derivatives
Derivative [Line Items]
Volume (in MBbl, MMBtu, or Gallon) | MMBTU	3,000
Weighted average fixed price (in usd per unit) | $ / BTU	2.75
Natural gas basis swaps | Derivative Maturing In 2020 | Natural gas derivatives
Derivative [Line Items]
Volume (in MBbl, MMBtu, or Gallon) | MMBTU	3,000
Weighted average fixed price (in usd per unit) | $ / BTU	0.46

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Derivative instruments (Balance Sheet at Fair Value) (Details) - USD ($) $ in Thousands	Jun. 30, 2020	Dec. 31, 2019
Fair value of derivative instruments
Derivative assets, gross	$ 17,687	$ 6,811
Derivative liabilities, gross	(500)	(22,896)
Derivative assets (liabilities), net	17,187	(16,085)
Derivative assets, netting adjustments	(500)	(5,864)
Derivative liabilities, netting adjustments	500	5,864
Current derivative assets, net	15,197	947
Current derivative liabilities, net	0	(11,957)
Current derivative assets (liabilities), net	15,197	(11,010)
Long-term derivative assets, net	1,990	0
Long-term derivative liabilities, net	0	(5,075)
Long-term derivative assets (liabilities), net	1,990	(5,075)
Natural gas derivative contracts
Fair value of derivative instruments
Derivative assets, gross	2,288	3,552
Derivative liabilities, gross	(500)	(1)
Derivative assets (liabilities), net	1,788	3,551
Crude oil derivative contracts
Fair value of derivative instruments
Derivative assets, gross	15,399	391
Derivative liabilities, gross	0	(22,196)
Derivative assets (liabilities), net	15,399	(21,805)
NGL derivative contracts
Fair value of derivative instruments
Derivative assets, gross	0	2,868
Derivative liabilities, gross	0	(699)
Derivative assets (liabilities), net	$ 0	$ 2,169

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Derivative instruments (Derivative Gains (Losses) in the Consolidated Statements of Operations) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Change in fair value of commodity price derivatives	$ (35,934)	$ 17,596	$ 33,272	$ (33,935)
Net settlements received on commodity price derivatives	22,915	138	32,089	653
Total derivative gains (losses)	$ (13,019)	$ 17,734	$ 65,361	$ (33,282)

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Fair value measurements (Recurring) (Details) - USD ($) $ in Thousands	Jun. 30, 2020	Dec. 31, 2019
Fair Value Hierarchy for Financial Instruments Measured at Fair Value on a Recurring Basis
Derivative assets, gross	$ 17,687	$ 6,811
Derivative liabilities, gross	(500)	(22,896)
Derivative assets (liabilities), net	17,187	(16,085)
Derivative assets, amount offset	(500)	(5,864)
Derivative liabilities, amounts offset	500	5,864
Derivative assets, net	17,187	947
Derivative liabilities, net	0	(17,032)
Recurring Fair Value Measurements
Fair Value Hierarchy for Financial Instruments Measured at Fair Value on a Recurring Basis
Derivative assets (liabilities), net	17,187	(16,085)
Derivative assets, amount offset	(500)	(5,864)
Derivative liabilities, amounts offset	500	5,864
Derivative assets, net	17,187	947
Derivative liabilities, net	0	(17,032)
Recurring Fair Value Measurements | Significant other observable inputs (Level 2)
Fair Value Hierarchy for Financial Instruments Measured at Fair Value on a Recurring Basis
Derivative assets, gross	17,687	6,576
Derivative liabilities, gross	0	(22,895)
Derivative assets (liabilities), net	17,687	(16,319)
Recurring Fair Value Measurements | Significant unobservable inputs (Level 3)
Fair Value Hierarchy for Financial Instruments Measured at Fair Value on a Recurring Basis
Derivative assets, gross	0	235
Derivative liabilities, gross	(500)	(1)
Derivative assets (liabilities), net	$ (500)	$ 234

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Fair value measurements (Level 3 Rollforward) (Details) - Recurring Fair Value Measurements - Significant unobservable inputs (Level 3) - Derivative - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019
Level 3 Rollforward
Beginning balance	$ 234	$ 30
Realized and unrealized gains included in derivative losses	1,033	441
Settlements (received) paid	(1,767)	116
Ending balance	(500)	587
(Losses) gains relating to instruments still held at the reporting date included in derivative gains (losses) for the period	$ (430)	$ 742

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Fair value measurements (Inflation and Discount Rate) (Details) - Significant Unobservable Inputs - Nonrecurring Fair Value Measurements	Jun. 30, 2020	Jun. 30, 2019
Inflation rate
Nonrecurring Fair Value Measurements
Asset retirement obligations, measurement input	0.0221	0.0225
Credit- adjusted risk-free discount rate | Minimum
Nonrecurring Fair Value Measurements
Asset retirement obligations, measurement input	0.2500	0.1235
Credit- adjusted risk-free discount rate | Maximum
Nonrecurring Fair Value Measurements
Asset retirement obligations, measurement input	0.2500	0.1460

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Fair value measurements (Other Financial Instruments) (Details) - USD ($) $ in Thousands	Jun. 30, 2020	Dec. 31, 2019	Jun. 29, 2018
8.75% Senior Notes due 2023
Fair Value of Other Financial Instruments
Debt instrument, interest rate			8.75%
Significant other observable inputs (Level 2) | Senior Notes | 8.75% Senior Notes due 2023 | Carrying value
Fair Value of Other Financial Instruments
Debt	$ 300,000	$ 300,000
Significant other observable inputs (Level 2) | Senior Notes | 8.75% Senior Notes due 2023 | Estimated fair value
Fair Value of Other Financial Instruments
Debt	30,000	133,050
Significant other observable inputs (Level 2) | Credit facility | Carrying value
Fair Value of Other Financial Instruments
Debt	225,000	130,000
Significant other observable inputs (Level 2) | Credit facility | Estimated fair value
Fair Value of Other Financial Instruments
Debt	225,000	130,000
Significant other observable inputs (Level 2) | Other secured debt | Carrying value
Fair Value of Other Financial Instruments
Debt	0	371
Significant other observable inputs (Level 2) | Other secured debt | Estimated fair value
Fair Value of Other Financial Instruments
Debt	$ 0	$ 371

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Fair value measurements (Counterparty Credit Risk) (Details)	Jun. 30, 2020 financial_institutions
Concentration of Counterparty Credit Risk
Counterparty Credit Risk
Derivative contracts, number of counterparties	5

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Fair value measurements (Derivatives Offset in Balance Sheet) (Details) - USD ($) $ in Thousands	Jun. 30, 2020	Dec. 31, 2019
Fair Value Disclosures [Abstract]
Derivative assets, gross	$ 17,687	$ 6,811
Derivative assets, amount offset	(500)	(5,864)
Derivative assets, net	17,187	947
Derivative assets, not offset	0	0
Credit facility balance available to offset net derivative assets	(17,187)	(947)
Derivative asset, net	0	0
Derivative liabilities, gross	(500)	(22,896)
Derivative liabilities, amounts offset	500	5,864
Derivative liabilities, net	0	(17,032)
Derivative liabilities, not offset	0	0
Derivative liabilities, outstanding under credit facility	0	947
Derivative liability, net	0	(16,085)
Derivative asset (liability), gross	17,187	(16,085)
Derivative asset (liability), amount offset	0	0
Derivative asset (liability), net	17,187	(16,085)
Derivative asset (liability) not offset	0	0
Derivative asset (liability). outstanding under credit facility	(17,187)	0
Derivative asset (liability), net	$ 0	$ (16,085)

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Asset retirement obligations (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2020	Dec. 31, 2019
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	$ 23,156
Liabilities incurred in current period	84
Liabilities settled or disposed in current period	(419)
Revisions in estimated cash flows	49
Accretion expense	649
Ending balance	23,519
Less current portion included in accounts payable and accrued liabilities	2,107
Asset retirement obligations, long-term	$ 21,412	$ 21,073

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Deferred compensation (Cash Awards) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items]
Vesting period			3 years
Cash LTIP expense (net of amounts capitalized)	$ 187	$ 67	$ 354	$ 158
Cash LTIP
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items]
Outstanding liability accrued	$ 1,366		$ 1,366
Minimum
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items]
Vesting period			1 year
Maximum
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items]
Vesting period			4 years

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Deferred compensation (Equity Awards) (Details) - $ / shares	Jun. 30, 2020	Dec. 31, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common Class A
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common stock, par value (in dollars per share)		$ 0.01
Common Class A | Management Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares issued or reserved for issuance (in shares)		3,500,000

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Deferred compensation (Restricted Stock Awards) (Details) - Management Incentive Plan $ / shares in Units, $ in Thousands	6 Months Ended
	Jun. 30, 2020 USD ($) $ / shares shares
Time Shares
Weighted average award date fair value
Unvested and outstanding at beginning of period (in dollars per share) | $ / shares	$ 5.41
Granted (in dollars per share) | $ / shares	0
Vested (in dollars per share) | $ / shares	15.71
Forfeited (in dollars per share) | $ / shares	8.87
Cancelled (in dollars per share) | $ / shares	20.05
Unvested and outstanding at end of period (in dollars per share) | $ / shares	$ 2.09
Restricted shares
Unvested and outstanding at beginning of period (in shares) | shares	1,069,505
Granted (in shares) | shares	0
Vested (in shares) | shares	(203,888)
Forfeited (in shares) | shares	(82,658)
Cancelled (in shares) | shares	(12,088)
Unvested and outstanding at end of period (in shares) | shares	770,871
Vest date fair value | $	$ 130
Performance Shares
Weighted average award date fair value
Unvested and outstanding at beginning of period (in dollars per share) | $ / shares	$ 1.53
Granted (in dollars per share) | $ / shares	0
Vested (in dollars per share) | $ / shares	0
Forfeited (in dollars per share) | $ / shares	6.94
Cancelled (in dollars per share) | $ / shares	0
Unvested and outstanding at end of period (in dollars per share) | $ / shares	$ 1.33
Restricted shares
Unvested and outstanding at beginning of period (in shares) | shares	1,089,343
Granted (in shares) | shares	0
Vested (in shares) | shares	0
Forfeited (in shares) | shares	(20,833)
Cancelled (in shares) | shares	0
Unvested and outstanding at end of period (in shares) | shares	1,068,510

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Deferred compensation (Restricted Stock Units) (Details) - Employee LTIP $ / shares in Units, $ in Thousands	6 Months Ended
	Jun. 30, 2020 USD ($) $ / shares shares
Liability classified RSUs
Weighted average award date fair value
Unvested and outstanding at beginning of period (in dollars per share) | $ / shares	$ 4.57
Granted (in dollars per share) | $ / shares	0
Vested (in dollars per share) | $ / shares	1.33
Forfeited (in dollars per share) | $ / shares	17.66
Unvested and outstanding at end of period (in dollars per share) | $ / shares	$ 16.83
Restricted units
Unvested and outstanding at beginning of period (in shares) | shares	75,779
Granted (in shares) | shares	0
Vested (in shares) | shares	(60,000)
Forfeited (in shares) | shares	(1,515)
Unvested and outstanding at end of period (in shares) | shares	14,264
Vest date fair value | $	$ 41
Service-condition | Equity classified RSUs
Weighted average award date fair value
Unvested and outstanding at beginning of period (in dollars per share) | $ / shares	$ 2.41
Granted (in dollars per share) | $ / shares	1.95
Vested (in dollars per share) | $ / shares	0
Forfeited (in dollars per share) | $ / shares	1.56
Unvested and outstanding at end of period (in dollars per share) | $ / shares	$ 2.87
Restricted units
Unvested and outstanding at beginning of period (in shares) | shares	638,383
Granted (in shares) | shares	4,500
Vested (in shares) | shares	0
Forfeited (in shares) | shares	(228,094)
Unvested and outstanding at end of period (in shares) | shares	414,789
Vest date fair value | $	$ 0
Market condition | Equity classified RSUs
Weighted average award date fair value
Unvested and outstanding at beginning of period (in dollars per share) | $ / shares	$ 1.36
Granted (in dollars per share) | $ / shares	0
Vested (in dollars per share) | $ / shares	0
Forfeited (in dollars per share) | $ / shares	1.36
Unvested and outstanding at end of period (in dollars per share) | $ / shares	$ 1.36
Restricted units
Unvested and outstanding at beginning of period (in shares) | shares	390,000
Granted (in shares) | shares	0
Vested (in shares) | shares	0
Forfeited (in shares) | shares	(200,000)
Unvested and outstanding at end of period (in shares) | shares	190,000

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Deferred compensation (Stock-based Compensation Cost) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019	Dec. 31, 2019
Share-based Payment Arrangement, Noncash Expense [Abstract]
Stock-based compensation cost	$ 101	$ 1,260	$ 771	$ 2,720
Less: stock-based compensation cost capitalized	(7)	(399)	(281)	(1,025)
Stock-based compensation expense	$ 94	$ 861	$ 490	$ 1,695
Number of vested shares repurchased or settled in cash	92,649	126,231	96,505	206,653
Payments for stock-based compensation	$ 53	$ 708	$ 59	$ 1,171
Estimated fair value per share at end of period (in dollars per share)	$ 0.65		$ 0.65
Aggregate intrinsic value of unvested restricted shares outstanding	$ 1,593		$ 1,593
Deferred compensation current	45		45		$ 52
Unrecognized stock-based compensation cost	$ 1,357		$ 1,357
Weighted-average period for unrecognized compensation cost to be recognized			1 year 3 months 18 days

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Commitments and Contingencies (Details)						6 Months Ended		12 Months Ended
	Aug. 14, 2020 USD ($)	Jul. 27, 2020 USD ($)	Apr. 20, 2017 USD ($)	Aug. 15, 2016 USD ($)	Jun. 07, 2011 USD ($)	Jun. 30, 2020 USD ($)	Jun. 30, 2019 USD ($)	Dec. 31, 2022 well	Dec. 31, 2021 well	Dec. 31, 2020 well	Dec. 31, 2019 USD ($) well	Aug. 15, 2020 shares	Mar. 31, 2020 USD ($)	Jan. 17, 2017
Loss Contingencies [Line Items]
Cash provided as collateral						$ 950,000
Leasehold commitment, minimum number of wells to drill and complete | well											10
Leasehold commitment, penalty for each deficient well (per well)						250,000
Leasehold commitment, accrual for deficient wells													$ 2,500,000
Leasehold commitment, accrual for additional deficiency						6,250,000
Subsequent event
Loss Contingencies [Line Items]
Repayments of lines of credit		$ 24,000,000
Forecast
Loss Contingencies [Line Items]
Leasehold commitment, minimum number of wells to drill and complete | well								15	10	10
Naylor Farms Case Putative Class Action | Subsequent event
Loss Contingencies [Line Items]
Damages sought, value	$ 45,000,000
Litigation settlement, amount awarded to other party	2,500,000
Legal fees	850,000
Litigation settlement, expense	$ 150,000
Naylor Farms Case Putative Class Action | Class A Common Stock | Subsequent event
Loss Contingencies [Line Items]
Litigation settlement, number of common stock awarded (in shares) | shares												1,432,300
Naylor Farms Case Putative Class Action | Pending Litigation
Loss Contingencies [Line Items]
Percentage of leases certified in modified plaintiff class (less than)														60.00%
Naylor Farms Case Putative Class Action | Minimum | Pending Litigation
Loss Contingencies [Line Items]
Damages sought, value			$ 90,000,000	$ 150,000,000	$ 5,000,000
W.H. Davis Case
Loss Contingencies [Line Items]
Damages sought, value											$ 17,262,000
Amount of bankruptcy claims settled											2,650,000
Surety Bond
Loss Contingencies [Line Items]
Letters of credit outstanding						2,121,000
Letter of Credit
Loss Contingencies [Line Items]
Letters of credit outstanding						0					$ 0
Repayments of lines of credit						0	$ 0
Cash payments for interest						$ 0	$ 0

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Subsequent events (Details) - USD ($)	Aug. 15, 2020	Jul. 27, 2020	Aug. 17, 2020
Subsequent Event [Line Items]
Common stock outstanding (in shares)			47,790,146
Subsequent event
Subsequent Event [Line Items]
Proceeds from early termination of derivative contracts		$ 28,237,000
Repayments of lines of credit		$ 24,000,000
Debtor reorganization items, lenders agreed to provide revolving commitments, minimum additional cash	$ 5,000,000
Debtor reorganization items, holders of credit agreement claims term, maximum amount of severance settlement agreements	1,220,000
Debtor reorganization items, existing equityholders term, ratable share of cash to be received	$ 1,200,000
Debtor reorganization items, existing equityholders term, cash amount per share in lieu of warrants	$ 0.01508
Subsequent event | Maximum
Subsequent Event [Line Items]
Plan of reorganization, amount of prepetition obligations to be settled in cash	$ 150,000
Subsequent event | Tranche A
Subsequent Event [Line Items]
Percentage of new common equity of cashless exercise warrants to be received by existing equityholders	5.00%
Cashless exercise warrants for existing equityholders, equity value strike price	$ 300,000,000
Cashless exercise warrants for existing equityholders, period	4 years
Subsequent event | Tranche B
Subsequent Event [Line Items]
Percentage of new common equity of cashless exercise warrants to be received by existing equityholders	5.00%
Cashless exercise warrants for existing equityholders, equity value strike price	$ 350,000,000
Cashless exercise warrants for existing equityholders, period	5 years
Exit Facility | Subsequent event
Subsequent Event [Line Items]
Debtor-in-possession financing, amount	$ 300,000,000
Debtor-in-processing financing, maturity date, period	456 days
Revolving facility | Subsequent event
Subsequent Event [Line Items]
Debtor-in-processing financing, maturity date, period	40 months
Debtor-in-processing financing, initial borrowing base term, period of proved developed producing reserves	6 months
Revolving facility | Subsequent event | Minimum
Subsequent Event [Line Items]
Debtor-in-processing financing, available capacity	$ 20,000,000
Revolving facility | Subsequent event | Maximum
Subsequent Event [Line Items]
Debtor-in-processing financing, available capacity	175,000,000
2L Convertible Notes | Subsequent event
Subsequent Event [Line Items]
Liquidity benchmark to require interest paid in kind with additional principal	20,000,000
2L Convertible Notes | Senior Notes | Subsequent event
Subsequent Event [Line Items]
Debtor-in-possession financing, amount	$ 35,000,000
New Common Stock outstanding percentage	50.00%
Debtor-in-processing financing, term	52 months
Percentage of new common equity to be received in exchange for commitment	10.00%
Required put option premium in cashin lieu of new common stock	$ 2,625,000
Management Incentive Plan term, percentage of new common equity as equity based award	7.00%
Debtor reorganization items, percentage of new common equity to be received by holders of Senior Notes	100.00%
2L Convertible Notes | Senior Notes, paid in cash | Subsequent event
Subsequent Event [Line Items]
Debtor-in-possession financing, interest rate per annum	9.00%
2L Convertible Notes | Payment in Kind (PIK) Note | Subsequent event
Subsequent Event [Line Items]
Debtor-in-possession financing, interest rate per annum	13.00%