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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended ~~March 31~~June 30, 2020

¨☐ 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 x☒ Non-accelerated filer ¨☐ Smaller reporting company ¨☐ Emerging growth company ¨☐

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes ☐ No ☒

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.

Yes ☒ No ☐

Number of shares outstanding of each of the issuer’s classes of common stock as of ~~May~~August 817, 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~~	Page
Part I. FINANCIAL INFORMATION
Item 1. Financial Statements (Unaudited)	7	8
Consolidated Balance Sheets	7	8
Consolidated Statements of Operations	8	9
Consolidated Statement of Stockholders’ Equity	9	10
Consolidated Statements of Cash Flows	10	11
Condensed Notes to Consolidated Financial Statements	11	12
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	30	36
Overview	30	36
Results of Operations	34	41
Liquidity and Capital Resources	31	37
Non-GAAP Financial Measure and Reconciliation	41	50
Critical Accounting Policies	42	51
Recent Accounting Pronouncements	43	51
Item 3. Quantitative and Qualitative Disclosures about Market Risk	43	51
Item 4. Controls and Procedures	45	53
Part II. OTHER INFORMATION
Item 1. Legal Proceedings	45	53
Item 1A. Risk Factors	45	53
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	47	59
Item 5. Other Information	47	59
Item 6. Exhibits	48	60
Signatures	49	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:

• ~~fluctuations in demand or~~ the ~~prices~~Chapter ~~received~~11 ~~for oil and natural gas~~Cases;

•the effects of the ~~amount,~~Chapter ~~nature~~11 ~~and~~Cases ~~timing~~on our liquidity or results of ~~capital~~operations ~~expenditures~~or business prospects;

•the ~~drilling,~~expected ~~completion~~terms ~~and~~of ~~performance~~a proposed plan of ~~wells~~reorganization;

•our ~~inventory~~ability ofto ~~drillable~~confirm ~~locations~~and consummate a Chapter 11 plan of reorganization;

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

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

•the ~~timing~~potential ~~and~~impact ~~amount~~ of ~~future~~any ~~production~~epidemics ofor ~~oil~~pandemics, ~~and~~including ~~natural gas~~COVID-19;

•fluctuations ~~costs~~in ofdemand ~~exploiting~~or ~~and~~the ~~developing~~prices ~~properties~~received ~~and~~for ~~conducting~~oil ~~other operations, in the aggregate~~ and onnatural ~~a per-unit equivalent basis~~gas;

•the ~~changes~~amount, innature ~~proved~~and ~~reserves~~timing of capital expenditures;

•drilling, ~~operating~~completion ~~costs~~ and ~~other~~performance ~~expenses~~of wells;

•inventory ~~our future financial condition, results~~ of ~~operations,~~drillable ~~revenue, cash flows and expenses~~locations;

• ~~estimates of proved reserves~~competition;

•government ~~exploitation of property acquisitions~~regulations;

•timing ~~takeaway~~and ~~constraints~~amount ~~and~~of ~~storage~~future ~~capacity~~production ~~for~~of oil and natural gas; ~~and~~

•costs ~~marketing~~ of ~~oil~~exploiting and ~~natural~~developing ~~gas.~~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 ~~future~~and ~~capital~~uncertainties ~~expenditures~~regarding ~~(or~~the ~~funding~~Company’s ~~thereof)~~ability ~~and~~to ~~working~~complete ~~capital;~~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 ~~worldwide~~Company’s ~~supply~~ability ofto ~~and~~obtain ~~demand~~timely ~~for~~approval ~~oil~~by ~~and natural gas, including to~~ the ~~extent~~Bankruptcy ~~affected~~Court byregarding the ~~COVID-19~~motions ~~pandemic~~filed ~~and~~in the ~~recovery~~Chapter ~~therefrom;~~11 Cases;

•the ~~volatility~~time ~~and~~that ~~declines~~the inCompany ~~oil~~will ~~and~~operate ~~natural~~under ~~gas~~Chapter ~~prices,~~11 ~~including~~protection toand the ~~extent~~continued ~~affected~~availability byof ~~the~~operating ~~COVID-19~~capital ~~pandemic~~during ~~and~~the pendency of the ~~recovery~~Chapter ~~therefrom;~~11 Cases;

•the ~~geopolitical~~effects ~~events~~of ~~affecting~~the ~~oil~~Chapter ~~and~~11 ~~natural~~Cases ~~gas~~on ~~prices;~~our liquidity or results of operations or business prospects;

•the effects of the ~~nature~~Chapter or11 ~~results,~~Cases ifon ~~any,~~our business and the interests of ~~any~~various ~~strategic~~constituents, ~~alternatives~~including our stockholders;

•employee ~~recent~~attrition ~~changes~~and in the ~~composition~~Company’s ofability to retain senior management and other key personnel due to the ~~board~~distractions ofand ~~directors~~uncertainties, ofincluding the Company’s (ability to provide adequate compensation and benefits during the ~~“Board”);~~Chapter 11 Cases;

• the effects of the departures of former executives and the hiring of new executives on our employees, suppliers, regulators and business counterparties;

• our inability to retain and attract key personnel;

• 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;

•the ~~activities~~Company’s onability ~~properties~~to wemaintain dorelationships ~~not~~with ~~operate;~~suppliers, customers, employees and other third parties and regulatory authorities because of the Chapter 11 filing;

•the ~~availability~~effects ~~and~~of ~~cost~~the ofChapter ~~drilling~~11 ~~and~~Cases ~~production~~on ~~equipment,~~the ~~facilities,~~market ~~field~~price ~~service~~of ~~providers,~~the ~~gathering,~~Company’s ~~processing~~common stock and ~~transportation;~~on the Company’s ability to access the capital markets;

•risks ~~takeaway~~associated ~~constraints~~with ~~and~~third ~~storage~~party ~~capacity~~motions ~~for~~in ~~oil~~the ~~and~~Chapter ~~natural~~11 ~~gas;~~Cases, which may interfere with the Company’s ability to consummate the restructuring or an alternative restructuring;

•increased ~~competition~~administrative inand ~~the~~legal ~~oil~~costs ~~and~~related ~~natural~~to ~~gas~~the ~~industry;~~Chapter 11 process;

•potential ~~outcome,~~delays ~~effects~~in orthe ~~timing~~Chapter of11 ~~legal~~process ~~proceedings~~due ~~(including~~to ~~environmental~~the ~~litigation);~~effects of COVID-19;

•other ~~weather,~~litigation ~~including its impact on oil~~ and ~~natural~~inherent ~~gas~~risks ~~demand~~involved ~~and~~in ~~weather-related~~a ~~delays~~bankruptcy ~~on operations;~~process;

•future ~~the~~capital ~~impact~~expenditures of(or ~~natural~~funding ~~disasters~~thereof) ~~on our present~~ and ~~future~~working ~~operations~~capital;

•worldwide ~~the~~supply ~~operating~~of ~~hazards~~and ~~attendant~~demand tofor ~~the~~ oil and natural gas, ~~business~~including to the extent affected by the COVID-19 pandemic and the recovery therefrom;

•volatility ~~effectiveness~~and declines in oil and natural gas prices, including to the extent ofaffected ~~our~~by ~~risk~~the ~~management~~COVID-19 ~~activities~~pandemic and the recovery therefrom;

•geopolitical ~~effectiveness~~events ofaffecting ~~orders~~oil ~~from the Oklahoma Corporation Commission~~ and ~~other~~natural ~~regulatory~~gas ~~bodies in mitigating the risk of lease cancellation actions associated with the voluntary shut-in of production~~prices;

•the ~~current~~impact ~~borrowings,~~of ~~capital~~COVID-19 ~~resources~~on ~~and~~the ~~liquidity~~health of our key personnel;

•risks ~~covenant~~related ~~compliance~~to ~~under~~the ~~instruments~~geographic ~~governing~~concentration ~~any~~ of our ~~existing or future indebtedness, including our ability to comply with financial covenants under our Credit Agreement~~assets;

•our ~~the~~ability ~~effects~~to ofdevelop, ~~government~~explore ~~regulation~~for, acquire and ~~permitting~~replace oil and ~~other~~natural ~~legal~~gas ~~requirements~~reserves and sustain production;

•drilling ~~the~~plans ~~impact~~(including ofscheduled ~~legislative, tax~~ and ~~regulatory~~budgeted ~~initiatives, including in response to the COVID-19 pandemic~~wells);

•the ~~volatility~~extent into ~~the~~which ~~price~~we ofare ~~our~~able ~~common~~to ~~stock~~continue to reduce lease operating expense and G&A costs;

•geologic ~~integration~~and ofreservoir ~~existing~~complexity and ~~new technologies into operations~~variability;

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

•the ~~changes~~number, intiming ~~strategy~~or ~~and~~results ~~business~~of ~~discipline;~~any ~~and~~wells;

•changes ~~the~~in ~~ability~~wells tooperated ~~successfully complete merger, acquisition or divestiture plans, regulatory or other limitations imposed as a result of a merger, acquisition or divestiture,~~ and ~~the~~in ~~success~~reserve ~~of the business following a merger, acquisition or divestiture.~~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 update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required under applicable securities laws. All forward-looking statements included herein are expressly qualified in their entirety by the cautionary statements contained or referred to in this section.

~~GLOSSARY~~update OFor ~~CERTAIN~~revise ~~DEFINED~~any ~~TERMS~~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.

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	The voluntary petitions filed by Chaparral Energy, Inc. and its subsidiaries on May 9, 2016 seeking relief under Title 11 of the United States Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the District of Delaware commencing cases for relief under chapter 11 of the Bankruptcy Code.
Completion	The process of treating a drilled well followed by the installation of permanent equipment for the production of oil or natural gas, or in the case of a dry well, the reporting to the appropriate authority that the well has been abandoned.
CO2	Carbon dioxide.
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.
Effective Date	March 21, 2017, the date of the Company’s emergence from bankruptcy.
Enhanced oil recovery (EOR)	The use of any improved recovery method, including injection of CO2 or polymer, to remove additional oil after Secondary Recovery.
Field	An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.
MBbls	One thousand barrels of crude oil, condensate, or natural gas liquids.
MBoe	One thousand barrels of crude oil equivalent.
Mcf	One thousand cubic feet of natural gas.
MMBtu	One million British thermal units.
MMcf	One million cubic feet of natural gas.
Natural gas liquids (NGLs)	Those hydrocarbons in natural gas that are separated from the gas as liquids through the process of absorption, condensation, or other methods in gas processing or cycling plants. Natural gas liquids primarily include propane, butane, isobutane, pentane, hexane and natural gasoline.
NYSE	The New York Stock Exchange.

Play	A term describing an area of land following the identification by geologists and geophysicists of reservoirs with potential oil and natural gas reserves.
Proved developed reserves	Reserves that can be expected to be recovered (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%.
Reorganization Plan	First Amended Joint Plan of Reorganization for Chaparral Energy, Inc. and its Affiliate Debtors under Chapter 11 of the Bankruptcy Code.
SEC	The Securities and Exchange Commission.
Senior Notes	Our 8.75% senior notes due 2023.
STACK	The STACK is a play in the Anadarko basin of Oklahoma in which we operate and derives its name from the acronym standing for Sooner Trend Anadarko Canadian Kingfisher. It is a horizontal drilling play in an area with multiple productive reservoirs that had previously been drilled with vertical wells. Our STACK areas encompass all or parts of Canadian, Garfield, Kingfisher, Major, Blaine, Dewey, Woodward, Logan and Grady counties in Oklahoma. Our STACK areas’ borders include the Nemaha Ridge (East), the Chester outcrop (North), and deep gas bearing characteristics (South and West). This thick column (500’+) includes multiple, stacked, and productive reservoirs, each with high oil saturations and includes the Woodford, Osage, Meramec, Oswego, and other intervals within the STACK.
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.

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.


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.

Chaparral Energy, Inc. and Subsidiaries

Consolidated Balance Sheets

(Unaudited)

PART I — FINANCIAL INFORMATION


ITEM 1.			FINANCIAL STATEMENTS

(dollars in thousands, except share data)

~~March 31, 2020~~

~~December~~June 3130, ~~2019~~2020

December 31, 2019

Assets

Current assets:

Cash and cash equivalents

~~13,291~~

2256,~~595~~137

22,595

Accounts receivable:

Accounts receivable, gross

~~46,085~~

5043,~~744~~197

50,744

Allowance for credit losses

~~(2,768~~

)

(14,~~097~~215)

)

(1,097)

Accounts receivable, net

~~43,317~~

4938,~~647~~982

49,647

Inventories, net

~~2,842~~

32,~~730~~456

3,730

Prepaid expenses

~~2,981~~

34,~~471~~034

3,471

Derivative instruments

~~48,458~~

~~947~~15,197

947

Total current assets

~~110,889~~

80116,~~390~~806

80,390

Property and equipment, net

~~8,603~~

97,~~217~~948

9,217

Right of use assets from operating leases

~~2,097~~

21,~~444~~744

2,444

Oil and natural gas properties, using the full cost method:

Proved

~~1,348,229~~

1,~~276~~569,~~036~~627

1,276,036

Unevaluated (excluded from the amortization base)

~~354,547~~

~~371~~142,~~229~~295

371,229

Accumulated depreciation, depletion, amortization and impairment

~~(848,002~~

)

(~~754~~1,~~379~~246,703)

)

(754,379)

Total oil and natural gas properties

~~854,774~~

~~892~~465,~~886~~219

892,886

Held for sale assets

~~164~~

~~2,860~~111

2,860

Derivative instruments

~~4,663~~

—1,990

—

Other assets

~~2,136~~

~~635~~1,349

635

Total assets

~~983,326~~

~~988~~595,~~432~~167

988,432

Liabilities and stockholders’ equity

Current liabilities:

Accounts payable and accrued liabilities

~~65,966~~

6439,~~558~~272

64,558

Accrued payroll and benefits payable

~~6,514~~

105,~~963~~970

10,963

Accrued interest payable

~~5,650~~

12,~~227~~309

12,227

Revenue distribution payable

~~21,752~~

229,~~370~~322

22,370

Long-term debt and financing leases, classified as current

~~497~~

~~594~~521,292

594

Derivative instruments

—

~~11,957~~—

11,957

Total current liabilities

~~100,379~~

~~122~~588,~~669~~165

122,669

Long-term debt and financing leases, less current maturities

~~436,755~~

~~421,392~~996

421,392

Derivative instruments

—

~~5,075~~—

5,075

Noncurrent operating lease obligations

~~579~~

~~917~~234

917

Deferred compensation

~~467~~

~~165~~419

165

Asset retirement obligations

~~22,544~~

21,~~073~~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; 48,390,691 issued and 47,915,880 outstanding at March 31, 2020 and 48,413,185 issued and 47,942,230 outstanding at December 31, 2019

484

485

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

~~977,879~~

977,~~174~~957

977,174

Treasury stock, at cost, 474,811 and 470,955 shares as of March 31, 2020, and December 31, 2019

(6,116

)

(6,110

)

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

~~(549,645~~

)

(~~554~~988,~~408~~371)

)

(554,408)

Total stockholders’ equity

~~422,602~~

~~417~~(16,~~141~~059)

417,141

Total liabilities and stockholders’ equity

~~983,326~~

~~988~~595,~~432~~167

988,432

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

Chaparral Energy, Inc. and Subsidiaries

Consolidated Statements of Operations

(Unaudited)

	~~Three months ended~~			Three months ended							Six months ended
(in thousands, except share and per share data)	~~March 31, 2020~~			~~March~~June 3130, ~~2019~~2020			June 30, 2019		June 30, 2020		June 30, 2019
Revenues:
Net commodity sales	$	~~48,851~~		$	4815,~~619~~880		$	66,707	$	64,731	$	115,326
Sublease revenue	—			~~1,198~~—			1,198		—		2,396
Total revenues	~~48,851~~			4915,~~817~~880			67,905		64,731		117,722
Costs and expenses:
Lease operating	~~10,088~~			125,~~294~~971			13,371		16,059		25,665
Production taxes	~~2,750~~			~~2,880~~823			3,802		3,573		6,682
Depreciation, depletion and amortization	~~23,012~~			2314,~~715~~821			30,282		37,833		53,997
Impairment of oil and gas assets	~~71,371~~			49384,~~722~~639			63,593		456,010		113,315
Impairment of other assets	~~153~~			—310			6,407		463		6,407
General and administrative	~~8,068~~			89,~~313~~488			7,315		17,556		15,628
Subleases	—			403
Liability management				8,047			—		8,047		—
Total costs and expenses	115,442			97,327
Litigation loss				4,359			—		4,359		—
Operating loss	(66,591		)	(47,510		)
Subleases				—			403		—		806
Non-operating income (expense):
Total costs and expenses				428,458			125,173		543,900		222,500
Interest expense	(6,636		)	(4,564		)
Operating loss				(412,578)			(57,268)		(479,169)		(104,778)
Derivative gains (losses)	78,380			(51,016		)
Non-operating income (expense):
Gain (loss) on sale of assets	102			(1		)
Interest expense				(8,047)			(5,571)		(14,683)		(10,135)
Other income, net	246			14
Write-off of Senior Note issuance costs				(4,420)			—		(4,420)		—
Net non-operating income (expense)	72,092			(55,567		)
Derivative (losses) gains				(13,019)			17,734		65,361		(33,282)
Reorganization items, net	(584		)	(463		)
(Loss) gain on sale of assets				(261)			491		(159)		490
Income (loss) before income taxes	4,917			(103,540		)
Other income (expense), net				35			(302)		281		(288)
Income tax expense	—			—
Net non-operating income (expense)				(25,712)			12,352		46,380		(43,215)
Net income (loss)	$	4,917		$	(103,540	)
Reorganization items, net				(436)			(313)		(1,020)		(776)
Earnings (loss) per share:
Loss before income taxes				(438,726)			(45,229)		(433,809)		(148,769)
Basic	$	0.11		$	(2.28	)
Income tax expense				—			—		—		—
Diluted	$	0.11		$	(2.28	)
Net loss				$	(438,726)		$	(45,229)	$	(433,809)	$	(148,769)
Weighted average shares used to compute earnings per share:
Loss per share:
Basic	~~45,830,286~~			~~45,456,214~~$	(9.55)		$	(0.99)	$	(9.45)	$	(3.27)
Diluted	~~46,194,495~~			~~45,456,214~~$	(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.

Chaparral Energy, Inc. and Subsidiaries

Consolidated Statement of Stockholders’ Equity

(Unaudited)

	~~Common stock~~			Common stock
(dollars in thousands)	~~Sharesoutstanding~~		~~Amount~~	Sharesoutstanding		~~Additionalpaid in capital~~		Amount	~~Treasurystock~~			~~Accumulateddeficit~~	Additionalpaid in capital		~~Total~~			Treasurystock		Accumulateddeficit		Total
As of December 31, 2018	~~46,390,513~~		$	~~467~~46,390,513		$	~~974,616~~	$	$467	~~(4,936~~	)	$	~~(85,460~~$	)974,616	$	~~884,687~~		$	(4,936)	$	(85,460)	$	884,687
Stock-based compensation	~~94,078~~		1	94,078		~~1,423~~		1	—			—	1,423		~~1,424~~			—		—		1,424
Restricted stock forfeited	~~(97,113~~	)	(1	(97,113)	)	—		(1)	—			—	—		(1		)	—		—		(1)
Repurchase of common stock	~~(80,422~~	)	—	(80,422)		—		—	~~(463~~		)	—	—		~~(463~~		)	(463)		—		(463)
Net loss	—		—	—		—		—	—			~~(103,540~~	—	)	~~(103,540~~		)	—		(103,540)		(103,540)
Balance at March 31, 2019	~~46,307,056~~		$	~~467~~46,307,056		$	~~976,039~~	$	$467	~~(5,399~~	)	$	~~(189,000~~$	)976,039	$	~~782,107~~		$	(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~~			Common stock
(dollars in thousands)	~~Sharesoutstanding~~		~~Amount~~	Sharesoutstanding		~~Additionalpaid in capital~~		Amount	~~Treasurystock~~			~~Accumulateddeficit~~	Additionalpaid in capital		~~Total~~			Treasurystock		Accumulateddeficit		Total
As of December 31, 2019	~~47,942,230~~		$	~~485~~47,942,230		$	~~977,174~~	$	$485	~~(6,110~~	)	$	~~(554,408~~$	)977,174	$	~~417,141~~		$	(6,110)	$	(554,408)	$	417,141
Cumulative effect of accounting standard adoption	—		—	—		—		—	—			~~(154~~	—	)	~~(154~~		)	—		(154)		(154)
Stock-based compensation	—		—	—		~~705~~		—	—			—	705		~~705~~			—		—		705
Restricted stock forfeited or canceled	~~(22,494~~	)	(1	(22,494)	)	—		(1)	—			—	—		(1		)	—		—		(1)
Repurchase of common stock	~~(3,856~~	)	—	(3,856)		—		—	(6		)	—	—		(6		)	(6)		—		(6)
Net income	—		—	—		—		—	—			~~4,917~~	—		~~4,917~~			—		4,917		4,917
Balance at March 31, 2020	~~47,915,880~~		$	~~484~~47,915,880		$	~~977,879~~	$	$484	~~(6,116~~	)	$	~~(549,645~~$	)977,879	$	~~422,602~~		$	(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.

910

Chaparral Energy, Inc. and Subsidiaries

Consolidated Statements of Cash Flows

(Unaudited)

	Three months ended
				Six months ended
(in thousands)	~~March 31, 2020~~			~~March~~June 3130, ~~2019~~2020			June 30, 2019
Cash flows from operating activities
Net income (loss)	$	4,917		$	(103,540	)
Net loss				$	(433,809)		$	(148,769)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Adjustments to reconcile net loss to net cash (used in) provided by operating activities
Depreciation, depletion and amortization	~~23,012~~			2337,~~715~~833			53,997
Derivative (gains) losses	~~(78,380~~		)	51(65,~~016~~361)			33,282
Impairment of oil and gas assets	~~71,371~~			49456,~~722~~010			113,315
Impairment of other assets	~~153~~			—463			6,407
(Gain) loss on sale of assets	(102		)	1
Write-off of Senior Note issuance costs				4,420			—
Other	2,338			542
Loss (gain) on sale of assets				159			(490)
Change in assets and liabilities
Other				4,612			1,621
Accounts receivable	4,835			7,910
Change in assets and liabilities
Inventories	675			207
Accounts receivable				6,206			13,584
Prepaid expenses and other assets	(1,011		)	256
Inventories				747			40
Accounts payable and accrued liabilities	(14,870		)	(16,689		)
Prepaid expenses and other assets				(1,277)			1,055
Revenue distribution payable	(619		)	(5,511		)
Accounts payable and accrued liabilities				(7,217)			(18,389)
Deferred compensation	564			925
Revenue distribution payable				(13,049)			600
Net cash provided by operating activities	12,883			8,554
Deferred compensation				844			1,852
Cash flows from investing activities
Net cash (used in) provided by operating activities				(9,419)			58,105
Expenditures for property, plant, and equipment and oil and natural gas properties	(49,053		)	(64,044		)
Cash flows from investing activities
Proceeds from asset dispositions	3,209			—
Expenditures for property, plant, and equipment and oil and natural gas properties				(86,862)			(146,434)
Proceeds from derivative instruments, net	9,174			515
Proceeds from asset dispositions				3,370			857
Net cash used in investing activities	(36,670		)	(63,529		)
Proceeds from derivative instruments, net				32,089			653
Cash flows from financing activities
Net cash used in investing activities				(51,403)			(144,924)
Proceeds from long-term debt	15,000			30,000
Cash flows from financing activities
Repayment of long-term debt	(313		)	(171		)
Proceeds from long-term debt				120,000			85,000
Principal payments under financing lease obligations	(105		)	(699		)
Repayment of long-term debt				(25,313)			(343)
Payment of debt issuance costs and other financing fees	(93		)	(20		)
Principal payments under financing lease obligations				(212)			(1,445)
Treasury stock purchased	(6		)	(463		)
Payment of debt issuance costs and other financing fees				(93)			(20)
Net cash provided by financing activities	14,483			28,647
Treasury stock purchased				(18)			(1,171)
Net decrease in cash and cash equivalents	(9,304		)	(26,328		)
Net cash provided by financing activities				94,364			82,021
Cash and cash equivalents, at beginning of period	22,595			37,446
Net increase (decrease) in cash and cash equivalents				33,542			(4,798)
Cash and cash equivalents, at end of period	$	13,291		$	11,118
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.

1011

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~~, as amended~~.

The financial information as of ~~March 31~~June 30, 2020, and for the three and six months ended ~~March 31~~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 ~~March 31~~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

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 ~~March 31~~June 30, 2020, cash with a recorded balance totaling approximately $1255,~~698~~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 ~~comprising~~constituting its total accounts receivables: (i) ~~commodity~~joint ~~sales~~interest receivables; (ii) ~~joint~~commodity ~~interest~~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.

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

	March 31,2020			December 31,2019
Joint interests	$	16,362		$	16,664
Commodity sales	19,818			30,819
Derivative settlements	8,009			717
Other	1,896			2,544
Allowance for doubtful accounts	(2,768		)	(1,097		)
	$	43,317		$	49,647

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.

~~Commodity~~Derivative ~~sales~~settlement receivables. Our ~~The~~derivative ~~Company~~receivables ~~sells~~relate ~~its commodity products primarily~~ to ~~oil~~net ~~and~~settlements ~~natural~~due ~~gas~~from ~~midstream~~counterparties ~~entities~~to ~~including~~our ~~crude~~derivative ~~oil refineries and natural gas processing plants~~contracts. WeSince ~~also~~derivative ~~sell~~settlements afluctuate ~~small~~depending ~~percentage~~on ofcommodity ~~our~~price ~~natural~~changes, ~~gas~~which ~~and~~are ~~natural~~volatile, ~~gas~~the ~~liquids~~associated toamounts ~~energy~~can ~~marketing~~result ~~entities.~~in ~~Payment~~a isnet ~~generally~~payable ~~due~~or ~~within~~a 30net ~~days~~receivable ofposition ~~sales~~in ~~and~~any ~~amount~~given ~~outstanding longer than 90 days are considered past due~~month. Our ~~Based~~derivative oncontracts ~~2019~~generally ~~commodity~~require ~~sales,~~payment ~~our~~within 1060 ~~largest~~days ~~purchasers accounting for over 75%~~ of ~~our~~the ~~commodity~~fixing ~~sales~~date. We ~~Based~~have ona ~~our~~limited ~~history~~number of ~~collections~~counterparties ~~from~~to our ~~purchasers~~derivative contracts, weall ~~believe the probability~~ of ~~credit~~whom ~~losses~~are ~~from~~large ~~uncollectible~~financial ~~receivables~~institutions toand beare ~~remote.~~also Welenders ~~perform~~under ~~annual~~our credit ~~evaluations on purchasers comprising 85% or more of our commodity revenues~~agreement. These ~~The~~financial ~~evaluations~~institution ~~include~~counterparties ~~(i)~~bear aninvestment ~~assessment~~grade ~~of external~~ credit ratings;. We ~~(ii)~~have ~~performing~~never ~~internal~~incurred ~~risk~~credit ~~evaluations~~losses ~~when~~from ~~external~~our ~~ratings~~derivative ~~are~~receivables ~~not~~and ~~available;~~believe ~~(iii) assessing~~ the ~~need~~probability ~~for~~of ~~guarantor~~such ~~letters~~losses orto ~~letters~~be ofhighly ~~credit~~remote. Furthermore, Weto ~~estimate~~ the ~~expected~~extent ~~losses~~that ona ~~uncollectible~~balance ~~receivables~~is byuncollectible, ~~applying~~we abelieve ~~uniform~~that ~~allowance~~we ~~rate~~have onoffset ~~the~~rights ~~total~~against ~~outstanding~~amounts ~~balance~~owed ~~taking~~to ~~into~~the ~~consideration~~counterparty ~~general~~under ~~industry~~our ~~conditions~~credit ~~and~~facility. Based ~~more~~on ~~specifically~~these circumstances, ~~factors~~we ~~impacting~~have ~~the~~not ~~midstream~~recorded ~~energy~~any ~~segment.~~allowance Wefor ~~may~~credit ~~make~~losses ~~further~~related ~~adjustments~~ to ~~our~~these ~~allowance~~receivables. As ~~for~~discussed ~~credit~~in ~~losses~~“Note ~~according~~11: toSubsequent ~~any~~events,” ~~specific~~we ~~news~~terminated weall ~~may~~our ~~receive~~outstanding ~~regarding~~derivatives ~~individual~~in ~~purchasers.~~July 2020.

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 collectibility 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.

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.

12Response 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.

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

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 storage constraints, including at refineries which have reached capacity due to excess product. We have incorporated the prevailing industry crisis into our forecast of credit losses by increasing the allowance rates which 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.


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

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 March 31,
	2020		2019
Credit losses on receivables	$	1,517	$	(258	)

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 in 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	March 31,2020
Accounts which have sufficient related revenue distributions payable to offset entire receivable balance	$	1,895
Accounts which have related revenue distributions payable but not sufficient to offset entire receivable balance	10,286
Accounts without related revenue distributions payable	4,181
Total	$	16,362

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

	Three months ended March 31, 2020
			Six months ended June 30, 2020
	~~Commodity sales~~		~~Joint~~Commodity ~~interest~~sales		~~Derivatives~~		Joint interest		~~Other~~		~~Total~~Derivatives		Other		Total
Balance at January 1, 2020	$	—	$	~~1,097~~—	$	—	$	1,097	$	—	$	~~1,097~~—	$	—	$	1,097
Cumulative effect of accounting standard adoption	~~154~~		—154		—		—		—		~~154~~—		—		154
Credit losses	44		~~1,473~~59		—		2,905		—		~~1,517~~—		—		2,964
Write-offs	—		—		—		—		—		—		—		—
Recoveries	—		—		—		—		—		—		—		—
Balance at March 31, 2020	$	198	$	2,570	$	—			$	—	$	2,768
Balance at June 30, 2020			$	213			$	4,002			$	—	$	—	$	4,215

Inventories

Inventories consisted of the following:

	March 31,2020			December 31,2019
				June 30,2020			December 31,2019
Equipment inventory	$	~~2,730~~		$	32,~~435~~673		$	3,435
Commodities	~~444~~			~~474~~425			474
Inventory valuation allowance	~~(332~~		)	(~~179~~642)		)	(179)
	$	~~2,842~~		$	32,~~730~~456		$	3,730

13During 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

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

~~During~~to reflect the ~~three~~disposal ~~months~~group ~~ended~~separately ~~March 31,~~on ~~2020,~~the webalance ~~recorded~~sheet aas ~~lower~~“Assets ofheld ~~cost~~for orsale” ~~market~~at ~~impairment~~carrying ofvalue ~~$153~~or onfair ~~our~~value ~~equipment~~less ~~inventory~~cost to sell, ~~which~~whichever is ~~reflected~~less. The ascarrying ~~“Impairment~~value of ~~other~~ assets” onheld ~~our~~for ~~consolidated~~sale ~~statements~~is ofnot ~~operations~~included in the table above. Our held for sale assets are as follows:

Property and equipment, net


	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

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

	March 31,2020		December 31,2019
Machinery and equipment	$	3,477	$	3,543
Office and computer equipment	3,556		3,363
Automobiles and trucks	2,678		3,071
Building and improvements	664		693
Furniture and fixtures	8		8
	10,383		10,678
Less accumulated depreciation, amortization and impairment	3,716		3,459
	6,667		7,219
Land	1,936		1,998
	$	8,603	$	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:

	Carrying value at
	March 31, 2020		December 31, 2019
Equipment	$	—	$	1,572
Vehicles	164		488
Real estate	—		800
Total held for sale	$	164	$	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.

14In 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.

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

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.


	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

InProducer ~~the~~imbalances. We ~~past,~~recognize ~~the~~revenue ~~costs~~on ~~associated~~all ~~with~~natural ~~unevaluated~~gas ~~properties~~sold ~~typically related~~ to ~~acquisition~~our ~~costs~~customers ofregardless ~~unproved acreage. As a result~~ of ~~the~~our ~~application~~proportionate ofworking ~~fresh~~interest ~~start~~in ~~accounting on the Effective Date,~~ a ~~substantial~~well. Liabilities ~~portion~~are ofrecorded ~~the~~for ~~carrying~~imbalances ~~value~~greater ofthan our ~~unevaluated~~proportionate ~~properties~~share ~~are~~of ~~the~~remaining ~~result~~estimated ofnatural agas ~~fair~~reserves. Our ~~value~~aggregate ~~increase~~imbalance topositions ~~reflect~~at ~~the~~June ~~value~~30, of2020, ~~our~~and ~~acreage~~December in31, ~~our~~2019, ~~Focus~~were ~~Areas~~immaterial.

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

	March 31,2020		December 31,2019
Leasehold acreage	$	332,226	$	334,083
Capitalized interest	17,617		16,785
Wells and facilities in progress of completion	4,704		20,361
Total unevaluated oil and natural gas properties excluded from amortization	$	354,547	$	371,229

Our estimates of oil and natural gas reserves as of March 31, 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. We recorded ceiling test write-downs to our oil and natural gas properties of $71,371 and $49,722 for the three months ended March 31, 2020, and 2019, respectively. These losses are reflected in “Impairment of oil and gas assets” in our consolidated statements of operations.

Producer imbalances. We recognize revenue on all natural gas sold to our customers regardless of our proportionate working interest in a well. Liabilities are recorded for imbalances greater than our proportionate share of remaining estimated natural gas reserves. Our aggregate imbalance positions at March 31, 2020, and December 31, 2019, were immaterial.

Revenue recognition

	Three months ended March 31,
	2020			2019
Revenues:
Oil	$	37,026		$	32,802
Natural gas	8,655			11,206
Natural gas liquids	9,682			9,217
Gross commodity sales	55,363			53,225
Transportation and processing	(6,512		)	(4,606		)
Net commodity sales	$	48,851		$	48,619

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 ~~March~~June 3130, 2020, no material adjustments were made to provision amounts recorded as a result of the enactment of the CARES Act.

15The 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.

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

~~The~~required. Such ~~provision~~evidence ~~for~~can ~~income~~include ~~taxes~~our iscurrent ~~based~~financial onposition, aour ~~current~~results ~~estimate~~ of ~~the~~operations, ~~annual~~both ~~effective~~actual ~~income~~and ~~tax~~forecasted, ~~rate adjusted to reflect~~ the ~~impact~~reversal of ~~permanent~~deferred ~~differences and discrete items. Management judgment is required in estimating operating income in order to determine our effective income~~ tax ~~rate. Our~~liabilities, ~~effective~~and ~~income~~ tax ~~rate~~planning ~~was~~strategies 0%as ~~and~~well 0%as ~~for~~ the ~~three~~current ~~month periods ended March 31, 2020~~ and ~~2019,~~forecasted ~~respectively.~~business ~~The~~economics ~~consistent effective tax rate for the three months ended March 31, 2020, is a result~~ of ~~maintaining a valuation allowance against substantially all of~~ our ~~net deferred tax asset~~industry.

Despite the Company’s net income for the three month period ended March 31, 2020, we did not record any net deferred tax expense 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 ~~March~~June 3130, 2020, or December 31, 2019.

As a result of the ~~Chapter~~Prior 11Reorganization ~~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 ~~three~~six month period ended ~~March 31~~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 ~~bankruptcy~~ claims and fees to the U.S. Bankruptcy Trustee, which we will continue to incur until ~~our~~both ~~bankruptcy~~the ~~case~~Prior isChapter 11 Cases and the Chapter 11 Cases are closed.

16Liability 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.”

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

Going concern

These financial statements have been prepared on a going concern basis. However, we are facing a recent unprecedented decline in crude oil prices. The COVID-19 pandemic has contributed to a significant deterioration in the domestic and global demand for oil and gas. The rapid decline in demand has subsequently led to a current shortage of storage capacity for crude oil, further adding downward pressure on commodity energy prices. Compounding the impact of COVID-19, the oil production output alliance between Russia, Saudi Arabia and other oil 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 production cuts, but that announcement has done little to aid in oil price recovery because of the significant drop in global demand. These factors, among others, have caused crude oil prices to collapse to levels that are unsustainable to achieve profitable operations. Our profitability 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 these financial statements.

Management has undertaken steps as part of a plan to improve operations and weather the disruption to the industry caused by COVID-19 with the goal of sustaining our operations for the next twelve months and beyond. These steps include the following:

• 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;

• significantly increasing our cash balance by making additional borrowings under our credit facility (see “Note 4: Debt”);

• continuing efforts 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.

Considering the Company’s hedge position in crude oil for 2020, the proceeds of which do not require the physical delivery of any oil or gas and that we do not have any material volume commitments or other contractual obligations to produce oil or gas, we determined that it is not prudent or necessary to continue developing our inventory or sell all of our products at current market prices. Depending on how quickly supply and demand for oil return to balance and commodity prices reflect same, and the consequent duration of the production shut-ins described above, our ability to remain in compliance with financial covenants under our debt agreements (see “Note 4: Debt”) may be materially negatively affected.

There can be no assurance that these steps will be sufficient for us to continue to operate during the COVID-19 pandemic until such a time energy commodity prices recover to levels which can sustain our ongoing business, enable us to comply with the financial covenants under our debt agreements and allow us meet day-to-day obligations in the long term. Therefore, management does not believe that our plans as outlined above will sufficiently mitigate the conditions that raise the substantial doubt.

The accompanying financial statements do not include any adjustments to reflect the possible future effects on the recoverability and classification of assets or the amounts and classifications of liabilities that may result from the possible inability of the Company to continue as a going concern.

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.

17Note 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

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

Note 2: Earnings per share

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

	Three months ended March 31,
(in thousands, except share and per share data)	2020		2019
Numerator for basic and diluted earnings per share
Net income (loss)	$	4,917	$	(103,540	)
Denominator for basic earnings per share
Weighted average common shares	45,830,286		45,456,214
Denominator for diluted earnings per share (1)
Weighted average common shares	46,194,495		45,456,214
Earnings per share
Basic	$	0.11	$	(2.28	)
Diluted	$	0.11	$	(2.28	)
Participating securities excluded from earnings per share calculations
Unvested restricted stock units - stock settled	606,946		—
Unvested restricted stock awards	1,439,810		886,482

____________________________

(1) Incremental dilutive securities consist of unvested restricted stock and restricted stock units associated with the Company’s deferred compensation plans.

	Three months ended March 31,
	2020			2019
Net cash provided by operating activities included:
Cash payments for interest	$	14,755		$	14,681
Interest capitalized	(2,318		)	(3,492		)
Cash payments for reorganization items	562			394
Non-cash investing activities included:
Asset retirement obligation additions and revisions	56			76
Financing lease right of use asset additions (see Note 5: Leases)	—			670
Change in accrued oil and gas capital expenditures	6,283			15,174

Note 4: Debt

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

	March 31,2020			December 31,2019
				June 30,2020			December 31,2019
8.75% Senior Notes due 2023	$	~~300,000~~		$	300,000		$	300,000
Credit facility	~~145,000~~			~~130~~225,000			130,000
Installment note payable	58			~~371~~—			371
Financing lease obligations	~~1,549~~			1,~~653~~442			1,653
Unamortized debt issuance costs	~~(9,355~~		)	(104,~~038~~154)		)	(10,038)
Total debt, net	~~437,252~~			~~421~~522,~~986~~288			421,986
Less current portion	~~497~~			~~594~~521,292			594
Total long-term debt, net	$	~~436,755~~		$	~~421,392~~996		$	421,392

18Chapter 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

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.

~~Pursuant~~On toJuly ~~our~~15, ~~Credit~~2020, ~~Agreement (~~the ~~“Credit~~Company ~~Agreement”)~~entered ~~with~~into ~~Royal~~a ~~Bank~~Limited ofForbearance ~~Canada,~~Agreement aswith ~~administrative~~the ~~agent~~lenders ~~and~~under ~~issuing~~its ~~bank,~~Credit ~~and~~Agreement (the ~~additional~~“Lenders”). The ~~lenders~~Limited ~~party~~Forbearance ~~thereto~~Agreement included, weamong ~~have~~other things, a ~~$750,000~~requirement ~~credit~~that ~~facility~~the ~~collateralized~~Company byterminate ~~our~~all ~~oil~~of ~~and~~its ~~natural~~outstanding ~~gas~~commodity ~~properties~~hedges and ~~is scheduled~~ to ~~mature~~apply ona ~~December 21,~~certain ~~2022.~~portion ~~Availability~~of ~~under~~the ~~our~~proceeds ~~credit~~thereof ~~facility~~toward ispartial ~~subject~~repayment toof the ~~financial~~outstanding ~~covenants~~amount ~~discussed~~under ~~below~~the ~~and~~Credit aAgreement. The ~~borrowing~~Limited ~~base~~Forbearance ~~based~~Agreement onwas ~~the~~amended ~~value~~effective as of ~~our~~July ~~oil~~24, ~~and~~2020, ~~natural~~by ~~gas~~the ~~properties~~First ~~and~~Amendment ~~set~~to byLimited ~~the~~Forbearance ~~banks~~Agreement ~~semi-annually~~(the on“First orAmendment”) ~~around~~and ~~May~~was 1further ~~and~~amended ~~November~~effective 1July of29, ~~each~~2020 ~~year.~~by ~~Our~~a ~~borrowing~~Second ~~base~~Amendment ~~under~~ (the ~~credit~~“Second ~~facility~~Amendment” and, as ~~of March 31~~amended, ~~2020,~~such ~~was $325,000~~Limited ~~while~~Forbearance Agreement, the ~~unused~~“Lender ~~portion~~Forbearance ~~on that date was $180,000~~Agreement”).

AsThe offorbearance ~~March 31~~period under the Lender Forbearance Agreement began on July 15, 2020 and was scheduled to expire on July 29, ~~our~~2020, ~~outstanding~~unless ~~borrowings~~terminated ~~were~~earlier ~~accruing~~in ~~interest~~accordance atwith the ~~Adjusted~~terms ~~LIBO~~thereof. The ~~Rate~~Second ~~(as~~Amendment ~~defined~~extended the scheduled termination date to August 9, 2020, unless terminated earlier in accordance with the ~~Credit~~terms of the Forbearance Agreement. However, asthe ~~defined~~Second ~~below)~~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, ~~plus~~2020. The Administrative Agent and the ~~Applicable~~Company ~~Margin~~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 ~~defined~~amended, insuch Lender Forbearance Agreement, the ~~Credit~~“Final Lender Forbearance Agreement”), which, ~~resulted~~among inother athings, ~~weighted~~extended ~~average~~the ~~interest~~scheduled ~~rate~~termination date to August 17, 2020, unless terminated earlier in accordance with the terms of 3the Final Lender Forbearance Agreement.~~15%.~~

~~The~~Pursuant ~~Credit~~to ~~Agreement~~the ~~contains~~Final ~~financial~~Lender ~~covenants~~Forbearance ~~that require~~Agreement, ~~for~~the ~~each~~Lenders ~~fiscal quarter~~agreed, weduring ~~maintain:~~the ~~(1)~~forbearance aperiod, ~~Current~~to ~~Ratio~~forbear ~~(as~~from ~~defined~~exercising inany remedies under the Credit Agreement) for any default or event of nodefault ~~less~~resulting ~~than~~from ~~1.00~~any failure by the Company or any of its subsidiaries to ~~1.00~~make all or any part of the required interest payment due on July 15, ~~and~~2020 with respect to the Company’s Senior Notes (2including 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 ~~Ratio~~30-day grace period before an event of ~~Total~~default ~~Debt~~occurs under the indenture, the failure to ~~EBITDAX~~make ~~(as~~the ~~defined~~interest inpayment on the ~~Credit~~due ~~Agreement)~~date constituted an event of nodefault ~~greater~~under ~~than~~the ~~4.0~~cross-default toprovisions 1of the Credit Agreement.0 The ~~calculated~~Company did not make the required interest payment of $13,125 on athe ~~trailing~~due ~~four~~date or within the 30-~~quarter~~day ~~basis~~grace period. WeThe ~~were~~Final inLender ~~compliance~~Forbearance ~~with~~Agreement ~~these~~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 ~~covenants~~statements asfor ofthe ~~March 31~~period ended June 30, 2020 and the required accompanying officer’s certificate.

~~The~~Pursuant ~~Credit~~to ~~Agreement~~the ~~contains~~Limited ~~covenants~~Forbearance ~~and~~Agreement ~~events~~with ofthe ~~default~~lenders ~~customary~~under ~~for~~our ~~oil and natural gas reserve-based lending facilities. Our~~ Credit Agreement, ~~and~~we ~~Senior~~terminated ~~Notes~~all ~~include~~our ~~cross~~outstanding ~~default~~derivatives ~~provisions~~contracts ~~wherein~~on aJuly 27, ~~default~~2020 onand ~~one~~applied ~~instrument~~a ~~may~~certain ~~cause~~portion ~~default~~of on the ~~other.~~proceeds ~~Please~~thereof ~~see~~toward ~~“Note~~partial 8:repayment ~~Debt” in “Item 8. Financial Statements and Supplementary Data”~~ of ~~our~~the ~~Annual~~outstanding ~~Report~~amount onunder ~~Form 10-K for~~ the ~~year~~Credit ~~ended December 31~~Agreement, ~~2019,~~which ~~for~~we adiscuss ~~discussion~~in of“Note ~~the~~11: ~~material~~Subsequent ~~provisions of our Credit Agreement~~events.”

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”). The Company notified the administrative agent for the Credit Facility on April 14, 2020, that it intends to eliminate such Borrowing Base Deficiency by repaying the amount of the Borrowing Base Deficiency in six equal monthly installments, in accordance with the Credit Agreement. We made the first payment of $12,500 plus interest on May 1, 2020. No premium or penalty would be charged with respect to those repayments. If the Company is unable to repay the amount of the Borrowing Base Deficiency within the time period required under the Credit Agreement, an event of default would occur under the Credit Agreement.

Senior Notes

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

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

The ~~Senior~~Indenture ~~Notes~~contains ~~contain~~ customary covenants, certain ~~callable~~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.

19On 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.

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.

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

	As of March 31, 2020
	Operating leases		Financing leases
Right of use asset:
Right of use assets from operating leases	$	2,097	$	—
Plant, property and equipment, net	—		1,542
Total lease assets	$	2,097	$	1,542
Lease liability:
Account payable and accrued liabilities	$	1,295	$	—
Long-term debt and financing leases, classified as current	—		439
Long-term debt and financing leases, less current maturities	—		1,110
Noncurrent operating lease obligations	579		—
Total lease liabilities	$	1,874	$	1,549

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

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
				Three months ended June 30,							Six months ended June 30,
	March 31, 2020			March 31, 2019
				2020			2019		2020		2019
Lease cost
Finance lease cost:
Amortization of right-of-use assets	$	~~117~~		$	~~693~~114		$	749	$	231	$	1,442
Interest on lease liabilities	27			~~113~~26			117		53		230
Operating lease cost	~~390~~			~~308~~389			308		779		616
Short-term lease cost	~~218~~			~~129~~92			154		310		283
Variable lease cost	—			95—			95		—		190
Sublease income	—			~~(1,198~~—		)	(1,198)		—		(2,396)
Total lease cost	$	~~752~~		$	~~140~~621		$	225	$	1,373	$	365
Capitalized operating lease cost (1)	$	—		$	~~3,335~~—		$	3,371	$	—	$	6,706
Other information
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows for finance leases	$	~~(27~~	)	$	(~~113~~26)	)	$	(117)	$	(53)	$	(230)
Operating cash flows for operating leases	~~(345~~		)	(~~308~~344)		)	(308)		(689)		(616)
Investing cash flows for operating leases	—			~~(1,023~~—		)	(2,965)		—		(3,988)
Financing cash flows for finance leases	~~(105~~		)	(~~699~~107)		)	(746)		(212)		(1,445)
Right-of-use assets obtained in exchange for new finance lease liabilities	—			~~670~~—			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.

		Weighted average fixed price per Bbl
Period and type of contract	VolumeMBbls	Swaps
2020
Oil swaps	1,770	$	51.16
Oil roll swaps	290	$	0.34
2021
Oil swaps	689	$	46.24
Oil roll swaps	150	$	0.30

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

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

Period and type of contract	VolumeBBtu	Weighted average fixed price per MMBtu
2020
Natural gas swaps	5,340	$	2.72
Natural gas basis swaps	5,040	$	(0.46	)

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

Period and type of contract	~~VolumeThousands of Gallons~~	~~Weighted average fixed price per gallon~~	VolumeBBtu	Weighted average fixed price per MMBtu
2020
Natural gasoline swaps	2,476	$	1.17
Natural gas swaps			3,000	$	2.75
Propane swaps	5,884	$	0.51
Natural gas basis swaps			3,000	$	(0.46)
Butane swaps	497	$	0.53

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 March 31, 2020								As of December 31, 2019
			As of June 30, 2020																		As of December 31, 2019
	~~Assets~~		~~Liabilities~~Assets		~~Net value~~		Liabilities		~~Assets~~			~~Liabilities~~Net value			~~Net value~~		Assets		Liabilities		Net value
Natural gas derivative contracts	$	~~4,255~~	$	—2,288	$	~~4,255~~	$	(500)	$	~~3,552~~		$	(1,788	)	$	~~3,551~~	$	3,552	$	(1)	$	3,551
Crude oil derivative contracts	~~45,436~~		—15,399		~~45,436~~		—		~~391~~			~~(22~~15,~~196~~399		)	~~(21,805~~		)391		(22,196)		(21,805)
NGL derivative contracts	~~3,430~~		—		~~3,430~~		—		~~2,868~~			~~(699~~—		)	~~2,169~~		2,868		(699)		2,169
Total derivative instruments	~~53,121~~		—17,687		~~53,121~~		(500)		~~6,811~~			~~(22~~17,~~896~~187		)	~~(16,085~~		)6,811		(22,896)		(16,085)
Less:
Netting adjustments (1)	—		—(500)		—		500		~~(5,864~~		)	~~5,864~~—			—		(5,864)		5,864		—
Derivative instruments - current	~~48,458~~		—15,197		~~48,458~~		—		~~947~~			~~(11~~15,~~957~~197		)	~~(11,010~~		)947		(11,957)		(11,010)
Derivative instruments - long-term	$	~~4,663~~	$	—1,990	$	~~4,663~~	$	—	$	—		$	(51,~~075~~990	)	$	~~(5,075~~	)$	—	$	(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

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

	Three months ended March 31,
			Three months ended June 30,							Six months ended June 30,
	~~2020~~		~~2019~~2020			2019		2020		2019
Change in fair value of commodity price derivatives	$	~~69,206~~	$	(5135,~~531~~934)	)	$	17,596	$	33,272	$	(33,935)
Net settlements received on commodity price derivatives	~~9,174~~		~~515~~22,915			138		32,089		653
Total derivative gains (losses)	$	~~78,380~~	$	(5113,~~016~~019)	)	$	17,734	$	65,361	$	(33,282)

22Pursuant 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.”

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 ~~March 31~~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.

	As of March 31, 2020						As of December 31, 2019
	Derivativeassets		Derivativeliabilities		Net assets(liabilities)		Derivativeassets			Derivativeliabilities			Net assets(liabilities)
Significant other observable inputs (Level 2)	$	53,016	$	—	$	53,016	$	6,576		$	(22,895	)	$	(16,319	)
Significant unobservable inputs (Level 3)	105		—		105		235			(1		)	234
Netting adjustments (1)	—		—		—		(5,864		)	5,864			—
	$	53,121	$	—	53,121		$	947		$	(17,032	)	$	(16,085	)

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.

23Changes in the fair value of our derivative instruments, classified as Level 3 in the fair value hierarchy, were as follows for the periods presented:

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

	Three months ended March 31,
				Six months ended June 30,
Net derivative assets (liabilities)	~~2020~~			~~2019~~2020			2019
Beginning balance	$	~~234~~		$	30234		$	30
Realized and unrealized gains (losses) included in derivative losses	1,863			(981		)
Realized and unrealized gains included in derivative losses				1,033			441
Settlements (received) paid	~~(1,992~~		)	~~413~~(1,767)			116
Ending balance	$	~~105~~		$	(~~538~~500)	)	$	587
Gains (losses) relating to instruments still held at the reporting date included in derivative gains (losses) for the period	$	4		$	(537	)
(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:

	Three months ended March 31,
				Six months ended June 30,
	~~2020~~		~~2019~~	2020		2019
Inflation rate	~~2.21~~	%	~~2.25~~	%2.21	%	2.25	%
Credit-adjusted risk-free discount rate	25.00	%	12.35	%
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.

	March 31, 2020				December 31, 2019
Level 2	Carryingvalue (1)		Estimatedfair value		Carryingvalue (1)		Estimatedfair value
8.75% Senior Notes due 2023	$	300,000	$	13,500	$	300,000	$	133,050
Credit facility	145,000		145,000		130,000		130,000
Other secured debt (2)	58		58		371		371

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

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


	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

~~(2) The balance on March 31, 2020, and December 31, 2019, consisted of only equipment installment notes.~~________________________________

(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.

2427

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

~~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 ~~March 31~~June 30, 2020, the counterparties to our open derivative contracts consisted of ~~seven~~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~~			Offset in the consolidated balance sheets							~~Gross amounts not offset in the consolidated balance sheets~~											Gross amounts not offset in the consolidated balance sheets
	~~Gross assets(liabilities)~~			~~Offsetting~~Gross assets(liabilities)			~~Net assets(liabilities)~~		Offsetting assets(liabilities)		~~Derivatives (1)~~		~~Amountsoutstandingunder~~Net ~~creditfacilities~~ assets(2liabilities)			~~Net amount~~		Derivatives (1)		Amountsoutstandingunder creditfacilities (2)		Net amount
March 31, 2020
June 30, 2020
Derivative assets	$	~~53,121~~		$	—17,687		$	~~53,121~~	$	(500)	$	—	$	~~(44~~17,~~411~~187	)	$	~~8,710~~	$	—	$	(17,187)	$	—
Derivative liabilities	—			—(500)			—		500		—		—			—		—		—		—
	$	~~53,121~~		$	—17,187		$	~~53,121~~	$	—	$	—	$	~~(44~~17,~~411~~187	)	$	~~8,710~~	$	—	$	(17,187)	$	—
December 31, 2019
Derivative assets	$	~~6,811~~		$	(56,~~864~~811	)	$	~~947~~	$	(5,864)	$	—	$	(947	)	$	—	$	—	$	(947)	$	—
Derivative liabilities	~~(22,896~~		)	5(22,~~864~~896)			~~(17,032~~		)5,864		—		~~947~~(17,032)			~~(16,085~~		)—		947		(16,085)
	$	~~(16,085~~	)	$	—(16,085)		$	~~(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 ~~nil~~$500 before offsets at ~~March 31~~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~~	$	23,156
Liabilities incurred in current period	41		84
Liabilities settled or disposed in current period	~~(63~~		(419)
Revisions in estimated cash flows	15		49
Accretion expense	~~323~~		649
Balance at March 31, 2020	$	23,472
Balance at June 30, 2020			$	23,519
Less current portion included in accounts payable and accrued liabilities	~~928~~		2,107
Asset retirement obligations, long-term	$	~~22,544~~	$	21,412

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

~~Note 9: Deferred compensation~~28

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

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 March 31,
			Three months ended June 30,						Six months ended June 30,
	~~2020~~		~~2019~~2020		2019		2020		2019
Cash LTIP expense (net of amounts capitalized)	$	~~167~~	$	91187	$	67	$	354	$	158

As of ~~March 31~~June 30, 2020, the outstanding liability accrued for our Cash LTIP, based on requisite service provided, was $1,~~130~~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 (“~~RSAs~~restricted shares”) and restricted stock units (“RSUs”). In December 2019, we also granted ~~RSAs~~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 ~~RSAs~~restricted shares and RSUs.

A summary of our ~~RSA~~restricted share activity is presented below:

	~~Time Shares~~		Time Shares					~~Performance Shares~~								Performance Shares
	~~Weightedaverageaward datefair value~~		~~Restrictedshares~~Weightedaverageaward datefair value		~~Vestdatefairvalue~~		Restrictedshares	~~Weightedaverageaward datefair value~~		~~Restrictedshares~~	Vestdatefairvalue		Weightedaverageaward datefair value		Restrictedshares
	~~($ per share)~~		($ per share)					~~($ per share)~~					($ per share)
Unvested and outstanding at January 1, 2020	$	~~5.41~~	~~1,069,505~~$	5.41			1,069,505	$	~~1.53~~	~~1,089,343~~			$	1.53	1,089,343
Granted	$	—	—$	—			—	$	—	—			$	—	—
Vested	$	~~16.25~~	~~(83,130~~$	)15.71	$	88	(203,888)	$	—	—	$	130	$	—	—
Forfeited	$	~~20.05~~	~~(10,406~~$	)8.87			(82,658)	$	—	—			$	6.94	(20,833)
Cancelled	$	~~20.05~~	~~(12,088~~$	)20.05			(12,088)	$	—	—			$	—	—
Unvested and outstanding at March 31, 2020	$	4.14	963,881					$	1.53	1,089,343
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:~~29

	Equity classified RSUs
	Service-condition RSUs						Market condition RSUs
	Weighted averageaward date fair value		Restrictedunits		Vest datefair value		Weighted averageaward datefair value		Restrictedunits
	($ per share)						($ per share)
Unvested and outstanding at January 1, 2020	$	2.41	638,383				$	1.36	390,000
Granted	$	—	—				$	—	—
Vested	$	—	—		$	—	$	—	—
Forfeited	$	1.33	(76,621	)			$	1.36	(62,500	)
Unvested and outstanding at March 31, 2020	$	2.56	561,762				$	1.36	327,500

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

	Liability classified RSUs
	Weighted averageaward date fair value		Restrictedunits		Vest datefair value
	($ per share)
Unvested and outstanding at January 1, 2020	$	4.57	75,779
Granted	$	—	—
Vested	$	—	—		$	—
Forfeited	$	17.66	(1,515	)
Unvested and outstanding at March 31, 2020	$	4.31	74,264

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 March 31,
				Three months ended June 30,							Six months ended June 30,
	~~2020~~			~~2019~~2020			2019		2020		2019
Stock-based compensation cost	$	~~670~~		$	~~1,460~~101		$	1,260	$	771	$	2,720
Less: stock-based compensation cost capitalized	~~(274~~		)	(~~626~~7)		)	(399)		(281)		(1,025)
Stock-based compensation expense	$	~~396~~		$	~~834~~94		$	861	$	490	$	1,695
Number of vested shares repurchased or settled in cash	~~3,856~~			8092,~~422~~649			126,231		96,505		206,653
Payments for stock-based compensation	6			~~463~~53			708		59		1,171

Based on a quarter end market price of $0.4765 per share of our Class A common stock, the aggregate intrinsic value of all ~~RSAs~~restricted shares and RSUs outstanding was $1,~~418~~593 as of ~~March 31~~June 30, 2020. ~~Our payments for stock-based compensation are predominantly for tax withholding during vesting events although we also make an immaterial amount of payments for our cash settled RSUs.~~ Payments for ~~RSAs~~restricted shares and the associated number of shares repurchased are reflected as treasury stock transactions in our consolidated statements of equity. As of ~~March 31~~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 $23 and $52, respectively, all of which relates to our cash-settled RSUs. Unrecognized stock-based compensation cost of approximately $2,277 as of March 31, 2020, is expected to be recognized over a weighted-average period of 1.4 years.

~~Note 10: Commitments and contingencies~~ 30

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 March 31, 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 three months ended March 31, 2020 or 2019.

Surety bonds totaling $3,389 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 in “Note 4: Debt” above, the surety for these

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

~~bonds,~~twelve onmonths ~~April~~were 15$45 and $52, ~~2020~~respectively, ~~exercised~~all ~~its~~of ~~right~~which relates to ~~demand~~our ~~that~~cash-settled ~~the~~RSUs. Unrecognized ~~Company~~stock-based ~~post~~compensation ~~cash~~cost ~~collateral~~of inapproximately ~~respect~~$1,357 as of ~~the~~June ~~bonds. The~~30, ~~Company~~2020, ~~subsequently~~is ~~provided~~expected ~~$500~~to inbe ~~such~~recognized ~~collateral~~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 ~~Proceedings~~Cases. Commencement of the Prior Chapter 11 Cases ~~in 2016~~ 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 ~~will~~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., Ifin ~~the~~each ~~Bankruptcy~~case ~~Court~~subject ~~were~~ to ~~allow~~their ~~the~~further ~~remaining~~treatment ~~unresolved~~prescribed ~~proofs~~by ~~of claims from any of these cases in~~ the ~~full amount asserted therein, the Company, pursuant to the~~ Plan of Reorganization, ~~would~~assuming beits ~~required~~ultimate ~~to issue additional shares to the holders of such allowed proofs of claim that are in excess of a convenience class threshold, which could result in dilution to existing stockholders~~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, to which we will also object. 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.

~~We continue to dispute the plaintiffs’ allegations and are objecting to the claims both individually and on a class-wide basis.~~31

W.H. Davis Family Limited Partnership Claims in the Company’s Chapter 11 Bankruptcy 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 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

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

~~of $2,650 in~~may ~~Class~~file ~~6 under the Reorganization Plan, which agreement was memorialized in~~ a ~~settlement~~claim ~~term sheet executed by both parties~~ on ~~the~~behalf ~~day~~ of the ~~mediation,~~class. This aorder ~~settlement~~did ~~agreement~~not ~~executed~~establish byliability ~~both~~or ~~parties~~otherwise ~~thereafter,~~address ~~and~~the amerits ~~settlement~~of ~~stipulation~~the ~~executed~~plaintiffs’ byclaims. The ~~both~~Bankruptcy ~~parties~~Court ~~that~~order was ~~filed~~affirmed ~~with~~by the ~~Bankruptcy~~United ~~Court.~~States ~~Davis~~District isCourt ~~now~~for ~~contesting~~ the ~~enforcement~~District of ~~the~~Delaware ~~settlement~~on ~~under~~September ~~its terms~~24, ~~which~~2019. On ~~resulted~~October ~~in the issuance of 84~~24,~~347~~ ~~shares of Class A common stock to Davis~~2019, ~~claiming~~the ~~that~~Company hefiled ~~was~~its ~~mistaken~~notice ~~in his understanding~~ of ~~the~~appeal ~~terms~~to of the ~~Reorganization~~United ~~Plan~~States asCourt ~~relate to Class 6 claims. The Company is vigorously pursuing the enforcement~~ of ~~the~~Appeals ~~settlement~~for in the ~~Bankruptcy~~Third ~~Court~~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 as it does not intend to drill wells on the subject acreage in 2020 given the current commodity price environment. No determination has been made with respect to 2021 or 2022; however, if the Company fails to drill the prescribed number of wells in either year, it would be obligated to make additional payments to the sellers.

~~As of March 31, 2020, we did not have material changes to our contractual commitments since December 31, 2019.~~32

29Chaparral 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

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.

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. 


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 ~~207~~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 ~~120~~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 ~~March 31~~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 ~~First~~2020 ~~Quarter~~ Activity

AtEarly ~~the~~in ~~beginning of~~ the first quarter ~~ended~~of ~~March 31,~~ 2020, Chaparral management ~~commenced~~began a comprehensive cash improvement effort. The initiative, which involves the formation and collaboration of multiple working teams, iswas 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 ~~have~~were ~~been~~ implemented and ~~are yielding~~ expanded cash flow at the project level ~~already~~. However, because of the extraordinary and unprecedented events affecting the oil and gas industry discussed below, ~~initiatives~~the ~~that~~benefits – which are scale-dependent ~~are~~– ~~expected~~were tonot beable ~~fully realized only when activity has resumed~~ to ~~more~~achieve ~~normal~~their ~~levels~~full potential.

Macroeconomic Developments and Their Impact on the Oil and Gas Industry

The ~~rapid~~energy industry has recently experienced two significant external forces that have impacted, ~~global~~and ~~spread~~are ofanticipated to continue impacting, both day-to-day operations and the macro environment. The COVID-19 inoutbreak ~~the~~and ~~first~~voluntary ~~quarter~~and ofmandatory ~~2020~~quarantines, travel restrictions and other restrictions throughout the ~~resulting~~United ~~economic~~States ~~repercussions~~and ~~created~~other ~~significant~~parts ~~volatility~~of the world have resulted in ~~the~~decreased demand for crude oil, NGLs and ~~gas~~natural ~~industry~~gas. Additionally, ~~Stay-at-home~~in ~~and~~March ~~similar~~2020, ~~protective~~the ~~measures~~group ~~that~~of ~~were~~oil ~~enacted~~producing bynations ~~federal,~~known ~~foreign,~~as ~~state~~OPEC+ ~~and~~failed ~~local~~to ~~governments~~reach an agreement over proposed oil production cuts due to ~~slow~~the decrease in global demand for oil stemming from the ~~spread~~COVID-19 ofpandemic (the ~~virus~~oil ~~contributed~~price war). Although the members of OPEC+ eventually reached an agreement to areduce ~~significant~~their ~~deterioration~~oil production beginning in May 2020 and continuing through April 2022, there remains significant uncertainty regarding the ~~domestic~~future actions of OPEC+, its members and ~~global~~other ~~demand~~state-controlled ~~for~~oil companies related to oil price and ~~gas~~production controls, including anticipated increases in supply from Russia and other members of OPEC+, particularly Saudi Arabia.

~~Compounding~~In addition, the ~~impact of~~ COVID-19, ~~the~~pandemic ~~oil~~has ~~production~~increased ~~output~~volatility ~~alliance between Russia, Saudi Arabia~~ and ~~other~~caused ~~oil~~negative ~~producing~~pressure ~~nations (“OPEC+”) broke down as both sides were unable to reach agreement~~ in ~~early~~the ~~March~~capital ~~2020~~and ~~over~~credit ~~how much to restrict production in order to stabilize crude oil prices~~markets. As a result, ~~Saudi~~we ~~Arabia~~have ~~and~~not ~~Russia~~had ~~both~~the ~~initiated~~sort ~~efforts~~of access to ~~increase~~the ~~production,~~capital ~~driving~~and ~~down~~credit ~~oil~~markets ~~prices.~~that ~~OPEC+~~ was ~~later~~once ~~able~~available to ~~agree~~us. That onlack ~~approximately~~of ~~9.7~~access ~~million~~to ~~barrels~~financing ofcompounded ~~oil~~the ~~per~~impact ~~day~~ of ~~production~~the ~~cuts,~~depressed ~~but~~commodity ~~that~~price ~~announcement~~environment ~~has~~triggered ~~done~~by ~~little~~COVID-19 toand ~~aid~~the in oil price ~~recovery because of the significant drop in global demand~~war.

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 West Texas Intermediate (“WTI”) prices dipped into the negative, and as of the time of this filing were less than $26.00 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. Therefore, the price shock described above will be detrimental to our April and May 2020 crude revenues. Furthermore, producers are not able to produce significant volumes of oil now and store it for later sale because little or no storage capacity remains available.

This combination of events has led to an unprecedented supply-demand oil imbalance in the range of 25 million to 28 million barrels of oil per day during April 2020, 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.

In addition, the COVID-19 pandemic 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.

Chaparral’s Response and 2020 Outlook

In response to the depressed commodity price environment, Chaparral ishas ~~taking~~taken material and unusual actions to maximize the value of its assets and improve its financial position. Because the Company ~~has~~had (a) a strong hedge position for crude oil in 2020, the ~~proceeds~~terms of which dodid 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 iswas not prudent or necessary to continue developing our inventory or to sell all of our products at ~~current~~the prevailing low market prices.

~~Accordingly,~~Shut-ins weand 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 was performing above expectations. Since then, the Company has begun to shut-in operated production that is not associated with waterfloods or exposed to well-specific mechanical or other risks. Procedures and precautions were followed to help protect mechanical and reservoir integrity and to minimize the cost and timing of resuming production to help ensure that production can be resumed efficiently on these shut-in wells once commodity prices recover sufficiently. Furthermore, in order to facilitate a swift restart of sales when that price recovery occurs, we are taking steps now to increase crude storage in the tank batteries at our operated lease locations. Once tank batteries are full, we expect that the majority of our operated production will be curtailed, with future prices determining the timing of when the wells will be turned back online. These operational adjustments will result in lower production (with a resulting decline in revenues) and lower costs and capital spending requirements in the second quarter.

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.

~~Cash~~Proceeds ~~Flows~~ from ~~Operating~~Revolving ~~Activities. As~~Credit ~~described~~Facility ~~above,~~and inSenior ~~light~~Notes ofInterest Payment. In order to address the ~~significant~~net ~~deterioration~~reduction in ~~commodity~~cash ~~prices~~flows discussed above, we ~~have~~significantly ~~shut~~increased inour acash ~~substantial~~balance ~~number~~by ofborrowing ~~our~~an ~~producing~~additional ~~wells~~$105 ~~and~~million ~~have~~at ~~suspended~~the ~~all~~beginning ~~drilling~~of ~~and~~April ~~stimulation operations~~2020. AsThese aborrowings ~~result,~~were wemade ~~expect~~as ~~the~~a ~~cash~~precautionary ~~flows~~measure ~~generated~~to ~~from~~increase our ~~operating~~cash ~~activities~~position toand ~~decline~~provide ~~significantly,~~operational ~~offset~~flexibility byin ~~(a)~~ the ~~related~~current ~~reductions~~challenging inbusiness ~~expenses and capital expenditures and (b) proceeds from hedge settlements~~environment. The ~~impact~~April of2020 ~~this~~borrowings ~~response~~increased ~~on liquidity during~~ the ~~second~~total ~~quarter~~amount ~~will~~outstanding ~~depend~~under onour ~~gas~~Credit ~~and~~Agreement ~~NGL revenues prior~~ to ~~shut-in,~~$250.0 ~~how much variable lease operating expense can be eliminated and how long the shut-ins last~~million.

~~Proceeds~~Borrowing ~~from~~Base ~~Revolving~~Deficiency ~~Credit Facility~~ and ~~Senior~~Past ~~Notes~~Due ~~Interest~~August Deficiency Payment. AtShortly ~~the~~after ~~beginning~~we ofmade these borrowings in April 2020, weour ~~significantly~~lenders ~~increased~~made ~~our~~an ~~cash~~interim ~~balance~~redetermination byof the Company’s borrowing anbase, ~~additional~~reducing the borrowing base from $~~105~~325.0 million to $175.0 million, ~~which~~effective ~~increased~~April 3, 2020. The combination of the ~~total~~borrowing ~~amount~~base ~~outstanding~~reduction ~~under~~and our ~~Credit~~April ~~Agreement~~2020 ~~(as~~borrowings ~~defined~~created ~~below)~~a to $~~250~~75.0 million~~. Contemporaneously~~ ~~with~~borrowing ~~the~~base ~~additional~~deficiency ~~borrowings~~ under the Credit Agreement, (the ~~lenders~~“Borrowing ~~under~~Base ~~that~~Deficiency”). In ~~agreement~~accordance ~~notified~~with the ~~Company~~Credit ~~regarding~~Agreement, ~~the~~we ~~Borrowing~~elected ~~Base~~to ~~Redetermination~~follow ~~(as~~a ~~defined~~procedure ~~below). The~~that ~~Company~~permitted isthe ~~required~~Company to repay the ~~resulting~~ $75 .0 million ~~borrowing base~~ deficiency in six equal monthly installments, ~~plus~~of ~~interest~~$12.5 million, beginning onin early May 2, 2020. ~~Furthermore~~Since making that election, ~~our~~we ~~next~~have ~~semi-annual~~made ~~interest~~three ~~payment~~deficiency payments, for a total of $1337.1 5 million. However, onwe ~~our~~did 8not make the fourth installment payment of $12.~~75%~~5 ~~Senior~~million ~~Notes~~that iswas due on ~~July 15~~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.

~~Hedging~~Past Due Interest Payment on the Senior Notes. AsOn ~~described~~July ~~above~~15, in2020, ~~“Note 6:~~the ~~Derivative~~Company ~~Instruments”~~elected ~~above~~not into make the ~~accompanying~~$13.125 ~~financial~~million ~~statements,~~interest wepayment ~~have~~on athe ~~strong~~Senior ~~hedge~~Notes ~~position~~due ~~for~~on ~~crude~~that ~~oil~~day in(the ~~2020~~“Past Due Interest Payment”). Under the ~~proceeds~~Indenture, ofthe ~~which~~Company dohas ~~not~~a ~~require~~30-day grace period to make the ~~physical~~Past ~~delivery~~Due ofInterest ~~any~~Payment ~~oil~~before orthat ~~gas. In~~non-payment ~~light~~becomes ofan ~~the~~event ~~significant~~of ~~difference~~default. The ~~between~~Company ~~near-term~~subsequently ~~commodity~~did ~~prices~~not ~~and~~make ~~future~~the ~~prices,~~Past ~~one~~Due ~~possible~~Interest ~~strategy~~payment ~~would~~upon beexpiration ~~for~~of usthe to30-day ~~increase~~grace ~~and~~period ~~lengthen~~on ~~our~~August ~~hedging~~14, ~~position~~2020. ~~This~~Even ~~approach~~though ~~would~~the ~~align~~Indenture ~~our~~provides ~~hedges~~for ~~with~~a ~~our~~30-day ~~decision~~grace period to ~~suspend~~make ~~drilling~~the ~~and~~Past Due Interest Payment, the failure to ~~shut-in~~make athat ~~substantial~~interest ~~amount~~payment ofon ~~production~~its ~~until~~due ~~prices~~date ~~recover. However~~of July 15, ~~our~~2020 ~~hedging~~constituted ~~counterparties~~an ~~(who~~immediate ~~are~~event ~~also~~of ~~lenders~~default under ~~our~~cross-default provisions of the Credit Agreement). The ~~have~~subsequent ~~informed~~failure usto make that ~~they~~interest ~~currently~~payment doupon ~~not~~expiration ~~intend~~of tothe ~~enter~~30-day ~~into~~grace ~~new~~period ~~hedges~~on ~~with~~August us14, ~~until~~2020 weconstituted ~~have~~an ~~cured~~event of default under the ~~Borrowing~~indenture ~~Base~~governing ~~Deficiency~~our ~~(as~~Senior ~~defined~~Notes ~~below~~(the “Indenture”).

WeLender ~~believe~~Forbearance ~~that~~Agreement. On ~~the~~July ~~actions~~15, ~~that~~2020, ~~the~~in ~~Company~~order ~~has taken~~ to ~~draw~~address ~~down on its revolving credit facility and to implement material operational changes afford us~~ the ~~ability~~cross-default tothat ~~diligently explore all credible operating and capitalization scenarios available to us. However, our profitability outlook based on current strip prices has~~ resulted inunder athe ~~situation~~Credit ~~that~~Agreement ~~raises~~from ~~substantial~~the ~~doubt~~failure ~~about our ability~~ to ~~continue~~timely aspay ~~a going concern within one year of~~ the ~~time~~Past ofDue ~~this~~Interest ~~filing. In that regard~~Payment, the Company’s ~~Board~~entered ofinto ~~Directors has formed~~ a ~~Special~~Limited ~~Committee~~Forbearance ~~composed~~Agreement ofwith ~~independent directors to review and evaluate strategic alternatives to preserve and grow~~ the ~~value~~lenders ofunder ~~the~~its ~~enterprise~~Credit Agreement. WeThe ~~have~~Limited ~~also~~Forbearance ~~retained~~Agreement ~~financial~~was ~~and~~amended ~~legal~~effective ~~advisors to assist in this evaluation process. No assurances can be given~~ as ~~to the outcome or timing~~ of ~~the~~July ~~evaluation~~24, or2020, ~~whether~~by ~~any~~the ~~particular transaction may be pursued or consummated.~~First

3137

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.

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)	~~March 31, 2020~~			~~December~~June 3130, ~~2019~~2020			December 31, 2019
8.75% Senior Notes due 2023	$	~~300,000~~		$	300,000		$	300,000
Credit facility	~~145,000~~			~~130~~225,000			130,000
Financing lease obligations	~~1,549~~			1,~~653~~442			1,653
Installment note payable	58			~~371~~—			371
Unamortized issuance costs	~~(9,355~~		)	(104,~~038~~154)		)	(10,038)
Total debt, net	$	~~437,252~~		$	~~421~~522,~~986~~288		$	421,986

Credit facility

Pursuant to our Credit Agreement (the “Credit Agreement”) with Royal Bank of Canada, as administrative agent and issuing bank, and the additional lenders party thereto, we have a $750.0 million credit facility collateralized by our oil and natural gas properties and is scheduled to mature on December 21, 2022. Availability under our credit facility is subject to financial covenants (see “Note 4: Debt” in “Item 1. Financial Statements” of this report) and a borrowing base predicated on the value of our oil and natural gas properties and set by the banks semi-annually on or around May 1 and November 1 of each year. As of March 31, 2020, our borrowing base on the credit facility was $325.0 million. Depending on how quickly supply and demand for oil return to balance and commodity prices reflect same, and the consequent duration of the production shut-ins described above, our ability to remain in compliance with the financial covenants referenced above may be materially negatively affected.

The Credit Agreement contains covenants and events of default customary for oil and natural gas reserve-based lending facilities. Please see “Note 8: Debt” in “Item 8 Financial Statements and Supplementary Data” of our Annual Report on Form 10-K for the year ended December 31, 2019, for a discussion of the material provisions of our Credit Agreement.

On April 1, 2020, we borrowed $15.0 million and on April 2, 2020, we provided notice to our lenders to borrow an additional $90.0 million (the latter herein referred to as the “Borrowing”) which increased the total amount outstanding under the Credit Agreement to $250.0 million. 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 $325.0 million to $175.0 million, effective April 3, 2020. Our lenders subsequently reaffirmed the borrowing base at the same level on May 5, 2020, in conjunction with the Company’s 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 $75.0 million under the Credit Agreement (the “Borrowing Base Deficiency”). The Company notified the administrative agent for the Credit Facility on April 14, 2020, that it intends to eliminate such Borrowing Base Deficiency by repaying the amount of the Borrowing Base Deficiency in six equal monthly installments, with the first payment of $12.5 million plus interest made on May 1, 2020. No premium or penalty would be charged with respect to those repayments. If the Company is unable to repay the amount of the Borrowing Base Deficiency within the time period required under the Credit Agreement, an event of default would occur under the Credit Agreement.

8.75% Senior Notes

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

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

Finance leases

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

Our net change in cash is summarized as follows:

	Three months ended March 31,
(in thousands)	2020			2019
Cash flows provided by operating activities	$	12,883		$	8,554
Cash flows used in investing activities	(36,670		)	(63,529		)
Cash flows provided by financing activities	14,483			28,647
Net decrease in cash during the period	$	(9,304	)	$	(26,328	)

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 three months ended March 31, 2020, of $12.9 million increased compared to the prior year quarter primarily due to higher gross revenues and lower lease operating expenses partially offset by higher transportation and processing deductions.


	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)

WeOur ~~use~~cash ~~the~~flows ~~net~~from ~~cash~~operating ~~provided~~activities byare ~~operations~~derived tosubstantially ~~partially~~from ~~fund~~the ~~our~~production ~~acquisition,~~and ~~exploration~~sale of oil and ~~development~~natural ~~activities~~gas. Cash ~~During~~flows from operating activities for the six months ended June 30, 2020, wewhich ~~also~~was ~~relied~~an onoutflow ~~borrowings~~of ~~from~~$9.4 ~~our~~million, ~~credit~~decreased ~~facility~~compared ~~and~~to ~~cash~~the onprior ~~hand~~year period primarily due to ~~fund~~a ~~our~~reduction in gross revenues, liability management expenses that we incurred and working capital ~~expenditures~~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 ~~three~~six months ended ~~March 31~~June 30, 2020, are summarized in the table below.

(in thousands)	~~Three months ended March 31, 2020~~		Six months ended June 30, 2020
Acquisitions (1)	$	~~4,232~~	$	11,080
Drilling (2)	~~43,298~~		42,750
Enhancements	~~3,523~~		4,069
Operational capital expenditures incurred	~~51,053~~		57,899
Other (3)	~~4,651~~		6,952
Total capital expenditures incurred	$	~~55,704~~	$	64,851

______________________________________________________

(1) Includes $28.58 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 ~~three~~six months ended ~~March~~June 3130, 2020, this amount includes $2.29 million for capitalized general and administrative expenses, and $2.3.9 million for capitalized interest.

Net cash used in investing activities during the ~~three~~six months ended ~~March 31~~June 30, 2020 consisted of cash outflows for capital expenditure of $4986.19 million partially offset by receipts for derivative settlements of $932.21 million and proceeds from asset sales of $3.24 million. Our ~~The~~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 ~~three~~ six months ended ~~March 31~~ June 30, 2019 consisted of cash outflows for capital expenditure of $64146.04 million partially offset by receipts for derivative settlements of $0.57 million and proceeds from asset sales of $0.9 million.

Net cash from financing activities during the ~~three~~six months ended ~~March 31~~June 30, 2020, consisted of borrowings on our credit facility of $15120.0 million partially offset by cash outflows of $025.45 million for repayment of debt, including financing leases, and $0.1 million for debt financing fees. Net cash from financing activities during the ~~three~~ six months ended ~~March 31~~ June 30, 2019, consisted of borrowings on our ~~Credit~~credit ~~Facility~~facility of $3085.0 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.

million partially offset by cash outflows for repayment of debt and financing leases of $0.9 million and for treasury stock repurchases of $0.5 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 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 an accrual of $2.5 million in March 2020 for the deficiency on its 2020 drilling commitment as it does not intend to drill wells on the subject acreage in 2020 given the current commodity price environment. No determination has been made with respect to 2021 or 2022; however, if the Company fails to drill the prescribed number of wells in either year, it would be obligated to make additional payments to the sellers.

Surety bonds totaling $3.4 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, the surety for these bonds, on April 15, 2020, exercised its right to demand that the Company post cash collateral in respect of the bonds. The Company subsequently provided $0.5 million in such collateral.40

~~Other~~Company ~~than~~does ~~additional~~not ~~borrowings~~drill ~~under~~and ~~our~~complete ~~credit~~the ~~facility~~minimum ~~and~~number of wells in a given year, it is required to pay the ~~Borrowing~~sellers ~~Base~~of ~~Deficiency~~the ~~described~~acreage $250,000 for ineach ~~“Note~~deficient 4:well. The ~~Debt”~~Company inhas ~~“Item~~paid 1:the ~~Financial~~deficiency ~~Information”~~amount related to its 2019 drilling commitment and recorded accruals of ~~this~~$2.5 ~~Quarterly~~million ~~Report~~in onMarch ~~Form~~2020 ~~10-Q,~~and we$6.3 ~~have~~million ~~not~~in ~~had~~June ~~material~~2020 ~~changes~~for the remaining obligation as it does not intend to ~~our~~drill ~~contractual~~any ~~commitments~~further ~~since December 31,~~wells ~~2019~~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 ~~first~~second quarter of 2020 includes the following highlights and comparisons to the prior year quarter:

• We generated a net ~~income~~loss for the three months ended ~~March~~June 3130, 2020, of $4438.97 million. Included in our ~~income~~loss ~~were~~was ~~gains on commodity derivative instruments of $78.4 million partially offset by~~ a ceiling impairment of $71384.46 million.

• Our ~~gain~~loss on commodity derivatives for the three months ended ~~March~~June 3130, 2020, ~~was~~of ~~attributable to~~ $913.20 million ofwas ~~realized~~attributable ~~settlement~~to ~~gains and~~ $6935.29 million of noncash mark-to-market ~~gains~~losses ~~driven~~partially offset by ~~the~~$22.9 ~~decline~~million in ~~crude~~realized ~~oil~~settlement ~~and NGL prices~~gains.

•Our ~~We grew~~ net ~~production~~sales byvolume 49decreased 34% to 21,~~793~~689 MBoe for the three months ended ~~March~~June 3130, 2020., ~~Within~~compared ~~our~~to ~~Focus~~the ~~Areas,~~prior ~~net~~year ~~production~~quarter ~~grew~~as ~~68%~~we tocurtailed ~~2,404~~capital ~~MBoe~~development ~~over~~and shut-in wells for a portion of the ~~same~~quarter ~~time~~in ~~period~~response to low commodity prices.

• We lowered our lease operating expense by 1855% to $106.10 million for the three months ended ~~March~~June 3130, 2020., ~~Our~~compared ~~cost~~to ~~reductions~~the ~~were~~prior ~~accomplished~~year ~~despite~~quarter. The ancorresponding ~~increase~~change inon ~~production,~~a asper ~~evidenced~~Boe bybasis ~~the~~was ~~45%~~a decrease inof ~~lease~~32% ~~operating expense per Boe~~ to $3.6158/Boe.

• We ~~lowered~~incurred ~~general~~liability ~~and~~management ~~administrative~~ expenses onof ~~a per Boe basis by 35% to~~ $28.890 ~~per~~million ~~Boe~~from ~~compared~~our activities to ~~the~~restructure ~~prior~~our ~~year~~debt ~~quarter. Total general~~ and ~~administrative~~in ~~expenses~~preparation ~~was reduced by 3% to $8.1 million~~ for ~~the~~our ~~three~~Chapter ~~months~~11 ~~ended March 31, 2020~~Case.

• Our oil and natural gas capital expenditures for the ~~three~~six months ended ~~March~~June 3130, 2020, were $5564.79 million, with $4342.38 million incurred for drilling and completions and $411.21 million on acquisitions. Our capital activity during ~~this~~the ~~period~~first half of the year included completing and bringing online 15 wells, of which nine were drilled in the current ~~quarter~~year and six in the prior year. We also drilled ~~two~~three wells scheduled to be completed subsequent to quarter end.

34•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.

~~Production~~ Sales

	Three months ended March 31,		Increase/		Percent
	2020	2019	(Decrease)		Change
Focus Areas:
Kingfisher County	750	605	145		24.0	%
Canadian County	1,382	476	906		190.3	%
Garfield County	236	296	(60	)	(20.3	)%
Other	36	57	(21	)	(36.8	)%
Total Focus Areas	2,404	1,434	970		67.6	%
Other	389	440	(51	)	(11.6	)%
Total	2,793	1,874	919		49.0	%

Sales volumes by area were as follows (MBoe)

For the three months ended March 31, 2020, our total net production increased compared to the prior year quarter. This increase is primarily due to increases in production in our Focus Areas, primarily in Kingfisher County and Canadian County where we brought online an additional 62 wells during the period. This pattern of growth underscores our emphasis on developing our Focus Areas which includes bringing online 66 gross (57 net) operated new wells in the area in the last 12 months.


	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)	%


	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.

35The following table presents information about our sales volumes and revenues before the effects of commodity derivative settlements:

The following table presents information about our production and commodity sales 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)

	Three months ended March 31,						Increase/			Percent
	2020			2019			(Decrease)			Change
Commodity sales (in thousands):
Oil	$	37,026		$	32,802		$	4,224		12.9	%
Natural gas	8,655			11,206			(2,551		)	(22.8	)%
Natural gas liquids	9,682			9,217			465			5.0	%
Gross commodity sales	$	55,363		$	53,225		$	2,138		4.0	%
Transportation and processing	(6,512		)	(4,606		)	(1,906		)	41.4	%
Net commodity sales	$	48,851		$	48,619		$	232		0.5	%
Production:
Oil (MBbls)	840			618			222			35.9	%
Natural gas (MMcf)	6,450			4,474			1,976			44.2	%
Natural gas liquids (MBbls)	878			510			368			72.2	%
MBoe	2,793			1,874			919			49.0	%
Average daily production (Boe/d)	30,692			20,819			9,873			47.4	%
Average sales prices (excluding derivative settlements):
Oil per Bbl	$	44.08		$	53.08		$	(9.00	)	(17.0	)%
Natural gas per Mcf	$	1.34		$	2.50		$	(1.16	)	(46.4	)%
NGLs per Bbl	$	11.03		$	18.07		$	(7.04	)	(39.0	)%
Transportation and processing per Boe	$	(2.33	)	$	(2.46	)	$	0.13		(5.3	)%
Average sales price per Boe	$	17.49		$	25.95		$	(8.46	)	(32.6	)%

Our gross commodity sales (excluding transportation and processing deductions) for the three months ended March 31, 2020, increased due to an increase in production across all commodities, partially offset by price decreases on all three commodities. The table below discloses the impact of price and production volume changes on our revenues.


	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)	%

	Three months ended March 31, 2020 vs. 2019
(in thousands)	Saleschange			Percentagechangein sales
Change in oil sales due to:
Prices	$	(7,560	)	(23.0	)%
Production	11,784			35.9	%
Total change in oil sales	$	4,224		12.9	%
Change in natural gas sales due to:
Prices	$	(7,491	)	(66.8	)%
Production	4,940			44.1	%
Total change in natural gas sales	$	(2,551	)	(22.8	)%
Change in natural gas liquids sales due to:
Prices	$	(6,185	)	(67.1	)%
Production	6,650			72.1	%
Total change in natural gas liquids sales	$	465		5.0	%

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 ~~March 31~~June 30, 2020, were ~~higher~~lower than the prior year ~~periods~~quarter due primarily to ~~increases~~ decreases in natural gas and natural gas liquids ~~production~~volumes sold. Transportation and processing deductions for the six months ended June 30, 2020,

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 March 31,
				Three months ended June 30,									Six months ended June 30,
	~~2020~~			~~2019~~2020			2019			2020			2019
Oil (per Bbl):
Before derivative settlements	$	~~44.08~~		$	5322.0892		$	58.41		$	36.67		$	56.20
After derivative settlements	$	~~49.03~~		$	5463.7155		$	56.13		$	54.12		$	55.54
Post-settlement to pre-settlement price	~~111.2~~		%	~~103~~277.13		%	96.1		%	147.6		%	98.8		%
Natural gas liquids (per Bbl):
Before derivative settlements	$	~~11.03~~		$	188.0738		$	14.72		$	10.11		$	16.08
After derivative settlements	$	~~14.82~~		$	1913.1873		$	16.08		$	14.44		$	17.33
Post-settlement to pre-settlement price	~~134.4~~		%	~~106~~163.18		%	109.2		%	142.8		%	107.8		%
Natural gas (per Mcf):
Before derivative settlements	$	~~1.34~~		$	21.5023		$	1.83		$	1.29		$	2.13
After derivative settlements	$	~~1.60~~		$	21.2767		$	2.03		$	1.63		$	2.13
Post-settlement to pre-settlement price	~~119.4~~		%	90135.8		%	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)	~~March 31, 2020~~		~~December~~June 3130, ~~2019~~2020			December 31, 2019
Derivative assets (liabilities):
Crude oil derivatives	$	~~45,436~~	$	~~(21~~15,~~805~~399	)	$	(21,805)
Natural gas derivatives	~~4,255~~		31,~~551~~788			3,551
NGL derivatives	~~3,430~~		~~2,169~~—			2,169
Net derivative assets (liabilities)	$	~~53,121~~	$	~~(16~~17,~~085~~187	)	$	(16,085)

3744

Our derivative portfolio, which was in a net liability position at the end of 2019, reverted to a net asset of $5317.12 million as of ~~March~~June 3130, 2020. The change, which also corresponds to the non-cash fair value adjustment gain of $6933.23 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 March 31,
			Three months ended June 30,
	~~2020~~		2020		~~2019~~									2019
(in thousands)	~~Non-cashfair valueadjustment~~		~~Settlements~~Non-cashfair ~~(paid) received~~valueadjustment		~~Non-cashfair valueadjustment~~		Settlements (paid) received		~~Settlements (paid) received~~			Non-cashfair valueadjustment		Settlements (paid) received
Derivative gains (losses):
Crude oil derivatives	$	~~67,240~~	$	4(30,~~156~~036)	$	~~(48,669~~	)$	18,405	$	~~1,011~~		$	11,466	$	(1,991)
Natural gas derivatives	~~705~~		1(2,~~688~~468)		~~(139~~		)2,017		~~(1,061~~		)	4,889		1,113
NGL derivatives	~~1,261~~		(3,~~330~~430)		~~(2,723~~		)2,493		~~565~~			1,241		1,016
Derivative gains (losses)	$	~~69,206~~	$	9(35,~~174~~934)	$	~~(51,531~~	)$	22,915	$	~~515~~		$	17,596	$	138
			Six months ended June 30,
			2020											2019
(in thousands)			Non-cashfair valueadjustment				Settlements (paid) received					Non-cashfair valueadjustment		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 March 31,				Increase/				Percent
			Three months ended June 30,										Increase/		Percent
(in thousands, except per Boe data)	~~2020~~		~~2019~~2020		~~(Decrease)~~		2019		~~Change~~		(Decrease)		Change
Lease operating expenses:
Focus Areas	$	~~5,609~~	$	73,~~114~~082	$	~~(1,505~~	)$	8,445	~~(21.2~~	)%	$	(5,363)	(63.5)	%
Other	~~4,479~~		52,~~180~~889		~~(701~~		)4,926		~~(13.5~~	)%	(2,037)		(41.4)	%
Total lease operating expenses	$	~~10,088~~	$	125,~~294~~971	$	~~(2,206~~	)$	13,371	~~(17.9~~	)%	$	(7,400)	(55.3)	%
Lease operating expenses per Boe:
Focus Areas	$	~~2.33~~	$	42.9623	$	~~(2.63~~	)$	3.90	~~(53.0~~	)%	$	(1.67)	(42.8)	%
Other	$	~~11.51~~	$	119.7738	$	~~(0.26~~	)$	12.04	~~(2.2~~	)%	$	(2.66)	(22.1)	%
Lease operating expenses per Boe	$	~~3.61~~	$	63.5654	$	~~(2.95~~	)$	5.19	~~(45.0~~	)%	$	(1.65)	(31.8)	%

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 March 31, 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 in certain parts of our Focus Areas as pipeline infrastructure is expanded into the area and contract rates are locked in as well as due to reduced costs for well maintenance. 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.45


	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 March 31,						Increase/				Percent
				Three months ended June 30,											Increase/		Percent
	~~2020~~			~~2019~~2020			~~(Decrease)~~		2019		~~Change~~		(Decrease)		Change
Production taxes (in thousands)	$	~~2,750~~		$	~~2,880~~823		$	~~(130~~	)$	3,802	~~(4.5~~	)%	$	(2,979)	(78.4)	%
Production taxes per Boe	$	~~0.98~~		$	10.5449		$	~~(0.56~~	)$	1.48	~~(36.4~~	)%	$	(0.99)	(66.9)	%
Production taxes as % of commodity sales	~~5.0~~		%	5.4.1		%			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 ~~March 31~~June 30, 2020 were 5% lower than the prior year ~~period.~~periods ~~The~~due ~~quarter~~to ~~over~~a ~~quarter~~ decrease onin acommodity ~~dollar~~revenues ~~basis~~driven by volume and price declines as discussed above. The corresponding decreases on a per Boe basis ~~was~~were primarily a result of lower commodity prices and a greater percentage of revenues ~~driven~~being byderived from gas volumes, which yield a ~~decline~~lower inrevenue ~~commodity~~per ~~pricing~~Boe compared to crude oil and NGLs.

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

	Three months ended March 31,				Increase/				Percent
			Three months ended June 30,										Increase/		Percent
	~~2020~~		~~2019~~2020		~~(Decrease)~~		2019		~~Change~~		(Decrease)		Change
DD&A (in thousands):
Oil and natural gas properties (1)	$	~~22,575~~	$	2114,~~881~~388	$	~~694~~	$	28,488	~~3.2~~	%	$	(14,100)	(49.5)	%
Property and equipment	~~437~~		~~1,834~~433		~~(1,397~~		)1,794		~~(76.2~~	)%	(1,361)		(75.9)	%
Total DD&A	$	~~23,012~~	$	2314,~~715~~821	$	~~(703~~	)$	30,282	~~(3.0~~	)%	$	(15,461)	(51.1)	%
DD&A per Boe:
Oil and natural gas properties (1)	$	~~8.08~~	$	118.6752	$	~~(3.59~~	)$	11.07	~~(30.8~~	)%	$	(2.55)	(23.0)	%
Other fixed assets	~~0.16~~		0.9825		~~(0.82~~		)0.69		~~(83.7~~	)%	(0.44)		(63.8)	%
Total DD&A per Boe	$	~~8.24~~	$	128.6577	$	~~(4.41~~	)$	11.76	~~(34.9~~	)%	$	(2.99)	(25.4)	%


	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 ~~March 31~~June 30, 2020 ofdecreased ~~$22.6~~compared ~~million~~to ~~was 3% higher than~~ the prior year periods due to ~~higher~~lower production, ~~partially~~and ~~offset by~~ a lower DD&A rate. The ~~driven~~DD&A byrate ~~decreases~~declined indue ~~overall~~to ~~reserve~~prior ~~values~~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 ~~decreasing~~being ~~commodity~~uneconomic ~~prices~~in the current price environment.

General and administrative expenses (“G&A”)

	Three months ended March 31,						Increase/				Percent
				Three months ended June 30,											Increase/		Percent
(in thousands)	~~2020~~			~~2019~~2020			~~(Decrease)~~		2019		~~Change~~		(Decrease)		Change
G&A:
Gross G&A expenses	$	~~10,293~~		$	1110,~~035~~187		$	~~(742~~	)$	9,836	~~(6.7~~	)%	$	351	3.6	%
Capitalized exploration and development costs	~~(2,225~~		)	(~~2,722~~699)		)	~~497~~		(2,521)		~~(18.3~~	)%	1,822		(72.3)	%
Net G&A expenses	~~8,068~~			89,~~313~~488			~~(245~~		)7,315		~~(2.9~~	)%	2,173		29.7	%
Net G&A expense per Boe	$	~~2.89~~		$	45.4462		$	~~(1.55~~	)$	2.84	~~(34.9~~	)%	$	2.78	97.9	%

Net G&A of $8.1 million for the three months ended March 31, 2020, decreased 3% from the prior year periods primarily due to reductions in payroll and benefits, stock based compensation and severance costs partially offset by an increase in bad debt 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 in 2017 were front loaded for three-year periods and subject to accelerated cost recognition which results in higher expense early during the life of a grant with graded vesting. To a lesser extent stock compensation expense was also lower due to forfeitures in the preceding twelve months. In addition, severance costs for employees impacted by our reductions in force during period were lower than the prior year period. These decreases were partially offset by an increase in credit losses on expected uncollectible receivables. 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. The table below discloses the impact of the items discussed above.

Six months ended June 30,

Increase/

Percent

(in thousands)

2020

2019

(Decrease)

Change

G&A:

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