Chaparral Energy (CHAP) 10-Q 2020 Q1 Quarterly report

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, 2020

or

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

For the transition period from to

Commission File Number: 001-38602

Chaparral Energy, Inc.

(Exact name of registrant as specified in its charter)

Delaware	73-1590941
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
701 Cedar Lake Boulevard Oklahoma City, Oklahoma	73114
(Address of principal executive offices)	(Zip Code)

(405) 478-8770

(Registrant’s telephone number, including area code)

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

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

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

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

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

Large accelerated filer	¨	Accelerated filer	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 8, 2020: 47,790,146 shares of Class A Common Stock, par value $0.01 per share.

CHAPARRAL ENERGY, INC.

Index to Form 10-Q

	Page
Part I. FINANCIAL INFORMATION
Item 1. Financial Statements (Unaudited)	7
Consolidated Balance Sheets	7
Consolidated Statements of Operations	8
Consolidated Statement of Stockholders’ Equity	9
Consolidated Statements of Cash Flows	10
Condensed Notes to Consolidated Financial Statements	11
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	30
Overview	30
Results of Operations	34
Liquidity and Capital Resources	31
Non-GAAP Financial Measure and Reconciliation	41
Critical Accounting Policies	42
Recent Accounting Pronouncements	43
Item 3. Quantitative and Qualitative Disclosures about Market Risk	43
Item 4. Controls and Procedures	45
Part II. OTHER INFORMATION
Item 1. Legal Proceedings	45
Item 1A. Risk Factors	45
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	47
Item 5. Other Information	47
Item 6. Exhibits	48
Signatures	49

CAUTIONARY NOTE

REGARDING FORWARD-LOOKING STATEMENTS

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

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

• the amount, nature and timing of capital expenditures;

• drilling, completion and performance of wells;

• inventory of drillable locations;

• competition;

• government regulations;

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

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

• changes in proved reserves;

• operating costs and other expenses;

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

• estimates of proved reserves;

• exploitation of property acquisitions;

• 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:

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

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

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

• geopolitical events affecting oil and natural gas prices;

• the nature or results, if any, of any strategic alternatives;

• recent changes in the composition of the board of directors of the Company (the “Board”);

• 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;

3

• 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.

4

GLOSSARY OF CERTAIN DEFINED TERMS

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

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

5

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.

6

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 31, 2019
Assets
Current assets:
Cash and cash equivalents	$	13,291		$	22,595
Accounts receivable:
Accounts receivable, gross	46,085			50,744
Allowance for credit losses	(2,768		)	(1,097		)
Accounts receivable, net	43,317			49,647
Inventories, net	2,842			3,730
Prepaid expenses	2,981			3,471
Derivative instruments	48,458			947
Total current assets	110,889			80,390
Property and equipment, net	8,603			9,217
Right of use assets from operating leases	2,097			2,444
Oil and natural gas properties, using the full cost method:
Proved	1,348,229			1,276,036
Unevaluated (excluded from the amortization base)	354,547			371,229
Accumulated depreciation, depletion, amortization and impairment	(848,002		)	(754,379		)
Total oil and natural gas properties	854,774			892,886
Held for sale assets	164			2,860
Derivative instruments	4,663			—
Other assets	2,136			635
Total assets	$	983,326		$	988,432
Liabilities and stockholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	65,966		$	64,558
Accrued payroll and benefits payable	6,514			10,963
Accrued interest payable	5,650			12,227
Revenue distribution payable	21,752			22,370
Long-term debt and financing leases, classified as current	497			594
Derivative instruments	—			11,957
Total current liabilities	100,379			122,669
Long-term debt and financing leases, less current maturities	436,755			421,392
Derivative instruments	—			5,075
Noncurrent operating lease obligations	579			917
Deferred compensation	467			165
Asset retirement obligations	22,544			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
Additional paid in capital	977,879			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		)
Accumulated deficit	(549,645		)	(554,408		)
Total stockholders’ equity	422,602			417,141
Total liabilities and stockholders’ equity	$	983,326		$	988,432

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

7

Chaparral Energy, Inc. and Subsidiaries

Consolidated Statements of Operations

(Unaudited)

	Three months ended
(in thousands, except share and per share data)	March 31, 2020			March 31, 2019
Revenues:
Net commodity sales	$	48,851		$	48,619
Sublease revenue	—			1,198
Total revenues	48,851			49,817
Costs and expenses:
Lease operating	10,088			12,294
Production taxes	2,750			2,880
Depreciation, depletion and amortization	23,012			23,715
Impairment of oil and gas assets	71,371			49,722
Impairment of other assets	153			—
General and administrative	8,068			8,313
Subleases	—			403
Total costs and expenses	115,442			97,327
Operating loss	(66,591		)	(47,510		)
Non-operating income (expense):
Interest expense	(6,636		)	(4,564		)
Derivative gains (losses)	78,380			(51,016		)
Gain (loss) on sale of assets	102			(1		)
Other income, net	246			14
Net non-operating income (expense)	72,092			(55,567		)
Reorganization items, net	(584		)	(463		)
Income (loss) before income taxes	4,917			(103,540		)
Income tax expense	—			—
Net income (loss)	$	4,917		$	(103,540	)
Earnings (loss) per share:
Basic	$	0.11		$	(2.28	)
Diluted	$	0.11		$	(2.28	)
Weighted average shares used to compute earnings per share:
Basic	45,830,286			45,456,214
Diluted	46,194,495			45,456,214

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

8

Chaparral Energy, Inc. and Subsidiaries

Consolidated Statement of Stockholders’ Equity

(Unaudited)

	Common stock
(dollars in thousands)	Shares outstanding		Amount			Additional paid in capital		Treasury stock			Accumulated deficit			Total
As of December 31, 2018	46,390,513		$	467		$	974,616	$	(4,936	)	$	(85,460	)	$	884,687
Stock-based compensation	94,078		1			1,423		—			—			1,424
Restricted stock forfeited	(97,113	)	(1		)	—		—			—			(1		)
Repurchase of common stock	(80,422	)	—			—		(463		)	—			(463		)
Net loss	—		—			—		—			(103,540		)	(103,540		)
Balance at March 31, 2019	46,307,056		$	467		$	976,039	$	(5,399	)	$	(189,000	)	$	782,107

	Common stock
(dollars in thousands)	Shares outstanding		Amount			Additional paid in capital		Treasury stock			Accumulated deficit			Total
As of December 31, 2019	47,942,230		$	485		$	977,174	$	(6,110	)	$	(554,408	)	$	417,141
Cumulative effect of accounting standard adoption	—		—			—		—			(154		)	(154		)
Stock-based compensation	—		—			705		—			—			705
Restricted stock forfeited or canceled	(22,494	)	(1		)	—		—			—			(1		)
Repurchase of common stock	(3,856	)	—			—		(6		)	—			(6		)
Net income	—		—			—		—			4,917			4,917
Balance at March 31, 2020	47,915,880		$	484		$	977,879	$	(6,116	)	$	(549,645	)	$	422,602

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

9

Chaparral Energy, Inc. and Subsidiaries

Consolidated Statements of Cash Flows

(Unaudited)

	Three months ended
(in thousands)	March 31, 2020			March 31, 2019
Cash flows from operating activities
Net income (loss)	$	4,917		$	(103,540	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion and amortization	23,012			23,715
Derivative (gains) losses	(78,380		)	51,016
Impairment of oil and gas assets	71,371			49,722
Impairment of other assets	153			—
(Gain) loss on sale of assets	(102		)	1
Other	2,338			542
Change in assets and liabilities
Accounts receivable	4,835			7,910
Inventories	675			207
Prepaid expenses and other assets	(1,011		)	256
Accounts payable and accrued liabilities	(14,870		)	(16,689		)
Revenue distribution payable	(619		)	(5,511		)
Deferred compensation	564			925
Net cash provided by operating activities	12,883			8,554
Cash flows from investing activities
Expenditures for property, plant, and equipment and oil and natural gas properties	(49,053		)	(64,044		)
Proceeds from asset dispositions	3,209			—
Proceeds from derivative instruments, net	9,174			515
Net cash used in investing activities	(36,670		)	(63,529		)
Cash flows from financing activities
Proceeds from long-term debt	15,000			30,000
Repayment of long-term debt	(313		)	(171		)
Principal payments under financing lease obligations	(105		)	(699		)
Payment of debt issuance costs and other financing fees	(93		)	(20		)
Treasury stock purchased	(6		)	(463		)
Net cash provided by financing activities	14,483			28,647
Net decrease in cash and cash equivalents	(9,304		)	(26,328		)
Cash and cash equivalents, at beginning of period	22,595			37,446
Cash and cash equivalents, at end of period	$	13,291		$	11,118

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

10

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, 2020, and for the three months ended March 31, 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 months ended March 31, 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.

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, 2020, cash with a recorded balance totaling approximately $12,698 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 FASB issued 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 its total accounts receivables: (i) commodity sales receivables; (ii) joint interest receivables; (iii) derivative settlement receivables and (iv) other receivables. The table below discloses balances related to

11

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

these four segments:

	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

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 amount outstanding longer than 90 days are considered past due. Based on 2019 commodity sales, our 10 largest purchasers accounting 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 remote. We perform annual credit evaluations on purchasers comprising 85% or more of our commodity revenues. The evaluations include (i) an assessment of external credit ratings; (ii) performing internal risk evaluations when external ratings are not available; (iii) assessing the need for guarantor letters or letters of credit. We estimate the expected losses on uncollectible receivables by applying a uniform allowance rate on the total outstanding balance taking into consideration general industry conditions and more specifically, factors impacting the midstream energy segment. We may make further adjustments to our allowance for credit losses according to any specific news we may receive regarding individual purchasers.

Joint interest receivables. Our joint interest receivables represent amounts owed to us by other working interest owners on wells that we operate. We have numerous joint interest counterparties which are the result of combining all or portions of multiple oil and gas leases to form units for the drilling of wells under pooling or a joint interest agreements. The counterparties in this segment are diverse, ranging from large public company upstream operators to individual mineral leaseholders. Amounts billed to our joint interest owners generally consist of drilling and completion costs, in the early stages of a well, and lease operating expenses and costs for workovers and remediation work once a well in online. Payment is generally due within 60 days of billing and amount outstanding longer than 90 days are considered past due. Our historical losses on uncollectible receivables have predominantly been attributable to this portfolio segment, although losses in prior years have not been material. In the event of nonpayment, we may be able to mitigate our losses by netting the outstanding amount against any revenues payable to the joint interest owner and if still insufficient, by assuming the joint interest owner’s working interest in the well. The fair value of the working interest, which represents collateral for the outstanding receivable, will depend on the fair value of the remaining oil and natural gas reserves of the well. We monitor the ongoing 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.

12

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.

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
	Commodity sales		Joint interest		Derivatives		Other		Total
Balance at January 1, 2020	$	—	$	1,097	$	—	$	—	$	1,097
Cumulative effect of accounting standard adoption	154		—		—		—		154
Credit losses	44		1,473		—		—		1,517
Write-offs	—		—		—		—		—
Recoveries	—		—		—		—		—
Balance at March 31, 2020	$	198	$	2,570	$	—	$	—	$	2,768

Inventories

Inventories consisted of the following:

	March 31, 2020			December 31, 2019
Equipment inventory	$	2,730		$	3,435
Commodities	444			474
Inventory valuation allowance	(332		)	(179		)
	$	2,842		$	3,730

13

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

During the three months ended March 31, 2020, we recorded a lower of cost or market impairment of $153 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:

	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

14

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.

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

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

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 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 greaterthan 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

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

	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

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 months ended March 31, 2020, no material adjustments were made to provision amounts recorded as a result of the enactment of the CARES Act.

15

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

The provision for income taxes is based on a current estimate of the annual effective income tax rate adjusted to reflect the impact of permanent differences and discrete items. Management judgment is required in estimating operating income in order to determine our effective income tax rate. Our effective income tax rate was 0% and 0% for the three month periods ended March 31, 2020 and 2019, respectively. The 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.

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 31, 2020, or December 31, 2019.

As a result of the Chapter 11 reorganization and related transactions, the Company experienced an ownership change within the meaning of Internal Revenue Code (“IRC”) Section 382 on the 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 month period ended March 31, 2020, or any intervening period since the Effective Date. Since the 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. 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 bankruptcy case is closed.

16

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.

17

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.

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

	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
8.75% Senior Notes due 2023	$	300,000		$	300,000
Credit facility	145,000			130,000
Installment note payable	58			371
Financing lease obligations	1,549			1,653
Unamortized debt issuance costs	(9,355		)	(10,038		)
Total debt, net	437,252			421,986
Less current portion	497			594
Total long-term debt, net	$	436,755		$	421,392

18

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

Credit Agreement

Pursuant to our Credit Agreement (the “Credit Agreement”) with Royal Bank of Canada, as administrative agent and issuing bank, and the additional lenders party thereto, we have a $750,000 credit facility collateralized by our oil and natural gas properties and is scheduled to mature on December 21, 2022. Availability under our credit facility is subject to the financial covenants discussed below and a borrowing base based on the value of our oil and natural gas properties and set by the banks semi-annually on or around May 1 and November 1 of each year. Our borrowing base under the credit facility as of March 31, 2020, was $325,000 while the unused portion on that date was $180,000.

As of March 31, 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 3.15%.

The Credit Agreement contains financial covenants that require, for each fiscal quarter, we maintain: (1) a Current Ratio (as defined in the Credit Agreement) of no less than 1.00 to 1.00, and (2) a Ratio of Total Debt to EBITDAX (as defined in the Credit Agreement) of no greater than 4.0 to 1.0 calculated on a trailing four-quarter basis. We were in compliance with these financial covenants as of March 31, 2020.

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”). 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 Notes contain customary covenants, certain callable provisions and events of default. Please see “Note 8: Debt” in “Item 8. Financial Statements and Supplementary Data” of our Annual Report on Form 10-K for the year ended December 31, 2019, for a discussion of the material provisions of our Senior Notes.

19

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

Note 5: Leases

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

Lease assets and liabilities

Our operating lease and financing lease assets and liabilities are recorded on our balance sheet as of March 31, 2020 as:

	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

20

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
	March 31, 2020			March 31, 2019
Lease cost
Finance lease cost:
Amortization of right-of-use assets	$	117		$	693
Interest on lease liabilities	27			113
Operating lease cost	390			308
Short-term lease cost	218			129
Variable lease cost	—			95
Sublease income	—			(1,198		)
Total lease cost	$	752		$	140
Capitalized operating lease cost (1)	$	—		$	3,335
Other information
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows for finance leases	$	(27	)	$	(113	)
Operating cash flows for operating leases	(345		)	(308		)
Investing cash flows for operating leases	—			(1,023		)
Financing cash flows for finance leases	(105		)	(699		)
Right-of-use assets obtained in exchange for new finance lease liabilities	—			670

________________________________

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

Note 6: Derivative instruments

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

The following table summarizes our crude oil derivatives outstanding as of March 31, 2020:

		Weighted average fixed price per Bbl
Period and type of contract	Volume MBbls	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

21

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

The following table summarizes our natural gas derivatives outstanding as of March 31, 2020:

Period and type of contract	Volume BBtu	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 liquid derivatives outstanding as of March 31, 2020:

Period and type of contract	Volume Thousands of Gallons	Weighted average fixed price per gallon
2020
Natural gasoline swaps	2,476	$	1.17
Propane swaps	5,884	$	0.51
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
	Assets		Liabilities		Net value		Assets			Liabilities			Net value
Natural gas derivative contracts	$	4,255	$	—	$	4,255	$	3,552		$	(1	)	$	3,551
Crude oil derivative contracts	45,436		—		45,436		391			(22,196		)	(21,805		)
NGL derivative contracts	3,430		—		3,430		2,868			(699		)	2,169
Total derivative instruments	53,121		—		53,121		6,811			(22,896		)	(16,085		)
Less:
Netting adjustments (1)	—		—		—		(5,864		)	5,864			—
Derivative instruments - current	48,458		—		48,458		947			(11,957		)	(11,010		)
Derivative instruments - long-term	$	4,663	$	—	$	4,663	$	—		$	(5,075	)	$	(5,075	)

________________________________

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

Effect of derivative instruments on the consolidated statements of operations

We do not apply hedge accounting to any of our derivative instruments. As a result, all gains and losses associated with our derivative contracts are recognized immediately as “Derivative gains (losses)” in the consolidated statements of operations.

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

	Three months ended March 31,
	2020		2019
Change in fair value of commodity price derivatives	$	69,206	$	(51,531	)
Net settlements received on commodity price derivatives	9,174		515
Total derivative gains (losses)	$	78,380	$	(51,016	)

22

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, 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 consisted of natural gas basis swaps and collars. The fair value of these contracts is developed by a third-party pricing service using a proprietary valuation model, which we believe incorporates the assumptions that market participants would have made at the end of each period. Observable inputs include contractual terms, published forward pricing curves, and yield curves. Significant unobservable inputs are implied volatilities and proprietary pricing curves. Significant increases (decreases) in implied volatilities in isolation would result in a significantly higher (lower) fair value measurement. We review these valuations and the changes in the fair value measurements for reasonableness. All derivative instruments are recorded at fair value and include a measure of our own nonperformance risk for derivative liabilities or our counterparty credit risk for derivative assets. 

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

	As of March 31, 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)	$	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	)

________________________________

(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.

23

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

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

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

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,
	2020		2019
Inflation rate	2.21	%	2.25	%
Credit-adjusted risk-free discount rate	25.00	%	12.35	%

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

Fair value of other financial instruments

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

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

	March 31, 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	$	13,500	$	300,000	$	133,050
Credit facility	145,000		145,000		130,000		130,000
Other secured debt (2)	58		58		371		371

________________________________

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

(2) The balance on March 31, 2020, and 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

24

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, 2020, the counterparties to our open derivative contracts consisted of seven financial institutions, all of which were lenders under our credit facility.

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

	Offset in the consolidated balance sheets									Gross amounts not offset in the consolidated balance sheets
	Gross assets (liabilities)			Offsetting assets (liabilities)			Net assets (liabilities)			Derivatives (1)		Amounts outstanding under credit facilities (2)			Net amount
March 31, 2020
Derivative assets	$	53,121		$	—		$	53,121		$	—	$	(44,411	)	$	8,710
Derivative liabilities	—			—			—			—		—			—
	$	53,121		$	—		$	53,121		$	—	$	(44,411	)	$	8,710
December 31, 2019
Derivative assets	$	6,811		$	(5,864	)	$	947		$	—	$	(947	)	$	—
Derivative liabilities	(22,896		)	5,864			(17,032		)	—		947			(16,085		)
	$	(16,085	)	$	—		$	(16,085	)	$	—	$	—		$	(16,085	)

________________________________

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

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

We did not post additional collateral under any of these contracts as all of our counterparties are secured by the collateral under our credit facilities. Payment on our derivative contracts could be accelerated in the event of a default under our Credit Agreement. The aggregate fair value of our derivative liabilities subject to acceleration in the event of default was nil before offsets at March 31, 2020.

Note 8: Asset retirement obligations

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

Balance at January 1, 2020	$	23,156
Liabilities incurred in current period	41
Liabilities settled or disposed in current period	(63		)
Revisions in estimated cash flows	15
Accretion expense	323
Balance at March 31, 2020	$	23,472
Less current portion included in accounts payable and accrued liabilities	928
Asset retirement obligations, long-term	$	22,544

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

Note 9: Deferred compensation

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

25

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

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,
	2020		2019
Cash LTIP expense (net of amounts capitalized)	$	167	$	91

As of March 31, 2020, the outstanding liability accrued for our Cash LTIP, based on requisite service provided, was $1,130.

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”) and restricted stock units (“RSUs”). In December 2019, we also granted RSAs 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 and RSUs.

A summary of our RSA activity is presented below:

	Time Shares						Performance Shares
	Weighted average award date fair value		Restricted shares		Vest date fair value		Weighted average award date fair value		Restricted shares
	($ per share)						($ per share)
Unvested and outstanding at January 1, 2020	$	5.41	1,069,505				$	1.53	1,089,343
Granted	$	—	—				$	—	—
Vested	$	16.25	(83,130	)	$	88	$	—	—
Forfeited	$	20.05	(10,406	)			$	—	—
Cancelled	$	20.05	(12,088	)			$	—	—
Unvested and outstanding at March 31, 2020	$	4.14	963,881				$	1.53	1,089,343

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	$	—	—				$	—	—
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

26

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

	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	$	—	—		$	—
Forfeited	$	17.66	(1,515	)
Unvested and outstanding at March 31, 2020	$	4.31	74,264

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,
	2020			2019
Stock-based compensation cost	$	670		$	1,460
Less: stock-based compensation cost capitalized	(274		)	(626		)
Stock-based compensation expense	$	396		$	834
Number of vested shares repurchased or settled in cash	3,856			80,422
Payments for stock-based compensation	6			463

Based on a quarter end market price of $0.47 per share of our Class A common stock, the aggregate intrinsic value of all RSAs and RSUs outstanding was $1,418 as of March 31, 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 and the associated number of shares repurchased are reflected as treasury stock transactions in our consolidated statements of equity. As of March 31, 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

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

27

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

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 $500 in such collateral.

Litigation and Claims

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

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

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

28

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

of $2,650 in Class 6 under the 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 is now contesting the enforcement of the settlement under its terms, which resulted in the issuance of 84,347 shares of Class A common stock to Davis, claiming that he was mistaken in his understanding of the terms of the Reorganization Plan as relate to Class 6 claims. The Company is vigorously pursuing the enforcement of the settlement in the Bankruptcy Court.

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.

29

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OFFINANCIAL 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 207,000 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 120,000 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 months ended March 31, 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 Quarter Activity

At the beginning of the quarter ended March 31, 2020, Chaparral management commenced a comprehensive cash improvement effort. The initiative, which involves the formation and collaboration of multiple working teams, is 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 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 that are scale-dependent are expected to be fully realized only when activity has resumed to more normal levels.

Macroeconomic Developments and Their Impact on the Oil and Gas Industry

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

Compounding the impact of COVID-19, the oil production output alliance between Russia, Saudi Arabia and other oil producing nations (“OPEC+”) broke down as both sides were unable to reach agreement in early March 2020 over how much to restrict production in order to stabilize crude oil prices. As a result, Saudi Arabia and Russia both initiated efforts to increase production, driving down oil prices. OPEC+ was later able to agree on approximately 9.7 million barrels of oil per day of production cuts, but that announcement has done little to aid in oil price recovery because of the significant drop in global demand.

Even though the price for oil in the commodities futures markets currently reflect some price improvement (although still less than pre-March 2020 prices), the current cash prices have deteriorated significantly. On April 20, 2020, the front-month futures contract for 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.

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Chaparral’s Response and 2020 Outlook

In response, Chaparral is taking material and unusual actions to maximize the value of its assets and improve its financial position. Because the Company has (a) a strong hedge position for crude oil in 2020, the proceeds of which do 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 is not prudent or necessary to continue developing our inventory or sell all of our products at current market prices.

Accordingly, we suspended all drilling and stimulation operations in early April, 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.

Liquidity and capital resources

Our primary sources of liquidity have historically been cash flows generated from operating activities, financing provided by our revolving credit facility or issuance of debt, and proceeds from hedge settlements.

Cash Flows from Operating Activities. As described above, in light of the significant deterioration in commodity prices, we have shut in a substantial number of our producing wells and have suspended all drilling and stimulation operations. As a result, we expect the cash flows generated from our operating activities to decline significantly, offset by (a) the related reductions in expenses and capital expenditures and (b) proceeds from hedge settlements. The impact of this response on liquidity during the second quarter will depend on gas and NGL revenues prior to shut-in, how much variable lease operating expense can be eliminated and how long the shut-ins last.

Proceeds from Revolving Credit Facility and Senior Notes Interest Payment. At the beginning of April 2020, we significantly increased our cash balance by borrowing an additional $105 million, which increased the total amount outstanding under our Credit Agreement (as defined below) to $250.0 million. Contemporaneously with the additional borrowings under the Credit Agreement, the lenders under that agreement notified the Company regarding the Borrowing Base Redetermination (as defined below). The Company is required to repay the resulting $75 million borrowing base deficiency in six equal monthly installments, plus interest, beginning on May 2, 2020. Furthermore, our next semi-annual interest payment of $13.1 million on our 8.75% Senior Notes is due on July 15, 2020.

Hedging. As described above in “Note 6: Derivative Instruments” above in the accompanying financial statements, we have a strong hedge position for crude oil in 2020 the proceeds of which do not require the physical delivery of any oil or gas. In light of the significant difference between near-term commodity prices and future prices, one possible strategy would be for us to increase and lengthen our hedging position. This approach would align our hedges with our decision to suspend drilling and to shut-in a substantial amount of production until prices recover. However, our hedging counterparties (who are also lenders under our Credit Agreement) have informed us that they currently do not intend to enter into new hedges with us until we have cured the Borrowing Base Deficiency (as defined below).

We believe that the actions that the Company has taken to draw down on its revolving credit facility and to implement material operational changes afford us the ability to diligently explore all credible operating and capitalization scenarios available to us. However, our profitability outlook based on current strip prices has resulted in a situation that raises substantial doubt about our ability to continue as a going concern within one year of the time of this filing. In that regard, the Company’s Board of Directors has formed a Special Committee composed of independent directors to review and evaluate strategic alternatives to preserve and grow the value of the enterprise. We have also retained financial and legal advisors to assist in this evaluation process. No assurances can be given as to the outcome or timing of the evaluation, or whether any particular transaction may be pursued or consummated.

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Indebtedness

Debt consists of the following as of the dates indicated:

(in thousands)	March 31, 2020			December 31, 2019
8.75% Senior Notes due 2023	$	300,000		$	300,000
Credit facility	145,000			130,000
Financing lease obligations	1,549			1,653
Installment note payable	58			371
Unamortized issuance costs	(9,355		)	(10,038		)
Total debt, net	$	437,252		$	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.

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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.

We use the net cash provided by operations to partially fund our acquisition, exploration and development activities. During 2020, we also relied on borrowings from our credit facility and cash on hand to fund our capital expenditures.

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

Our actual costs incurred, including costs that we have accrued for during the three months ended March 31, 2020, are summarized in the table below.

(in thousands)	Three months ended March 31, 2020
Acquisitions (1)	$	4,232
Drilling (2)	43,298
Enhancements	3,523
Operational capital expenditures incurred	51,053
Other (3)	4,651
Total capital expenditures incurred	$	55,704

______________________________________________________

(1) Includes $2.5 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 months ended March 31, 2020, this amount includes $2.2 million for capitalized general and administrative expenses, and $2.3 million for capitalized interest.

Net cash used in investing activities during the three months ended March 31, 2020 consisted of cash outflows for capital expenditure of $49.1 million partially offset by receipts for derivative settlements of $9.2 million and proceeds from asset sales of $3.2 million. The 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 months ended March 31, 2019 consisted of cash outflows for capital expenditure of $64.0 million partially offset by receipts for derivative settlements of $0.5 million.

Net cash from financing activities during the three months ended March 31, 2020, consisted of borrowings on our credit facility of $15.0 million partially offset by cash outflows of $0.4 million for repayment of debt and $0.1 million for debt financing fees. Net cash from financing activities during the three months ended March 31, 2019, consisted of borrowings on our Credit Facility of $30.0

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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.

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, 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 quarter of 2020 includes the following highlights and comparisons to the prior year quarter:

• We generated net income for the three months ended March 31, 2020, of $4.9 million. Included in our income were gains on commodity derivative instruments of $78.4 million partially offset by a ceiling impairment of $71.4 million.

• Our gain on commodity derivatives for the three months ended March 31, 2020, was attributable to $9.2 million of realized settlement gains and $69.2 million of noncash mark-to-market gains driven by the decline in crude oil and NGL prices.

• We grew net production by 49% to 2,793 MBoe for the three months ended March 31, 2020. Within our Focus Areas, net production grew 68% to 2,404 MBoe over the same time period.

• We lowered our lease operating expense by 18% to $10.1 million for the three months ended March 31, 2020. Our cost reductions were accomplished despite an increase in production, as evidenced by the 45% decrease in lease operating expense per Boe to $3.61.

• We lowered general and administrative expenses on a per Boe basis by 35% to $2.89 per Boe compared to the prior year quarter. Total general and administrative expenses was reduced by 3% to $8.1 million for the three months ended March 31, 2020.

• Our oil and natural gas capital expenditures for the three months ended March 31, 2020, were $55.7 million, with $43.3 million incurred for drilling and completions and $4.2 million on acquisitions. Our capital activity during this period included completing and bringing online 15 wells, of which nine were drilled in the current quarter and six in the prior year. We also drilled two wells scheduled to be completed subsequent to quarter end.

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Production

Production volumes by area were as follows (MBoe)

	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	%

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.

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.

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

	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.

	Three months ended March 31, 2020 vs. 2019
(in thousands)	Sales change			Percentage change in 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	%

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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, 2020, were higher than the prior year periods due to increases in natural gas and natural gas liquids production.

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,
	2020			2019
Oil (per Bbl):
Before derivative settlements	$	44.08		$	53.08
After derivative settlements	$	49.03		$	54.71
Post-settlement to pre-settlement price	111.2		%	103.1		%
Natural gas liquids (per Bbl):
Before derivative settlements	$	11.03		$	18.07
After derivative settlements	$	14.82		$	19.18
Post-settlement to pre-settlement price	134.4		%	106.1		%
Natural gas (per Mcf):
Before derivative settlements	$	1.34		$	2.50
After derivative settlements	$	1.60		$	2.27
Post-settlement to pre-settlement price	119.4		%	90.8		%

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 31, 2019
Derivative assets (liabilities):
Crude oil derivatives	$	45,436	$	(21,805	)
Natural gas derivatives	4,255		3,551
NGL derivatives	3,430		2,169
Net derivative assets (liabilities)	$	53,121	$	(16,085	)

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Our derivative portfolio, which was in a net liability position at the end of 2019, reverted to a net asset of $53.1 million as of March 31, 2020. The change, which also corresponds to the non-cash fair value adjustment gain of $69.2 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,
	2020				2019
(in thousands)	Non-cash fair value adjustment		Settlements (paid) received		Non-cash fair value adjustment			Settlements (paid) received
Derivative gains (losses):
Crude oil derivatives	$	67,240	$	4,156	$	(48,669	)	$	1,011
Natural gas derivatives	705		1,688		(139		)	(1,061		)
NGL derivatives	1,261		3,330		(2,723		)	565
Derivative gains (losses)	$	69,206	$	9,174	$	(51,531	)	$	515

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.

Lease operating expenses

	Three months ended March 31,				Increase/			Percent
(in thousands, except per Boe data)	2020		2019		(Decrease)			Change
Lease operating expenses:
Focus Areas	$	5,609	$	7,114	$	(1,505	)	(21.2	)%
Other	4,479		5,180		(701		)	(13.5	)%
Total lease operating expenses	$	10,088	$	12,294	$	(2,206	)	(17.9	)%
Lease operating expenses per Boe:
Focus Areas	$	2.33	$	4.96	$	(2.63	)	(53.0	)%
Other	$	11.51	$	11.77	$	(0.26	)	(2.2	)%
Lease operating expenses per Boe	$	3.61	$	6.56	$	(2.95	)	(45.0	)%

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 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.

Production taxes (which include severance and ad valorem taxes)

	Three months ended March 31,						Increase/			Percent
	2020			2019			(Decrease)			Change
Production taxes (in thousands)	$	2,750		$	2,880		$	(130	)	(4.5	)%
Production taxes per Boe	$	0.98		$	1.54		$	(0.56	)	(36.4	)%
Production taxes as % of commodity sales	5.0		%	5.4		%

Production taxes for the three months ended March 31, 2020 were 5% lower than the prior year period. The quarter over quarter decrease on a dollar basis and on a per Boe basis was primarily a result of lower revenues driven by a decline in commodity pricing.

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

	Three months ended March 31,				Increase/			Percent
	2020		2019		(Decrease)			Change
DD&A (in thousands):
Oil and natural gas properties (1)	$	22,575	$	21,881	$	694		3.2	%
Property and equipment	437		1,834		(1,397		)	(76.2	)%
Total DD&A	$	23,012	$	23,715	$	(703	)	(3.0	)%
DD&A per Boe:
Oil and natural gas properties (1)	$	8.08	$	11.67	$	(3.59	)	(30.8	)%
Other fixed assets	0.16		0.98		(0.82		)	(83.7	)%
Total DD&A per Boe	$	8.24	$	12.65	$	(4.41	)	(34.9	)%

_________________________________________

(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 months ended March 31, 2020 of $22.6 million was 3% higher than the prior year periods due to higher production, partially offset by a lower DD&A rate driven by decreases in overall reserve values and future development costs as a result of decreasing commodity prices.

General and administrative expenses (“G&A”)

	Three months ended March 31,						Increase/			Percent
(in thousands)	2020			2019			(Decrease)			Change
G&A:
Gross G&A expenses	$	10,293		$	11,035		$	(742	)	(6.7	)%
Capitalized exploration and development costs	(2,225		)	(2,722		)	497			(18.3	)%
Net G&A expenses	8,068			8,313			(245		)	(2.9	)%
Net G&A expense per Boe	$	2.89		$	4.44		$	(1.55	)	(34.9	)%

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.

	Three months ended March 31,					Increase/			Percent
(in thousands)	2020		2019			(Decrease)			Change
Employee severance costs	$	733	$	1,058		$	(325	)	(30.7	)%
Stock compensation, gross	660		1,419			(759		)	(53.5	)%
Credit losses on receivables	1,517		(258		)	1,775			*
	$	2,910	$	2,219		$	691		31.1	%

______________________________________________

* Not meaningful

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Subleases expense

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

Full-cost ceiling impairment

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

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

We recorded a ceiling test impairment on our oil and natural gas properties of $71.4 million for the three months ended March 31, 2020, primarily due to a decrease in the price of natural gas and NGLs used to estimate our reserves, as disclosed in the table below.

Benchmark prices utilized in ceiling test	March 31, 2020		December 31, 2019
Oil (per Bbl)	$	55.77	$	55.69
Natural gas (per MMbtu)	$	2.30	$	2.58
Natural gas liquids (per Bbl)	$	14.97	$	16.21

The precipitous crude oil price decline caused by COVD-19 has resulted in a first of the month price in April and May 2020 of $20.31/bbl and $19.78/bbl, respectively. If commodity prices remain at their current level, decline, or do not recover to a level above $55.00/bbl, we expect the trailing 12-month average price to decline as 2020 progresses and we believe that it is probable that we would record further ceiling test impairment losses in 2020. In addition to commodity prices, our production rates, levels of proved reserves, estimated future operating expenses, estimated future development costs, transfers of unevaluated properties and other factors will determine our actual ceiling test calculation and impairment analyses in future periods. Please see “Note 1: Nature of operations and summary of significant accounting policies and going concern” in “Item 1. Financial Statements” of this report for further discussion of our ceiling test.

Income taxes

We did not record any net deferred tax benefit for the three months ended March 31, 2020, as any deferred tax asset arising from the benefit is reduced by a valuation allowance as utilization of the loss carryforwards and realization of other deferred tax assets cannot be reasonably assured. Please see “Note 12: Income Taxes” in “Item 8. Financial Statement and Supplementary Data” of our Annual Report on Form 10-K for the year ended December 31, 2019, which contains additional information about our income taxes.

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

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Other income and expenses

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

	Three months ended March 31,
(in thousands)	2020			2019
Credit facility	$	1,389		$	150
Senior Notes	6,563			6,563
Bank fees, other interest and amortization of issuance costs	1,002			1,343
Interest expense, gross	8,954			8,056
Capitalized interest	(2,318		)	(3,492		)
Total interest expense	$	6,636		$	4,564
Average borrowings	$	446,840		$	333,708

Interest expense for the three months ended March 31, 2020, was higher than the prior year quarter due to both an increase in gross interest expense as well as a reduction in capitalized interest. Gross interest was higher due to increased borrowings on our credit facility as reflected in the average borrowings disclosed in the table above. We capitalize interest based on the carrying value of our unevaluated non-producing leasehold excluding any amounts that are the result of our fresh start fair value adjustment. Capitalized interest for the three months ended March 31, 2020, was lower than the prior year period due to a lower average carrying balance on unevaluated non-producing leasehold, for which a large portion was impaired in the prior year.

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. 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 bankruptcy case is closed.

Non-GAAP financial measure and reconciliation

Management uses adjusted EBITDA (as defined below) as a supplemental financial measurement to evaluate our operational trends. Items excluded generally represent non-cash and/or non-recurring adjustments, the timing and amount of which cannot be reasonably estimated and are not considered by management when measuring our overall operating performance. In addition, Adjusted EBITDA is generally consistent with the EBITDAX calculation that is used in the Ratio of Total Debt to EBITDAX covenant under our credit facility. We consider compliance with this covenant to be material.

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

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

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

	Three months ended March 31,
(in thousands)	2020			2019
Net income or loss	$	4,917		$	(103,540	)
Interest expense	6,636			4,564
Depreciation, depletion, and amortization	23,012			23,715
Non-cash change in fair value of derivative instruments	(69,206		)	51,531
Impact of derivative repricing	702			—
Stock-based compensation expense	406			802
(Gain) loss on sale of assets	(102		)	1
Loss on impairment of oil and gas assets	71,371			49,722
Loss on impairment of other assets	153			—
Credit loss on uncollectible receivables	1,517			(258		)
Restructuring, reorganization and other	1,317			1,520
Adjusted EBITDA	$	40,723		$	28,057

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

(dollars in thousands)	March 31, 2020			December 31, 2019
Current assets per GAAP	$	110,889		$	80,390
Plus—Availability under Credit Agreement	180,000			194,406
Less—Short term derivative instruments	(48,458		)	(947		)
Current assets as adjusted	$	242,431		$	273,849
Current liabilities per GAAP	100,379			122,669
Less—Current derivative instruments	—			(11,957		)
Less—Current operating lease obligation	(1,295		)	(1,259		)
Less—Current asset retirement obligation	(928		)	(2,083		)
Less—Current maturities of long term debt	(497		)	(594		)
Current liabilities as adjusted	$	97,659		$	106,776
Current ratio per GAAP	1.10			0.66
Current ratio for loan compliance	2.48			2.56

Off-Balance Sheet Arrangements

At March 31, 2020, we did not have any off-balance sheet arrangements.

Critical accounting policies

For a discussion of our critical accounting policies, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2019.

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

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Recent accounting pronouncements

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity prices

Our financial condition, results of operations, capital resources and inventory of drillable locations are highly dependent upon the prevailing market prices of, and demand for, oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. We cannot predict future oil and natural gas prices with any degree of certainty. Sustained declines in oil and natural gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of net oil and natural gas reserves that we can produce economically. Any reduction in reserves, including reductions due to price fluctuations, can reduce our borrowing base under our Credit Agreement and adversely affect our liquidity and our ability to obtain capital for our acquisition, exploration and development activities. Based on our production for the three months ended March 31, 2020, our gross revenues from oil and natural gas sales would change approximately $1.7 million for each $1.00 change in oil and natural gas liquid prices and $0.6 million for each $0.10 change in natural gas prices.

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

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

The fair value of our outstanding derivative instruments at March 31, 2020 was a net asset of $53.1 million. Based on our outstanding derivative instruments as of March 31, 2020, summarized below, a 10% increase in the March 31, 2020, forward curves used to mark-to-market our derivative instruments would have decreased our net asset position to $44.6 million, while a 10% decrease would have increased our net asset position to $62.0 million.

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Our outstanding oil derivative instruments as of March 31, 2020, are summarized below:

Period and type of contract	Volume MBbls	Weighted average fixed price per Bbl
April - June 2020
Oil swaps	744	$	51.99
Oil roll swaps	110	$	0.42
July - September 2020
Oil swaps	495	$	50.63
Oil roll swaps	90	$	0.30
October - December 2020
Oil swaps	531	$	50.49
Oil roll swaps	90	$	0.30
January - March 2021
Oil swaps	170	$	46.24
Oil roll swaps	90	$	0.30
April - June 2021
Oil swaps	165	$	45.97
Oil roll swaps	60	$	0.30
July - September 2021
Oil swaps	183	$	46.64
October - December 2021
Oil swaps	171	$	46.07

Our outstanding natural gas derivative instruments as of March 31, 2020, are summarized below:

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

Our outstanding natural gas liquid derivative instruments as of March 31, 2020 are summarized below:

Period and type of contract	Volume Thousands of Gallons	Weighted average fixed price per gallon
April - June 2020
Natural gasoline swaps	2,476	$	1.17
Propane swaps	5,884	$	0.51
Butane swaps	497	$	0.53

Interest rates.  All of the outstanding borrowings under our Credit Agreement as of March 31, 2020 are subject to market rates of interest as determined from time to time by the banks. As of March 31, 2020, borrowings bear interest at the adjusted LIBO Rate, as defined under the Credit Agreement, plus the applicable margin, which resulted in a weighted average interest rate of 3.15% on the

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amount outstanding. Any increases in these rates can have an adverse impact on our results of operations and cash flow. Assuming a constant debt level under our Credit Agreement of $325.0 million, equal to our borrowing base at March 31, 2020, the cash flow impact for a 12-month period resulting from a 100 basis point change in interest rates would be $3.3 million.

ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and procedures

As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Form 10-Q. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of March 31, 2020, at the reasonable assurance level.

Changes in Internal control over financial reporting

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

PART II—OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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

ITEM 1A. RISK FACTORS

Security holders and potential investors in our securities should carefully consider the risk factors in our Annual Report on Form 10-K filed with the SEC on March 12, 2020, together with the information set forth in our subsequent Quarterly Reports on Form 10-Q, current reports on Form 8-K and other materials we file with the SEC. 

Except for the risk factors discussed below, there have been no material changes to the Risk Factors previously disclosed in our Annual Report for the year ended December 31, 2019.

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

The rapid, global spread of COVID-19 in the first quarter of 2020 and the resulting economic repercussions created significant volatility in the oil and gas industry. Stay-at-home and similar protective measures that were enacted by federal, foreign, state and local governments to slow the spread of the virus contributed to a significant deterioration in the domestic and global demand for oil and gas. Compounding the impact of COVID-19, the oil production output alliance between Russia, Saudi Arabia and other oil producing nations (“OPEC+”) broke down as both sides were unable to reach agreement in early March 2020 over how much to restrict production in order to stabilize crude oil prices. As a result, Saudi Arabia and Russia both initiated efforts to increase production, driving down oil prices. OPEC+ was later able to agree on approximately 9.7 million barrels of oil per day of production cuts, but that announcement has done little to aid in oil price recovery because of the significant drop in global demand. Even though

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the price for oil in the commodities futures markets currently reflect some price improvement (although still less than pre-March 2020 prices), the current cash prices have deteriorated significantly. On April 20, 2020, the front-month futures contract for WTI prices dipped into the negative, and as of the time of this filing were less than $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.

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

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

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

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

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

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

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

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

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

• increasing crude storage at our lease locations; and

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

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

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

Period	Total number of shares purchased (1)	Average price paid per share	Total number of shares purchased as part of publicly announced plans or programs	Maximum number of shares that may yet be purchased under the plans or programs
January 1 - 30, 2020	3,856	1.58	N/A	N/A
February 1 - 29, 2020	—	—	N/A	N/A
March 1 - 31, 2020	—	—	N/A	N/A
Total	3,856	1.58	N/A	N/A

_________________________

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

ITEM 5. OTHER INFORMATION

Not applicable.

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ITEM 6. EXHIBITS

Exhibit No.	Description
3.1*	Third Amended and Restated Certificate of Incorporation of Chaparral Energy, Inc., dated as of March 21, 2017 (Incorporated by reference to Exhibit 3.1 of  the Company’s Current Report on Form 8-K filed on March 27, 2017).
3.2*	Certificate of Retirement of 7,869,929 shares of Class B Common Stock (Incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K filed on December 19, 2018).
3.3*	Second Amended and Restated Bylaws of Chaparral Energy, Inc., dated as of December 20, 2019 (Incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K filed on December 27, 2019).
4.1*	Indenture dated June 29, 2018, among the Company, the Guarantors party thereto, and UMB Bank, N.A., as Trustee (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K filed on July 2, 2018).
4.2*	Form of 8.750% Senior Note due 2023 (Incorporated by reference to Exhibit A of Exhibit 4.1 of the Company’s Current Report on Form 8-K filed on July 2, 2018).
4.3*	Registration Rights Agreement, dated as of March 21, 2017, by and among Chaparral Energy, Inc. and the Stockholders named therein (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K filed on March 27, 2017).
10.1 †	Chaparral Energy, Inc. 2020 Key Executive Incentive Plan dated April 24, 2020.
10.2 †	Form of Award Notice under Chaparral Energy, Inc. 2020 Key Executive Incentive Plan dated April 24, 2020.
10.3 †	Chaparral Energy, Inc. 2020 Key Executive Retention Plan dated April 24, 2020.
10.4 †	Form of Award Notice under Chaparral Energy, Inc. 2020 Key Executive Retention Plan dated April 24, 2020.
31.1	Certification by Principal Executive Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act.

31.2	Certification by Principal Financial Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act.
32.1	Certification by Principal Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	Certification by Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS	XBRL Instance Document.
101.SCH	XBRL Taxonomy Extension Schema Document.
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB	XBRL Taxonomy Extension Label Linkbase Document.
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document.

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

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SIGNATURES

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

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

Date: May 11, 2020

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