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

6 Months Ended

Jun. 30, 2020

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

Nature of operations

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

Interim financial statements

The accompanying unaudited consolidated interim financial statements of the Company have been prepared in accordance with the rules and regulations of the SEC and do not include all of the financial information and disclosures required by accounting principles generally accepted in the United States of America (“GAAP”) for complete financial statements. These financial statements and the notes thereto should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2019.

The financial information as of June 30, 2020, and for the three and six months ended June 30, 2020 and 2019, is unaudited. The financial information as of December 31, 2019 has been derived from the audited financial statements contained in our Annual Report on Form 10-K for the year ended December 31, 2019. In management’s opinion, such information contains all adjustments considered necessary for a fair presentation of the results of the interim periods. The results of operations for the three and six months ended June 30, 2020 are not necessarily indicative of the results of operations that will be realized for the year ended December 31, 2020.

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

Chapter 11 Cases and going concern

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

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

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

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

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

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

Cash and cash equivalents

We maintain cash and cash equivalents in bank deposit accounts and money market funds which may not be federally insured. As of June 30, 2020, cash with a recorded balance totaling approximately $55,445 was held at JP Morgan Chase Bank, N.A. We have not experienced any losses in such accounts and believe we are not exposed to any significant credit risk on such accounts.

Accounts receivable

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

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

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


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

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

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

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

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

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

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

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


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

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


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

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


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

Inventories

Inventories consisted of the following:


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

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

Property and equipment, net

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


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

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

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


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

Oil and natural gas properties

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

Costs associated with unevaluated oil and natural gas properties are excluded from the amortizable base until a determination has been made as to the existence of proved reserves. Quarterly, unevaluated leasehold costs are transferred to the amortization base with the costs of drilling the related well upon proving up reserves of a successful well or upon determination of a dry or uneconomic well. Furthermore, unevaluated oil and natural gas properties are reviewed for impairment if events and circumstances exist that indicate a possible decline in the recoverability of the carrying amount of such property. The impairment assessment is conducted at least once annually and whenever there are indicators that impairment has occurred. In assessing whether impairment has occurred, we consider factors such as intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; assignment of proved reserves; and economic viability of development if proved reserves are assigned. Upon determination of impairment, all or a portion of the associated leasehold costs are transferred to the full cost pool and become subject to amortization. The processes above are applied to unevaluated oil and natural gas properties on an individual basis or as a group if properties are individually insignificant. Our future depreciation, depletion and amortization rate would increase or we may incur ceiling test write-downs if costs are transferred to the amortization base without any associated reserves.

In the past, the costs associated with unevaluated properties typically related to acquisition costs of unproved acreage. As a result of the application of fresh start accounting on the Prior Effective Date in 2017, a substantial portion of the carrying value of our unevaluated properties are the result of a fair value increase to reflect the value of our acreage in our Focus Areas.

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


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

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

Our estimates of oil and natural gas reserves as of June 30, 2020, and the related PV-10 value, were prepared using an average price for oil and natural gas on the first day of each month for the prior twelve months as required by the SEC. These losses are reflected in “Impairment of oil and gas assets” in our consolidated statements of operations. The ceiling test impairment we recorded in the current year was driven in part by our impairment of unevaluated leasehold in the amount $216,173 and $218,741 for the three and six month periods ending June 30, 2020, respectively. Impairments of leasehold result in a transfer of amounts from unevaluated oil and natural gas properties to the full cost amortization base subsequently impacting the ceiling test.


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

Producer imbalances. We recognize revenue on all natural gas sold to our customers regardless of our proportionate working interest in a well. Liabilities are recorded for imbalances greater than our proportionate share of remaining estimated natural gas reserves. Our aggregate imbalance positions at June 30, 2020, and December 31, 2019, were immaterial.

Revenue recognition

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


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

Please see “Note 16: Revenue recognition” in “Item 8. Financial Statements and Supplementary Data” of our Annual Report on Form 10-K for the year ended December 31, 2019, for a discussion of our revenue recognition policy including a description of products and revenue disaggregation criteria, performance obligations, pricing, measurement and contract assets and liabilities.

Income taxes

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

The provision for income taxes is based on a current estimate of the annual effective income tax rate adjusted to reflect the impact of permanent differences and discrete items. Management judgment is required in estimating operating income in order to determine our effective income tax rate. The consistent effective tax rate, as disclosed below, is a result of maintaining a valuation allowance against substantially all of our net deferred tax asset.


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

Despite the Company’s net loss for the six month period ended June 30, 2020, we did not record any net deferred tax benefit due to the Company’s projected taxable loss for the year ending December 31, 2020. Nor did the Company record a net deferred tax benefit, as any deferred tax asset arising from the benefit is reduced by a valuation allowance as utilization of the loss carryforwards and realization of other deferred tax assets cannot be reasonably assured.

A valuation allowance for deferred tax assets, including NOLs, is recognized when it is more likely than not that some or all of the benefit from the deferred tax asset will not be realized. To assess that likelihood, we use estimates and judgment regarding our future taxable income, as well as the jurisdiction in which such taxable income is generated, to determine whether a valuation allowance is

required. Such evidence can include our current financial position, our results of operations, both actual and forecasted, the reversal of deferred tax liabilities, and tax planning strategies as well as the current and forecasted business economics of our industry.

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

The benefit of an uncertain tax position taken or expected to be taken on an income tax return is recognized in the consolidated financial statements at the largest amount that is more likely than not to be sustained upon examination by the relevant taxing authority. Interest and penalties, if any, related to uncertain tax positions would be recorded in interest expense and other expense, respectively. There were no uncertain tax positions at June 30, 2020, or December 31, 2019.

As a result of the Prior Reorganization Plan and related transactions, the Company experienced an ownership change within the meaning of Internal Revenue Code (“IRC”) Section 382 on the Prior Effective Date. This ownership change subjected certain of the Company’s tax attributes, including $760,067 of federal net operating loss carryforwards, to an IRC Section 382 limitation. This limitation has not resulted in a current tax liability for the six month period ended June 30, 2020, or any intervening period since the Prior Effective Date. Since the Prior Effective Date ownership change, the Company has generated additional NOLs and other tax attributes that are not currently subject to an IRC Section 382 limitation. The Company’s ability to use NOLs and other tax attributes to reduce taxable income and income taxes could be materially impacted by a future IRC 382 ownership change. Future transactions involving the Company’s stock, including those outside of the Company’s control, could cause an IRC 382 ownership change resulting in a limitation on tax attributes currently not limited and a more restrictive limitation on tax attributes currently subject to the previous IRC 382 limitation.

Subleases expense

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

Reorganization items

Reorganization items reflect, where applicable, expenses, gains and losses incurred that are incremental and a direct result of the reorganization of the business resulting from the Prior Chapter 11 Cases and Prior Reorganization Plan. The reorganization items disclosed in our consolidated statement of operations consist of professional fees for continuing legal work to resolve outstanding claims and fees to the U.S. Bankruptcy Trustee, which we will continue to incur until both the Prior Chapter 11 Cases and the Chapter 11 Cases are closed.

Liability management expenses

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

Litigation loss

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

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