Nature of operations and summary of significant accounting policies

Nature of operations

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

Interim financial statements

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

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

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

Cash and cash equivalents

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

Accounts receivable

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



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

Inventories

Inventories consisted of the following:



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

Property and equipment, net

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



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

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

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

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

Oil and natural gas properties

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

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

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

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



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

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

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

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

Revenue recognition

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

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



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

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

Income taxes

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

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

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

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

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

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

Cost reduction initiatives

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

Other expense

Other expense consisted of the following:



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

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

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

Joint development agreement

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

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

Reorganization items

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



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

Recently adopted accounting pronouncements

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

Recently issued accounting pronouncements

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