Note 1: Nature of operations and summary of significant accounting policies
Chaparral Energy, Inc. and its subsidiaries, (collectively, “we”, “our”, “us”, or the “Company”) are involved in the acquisition, exploration, development, production and operation of oil and natural gas properties. Our properties are located primarily in Oklahoma and our commodity products, which include crude oil, natural gas and natural gas liquids, are primarily sold to refineries and gas processing plants within close proximity to our producing properties. As discussed in “Note 3: Chapter 11 reorganization” we filed voluntary petitions for bankruptcy relief on May 9, 2016, and subsequently operated as debtor in possession, in accordance with the applicable provisions of the Bankruptcy Code, until emergence from bankruptcy on March 21, 2017. The cancellation of all existing shares outstanding followed by the issuance of new shares in the reorganized Company upon our emergence from bankruptcy caused a related change of control under U.S. GAAP. As a result of the application of fresh start accounting, as well as the effects of the implementation of the Reorganization Plan, the Company’s consolidated financial statements on or after March 21, 2017, are not comparable with the consolidated financial statements prior to that date. To facilitate our financial statement presentations, we refer to the post-emergence reorganized company in these consolidated financial statements and footnotes as the “Successor” for periods subsequent to March 21, 2017, and to the pre-emergence company as “Predecessor” for periods prior to and including March 21, 2017.
A summary of the significant accounting policies applied in the preparation of the accompanying consolidated financial statements follows.
Principles of consolidation
The consolidated financial statements include the accounts of Chaparral Energy, Inc. and its wholly owned subsidiaries. All significant intercompany balances and transactions have been eliminated.
Use of estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period.
The more significant areas requiring use of assumptions, judgments and estimates on our consolidated financial statements include: quantities of proved oil and natural gas reserves; value of nonproducing leasehold; cash flow estimates used in impairment tests of other long-lived assets; depreciation, depletion and amortization; asset retirement obligations; estimates of our stock-based compensation awards, assigning fair value and allocating purchase price in connection with business combinations; forecasting our effective income tax rate and valuation allowances associated with deferred income taxes; valuation of derivative instruments; and accrued revenue and related receivables. Although management believes these estimates are reasonable, actual results could significantly differ from these estimates.
Reclassifications
Certain reclassifications have been made to prior period financial statements to conform to current period presentation. The reclassifications had no effect on our previously reported results of operations or cash flows.
Cash and cash equivalents
We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. We maintain cash and cash equivalents in bank deposit accounts and money market funds which may not be federally insured. As of December 31, 2019, cash with a recorded balance totaling $22,057 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.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
Accounts receivable
We have receivables from joint interest owners and oil and natural gas purchasers which are generally uncollateralized. We generally review our oil and natural gas purchasers for credit worthiness and general financial condition. We may have the ability to withhold future revenue disbursements to recover non-payment of joint interest billings on properties of which we are the operator. Accounts receivable from joint interest owners are stated at amounts due, net of an allowance for doubtful accounts. Accounts receivable are generally due within 30 days and accounts outstanding longer than 60 days are considered past due. We establish our allowance for doubtful accounts by considering the length of time past due, previous loss history, future net revenues of the debtor’s ownership interest in oil and natural gas properties we operate, and our assessment of the owner’s ability to pay its obligation, among other things.
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. Accounts receivable consisted of the following:
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December 31,
2019
|
|
December 31,
2018
|
|
Joint interests
|
|
$
|
16,664
|
|
|
$
|
31,573
|
|
|
Accrued commodity sales
|
|
30,819
|
|
|
30,287
|
|
|
Derivative settlements
|
|
717
|
|
|
2,092
|
|
|
Other
|
|
2,544
|
|
|
3,375
|
|
|
Allowance for doubtful accounts
|
|
(1,097
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)
|
|
(1,240
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)
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|
|
|
$
|
49,647
|
|
|
$
|
66,087
|
|
Inventories
Inventories consist of equipment used in developing oil and natural gas properties and oil and natural gas product inventories. We evaluate our inventory each quarter and when there is evidence that the utility of our inventory, in their disposal in the ordinary course of business, will be less than cost, whether due to physical deterioration, obsolescence, changes in price levels, or other causes, we record an impairment loss for the difference. Inventories are shown net of a provision for obsolescence, commensurate with known or estimated exposure, which is reflected in the valuation allowance disclosed below. Inventories consisted of the following:
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December 31,
2019
|
|
December 31,
2018
|
|
Equipment inventory
|
|
$
|
3,435
|
|
|
$
|
3,663
|
|
|
Commodities
|
|
474
|
|
|
574
|
|
|
Inventory valuation allowance
|
|
(179
|
)
|
|
(178
|
)
|
|
|
|
$
|
3,730
|
|
|
$
|
4,059
|
|
We recorded lower of cost or net realizable value adjustments of $179 for the period from March 22, 2017 to December 31, 2017 due to depressed industry conditions which resulted in lower demand for such equipment and hence lower market prices, as well as obsolescence. These adjustments are reflected in “Impairment of other assets” in our consolidated statements of operations.
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
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
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 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 (see “Note 4: Fresh start accounting”). See “Note 19: Oil and natural gas activities (unaudited)” for further details of our unevaluated oil and natural gas properties.
Depreciation, depletion and amortization. Depreciation, depletion and amortization (“DD&A”) of oil and natural gas properties are provided using the units-of-production method based on estimates of proved oil and natural gas reserves and production, which are converted to a common unit of measure based upon their relative energy content. Our cost basis for depletion includes estimated future development costs to be incurred on proved undeveloped properties. The computation of DD&A takes into consideration restoration, dismantlement, and abandonment costs, and the anticipated proceeds from salvaging equipment.
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 December 31, 2019, 2018 and 2017 were prepared using an average price for oil and natural gas based upon the first day of each month for the prior twelve months as required by the SEC. As discussed in “Note 4: Fresh start accounting,” the application of fresh start accounting to our balance sheet on March 21, 2017, resulted in the carrying value of our oil and natural gas properties being restated based on their estimated fair value at the time.
We recorded ceiling adjustments to the oil and natural gas properties, for the periods disclosed below. The loss is reflected in “Impairment of oil and gas assets” in our consolidated statements of operations.
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Successor
|
|
|
Predecessor
|
|
|
|
|
|
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|
Period from
|
|
|
Period from
|
|
|
|
|
|
|
|
March 22, 2017
|
|
|
January 1, 2017
|
|
|
|
For the Year Ended December 31,
|
|
through
|
|
|
through
|
|
|
|
2019
|
|
2018
|
|
December 31, 2017
|
|
|
March 21, 2017
|
|
Ceiling test impairment
|
|
$
|
430,695
|
|
|
$
|
20,065
|
|
|
$
|
42,146
|
|
|
|
$
|
—
|
|
Impairment of long-lived assets
Impairment losses are recorded on property and equipment used in operations and other long-lived assets held and used when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets’
carrying amount. Impairment is measured based on the excess of the carrying amount over the fair value of the asset. Impairment losses are also recorded on assets classified as held for sale when there is an excess of carrying value over fair value less costs to sell.
During 2019, we recognized an impairment loss of $6,407 on the building and adjacent land housing our headquarters prior to its sale during the third quarter of 2019. See “Note 7: Property and equipment” for a discussion of the building sale.
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 on the balance sheet as “Assets held for sale” at carrying value or fair value less cost to sell, whichever is less. As a result of determining fair value on the assets held for sale, an impairment loss was recorded for the year ended December 31, 2019 in the amount of $781 which was included in the “Impairment of other assets” in the Statements of Operations.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
Income taxes
Deferred income taxes are provided for significant carryforwards and temporary differences between the tax basis of an asset or liability and its reported amount in the financial statements that will result in taxable or deductible amounts in future years. Deferred income tax assets or liabilities are determined by applying the presently enacted tax rates and laws. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in results of operations in the period the rate change is enacted.
We record a valuation allowance for the amount of net deferred tax assets when, in management’s opinion, it is more likely than not that such assets 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.
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 December 31, 2019, or December 31, 2018.
We file income tax returns in the U.S. federal jurisdiction and in various states, each with varying statutes of limitations. The 2011 through 2019 tax years generally remain subject to examination by federal and state tax authorities.
Derivative transactions
We use derivative instruments to reduce the effect of fluctuations in crude oil, natural gas and natural gas liquids prices, and we recognize all derivatives as either assets or liabilities measured at fair value. Our derivative instruments are not designated as hedges for accounting purposes, thus changes in the fair value of derivatives are reported immediately in “Derivative (losses) gains” in the consolidated statements of operations. Cash flows associated with derivatives are reported as investing activities in the consolidated statements of cash flows unless the derivatives contain a significant financing element, in which case that element is reported as financing activities.
Within current and noncurrent classifications on the balance sheet, we offset assets and liabilities for derivative contracts executed with the same counterparty under a master netting arrangement. See “Note 9: Derivative instruments” for additional information regarding our derivative transactions.
Fair value measurements
Fair value is defined by the Financial Accounting Standards Board (“FASB”) as 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.
Assets and liabilities recorded at fair value in the consolidated balance sheets are categorized according to the fair value hierarchy defined by the FASB. The hierarchical levels are based upon the level of judgment associated with the inputs used to measure the fair value of the assets and liabilities. 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.
Level 1 inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date. Level 2 inputs include adjusted quoted prices for similar instruments in active markets, and inputs other than quoted prices that are observable for the asset or liability. Fair value assets and liabilities included in this category are derivatives with fair values based on published forward commodity price curves and other observable inputs. 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. Assets carried at fair value and included in this category are certain financial derivatives and additions to our asset retirement obligations. See “Note 10: Fair value measurements” for additional information regarding our fair value measurements.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
Asset retirement obligations
We own oil and natural gas properties that require expenditures to plug, abandon or remediate wells and to remove tangible equipment and facilities at the end of oil and natural gas production operations in accordance with applicable federal and state laws. We record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of oil and natural gas properties. The accretion of the asset retirement obligations is included in “Depreciation, depletion and amortization” in our consolidated statements of operations. In certain instances, we are required to make deposits to escrow accounts for plugging and abandonment obligations. See “Note 11: Asset retirement obligations” for additional information regarding our asset retirement obligations.
Environmental liabilities
We are subject to extensive federal, state and local environmental laws and regulations covering discharge of materials into the environment. Because these laws and regulations change regularly, we are unable to predict the conditions and other factors over which we do not exercise control that may give rise to environmental liabilities affecting us. Environmental expenditures that relate to an existing condition caused by past operations and that do not contribute to current or future revenue generation are expensed. Liabilities are accrued when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. As of December 31, 2019 and 2018, we have not accrued for or been fined or cited for any environmental violations that would have a material adverse effect upon our financial position, operating results, or cash flows.
Revenue recognition
Beginning in 2018, we adopted new authoritative guidance that supersedes previous revenue recognition requirements. The guidance requires that we identify the performance obligations, under our sales agreements, which is for the delivery of crude oil, natural gas or NGLs, and to recognize revenue when those obligations are satisfied, which occurs when control of the commodity is transferred to the purchaser. Furthermore, any costs and fees levied by the customer subsequent to the transfer of control will be recognized as a reduction in revenue. See “Note 16: Revenue recognition” for additional information regarding our revenue recognition.
Stock-based compensation
Our deferred compensation plan currently consists of restricted stock awards (“RSAs”) or restricted stock units (“RSUs”). Currently outstanding RSAs and RSUs are subject to either service-based vesting conditions or market-based vesting conditions. The RSAs and RSUs are generally classified as equity-based awards with the exception of awards that contractually specify settlement in cash or have a prior history of cash settlement, which are classified as liability-based awards. Compensation cost for service-based awards is recognized and measured based on fair value as determined by the market price of our publicly traded common stock, while the fair value computation used to determine compensation cost for market-based awards incorporates the probability of vesting.
Service-based awards either vest in one year and are expensed over that time frame or are subject to a graded vesting schedule over three annual installments where expense is recognized under the accelerated method. Market-based awards vest in three tranches over three annual measurement periods according to our stock price performance relative to a group of peer companies. The market conditions for a given year are unique to that year, and vesting with respect to conditions for a given year is independent of the vesting with respect to other years. As a result, the requisite service period for each of the three tranches of the market-based awards relate to the individual annual period for which stock return performance is measured and do not overlap. Market-based awards are expensed based on the fair value of the award that incorporates the probability of vesting and estimated by Monte Carlo simulation. Since the probability of vesting an award with a market condition is embedded in its fair value, expense is recognized on the entire grant regardless of the number of shares that actually vest so long as the participant remains employed as of the vesting date. Market conditions have not been established for tranches with stock return measurement periods that begin in 2020 and 2021, hence a grant date for purposes of determining a measurement value had not been established and expense recognition has not commenced. As permitted by a recent accounting update, we do not recognize expense based on an estimate of forfeitures but rather recognize the impact of forfeitures only as they occur.
See “Note 13: Deferred compensation” for additional information relating to stock-based compensation.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
Other expense
Other expense consisted of the following:
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|
|
|
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|
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Successor
|
|
|
|
|
|
|
|
Period from
|
|
|
|
|
|
|
|
March 22, 2017
|
|
|
|
For the Year Ended December 31,
|
|
through
|
|
|
|
2019
|
|
2018
|
|
December 31, 2017
|
|
Restructuring
|
|
$
|
—
|
|
|
$
|
425
|
|
|
$
|
3,531
|
|
|
Subleases
|
|
1,075
|
|
|
1,611
|
|
|
197
|
|
|
Total other expense
|
|
$
|
1,075
|
|
|
$
|
2,036
|
|
|
$
|
3,728
|
|
Restructuring. We consider our EOR asset divestiture in November 2017 (see “Note 6: Acquisitions and divestitures”) to be an exit activity that qualifies as a restructuring in that it materially changed the scope and manner in which our business is conducted. The restructuring expense related to the divestiture 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 slate of employees terminated as a result of the divestiture.
Subleases. Our subleases consisted 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. Prior to the EOR divestiture, the financing leases were included in our full cost amortization base and hence subject to amortization on a units-of-production basis, while also incurring interest expense. The payments under our operating leases were previously recorded as “Lease operating” expense on our statement of operations. Subsequent to the execution of the subleases, 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, which we disclose in the table above. 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 17: Leases” for our disclosure on leases. In September 2019, U.S. Bank entered into agreements with the Sublessee that 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 STACK wells, subject to well cost caps that vary by well-type across location and targeted formations, ranging from $3,400 to $4,000 per gross well. The JDA provided us with a means to accelerate the delineation of our position within our Garfield County and Canadian County acreage, realizing further efficiencies and holding additional acreage by production, and potentially adding reserves. In exchange, BCE received 85% of our original working interest in each well (on a wellbore-only basis), with the Company retaining 15% of our original interests until the program reaches a 14% internal rate of return. If this 14% threshold is achieved, ownership interest in all wells would shift such that we would own 75% of our original working interests and BCE would retain 25% of our original working interests. We retained all acreage and reserves outside of the wellbores, with both parties paying their working interest share of lease operating expenses. We have drilled and completed all wells under the JDA.
Our drilling and completion costs exceeded the well cost caps specified under the JDA primarily due to inflation in the cost of oilfield services since entering into the JDA. We have therefore recorded additions to oil and natural gas properties of $4,061 and $13,212 during the years ended December 31, 2019 and 2018, respectively, in cumulative drilling and completion costs on JDA wells that have exceeded the well cost caps specified under the JDA. 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 to extend or expand the JDA.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
Cost reduction initiatives
Cost reduction initiatives include expenses related to our efforts to reduce our capital, operating and administrative costs in response to depressed commodity pricing environment. The expense consists of costs for one-time severance and termination benefits in connection with our reductions in force and third party legal and professional services we have engaged to assist in our cost savings initiatives as follows:
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|
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Successor
|
|
|
Predecessor
|
|
|
|
|
|
Period from
|
|
|
Period from
|
|
|
|
For the Year
|
|
March 22, 2017
|
|
|
January 1, 2017
|
|
|
|
Ended December 31,
|
|
through
|
|
|
through
|
|
|
|
2018
|
|
December 31, 2017
|
|
|
March 21, 2017
|
|
One-time severance and termination benefits
|
|
$
|
1,034
|
|
|
$
|
678
|
|
|
|
$
|
608
|
|
|
Professional fees
|
|
$
|
—
|
|
|
13
|
|
|
|
21
|
|
|
Total cost reduction initiatives expense
|
|
$
|
1,034
|
|
|
$
|
691
|
|
|
|
$
|
629
|
|
Recently adopted accounting pronouncements
In May 2014, the FASB issued authoritative guidance that supersedes previous revenue recognition requirements and 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. Please see “Note 16: Revenue recognition” for our disclosure regarding adoption of this update.
In January 2017, the FASB issued authoritative guidance that changes the definition of a business to assist entities with evaluating when a set of transferred assets and activities constitutes a business. The guidance requires an entity to evaluate if substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar identifiable assets; if so, the set of transferred assets and activities is not a business. The guidance also requires a business to include at least one substantive process and narrows the definition of outputs by more closely aligning it with how outputs are described under updated revenue recognition guidance. The guidance is effective for public business entities for fiscal years beginning after December 15, 2017, and interim periods within those years. We adopted this update effective January 1, 2018, without a material impact to our financial statements. We expect that the new guidance, when applied to the facts and circumstances of a future transaction, may impact the likelihood whether a future transaction would be accounted for as a business combination.
In January 2016, the FASB issued authoritative guidance that amends existing requirements on the classification and measurement of financial instruments. The standard principally affects accounting for equity investments and financial liabilities where the fair value option has been elected. The guidance is effective for fiscal years beginning after December 15, 2017, and interim periods thereafter. We adopted this update effective January 1, 2018, with no material impact to our financial statements or results of operations.
In August 2016, the FASB issued authoritative guidance that provides clarification on how certain cash receipts and cash payments are presented and classified on the statement of cash flows. This update provides guidance on eight specific cash flow issues: debt prepayment or debt extinguishment costs; settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies including bank-owned life insurance policies; distributions received from equity method investees; beneficial interests in securitization transactions; and separately identifiable cash flows and application of the predominance principle. The guidance is effective for fiscal years beginning after December 15, 2017, and is required to be adopted using a retrospective approach if practicable. We adopted this update effective January 1, 2018, without a material impact on our financial statements or results of operations.
In November 2016, the FASB issued authoritative guidance requiring that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. The guidance is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years and should be
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
applied using a retrospective transition method to each period presented. We adopted this update effective January 1, 2018, with no material impact to our financial statements or results of operations.
In May 2017, the FASB issued authoritative guidance that provides clarification on determining which changes to the terms and conditions of share-based payment awards require an entity to apply modification accounting. The guidance is effective for fiscal years, including interim periods within those annual periods, beginning after December 15, 2017, with early adoption permitted in any interim period. The guidance should be applied prospectively to an award modified on or after the adoption date. We adopted this guidance effective January 1, 2018, with no material impact to our financial statements or results of operations.
In March 2016, the FASB issued authoritative guidance with the objective to simplify several aspects of the accounting for share-based payments, including accounting for income taxes when awards vest or are settled, statutory withholdings and accounting for forfeitures. Classification of these aspects on the statement of cash flows is also addressed. We have adopted this guidance, which was effective for fiscal periods beginning after December 15, 2016, and interim periods thereafter, in 2017, with no material impact to our financial statements or results of operation. We did not have any previously unrecognized excess tax benefits that required an adjustment to the opening balance of retained earnings under the modified retrospective transition method required by the guidance.
In March 2016, the FASB issued authoritative guidance that clarifies that the assessment of whether an embedded contingent put or call option in a financial instrument is clearly and closely related to the debt host requires only an analysis of the four-step decision sequence described in ASC Topic 815, Derivatives and Hedging (“ASC 815”). We adopted this guidance, which was effective for fiscal periods beginning after December 15, 2016, and interim periods thereafter, in 2017, with no material impact to our financial statements or results of operations.
In February 2016, the FASB established ASC Topic 842, Leases (“ASC 842”) that requires lessees to recognize leases on-balance sheet and disclose key information about leasing arrangements. ASC 842 was subsequently amended by Accounting Standards Update (“ASU”) No. 2018-01, Land Easement Practical Expedient for Transition to Topic 842; ASU No. 2018-10, Codification Improvements to Topic 842, Leases; and ASU No. 2018-11, Targeted Improvements. Please see “Note 17: Leases” for our disclosure regarding adoption of this update.
Recently issued accounting pronouncements
In June 2016, the FASB issued authoritative guidance that modifies the measurement of expected credit losses of certain financial instruments. The guidance is effective for fiscal years beginning after December 15, 2019 for public business entities with the exception of small reporting companies, which have a later adoption date. 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.
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.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
Note 2: Earnings per share
Prior to our emergence from bankruptcy, we did not present earnings per share (“EPS”) in our financial statements because our common stock did not previously trade on a public market, either on a stock exchange or in the over-the-counter (“OTC”) market. Accordingly, we were permitted under accounting guidance to omit such disclosure. Subsequent to our emergence from bankruptcy, our Class A common stock was quoted on the OTC Pink marketplace under the symbol “CHHP” from May 18, 2017, through May 25, 2017. From May 26, 2017, through July 23, 2018, our Class A common stock was quoted on the OTCQB tier of the OTC Markets Group Inc. under the symbol “CHPE”. Our Class A common stock is currently trading on the NYSE under the symbol “CHAP” upon our listing on that exchange on July 24, 2018. Our Class B common stock was not listed or quoted on the OTCQB or any other national exchange; however, on December 19, 2018, all outstanding shares of our Class B common stock converted into the same number of shares of Class A common stock. With the conversion, all our common stock is now traded on the NYSE. Our Class A and previous Class B common stock shared equally in dividends and undistributed earnings. We are presenting basic and diluted EPS for all Successor periods subsequent to our emergence from bankruptcy but are not presenting EPS for any Predecessor period.
We are required under accounting guidance to compute EPS using the two-class method that considers multiple classes of common stock and participating securities. All securities that meet the definition of a participating security are to be included in the computation of basic EPS under the two-class method.
A reconciliation of the components of basic and diluted EPS is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
|
|
|
|
|
|
|
Period from
|
|
|
|
|
|
|
|
March 22, 2017
|
|
|
|
For the Year Ended December 31,
|
|
through
|
|
(in thousands, except share and per share data)
|
|
2019
|
|
2018
|
|
December 31, 2017
|
|
Numerator for basic and diluted earnings per share
|
|
|
|
|
|
|
|
|
Net (loss) income
|
|
$
|
(468,948
|
)
|
|
$
|
33,442
|
|
|
$
|
(118,902
|
)
|
|
Denominator for basic earnings per share
|
|
|
|
|
|
|
|
Weighted average common shares - Basic for Class A and Class B (1)
|
|
45,637,338
|
|
|
45,288,980
|
|
|
44,984,046
|
|
|
Effect of dilutive securities
|
|
|
|
|
|
|
|
Dilutive shares from equity compensation awards
|
|
—
|
|
|
441,191
|
|
|
—
|
|
|
Denominator for diluted earnings per share
|
|
|
|
|
|
|
|
Weighted average common shares - Diluted for Class A and Class B (1)
|
|
45,637,338
|
|
|
45,730,171
|
|
|
44,984,046
|
|
|
Earnings (loss) per share
|
|
|
|
|
|
|
|
Basic for Class A and Class B (1)
|
|
$
|
(10.28
|
)
|
|
$
|
0.74
|
|
|
$
|
(2.64
|
)
|
|
Diluted for Class A and Class B (1)
|
|
$
|
(10.28
|
)
|
|
$
|
0.73
|
|
|
$
|
(2.64
|
)
|
|
Securities excluded from earnings per share calculations
|
|
|
|
|
|
|
|
Unvested restricted stock awards or units at period end
|
|
3,187,231
|
|
|
125,323
|
|
|
1,833,136
|
|
|
Warrants (2)
|
|
—
|
|
|
—
|
|
|
140,023
|
|
____________________________________________________________
|
|
|
|
(1)
|
Effective December 19, 2018, Class B shares were converted to Class A shares.
|
|
|
|
|
(2)
|
The warrants to purchase shares of our Class A common stock are antidilutive for the period from March 22 to December 31, 2017, due to the exercise price exceeding the average price of our Class A shares and due to the net loss we incurred. These warrants expired on June 30, 2018. They were antidilutive during the first and second quarter of 2018 due to the exercise price exceeding the average price of our Class A shares and hence are omitted from diluted earnings per share for the year ended December 31, 2018.
|
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
Note 3: Chapter 11 reorganization
Bankruptcy petition and emergence. On May 9, 2016 (the “Petition Date”), Chaparral Energy, Inc. and its subsidiaries including Chaparral Energy, L.L.C., Chaparral Resources, L.L.C., Chaparral Real Estate, L.L.C., Chaparral CO2 , L.L.C., CEI Pipeline, L.L.C., CEI Acquisition, L.L.C., Green Country Supply, Inc., Chaparral Biofuels, L.L.C., Chaparral Exploration, L.L.C., and Roadrunner Drilling, L.L.C. (collectively, the “Chapter 11 Subsidiaries” and, together with Chaparral Energy, Inc., the “Debtors”) filed voluntary petitions seeking relief under Title 11 of the United States Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the District of Delaware (the “Bankruptcy Court”) commencing cases for relief under chapter 11 of the Bankruptcy Code (the “Chapter 11 Cases”).
On March 10, 2017 (the “Confirmation Date”), the Bankruptcy Court confirmed our Reorganization Plan and on March 21, 2017 (the “Effective Date”), the Reorganization Plan became effective and we emerged from bankruptcy.
Plan of Reorganization. Pursuant to the terms of the Reorganization Plan, which was supported by us, certain lenders under our Prior Credit Facility (collectively, the “Lenders”) and certain holders of our Prior Senior Notes (collectively, the “Noteholders”), the following transactions occurred on or around the Effective Date:
|
|
|
|
•
|
We issued 44,982,142 shares of common stock of the reorganized company (“New Common Stock”), which were the result of the transactions described below. We also entered into a stockholders agreement and a Registration Rights Agreement and amended our certificate of incorporation and bylaws for the authorization of the New Common Stock and to provide registration rights thereunder, among other corporate governance actions;
|
|
|
|
|
•
|
Our Predecessor common stock was cancelled, extinguished and discharged and the Predecessor equity holders did not receive any consideration in respect of their equity interests;
|
|
|
|
|
•
|
The $1,267,410 of indebtedness, including accrued interest, attributable to our Prior Senior Notes was exchanged for New Common Stock. In addition, we issued or reserved shares of New Common Stock to be exchanged in settlement of $2,439 of certain general unsecured claims. In aggregate, the shares of New Common Stock issued or to be issued in settlement of the Senior Note and these general unsecured claims represented approximately 90% of outstanding Successor common shares;
|
|
|
|
|
•
|
We completed a rights offering backstopped by certain holders of our Prior Senior Notes (the “Backstop Parties”), which generated $50,031 of gross proceeds. The rights offering resulted in the issuance of New Common Stock, representing approximately nine percent of outstanding Successor common shares, to holders of claims arising under the Prior Senior Notes and to the Backstop Parties;
|
|
|
|
|
•
|
In connection with the rights offering described above, the Backstop Parties received approximately one percent of outstanding Successor common shares as a backstop fee;
|
|
|
|
|
•
|
Additional shares, representing seven percent of outstanding Successor common shares on a fully diluted basis, were authorized for issuance under a new management incentive plan;
|
|
|
|
|
•
|
Warrants to purchase 140,023 shares of New Common Stock were issued to Mr. Mark Fischer, our founder and former Chief Executive Officer (“Mr. Fischer”), with an exercise price of $36.78 per share and expiring on June 30, 2018. The warrants were issued in exchange for consulting services provided by Mr. Fischer;
|
|
|
|
|
•
|
Pursuant to our Reorganization Plan, on January 5, 2017, we entered into the Retirement Agreement and General Release (the “Retirement Agreement”) with Mr. Fischer, whereupon Mr. Fischer terminated his employment with the Company on that date. The Retirement Agreement included severance consisting of cash and certain tangible assets in the amount of $4,038. Mr. Fisher provided consulting services to the Company during the period subsequent to his termination until the Effective Date for which he received the warrants disclosed above. The expense for Mr. Fischer’s severance and consulting services are reflected in “Reorganization items, net” and “General and administrative” expense, respectively, in our consolidated statement of operations during the 2017 Predecessor period. All amounts due to Mr. Fischer pursuant to the Retirement Agreement were paid as of December 31, 2017.
|
|
|
|
|
•
|
Our Prior Credit Facility, previously consisting of a senior secured revolving credit facility was restructured into an Exit Credit Facility consisting of a first-out revolving facility (“Exit Revolver”) and a second-out term loan (“Exit Term Loan”). On the Effective Date, the entire balance on the Prior Credit Facility in the amount of $444,440 was repaid while we received gross proceeds representing the opening balances on our Exit Revolver of $120,000 and an Exit Term Loan of $150,000. For more information refer to “Note 8: Debt;”
|
|
|
|
|
•
|
We paid $6,954 for creditor-related professional fees and also funded a $11,000 segregated account for debtor-related professional fees in connection with the reorganization related transactions above;
|
|
|
|
|
•
|
Certain other priority or convenience class claims were paid in full in cash, reinstated or otherwise treated in a manner acceptable to the creditor claimholders;
|
|
|
|
|
•
|
Plaintiffs to one of our royalty owner litigation cases, which were identified as a separate class of creditors (Class 8) in our bankruptcy case, rejected the Reorganization Plan. If the claimants under Class 8 are permitted to file a class of proof claim on
|
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
behalf of the putative class, certified on a class basis, and the plaintiffs ultimately prevail on the merits of their claims, any liability arising under judgement or settlement of the claims that relate to the pre-petition period would be satisfied through issuance of Successor common shares.
Liabilities subject to compromise. In accordance with ASC Topic 852, Reorganizations (“ASC 852”), our financial statements include amounts classified as liabilities subject to compromise which represent estimates of pre-petition obligations that were allowed as claims in our bankruptcy case. These liabilities are reported at the amounts allowed by the Bankruptcy Court, even if they may be settled for lesser amounts. The amounts disclosed below as of March 21, 2017, reflect the liabilities immediately prior to our Reorganization Plan becoming effective. As part of the Reorganization Plan, the Bankruptcy Court approved the settlement of these claims and they were subsequently settled in cash or equity, reinstated or otherwise reserved for at emergence.
|
|
|
|
|
|
|
|
|
|
|
Predecessor
|
|
|
|
March 21, 2017
|
|
Accounts payable and accrued liabilities
|
|
$
|
6,687
|
|
|
Accrued payroll and benefits payable
|
|
3,949
|
|
|
Revenue distribution payable
|
|
3,050
|
|
|
Prior Senior Notes and associated accrued interest
|
|
1,267,410
|
|
|
Liabilities subject to compromise
|
|
$
|
1,281,096
|
|
Note 4: Fresh start accounting
Upon emergence from bankruptcy, we qualified for and applied fresh start accounting to our financial statements in accordance with the provisions set forth in ASC 852 as (i) the holders of existing voting shares of the Company prior to its emergence received less than 50% of the voting shares of the Company outstanding following its emergence from bankruptcy and (ii) the reorganization value of our assets immediately prior to confirmation of the Reorganization Plan was less than the post-petition liabilities and allowed claims.
Adopting fresh start accounting results in a new reporting entity for financial reporting purposes with no beginning retained earnings or deficit. The cancellation of all existing shares outstanding on the Effective Date and issuance of new shares in the reorganized Company caused a related change of control under U.S. GAAP. As a result of the application of fresh start accounting, as well as the effects of the implementation of the Reorganization Plan, the Predecessor and Successor periods may lack comparability, as required in ASC Topic 205, Presentation of Financial Statements (“ASC 205”). ASC 205 states that financial statements are required to be presented comparably from year to year, with any exceptions to comparability clearly disclosed. Therefore, “black-line” financial statements are presented to distinguish between the Predecessor and Successor periods.
Enterprise Value and Reorganization Value
Reorganization value represents the fair value of the Company’s total assets prior to the consideration of liabilities and is intended to approximate the amount a willing buyer would pay for the Company’s assets immediately after restructuring. The reorganization value was allocated to the Company’s individual assets based on their estimated fair values.
The Company’s reorganization value was derived from enterprise value. Enterprise value represents the estimated fair value of an entity’s long-term debt and equity. The enterprise value of the Company on the Effective Date, as approved by the Bankruptcy Court in support of the Plan, was estimated to be within a range of $1,050,000 to $1,350,000 with a mid-point value of $1,200,000. Based upon the various estimates and assumptions necessary for fresh start accounting, as further discussed below, the estimated enterprise value was determined to be $1,200,000 before consideration of cash and cash equivalents and outstanding debt at the Effective Date.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
The following table reconciles the enterprise value to the estimated fair value of the Successor’s common stock as of the Effective Date:
|
|
|
|
|
|
|
|
Enterprise value
|
$
|
1,200,000
|
|
|
Plus: cash and cash equivalents
|
45,123
|
|
|
Less: fair value of outstanding debt
|
(296,061
|
)
|
|
Less: fair value of warrants (consideration for previously accrued consulting fees)
|
(118
|
)
|
|
Fair value of Successor common stock on the Effective Date
|
$
|
948,944
|
|
|
Total shares issued under the Reorganization Plan
|
44,982,142
|
|
|
Per share value (1)
|
$
|
21.10
|
|
____________________________________________________________
|
|
|
|
(1)
|
The per share value shown above is calculated based upon the financial information determined using US GAAP at the Effective Date.
|
The following table reconciles the enterprise value to the estimated reorganization value of the Successor’s assets as of the Effective Date:
|
|
|
|
|
|
|
|
Enterprise value
|
$
|
1,200,000
|
|
|
Plus: cash and cash equivalents
|
45,123
|
|
|
Plus: current liabilities
|
82,254
|
|
|
Plus: noncurrent liabilities excluding long-term debt
|
64,735
|
|
|
Reorganization value of Successor assets
|
$
|
1,392,112
|
|
Valuation of oil and gas properties
The Company’s principal assets are its oil and gas properties, which are accounted for under the full cost method of accounting. The oil and gas properties include proved reserves and unevaluated leasehold acreage. With the assistance of valuation consultants, the Company estimated the fair value of its oil and gas properties based on the discounted cash flows expected to be generated from these assets. The computations were based on market conditions and reserves in place as of the Effective Date.
The fair value analysis was based on the Company’s estimates of proved, probable and possible reserves developed internally by the Company’s reservoir engineers. Discounted cash flow models were prepared using the estimated future revenues and development and operating costs for all developed wells and undeveloped locations comprising the proved, probable and possible reserves. The value estimated for probable and possible reserves was utilized as an estimate of the fair value of the Company’s unevaluated leasehold acreage, which was further corroborated against comparable market transactions. Future revenues were based upon the forward NYMEX strip for oil and natural gas prices as of the Effective Date, adjusted for differentials realized by the Company. Development and operating cost estimates for the oil and gas properties were adjusted for inflation. The after-tax cash flows were discounted to the Effective Date at discount rate of 8.5%. This discount rate was derived from a weighted average cost of capital computation that utilized a blended expected cost of debt and expected return on equity for similar industry participants. Risk adjustment factors were applied to the values derived for the proved non-producing, proved undeveloped, probable and possible reserve categories based on consideration of the risks associated with geology, drilling success rates, development costs and the timing of development and extraction. The discounted cash flow models also included depletion, depreciation and income tax expense associated with an after-tax valuation analysis.
From this analysis the Company estimated the fair value of its proved reserves and undeveloped leasehold acreage to be $604,065 and $585,574, respectively, as of the Effective Date. These amounts are reflected in the Fresh Start Adjustments item (i) below.
Other valuations
Our adoption of fresh start accounting also required adjustments to certain other assets and liabilities on our balance sheet including property and equipment, other assets and asset retirement obligations.
Property and equipment — consists of real property which includes our headquarters, field offices and pasture land, and personal property which includes vehicles, machinery and equipment, office equipment and fixtures and a natural gas pipeline. These assets were valued using a combination of cost, income and market approaches with the exception of pasture land where we relied on government data to determine fair value.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
Other assets — includes, among others, an equity investment in a company that operates ethanol plants. The equity investment was valued utilizing a combination of the market approaches such as the guideline public company method and the similar transactions method. This equity investment was sold in June 2017.
Asset retirement obligations — our fresh start updates to these obligations included application of the Successor’s credit adjusted risk free rate, which now incorporates a term structure based on the estimated timing of plugging activity and resetting all obligations to a single layer.
Consolidated balance sheet
The following consolidated balance sheet is as of March 21, 2017. This consolidated balance sheet includes adjustments that reflect the consummation of the transactions contemplated by the Reorganization Plan (reflected in the column “Reorganization Adjustments”) as well as fair value adjustments as a result of the adoption of fresh start accounting (reflected in the column “Fresh Start Adjustments”) as of the Effective Date:
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor
|
|
Reorganization
Adjustments
|
|
|
|
Fresh Start
Adjustments
|
|
|
|
Successor
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
180,456
|
|
|
$
|
(135,333
|
)
|
|
(a)
|
|
$
|
—
|
|
|
|
|
$
|
45,123
|
|
|
Accounts receivable, net
|
|
46,837
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
46,837
|
|
|
Inventories, net
|
|
6,885
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
6,885
|
|
|
Prepaid expenses
|
|
4,933
|
|
|
(535
|
)
|
|
(b)
|
|
—
|
|
|
|
|
4,398
|
|
|
Derivative instruments
|
|
19,058
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
19,058
|
|
|
Total current assets
|
|
258,169
|
|
|
(135,868
|
)
|
|
|
|
—
|
|
|
|
|
122,301
|
|
|
Property and equipment
|
|
38,391
|
|
|
—
|
|
|
|
|
18,987
|
|
|
(i)
|
|
57,378
|
|
|
Oil and natural gas properties, using the full cost method:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
|
|
4,355,576
|
|
|
—
|
|
|
|
|
(3,751,511
|
)
|
|
(i)
|
|
604,065
|
|
|
Unevaluated (excluded from the amortization base)
|
|
26,039
|
|
|
—
|
|
|
|
|
559,535
|
|
|
(i)
|
|
585,574
|
|
|
Accumulated depreciation, depletion, amortization and impairment
|
|
(3,811,326
|
)
|
|
—
|
|
|
|
|
3,811,326
|
|
|
(i)
|
|
—
|
|
|
Total oil and natural gas properties
|
|
570,289
|
|
|
—
|
|
|
|
|
619,350
|
|
|
(i)
|
|
1,189,639
|
|
|
Derivative instruments
|
|
14,295
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
14,295
|
|
|
Other assets
|
|
5,499
|
|
|
2,410
|
|
|
(c)
|
|
590
|
|
|
(i)
|
|
8,499
|
|
|
Total assets
|
|
$
|
886,643
|
|
|
$
|
(133,458
|
)
|
|
|
|
$
|
638,927
|
|
|
|
|
$
|
1,392,112
|
|
|
Liabilities and stockholders’ equity (deficit)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable and accrued liabilities
|
|
$
|
64,413
|
|
|
$
|
(2,737
|
)
|
|
(a)(d)
|
|
$
|
—
|
|
|
|
|
$
|
61,676
|
|
|
Accrued payroll and benefits payable
|
|
7,366
|
|
|
2,186
|
|
|
(d)
|
|
—
|
|
|
|
|
9,552
|
|
|
Accrued interest payable
|
|
2,095
|
|
|
(2,095
|
)
|
|
(a)
|
|
—
|
|
|
|
|
—
|
|
|
Revenue distribution payable
|
|
7,975
|
|
|
3,050
|
|
|
(d)
|
|
—
|
|
|
|
|
11,025
|
|
|
Long-term debt and capital leases, classified as current
|
|
468,814
|
|
|
(464,182
|
)
|
|
(e)
|
|
—
|
|
|
|
|
4,632
|
|
|
Total current liabilities
|
|
550,663
|
|
|
(463,778
|
)
|
|
|
|
—
|
|
|
|
|
86,885
|
|
|
Long-term debt and capital leases, less current maturities
|
|
—
|
|
|
291,429
|
|
|
(f)
|
|
—
|
|
|
|
|
291,429
|
|
|
Deferred compensation
|
|
—
|
|
|
519
|
|
|
(d)
|
|
—
|
|
|
|
|
519
|
|
|
Asset retirement obligations
|
|
66,973
|
|
|
—
|
|
|
|
|
(2,757
|
)
|
|
(i)
|
|
64,216
|
|
|
Liabilities subject to compromise
|
|
1,281,096
|
|
|
(1,281,096
|
)
|
|
(d)
|
|
—
|
|
|
|
|
—
|
|
|
Commitments and contingencies
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders’ (deficit) equity:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor common stock
|
|
14
|
|
|
(14
|
)
|
|
(g)
|
|
—
|
|
|
|
|
—
|
|
|
Predecessor additional paid in capital
|
|
425,425
|
|
|
(425,425
|
)
|
|
(g)
|
|
—
|
|
|
|
|
—
|
|
|
Successor common stock
|
|
—
|
|
|
450
|
|
|
(g)
|
|
—
|
|
|
|
|
450
|
|
|
Successor additional paid in capital
|
|
—
|
|
|
948,613
|
|
|
(g)
|
|
—
|
|
|
|
|
948,613
|
|
|
(Accumulated deficit) retained earnings
|
|
(1,437,528
|
)
|
|
795,844
|
|
|
(h)
|
|
641,684
|
|
|
(j)
|
|
—
|
|
|
Total stockholders’ (deficit) equity
|
|
(1,012,089
|
)
|
|
1,319,468
|
|
|
|
|
641,684
|
|
|
|
|
949,063
|
|
|
Total liabilities and stockholders’ equity (deficit)
|
|
$
|
886,643
|
|
|
$
|
(133,458
|
)
|
|
|
|
$
|
638,927
|
|
|
|
|
$
|
1,392,112
|
|
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
Reorganization adjustments
|
|
|
|
(a)
|
Adjustments reflect the following net cash payments recorded as of the Effective Date from implementation of the Plan:
|
|
|
|
|
|
|
|
|
Cash proceeds from rights offering
|
$
|
50,031
|
|
|
Cash proceeds from Exit Term Loan
|
150,000
|
|
|
Cash proceeds from Exit Revolver
|
120,000
|
|
|
Fees paid to lender for Exit Term Loan
|
(750
|
)
|
|
Fees paid to lender for Exit Revolver
|
(1,125
|
)
|
|
Payment in full to extinguish Prior Credit Facility
|
(444,440
|
)
|
|
Payment of accrued interest on Prior Credit Facility
|
(2,095
|
)
|
|
Payment of previously accrued creditor-related professional fees
|
(6,954
|
)
|
|
Net cash used
|
$
|
(135,333
|
)
|
|
|
|
|
(b)
|
Reclassification of previously prepaid professional fees to debt issuance costs associated with the Exit Credit Facility.
|
|
|
|
|
(c)
|
Reflects issuance costs related to the Exit Credit Facility:
|
|
|
|
|
|
|
|
|
Fees paid to lender for Exit Term Loan
|
$
|
750
|
|
|
Fees paid to lender for Exit Revolver
|
1,125
|
|
|
Professional fees related to debt issuance costs on the Exit Credit Facility
|
535
|
|
|
Total issuance costs on Exit Credit Facility
|
$
|
2,410
|
|
|
|
|
|
(d)
|
As part of the Plan, the Bankruptcy Court approved the settlement of certain allowable claims, reported as liabilities subject to compromise in the Company’s historical consolidated balance sheet. As a result, a gain was recognized on the settlement of liabilities subject to compromise calculated as follows:
|
|
|
|
|
|
|
|
|
Prior Senior Notes including interest
|
$
|
1,267,410
|
|
|
Accounts payable and accrued liabilities
|
6,687
|
|
|
Accrued payroll and benefits payable
|
3,949
|
|
|
Revenue distribution payable
|
3,050
|
|
|
Total liabilities subject to compromise
|
1,281,096
|
|
|
Amounts settled in cash, reinstated or otherwise reserved at emergence
|
(10,089
|
)
|
|
Fair value of equity issued in settlement of Prior Senior Notes and certain general unsecured creditors
|
(898,914
|
)
|
|
Gain on settlement of liabilities subject to compromise
|
$
|
372,093
|
|
|
|
|
|
(e)
|
Reflects extinguishment of Prior Credit Facility along with associated unamortized issuance costs, establishment of Exit Credit Facility and adjustments to reclassify existing debt back to their scheduled maturities:
|
|
|
|
|
|
|
|
|
Reclassification from current to noncurrent, based on scheduled repayment, of debt no longer in default
|
$
|
(22,612
|
)
|
|
Establishment of Exit Term Loan - current portion
|
1,183
|
|
|
Payment in full to extinguish Prior Credit Facility
|
(444,440
|
)
|
|
Write-off unamortized issuance costs associated with Prior Credit Facility
|
1,687
|
|
|
|
$
|
(464,182
|
)
|
|
|
|
|
(f)
|
Reflects establishment of our Exit Credit Facility pursuant to our Reorganization Plan, net of issuance costs, as well as adjustments to reclassify existing debt back to their scheduled maturities:
|
|
|
|
|
|
|
|
|
Origination of the Exit Term Loan, net of current portion
|
$
|
148,817
|
|
|
Origination of the Exit Revolver
|
120,000
|
|
|
Reclassification from current to noncurrent, based on scheduled repayment, of debt no longer in default
|
22,612
|
|
|
|
$
|
291,429
|
|
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
|
|
|
|
(g)
|
Adjustment represents (i) the cancellation of Predecessor equity on the Effective Date, (ii) the issuance of 44,982,142 shares of Successor common stock on the Effective Date and (iii) the issuance of 140,023 warrants on the Effective Date (see “Note 3: Chapter 11 reorganization”)
|
|
|
|
|
|
|
|
|
Cancellation of predecessor equity - par value
|
$
|
(14
|
)
|
|
Cancellation of predecessor equity - paid in capital
|
(425,425
|
)
|
|
Issuance of successor common stock in settlement of claims
|
898,914
|
|
|
Issuance of successor common stock under rights offering
|
50,031
|
|
|
Issuance of warrants
|
118
|
|
|
Net impact to common stock-par and additional paid in capital
|
$
|
523,624
|
|
|
|
|
|
(h)
|
Reflects the cumulative impact of the following reorganization adjustments:
|
|
|
|
|
|
|
|
|
Gain on settlement of liabilities subject to compromise
|
$
|
372,093
|
|
|
Cancellation of predecessor equity
|
425,438
|
|
|
Write-off unamortized issuance costs associated with Prior Credit Facility
|
(1,687
|
)
|
|
Net impact to retained earnings
|
$
|
795,844
|
|
Fresh start adjustments
|
|
|
|
(i)
|
Represents fresh start accounting adjustments primarily to (i) remove accumulated depreciation, depletion, amortization and impairment, (ii) increase the value of proved oil and gas properties, (iii) increase the value of unevaluated oil and gas properties primarily to capture the value of our acreage in the STACK, (iv) increase other property and equipment primarily due to increases to land, vehicles, machinery and equipment and (v) decrease asset retirement obligations. These fair value measurements giving rise to these adjustments are primarily based on Level 3 inputs under the fair value hierarchy (See “Note 10: Fair value measurements”).
|
|
|
|
|
(j)
|
Reflects the cumulative impact of the fresh start adjustments discussed herein.
|
Reorganization items
We use this category to reflect, where applicable, post-petition revenues, expenses, gains and losses that are direct and incremental as a result of the reorganization of the business. Reorganization items are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
|
|
|
|
|
Period from
|
|
|
Period from
|
|
|
|
|
|
|
|
March 22, 2017
|
|
|
January 1, 2017
|
|
|
|
For the Year Ended December 31,
|
|
through
|
|
|
through
|
|
|
|
2019
|
|
2018
|
|
December 31, 2017
|
|
|
March 21, 2017
|
|
Loss (gain) on the settlement of liabilities subject to compromise
|
|
$
|
—
|
|
|
$
|
48
|
|
|
$
|
—
|
|
|
|
$
|
(372,093
|
)
|
|
Fresh start accounting adjustments
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
(641,684
|
)
|
|
Professional fees
|
|
1,753
|
|
|
2,344
|
|
|
3,091
|
|
|
|
18,790
|
|
|
Rejection of employment contracts
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
4,573
|
|
|
Write off unamortized issuance costs on Prior Credit Facility
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
1,687
|
|
|
Total reorganization items
|
|
$
|
1,753
|
|
|
$
|
2,392
|
|
|
$
|
3,091
|
|
|
|
$
|
(988,727
|
)
|
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
Note 5: Supplemental disclosures to the consolidated statements of cash flows
Supplemental disclosures to the consolidated statements of cash flows are presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
|
|
|
|
|
Period from
|
|
|
Period from
|
|
|
|
|
|
|
|
March 22, 2017
|
|
|
January 1, 2017
|
|
|
|
For the Year Ended December 31,
|
|
through
|
|
|
through
|
|
|
|
2019
|
|
2018
|
|
December 31, 2017
|
|
|
March 21, 2017
|
|
Net cash provided by operating activities included:
|
|
|
|
|
|
|
|
|
|
|
|
Cash payments for interest
|
|
$
|
32,465
|
|
|
$
|
6,266
|
|
|
$
|
17,195
|
|
|
|
$
|
4,105
|
|
|
Interest capitalized
|
|
(11,796
|
)
|
|
(10,925
|
)
|
|
(2,142
|
)
|
|
|
(248
|
)
|
|
Cash payments for income taxes
|
|
—
|
|
|
—
|
|
|
150
|
|
|
|
—
|
|
|
Cash payments for reorganization items
|
|
1,395
|
|
|
2,506
|
|
|
18,006
|
|
|
|
11,405
|
|
|
Non-cash investing activities included:
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligation additions and revisions
|
|
836
|
|
|
3,141
|
|
|
6,746
|
|
|
|
716
|
|
|
Oil and gas leasehold exchanges
|
|
1,399
|
|
|
10,913
|
|
|
816
|
|
|
|
—
|
|
|
Change in accrued oil and gas capital expenditures
|
|
3,630
|
|
|
6,559
|
|
|
9,534
|
|
|
|
5,387
|
|
|
Non-cash financing activities included:
|
|
|
|
|
|
|
|
|
|
|
Discharge of financing lease obligations (See Note 17)
|
|
9,832
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
Note 6: Acquisitions and divestitures
2019 Acquisitions and divestitures
For 2019, we did not enter into any material divestitures of oil and gas assets. During the year, we incurred $23,107 in acquisition costs, which consisted primarily of leasing and pooling of acreage and capitalized interest.
2018 Acquisitions and divestitures
For 2018, we received total cash proceeds of $50,523 on various non-core oil and gas assets, property and equipment disposals. Included in these disposals were:
|
|
|
|
•
|
A divestiture of certain properties in the Oklahoma/Texas Panhandle for gross cash proceeds before selling costs of $17,000 and the conveyance of $629 in liabilities to the buyer, all of which are subject to customary post-close adjustments. The purchaser of these assets is a company affiliated with Mark A. Fischer, our former Chief Executive Officer and former Chairman of the Board.
|
|
|
|
|
•
|
A divestiture of certain saltwater disposal infrastructure where we received proceeds of $11,841. In conjunction with this divestiture, we entered into a service agreement for salt water disposal with the purchaser of these assets, as discussed further below.
|
|
|
|
|
•
|
Disposals of various other non-core assets resulting in proceeds of approximately $22,637.
|
As the properties above did not represent a material portion of our oil and natural gas reserves, individually or in the aggregate, no gain or loss was recognized on these disposals and instead, we reduced our full cost pool by the amount of the net proceeds without significant alteration to our depletion rate.
In conjunction with our divestiture of saltwater disposal infrastructure discussed above, we entered into service agreements with two providers to dispose, via pipeline or truck, salt water produced by our wells within areas that encompass Kingfisher, Garfield and Canadian Counties, Oklahoma. The agreements covering Kingfisher and Garfield Counties, Oklahoma are for 15 years and specify fixed rates per barrel according to age of the well. The agreement covering Canadian County, Oklahoma is for 5 years and specifies per barrel rates that vary according to volume of water disposed.
During 2018, we incurred acquisition costs of $122,309. The amount includes costs to acquire approximately 24,600 acres of leasehold, capitalized interest of $10,925 and $10,913 in non-monetary acreage trades.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
2017 Acquisitions and divestitures
In November 2017, we closed on the sale of our EOR assets along with some minor assets within geographic proximity for cash proceeds, net of preliminary post-closing adjustments, of $163,630 plus certain contingent payments through December 2020. As these properties represented a material portion of our oil and natural gas reserves and our assessment indicated that our depletion rate would be significantly altered subsequent to the sale, in accordance with the full cost method of accounting for conveyances, we recognized a loss of $25,163 on the sale. The loss is recognized in “Loss (gain) on sale of assets” in the consolidated statements of operations.
In December 2017, we closed on the sale of certain producing properties located in Osage County, Oklahoma, for proceeds, net of preliminary post-closing adjustments, of $14,117. In addition, we had various other divestitures of non-core oil and gas properties throughout the year ended December 31, 2017 resulting in proceeds of approximately $9,200. Other than our EOR asset sale, these transactions did not individually, or in the aggregate, represent a material portion of our oil and natural gas reserves and therefore we did not record any gain or loss on the sale and instead, reduced our full cost pool by the amount of the net proceeds.
In December 2017, we entered into purchase and sale agreements to acquire acreage in the STACK play in Kingfisher County, Oklahoma. In early January 2018, immediately prior to closing the purchase, we amended the transaction to include additional acreage. The final purchase closed for $60,643 encompassing 7,000 acres. Under the terms of the agreements, the Company is required 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. Taking into account current commodity price conditions, the company does not intend to drill wells on the subject acreage in 2020 as it focuses on higher return opportunities. 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.
Note 7: Property and equipment
Major classes of property and equipment are shown in the following table. As discussed in “Note 4: Fresh start accounting,” the application of fresh start accounting to our balance sheet on March 21, 2017, resulted in restating our property and equipment to fair value, thus resetting the accumulated depreciation and amortization balance. Property acquired since that date is capitalized and stated at cost. Maintenance and repairs are expensed currently.
Depreciation and amortization are provided in amounts sufficient to relate the cost of depreciable assets to operations over their estimated service lives using the straight-line method. Estimated useful lives of our assets are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Useful Life
|
|
December 31,
2019
|
|
December 31,
2018
|
|
Furniture and fixtures
|
10
|
|
$
|
8
|
|
|
$
|
520
|
|
|
Automobiles and trucks
|
5
|
|
3,071
|
|
|
3,548
|
|
|
Machinery and equipment
|
10 — 20 years
|
|
3,543
|
|
|
21,482
|
|
|
Office and computer equipment
|
5 — 10 years
|
|
3,363
|
|
|
6,183
|
|
|
Building and improvements
|
10 — 40 years
|
|
693
|
|
|
18,693
|
|
|
|
|
|
10,678
|
|
|
50,426
|
|
|
Less accumulated depreciation and amortization
|
|
|
3,459
|
|
|
12,449
|
|
|
|
|
|
7,219
|
|
|
37,977
|
|
|
Land
|
|
|
1,998
|
|
|
5,119
|
|
|
|
|
|
$
|
9,217
|
|
|
$
|
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.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
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 early payoff of the note, 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 17: Leases.”
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. As a result of determining fair value on the assets held for sale, an impairment loss was recorded for the year ended December 31, 2019 in the amount of $781, which was included in the “Impairment of other assets” in the Statements of Operations. Our held for sale assets as of December 31, 2019 consisted of:
|
|
|
|
|
|
|
|
|
|
|
Carrying value at
|
|
|
|
December 31, 2019
|
|
Equipment
|
|
$
|
1,572
|
|
|
Vehicles
|
|
488
|
|
|
Real estate
|
|
800
|
|
|
Total held for sale
|
|
$
|
2,860
|
|
Leased compressors. 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. In September 2019, U.S. Bank, the originating lessor, entered into agreements with the Sublessee that resulted in the discharge of all our obligations with respect to these compressor leases and the removal of those assets and elimination of associated debt from our consolidated balance sheet.
Note 8: Debt
As of the dates indicated, long-term debt and financing leases consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
2019
|
|
December 31,
2018
|
|
Credit facility
|
|
$
|
130,000
|
|
|
$
|
—
|
|
|
Senior Notes
|
|
300,000
|
|
|
300,000
|
|
|
Real estate mortgage notes, principal and interest payable monthly, bearing interest at 5.50%, due December 2028; collateralized by real property
|
|
—
|
|
|
8,588
|
|
|
Installment notes payable, principal and interest payable monthly collateralized by personal property
|
|
371
|
|
|
354
|
|
|
Financing lease obligations
|
|
1,653
|
|
|
11,677
|
|
|
Unamortized issuance costs
|
|
(10,038
|
)
|
|
(13,148
|
)
|
|
Total debt, net
|
|
421,986
|
|
|
307,471
|
|
|
Less current portion
|
|
594
|
|
|
12,371
|
|
|
Total long-term debt, net
|
|
$
|
421,392
|
|
|
$
|
295,100
|
|
Maturities of long-term debt and capital leases, excluding unamortized debt issuance costs, are as follows as of December 31, 2019:
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
|
|
|
|
|
|
|
|
2020
|
$
|
594
|
|
|
2021
|
540
|
|
|
2022
|
130,577
|
|
|
2023
|
300,260
|
|
|
2024
|
53
|
|
|
2025 and thereafter
|
—
|
|
|
|
$
|
432,024
|
|
As discussed in “Note 7: Property and equipment,” upon the divestiture of our headquarters building in August 2019, we utilized the sale proceeds to pay off the outstanding balance of our real estate mortgage note which was $8,176 at the time of the repayment.
Our financing lease obligations as of December 31, 2018, included leases on CO2 compressors that were subleased to the buyer of our former EOR oil and natural gas properties. In August 2019, U.S. Bank entered into agreements with the Sublessee that resulted in the discharge of all our obligations with respect to these compressor leases and the removal of the associated debt from our consolidated balance sheet in the amount of $9,832. Our remaining finance leases consist primarily of leases on our fleet vehicles.
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 facility collateralized by our oil and natural gas properties and is scheduled to mature on December 21, 2022. Availability under our Credit Agreement 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 May 1 and November 1 of each year. In addition, the lenders may request a borrowing base redetermination once between each scheduled redetermination or upon the occurrence of certain specified events. The banks establish a borrowing base by making an estimate of the collateral value of our oil and natural gas properties. If oil and natural gas prices decrease from the amounts used in estimating the collateral value of our oil and natural gas properties, the borrowing base may be reduced, thus reducing funds available under the borrowing base. Our borrowing base under the Credit Agreement as of December 31, 2019, was $325,000 while the unused portion on that date was $195,000.
Interest on the outstanding amounts under the credit facility will accrue at an interest rate equal to either (i) the Alternate Base Rate (as defined in the Credit Agreement) plus an Applicable Margin (as defined in the Credit Agreement) that ranges between 1.00% to 2.00% depending on utilization or (ii) the Adjusted LIBO Rate (as defined in the Credit Agreement) applicable to one, two, three, or six month borrowings plus an Applicable Margin that ranges between 2.00% to 3.00% depending on utilization. In the case that an Event of Default (as defined under the Credit Agreement) occurs, the outstanding amounts will bear an additional 2.00% interest plus the applicable Alternate Base Rate or Adjusted LIBO Rate and corresponding Applicable Margin.
As of December 31, 2019, 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 4.03% on the amount outstanding.
Commitment fees that range between 0.375% and 0.500%, depending on utilization, accrue on the average daily amount of the unused portion of the borrowing base and are included as a component of interest expense. We generally have the right to make prepayments of the borrowings at any time without penalty or premium. Letter of credit fees will accrue at 0.125% plus the Applicable Margin used to determine the interest rate applicable to borrowings that are based on Adjusted LIBO Rate.
If the outstanding borrowings under our Credit Agreement were to exceed the borrowing base as a result of a redetermination, we would be required to eliminate this deficiency. Within 10 days after receiving notice of the new borrowing base, we would be required to make an election: (1) to repay the deficiency in a lump sum within 45 days, (2) commencing within 30 days to repay the deficiency in equal monthly installments over a six months period, (3) to submit within 45 days additional oil and gas properties we own for consideration in connection with the determination of the borrowing base sufficient to eliminate the deficiency or (4) any combination of repayment as provided in the preceding three elections.
On May 2, 2019, we entered into the Third Amendment (the “Third Amendment”) to the Credit Agreement. The Third Amendment, which was effective March 31, 2019, among other things, (i) reaffirmed the borrowing base at $325,000 and (ii) amended the definition of EBITDAX to add back certain severance and retirement payments, consulting fees, and related charges paid
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
or incurred in connection with any retirement, severance or departure of officers or former officers in an aggregate amount not to exceed $4,000.
On September 27, 2019, we entered into the Fourth Amendment (the “Fourth Amendment”) to the Credit Agreement. The Fourth Amendment, among other things, (i) reaffirmed the borrowing base at $325,000; (ii) amended the definition of EBITDAX to, among other things, (a) added back losses related to or resulting from the full or partial extinguishment of debt, (b) expanded the add-back of amounts associated with retirements, severance or departure to apply to all employees or former employees, and (c) clarified that gains related to or resulting from the full or partial extinguishment of debt are excluded; and (iii) revised certain negative covenants to provide that the Company, under certain circumstances, may prepay or otherwise redeem certain Permitted Senior Additional Debt (as defined in the Credit Agreement) in an aggregate amount not to exceed $30,000.
Other Provisions
Interest payment dates are dependent on the type of borrowing. In the case of Alternate Base Rate loans, interest is payable quarterly in arrears. In the case of Adjusted LIBO Rate borrowings, interest is payable on the last day of each relevant interest period and, in the case of any interest period longer than three months, on each successive date three months after the first day of such interest period.
The Credit Agreement contains covenants and events of default customary for oil and natural gas reserve-based lending facilities including restrictions on additional debt, guarantees, liens, restricted payments, investments and hedging activity. Additionally, our Credit Agreement specifies events of default, including non-payment, breach of warranty, non-performance of covenants, default on other indebtedness or swap agreements, restrictions on paying dividends, certain adverse judgments, bankruptcy events and change of control, among others.
The financial covenants require, for each fiscal quarter, that 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 December 31, 2019.
The Credit Agreement is guaranteed by all of our wholly owned subsidiaries, subject to customary exceptions, and is secured by first priority security interests on substantially all of our assets.
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 of the Securities Act of 1933, as amended. The offering costs were $7,337 resulting in net proceeds of $292,663, which we used to repay the outstanding balance on our credit facility at that time and for general corporate purposes.
The Senior Notes bear interest at a rate of 8.75% per year beginning June 29, 2018 (payable semi-annually in arrears on January 15 and July 15 of each year, beginning on January 15, 2019) and will mature on July 15, 2023.
The Senior Notes are the Company’s senior unsecured obligations and rank equal in right of payment with all of the Company’s existing and future senior indebtedness, senior to all of the Company’s existing and future subordinated indebtedness and effectively subordinated to all of the Company’s existing and future secured indebtedness, to the extent of the value of the collateral securing such indebtedness.
The Indenture for our Senior Notes contains certain covenants, which limit our ability to:
•incur additional indebtedness or issue certain preferred stock;
•pay dividends or repurchase or redeem capital stock;
•make certain investments;
•incur certain liens;
•enter into certain types of transactions with affiliates;
•sell assets;
•enter into agreements restricting our ability to pay dividends or make other payments;
•consolidate, merge, sell, or otherwise dispose of all or substantially all of our assets; and
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
•create unrestricted subsidiaries.
These limitations are subject to a number of important qualifications and exceptions.
Prior to July 15, 2020, the Company may, at its option, redeem all or, from time to time, a part of the Senior Notes at a redemption price equal to 100% of the principal amount thereof, plus an applicable make-whole premium and accrued and unpaid interest, if any, to the date of redemption. On or after July 15, 2020, the Company may, at its option, redeem all or, from time to time, a part of the Senior Notes at a redemption price equal to 100% of the principal amount thereof, plus a premium declining ratably to par and accrued and unpaid interest, if any, to the date of redemption.
Prior to July 15, 2020, the Company, at its option, may redeem up to 35% of the aggregate principal amount of the Senior Notes with proceeds of one or more qualified equity offerings at a redemption price of 108.75% of the principal amount of the Senior Notes redeemed, plus accrued and unpaid interest, if any, and liquidated damages provided that:
|
|
|
|
1.
|
at least 60% of the aggregate principal amount of the Senior Notes issued under the Indenture remains outstanding after each such redemption; and
|
|
|
|
|
2.
|
such redemption occurs within 180 days after the closing of any such qualified equity offering
|
Upon an Event of Default (as defined in the Indenture), the trustee under the Indenture or the holders of at least 25% in aggregate principal amount of the outstanding Senior Notes may declare the entire principal of, premium, if any, and accrued and unpaid interest, if any, on all the Senior Notes to be due and payable immediately.
If the Company experiences certain kinds of changes of control, holders of the Senior Notes will be entitled to require the Company to purchase all or a portion of the Senior Notes at 101% of their principal amount, plus accrued and unpaid interest.
Chaparral Energy, Inc. is a holding company and owns no operating assets and has no significant operations independent of its subsidiaries. Our obligations under our outstanding Senior Notes have been fully and unconditionally guaranteed, on a joint and several basis, by all of our wholly owned subsidiaries.
Interest expense during bankruptcy. Pursuant to accounting guidance, while in bankruptcy, we did not accrue interest expense on our Prior Senior Notes during the pendency of the Chapter 11 Cases as we did not expect to pay such interest. As a result, reported interest expense was $22,582 lower than contractual interest for the Predecessor periods of January 1, 2017 to March 21, 2017.
Note 9: Derivative instruments
Overview
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, which in the past have included commodity price swaps, collars, put options and basis protection swaps. During 2018, we also entered into additional derivative contracts to hedge our exposure to the WTI NYMEX calendar month average roll (“oil roll”), which is a contractual component of our crude oil sales prices.
As of December 31, 2019, our derivatives consisted of commodity price swaps (including basis and oil roll) and collars. See “Note 1: Nature of operations and summary of significant accounting policies” for additional information regarding our accounting policies for derivative transactions.
Commodity price swaps allow us to receive a fixed price for the hedged commodity and pay a floating market price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.
Collars contain a fixed floor price (purchased put) and ceiling price (sold call). If the market price exceeds the call strike price or falls below the put strike price, we receive the fixed price and pay the market price. If the market price is between the call and the put strike price, no payments are due from either party.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
The following table summarizes our crude oil derivatives outstanding as of December 31, 2019:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume
|
|
Weighted average fixed price per Bbl
|
|
Period and type of contract
|
|
MBbls
|
|
Swaps
|
|
Purchase puts
|
|
Sold calls
|
|
2020
|
|
|
|
|
|
|
|
|
|
|
|
Oil swaps
|
|
2,274
|
|
|
$
|
51.01
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Oil collars
|
|
195
|
|
|
$
|
—
|
|
|
$
|
55.00
|
|
|
$
|
66.42
|
|
|
Oil roll swaps
|
|
410
|
|
|
$
|
0.38
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
2021
|
|
|
|
|
|
|
|
|
|
Oil swaps
|
|
689
|
|
|
$
|
46.24
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Oil roll swaps
|
|
150
|
|
|
$
|
0.30
|
|
|
$
|
—
|
|
|
$
|
—
|
|
The following table summarizes our natural gas derivative instruments outstanding as of December 31, 2019:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average fixed price per MMBtu
|
|
Period and type of contract
|
|
Volume BBtu
|
|
Swaps
|
|
2020
|
|
|
|
|
|
|
|
Natural gas swaps
|
|
7,680
|
|
|
$
|
2.71
|
|
|
Natural gas basis swaps
|
|
7,080
|
|
|
$
|
(0.46
|
)
|
The following table summarizes our natural gas liquids derivative instruments outstanding as of December 31, 2019:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume
|
|
Weighted average fixed price per gallon
|
|
Period and type of contract
|
|
Gallons
|
|
Swaps
|
|
2020
|
|
|
|
|
|
|
|
Butane
|
|
2,849
|
|
|
$
|
0.68
|
|
|
Natural gasoline swaps
|
|
6,508
|
|
|
$
|
1.15
|
|
|
Propane swaps
|
|
14,872
|
|
|
$
|
0.57
|
|
In February 2018, we renegotiated the fixed pricing of certain crude oil swaps scheduled to settle during 2018 in exchange for entering crude oil swaps, scheduled to settle from 2020 through 2021, at lower-than-market pricing. The renegotiated swaps cover 1,086 MBbls and have a new fixed price of $60.00 per barrel, replacing the original weighted average fixed price of $54.80 per barrel. The new crude oil swaps scheduled to settle from 2020 through 2021 have weighted average fixed prices of $46.26 and $44.34 per barrel, respectively, and cover 543 MBbls each year.
Effect of derivative instruments on the consolidated balance sheets
All derivative financial instruments are recorded on the consolidated balance sheets at fair value. See “Note 10: 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.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2019
|
|
As of December 31, 2018
|
|
|
|
Assets
|
|
Liabilities
|
|
Net value
|
|
Assets
|
|
Liabilities
|
|
Net value
|
|
Natural gas derivative contracts
|
|
$
|
3,552
|
|
|
$
|
(1
|
)
|
|
$
|
3,551
|
|
|
$
|
833
|
|
|
$
|
(488
|
)
|
|
$
|
345
|
|
|
NGL derivative contracts
|
|
2,868
|
|
|
(699
|
)
|
|
2,169
|
|
|
4,581
|
|
|
—
|
|
|
4,581
|
|
|
Crude oil derivative contracts
|
|
391
|
|
|
(22,196
|
)
|
|
(21,805
|
)
|
|
24,208
|
|
|
(4,452
|
)
|
|
19,756
|
|
|
Total derivative instruments
|
|
6,811
|
|
|
(22,896
|
)
|
|
(16,085
|
)
|
|
29,622
|
|
|
(4,940
|
)
|
|
24,682
|
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Netting adjustments (1)
|
|
(5,864
|
)
|
|
5,864
|
|
|
—
|
|
|
(3,398
|
)
|
|
3,398
|
|
|
—
|
|
|
Derivative instruments - current
|
|
947
|
|
|
(11,957
|
)
|
|
(11,010
|
)
|
|
24,025
|
|
|
—
|
|
|
24,025
|
|
|
Derivative instruments - long-term
|
|
$
|
—
|
|
|
$
|
(5,075
|
)
|
|
$
|
(5,075
|
)
|
|
$
|
2,199
|
|
|
$
|
(1,542
|
)
|
|
$
|
657
|
|
____________________________________________________________
|
|
|
|
(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 related 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 (losses) gains” in the consolidated statements of operations.
“Derivative (losses) gains” in the consolidated statements of operations consists of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
|
|
|
|
|
Period from
|
|
|
Period from
|
|
|
|
|
|
|
|
March 22, 2017
|
|
|
January 1, 2017
|
|
|
|
For the Year Ended December 31,
|
|
through
|
|
|
through
|
|
|
|
2019
|
|
2018
|
|
December 31, 2017
|
|
|
March 21, 2017
|
|
Change in fair value of commodity price derivatives
|
|
$
|
(40,765
|
)
|
|
$
|
37,807
|
|
|
$
|
(46,478
|
)
|
|
|
$
|
46,721
|
|
|
Settlement gains (losses) on commodity price derivatives
|
|
7,567
|
|
|
(18,510
|
)
|
|
15,676
|
|
|
|
1,285
|
|
|
Derivative (losses) gains
|
|
$
|
(33,198
|
)
|
|
$
|
19,297
|
|
|
$
|
(30,802
|
)
|
|
|
$
|
48,006
|
|
Note 10: Fair value measurements
Recurring fair value measurements
Our financial instruments recorded at fair value on a recurring basis consist of commodity derivative contracts (see “Note 9: Derivative instruments”). We had no Level 1 assets or liabilities as of December 31, 2019 or December 31, 2018. Our derivative contracts classified as Level 2 as of December 31, 2019 and 2018 consisted of commodity price swaps, including our oil roll contracts, which are valued using an income approach. Future cash flows from these derivatives are estimated based on the difference between the fixed contract price and the underlying published forward market price, and are discounted at a rate that captures our own nonperformance risk for derivative liabilities or that of our counterparties for derivative assets.
As of December 31, 2019 and 2018 our derivative contracts classified as Level 3 consisted of collars and gas basis swaps. 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. 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.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
The fair value hierarchy for our financial assets and liabilities is shown by the following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2019
|
|
As of December 31, 2018
|
|
|
|
Derivative
assets
|
|
Derivative
liabilities
|
|
Net assets
(liabilities)
|
|
Derivative
assets
|
|
Derivative
liabilities
|
|
Net assets
(liabilities)
|
|
Significant other observable inputs (Level 2)
|
|
$
|
6,576
|
|
|
$
|
(22,895
|
)
|
|
$
|
(16,319
|
)
|
|
$
|
29,370
|
|
|
$
|
(4,718
|
)
|
|
$
|
24,652
|
|
|
Significant unobservable inputs (Level 3)
|
|
235
|
|
|
(1
|
)
|
|
234
|
|
|
252
|
|
|
(222
|
)
|
|
30
|
|
|
Netting adjustments (1)
|
|
(5,864
|
)
|
|
5,864
|
|
|
—
|
|
|
(3,398
|
)
|
|
3,398
|
|
|
—
|
|
|
|
|
$
|
947
|
|
|
$
|
(17,032
|
)
|
|
$
|
(16,085
|
)
|
|
$
|
26,224
|
|
|
$
|
(1,542
|
)
|
|
$
|
24,682
|
|
____________________________________________________________
|
|
|
|
(1)
|
Amounts represent the impact of master netting agreements that allow us to net settle positive and negative positions with the same counterparty. Positive and negative positions with counterparties are netted on the balance sheet only to the extent that they relate to the same current versus noncurrent classification.
|
Changes in the fair value of our derivative instruments classified as Level 3 in the fair value hierarchy were as follows for the periods presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
Net derivative assets (liabilities)
|
|
2019
|
|
2018
|
|
Beginning balance
|
|
$
|
30
|
|
|
$
|
(295
|
)
|
|
Realized and unrealized gains (losses) included in derivative (losses) gains
|
|
1,009
|
|
|
(1,101
|
)
|
|
Settlements (received) paid
|
|
(805
|
)
|
|
1,426
|
|
|
Ending balance
|
|
$
|
234
|
|
|
$
|
30
|
|
|
Gains relating to instruments still held at the reporting date included in derivative (losses) gains for the period
|
|
$
|
234
|
|
|
$
|
30
|
|
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. See “Note 11: Asset retirement obligations” for additional information regarding our asset retirement obligations. The table below discloses the inflation and discount rate assumptions for the periods presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
|
|
|
2019
|
|
2018
|
|
|
|
Low
|
|
High
|
|
Low
|
|
High
|
|
Inflation rate (1)
|
|
2.25
|
%
|
|
2.25
|
%
|
|
2.26
|
%
|
|
2.26
|
%
|
|
Credit adjusted risk-free discount rate
|
|
12.35
|
%
|
|
21.79
|
%
|
|
6.92
|
%
|
|
11.94
|
%
|
__________________________________________
(1) The inflation rate is measured as a single rate on an annual basis.
Our significant financial instruments, other than derivatives, consist primarily of cash and cash equivalents, accounts receivable, accounts payable, and long-term 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.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
The carrying value and estimated fair value of our debt at December 31, 2019 and 2018 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2019
|
|
December 31, 2018
|
|
Level 2
|
|
Carrying
value (1)
|
|
Estimated
fair value
|
|
Carrying
value (1)
|
|
Estimated
fair value
|
|
Credit facility
|
|
$
|
130,000
|
|
|
$
|
130,000
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Other secured debt (2)
|
|
371
|
|
|
371
|
|
|
8,942
|
|
|
8,942
|
|
|
8.75% Senior Notes due 2023
|
|
300,000
|
|
|
133,050
|
|
|
300,000
|
|
|
213,618
|
|
____________________________________________________________
|
|
|
|
(1)
|
The carrying value excludes deductions for debt issuance costs and discounts.
|
|
|
|
|
(2)
|
The balance on December 31, 2019, consisted of only equipment installment notes while the balance on December 31, 2018, consisted of real estate and equipment installment notes.
|
The carrying value of our credit facility and other secured long-term debt approximates fair value as 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.
See “Note 1: Nature of operations and summary of significant accounting policies” for additional information regarding our accounting policies for fair value measurements.
Concentrations of credit risk
Financial instruments that potentially subject us to concentrations of credit risk consist principally of derivative instruments and accounts receivable. Derivative instruments are exposed to credit risk from counterparties. Our derivative contracts are executed with institutions, or affiliates of institutions, that are parties to our credit facility at the time of execution, and we believe the credit risks associated with all of these institutions are acceptable. We do not require collateral or other security from counterparties to support derivative instruments. Master agreements are in place with each of our derivative counterparties that 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 December 31, 2019, the counterparties to our open derivative contracts consisted of eight financial institutions.
The following table summarizes our derivative assets and liabilities, which are offset in the consolidated balance sheets under our master netting agreements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
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
|
)
|
|
December 31, 2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative assets
|
|
$
|
29,622
|
|
|
$
|
(3,398
|
)
|
|
$
|
26,224
|
|
|
$
|
(1,542
|
)
|
|
$
|
—
|
|
|
$
|
24,682
|
|
|
Derivative liabilities
|
|
(4,940
|
)
|
|
3,398
|
|
|
(1,542
|
)
|
|
$
|
1,542
|
|
|
—
|
|
|
—
|
|
|
|
|
$
|
24,682
|
|
|
$
|
—
|
|
|
$
|
24,682
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
24,682
|
|
____________________________________________________________
|
|
|
|
(1)
|
Since positive and negative positions with a counterparty are netted on the balance sheet only to the extent that they related 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 facilities that is available to offset out net derivative assets due from counterparties that are lenders under our credit facilities.
|
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
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 on our Credit Agreement. The aggregate fair value of our derivative liabilities subject to acceleration in the event of default was $22,896 at December 31, 2019.
Accounts receivable are primarily from purchasers of oil and natural gas products, and exploration and production companies who own interests in properties we operate. The industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that customers may be similarly affected by changes in economic, industry or other conditions.
Commodity sales to our top three purchasers accounted for the following percentages of our total commodity sales, excluding the effects of hedging activities, for the years ended December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
|
2019
|
|
2018
|
|
2017
|
|
Coffeyville Resources LLC
|
|
*
|
|
|
*
|
|
|
20.9
|
%
|
|
Phillips 66 Company
|
|
21.4
|
%
|
|
26.0
|
%
|
|
14.6
|
%
|
|
Sunoco, Inc.
|
|
15.1
|
%
|
|
7.2
|
%
|
|
*
|
|
|
Alta Mesa Resources, Inc.
|
|
*
|
|
|
6.7
|
%
|
|
*
|
|
|
Tom Stack LLC.
|
|
10.0
|
%
|
|
*
|
|
|
*
|
|
|
Valero Energy Corporation
|
|
*
|
|
|
*
|
|
|
13.3
|
%
|
____________________________________________________________
* Not disclosed as not a top three purchaser during the fiscal year.
If we were to lose a purchaser, we believe we are able to secure other purchasers for the commodities we produce.
Note 11: Asset retirement obligations
The following table presents the balance and activity of our asset retirement obligations:
|
|
|
|
|
|
|
|
Liability for asset retirement obligations as of January 1, 2018
|
$
|
35,990
|
|
|
Liabilities incurred in current period
|
689
|
|
|
Liabilities settled and disposed in current period
|
(17,868
|
)
|
|
Revisions in estimated cash flows
|
2,452
|
|
|
Accretion expense
|
1,884
|
|
|
Liability for asset retirement obligations as of December 31, 2018
|
$
|
23,147
|
|
|
Liabilities incurred in current period
|
448
|
|
|
Liabilities settled and disposed in current period
|
(2,305
|
)
|
|
Revisions in estimated cash flows
|
388
|
|
|
Accretion expense
|
1,478
|
|
|
Liability for asset retirement obligations as of December 31, 2019
|
$
|
23,156
|
|
|
Less current portion included in accounts payable and accrued liabilities
|
2,083
|
|
|
Asset retirement obligations, long-term
|
$
|
21,073
|
|
Liabilities incurred include obligations related to new wells drilled and wells acquired during the period. Liabilities settled and disposed in 2018 primarily relate to our oil and natural gas property divestitures discussed in “Note 6: Acquisitions and divestitures.”
See “Note 10: Fair value measurements” for additional information regarding fair value measurements.
Note 12: Income taxes
Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. We are subject to U.S. federal corporate income taxes, state income tax in states where business is conducted (most notably Oklahoma), and margin tax in the state of Texas.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
Income tax (benefit) expense from continuing operations consists of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
|
|
|
|
|
Period from
|
|
|
Period from
|
|
|
|
|
|
|
|
March 22, 2017
|
|
|
January 1, 2017
|
|
|
|
For the Year Ended December 31,
|
|
through
|
|
|
through
|
|
|
|
2019
|
|
2018
|
|
December 31, 2017
|
|
|
March 21, 2017
|
|
Current income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$
|
—
|
|
|
$
|
(77
|
)
|
|
$
|
(162
|
)
|
|
|
$
|
—
|
|
|
State
|
|
—
|
|
|
—
|
|
|
(187
|
)
|
|
|
37
|
|
|
Total current income taxes
|
|
—
|
|
|
(77
|
)
|
|
(349
|
)
|
|
|
37
|
|
|
Deferred income taxes
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
|
State
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
|
Total deferred income taxes
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
|
Income tax (benefit) expense
|
|
$
|
—
|
|
|
$
|
(77
|
)
|
|
$
|
(349
|
)
|
|
|
$
|
37
|
|
A reconciliation of the U.S. federal statutory income tax rate to the effective tax rate is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
|
|
|
|
|
Period from
|
|
|
Period from
|
|
|
|
|
|
|
|
March 22, 2017
|
|
|
January 1, 2017
|
|
|
|
For the Year Ended December 31,
|
|
through
|
|
|
through
|
|
|
|
2019
|
|
2018
|
|
December 31, 2017
|
|
|
March 21, 2017
|
|
Federal statutory rate
|
|
21.0
|
%
|
|
21.0
|
%
|
|
35.0
|
%
|
|
|
35.0
|
%
|
|
Remeasurement of deferred taxes—U.S. tax reform legislation
|
|
—
|
%
|
|
—
|
%
|
|
(94.7
|
)%
|
|
|
—
|
%
|
|
State remeasurement of deferred taxes
|
|
0.3
|
%
|
|
—
|
%
|
|
—
|
%
|
|
|
—
|
%
|
|
State income taxes, net of federal benefit
|
|
4.5
|
%
|
|
(0.1
|
)%
|
|
5.8
|
%
|
|
|
2.2
|
%
|
|
Statutory depletion
|
|
—
|
%
|
|
(0.4
|
)%
|
|
0.4
|
%
|
|
|
—
|
%
|
|
Valuation allowance
|
|
(25.0
|
)%
|
|
2.8
|
%
|
|
54.1
|
%
|
|
|
(25.9
|
)%
|
|
EOR tax credit
|
|
—
|
%
|
|
(25.9
|
)%
|
|
(8.4
|
)%
|
|
|
—
|
%
|
|
Return to provision adjustment
|
|
(0.6
|
)%
|
|
(1.7
|
)%
|
|
10.2
|
%
|
|
|
—
|
%
|
|
Other, net
|
|
(0.2
|
)%
|
|
4.1
|
%
|
|
(2.4
|
)%
|
|
|
(11.3
|
)%
|
|
Effective tax rate
|
|
—
|
%
|
|
(0.2
|
)%
|
|
—
|
%
|
|
|
—
|
%
|
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
Components of the deferred tax assets and liabilities are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
2019
|
|
December 31,
2018
|
|
Deferred tax assets related to
|
|
|
|
|
|
|
|
Asset retirement obligations
|
|
$
|
8,500
|
|
|
$
|
10,013
|
|
|
Accrued expenses, allowance and other
|
|
2,254
|
|
|
2,264
|
|
|
Derivative instruments
|
|
4,095
|
|
|
—
|
|
|
Net operating loss carryforwards
|
|
|
|
|
|
Federal
|
|
258,388
|
|
|
242,070
|
|
|
State
|
|
69,100
|
|
|
66,575
|
|
|
Statutory depletion carryforwards
|
|
2,351
|
|
|
2,383
|
|
|
Enhanced oil recovery credit
|
|
18,758
|
|
|
18,758
|
|
|
Interest limitation
|
|
4,153
|
|
|
5,771
|
|
|
|
|
367,599
|
|
|
347,834
|
|
|
Less valuation allowance
|
|
(336,123
|
)
|
|
(216,109
|
)
|
|
Deferred tax asset
|
|
31,476
|
|
|
131,725
|
|
|
Deferred tax liabilities related to
|
|
|
|
|
|
Property and equipment
|
|
(31,355
|
)
|
|
(125,224
|
)
|
|
Derivative instruments
|
|
—
|
|
|
(6,353
|
)
|
|
Inventories
|
|
(121
|
)
|
|
(148
|
)
|
|
Deferred tax liability
|
|
(31,476
|
)
|
|
(131,725
|
)
|
|
Net deferred tax liability
|
|
$
|
—
|
|
|
$
|
—
|
|
Deferred tax asset valuation allowance. The ultimate realization of our deferred tax assets is dependent upon the generation of future taxable income during the periods in which those deferred tax assets would be deductible. We assess the realizability of our deferred tax assets each period by considering whether it is more likely than not that all or a portion of our deferred tax assets will not be realized. We consider all available evidence (both positive and negative) when determining whether a valuation allowance is required. We evaluated possible sources of taxable income that may be available to realize the benefit of deferred tax assets, including projected future taxable income, the reversal of existing temporary differences, taxable income in carryback years and available tax planning strategies in making this assessment.
Due to continued tax losses, we maintained our deferred tax asset position at December 31, 2019. We believe that it is more likely than not that these deferred tax assets will not be realized and as such we are maintaining the full valuation allowance against our net deferred tax assets.
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 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 assets is necessary, we likely will not have any additional deferred income tax expense or benefit.
Net operating loss carryforwards. We have federal net operating loss carryforwards of approximately $1,230,419 at December 31, 2019, of which $1,011,368 will expire at various times between 2028 and 2037 if not utilized in earlier periods. However, because of the 2017 Tax Act, the estimated federal net operating loss of $219,051 generated in 2018 and 2019 does not expire but may only offset 80% of taxable income in any given year. At December 31, 2019, we have state net operating loss carryforwards of approximately $1,498,363, which will expire between 2020 and 2039 if not utilized in earlier periods. In addition, at December 31, 2019, we had federal percentage depletion carryforwards of approximately $11,194, which are not subject to expiration.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
IRC Section 382 addresses company ownership changes and specifically limits the utilization of certain deductions and other tax attributes on an annual basis following an ownership change. As a result of the Chapter 11 reorganization and related transactions, the Company experienced an ownership change within the meaning of IRC Section 382 on March 21, 2017. The Company analyzed alternatives available within the IRC to taxpayers in Chapter 11 bankruptcy proceedings in order to minimize the impact of the March 21, 2017 ownership change on its tax attributes. Upon filing the 2017 U.S. Federal income tax return, the Company elected an available alternative which subjects existing tax attributes at emergence to an IRC Section 382 limitation that could result in some or all of the remaining net operating loss carryforwards expiring unused. Upon final determination of tax return amounts for the year ended December 31, 2017, including attribute reduction that occurred on January 1, 2018, the Company has total federal net operating loss carryforwards of $1,011,368 including $760,067 which are subject to limitation due to the ownership change that occurred upon emergence from bankruptcy and $251,301 of post-change net operating loss carryforwards not subject to this limitation. The limitation did not result in a current tax liability for the tax years ended December 31, 2017, 2018 and 2019.The Company has incurred additional net operating losses for the years ended December 31, 2018 and December 31, 2019 that are currently not subject to an IRC Section 382 limitation.
Note 13: Deferred compensation
Our deferred compensation includes cash awards and equity-based awards which are either settled in cash or in stock.
Cash Awards
From time to time, we have granted cash awards with long term vesting requirements. Our cash awards, which are generally service-based, vest either in one year, in annual increments over a three year period or in annual increments over a four year period. We accrue for the cost of each annual increment over the period that service is required to vest. A summary of compensation expense for our cash awards is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
|
|
|
|
Period from
|
|
|
Period from
|
|
|
|
|
|
|
March 22, 2017
|
|
|
January 1, 2017
|
|
|
For the Year Ended December 31,
|
|
through
|
|
|
through
|
|
|
2019
|
|
2018
|
|
December 31, 2017
|
|
|
March 21, 2017
|
|
Cash LTIP expense (net of amounts capitalized)
|
$
|
200
|
|
|
$
|
543
|
|
|
$
|
1,192
|
|
|
|
$
|
5
|
|
|
Cash LTIP grants (1)
|
1,300
|
|
|
174
|
|
|
5,637
|
|
|
|
—
|
|
|
Cash LTIP payments
|
955
|
|
|
1,183
|
|
|
1,285
|
|
|
|
42
|
|
|
|
|
|
(1)
|
All grants are service-based except for a market-condition grant of $263 to our new chief executive officer in December 2019.
|
As of December 31, 2019, the outstanding liability accrued for our Cash LTIP, based on requisite service provided, was $854.
Equity Awards
The Company’s outstanding equity based awards have generally 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 RSAs or RSUs. In December 2019, we also granted equity awards in the form of 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. Even though the inducement grant was made outside of the LTIP, except as expressly provided otherwise in the grant agreement, the grant will be governed in a manner consistent with the terms and conditions of the LTIP.
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 under the LTIP when it became effective was 3,500,000 shares. Generally, and to the extent not provided otherwise in an award agreement, (i) in the event of a Change in Control (as defined in the LTIP) in which the acquiring or surviving entity does not assume an outstanding award, the award will fully vest, and (ii) in the event of termination by the Company of a participant’s employment or service without cause or by the participant for Good Reason (as defined in the LTIP), in each case, within one year following the occurrence of a Change in Control, the award will fully vest. These accelerated vesting provisions, if triggered, take precedence over service, performance or market based vesting provisions described below.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
Restricted Stock Awards (“RSAs”)
We have granted RSAs to our employees and members of our Board of Directors (the “Board”). Grants awarded to employees consist of shares subject to service vesting conditions (the “Time Shares”) and shares subject to performance or market-based vesting conditions (the “Performance Shares”). All grants to members of our Board are Time Shares. Since 2019, vesting conditions established for all Performance Shares have been linked exclusively to the performance of the Company’s stock price vis-à-vis a peer group and hence have a market-based vesting condition. Please see “Note 1: Nature of operations and summary of significant accounting policies” for our accounting policies for awards that are subject to service-based vesting conditions compared to awards that are subject to market-based vesting conditions. The Time Shares vest in equal annual installments over a three -year vesting period. The Performance Shares vest in three tranches annually according to conditions established each year by our Board of Directors.
A summary of our restricted stock activity is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Time Shares
|
|
Performance Shares
|
|
|
|
Weighted
average
grant date
fair value
|
|
Restricted
shares
|
|
Vest date fair value
|
|
Weighted
average
grant date
fair value
|
|
Restricted
shares
|
|
Vest date fair value
|
|
|
|
($ per share)
|
|
|
|
|
|
($ per share)
|
|
|
|
|
|
Unvested and outstanding at March 21, 2017
|
|
$
|
—
|
|
|
—
|
|
|
|
|
$
|
—
|
|
|
—
|
|
|
|
|
Granted
|
|
20.11
|
|
|
1,403,626
|
|
|
|
|
20.12
|
|
|
429,510
|
|
|
|
|
Vested
|
|
—
|
|
|
—
|
|
|
|
|
20.05
|
|
|
(152,421
|
)
|
|
$
|
3,611
|
|
|
Cancelled
|
|
—
|
|
|
—
|
|
|
|
|
20.05
|
|
|
(7,616
|
)
|
|
|
|
Unvested and outstanding at December 31, 2017
|
|
$
|
20.11
|
|
|
1,403,626
|
|
|
|
|
$
|
20.15
|
|
|
269,473
|
|
|
|
|
Granted
|
|
18.75
|
|
|
41,250
|
|
|
|
|
18.75
|
|
|
13,750
|
|
|
|
|
Vested
|
|
20.12
|
|
|
(445,029
|
)
|
|
$
|
7,856
|
|
|
20.08
|
|
|
(107,590
|
)
|
|
$
|
529
|
|
|
Forfeited
|
|
20.05
|
|
|
(181,641
|
)
|
|
|
|
20.05
|
|
|
(50,105
|
)
|
|
|
|
Unvested and outstanding at December 31, 2018
|
|
$
|
20.06
|
|
|
818,206
|
|
|
|
|
$
|
20.12
|
|
|
125,528
|
|
|
|
|
Granted
|
|
2.40
|
|
|
886,451
|
|
|
|
|
1.38
|
|
|
1,087,110
|
|
|
|
|
Vested
|
|
20.08
|
|
|
(408,270
|
)
|
|
$
|
2,334
|
|
|
16.45
|
|
|
(33,359
|
)
|
|
$
|
59
|
|
|
Forfeited
|
|
20.05
|
|
|
(226,882
|
)
|
|
|
|
20.05
|
|
|
(89,936
|
)
|
|
|
|
Unvested and outstanding at December 31, 2019
|
|
$
|
5.41
|
|
|
1,069,505
|
|
|
|
|
$
|
1.53
|
|
|
1,089,343
|
|
|
|
Restricted Stock Units (“RSUs”)
We have granted RSUs to employees and members of our Board with the following provisions:
Executive employee awards: 50% of the RSUs granted during 2019 were subject only to service vesting conditions and the other 50% were subject to market-based vesting conditions. Service-based RSUs vest in equal annual installments over a three-year period. Market condition RSUs vest in three annual tranches – each year according to our stock return performance in such year relative to a group of peers identified prior to the beginning of such performance year. Both market-based and service-based awards were classified as equity awards.
Non-executive employee awards: Grants consisted of RSUs with service vesting conditions and vest in equal annual installments over a three-year period. Certain RSUs are to be settled in stock upon vesting while others are to be settled in cash. The stock-settled RSUs are classified as equity awards while the cash-settled RSUs are classified as liability awards.
Board awards: Grants consisted of RSUs with service vesting conditions and which vest in its entirety on the earlier of (a) the first anniversary of the grant date or (b) the date of the next Company ensuing annual meeting. These awards were classified as liability awards.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
A summary of our RSU activity is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity classified RSUs
|
|
|
|
Service-condition RSUs
|
|
Market-condition RSUs
|
|
|
|
Weighted
average
grant date
fair value
|
|
Restricted
units
|
|
Vest date
fair value
|
|
Weighted
average
grant date
fair value
|
|
Restricted
units
|
|
|
|
($ per unit)
|
|
|
|
|
|
($ per unit)
|
|
|
|
Unvested and outstanding at January 1, 2018
|
|
$
|
—
|
|
|
—
|
|
|
|
|
|
$
|
—
|
|
|
—
|
|
|
Granted
|
|
17.66
|
|
|
92,017
|
|
|
|
|
|
$
|
—
|
|
|
—
|
|
|
Forfeited
|
|
17.66
|
|
|
(2,384
|
)
|
|
|
|
|
$
|
—
|
|
|
—
|
|
|
Unvested and outstanding at December 31, 2018
|
|
$
|
17.66
|
|
|
89,633
|
|
|
|
|
|
$
|
—
|
|
|
—
|
|
|
Granted
|
|
1.33
|
|
|
788,323
|
|
|
|
|
|
$
|
1.36
|
|
|
565,000
|
|
|
Vested
|
|
17.66
|
|
|
(25,099
|
)
|
|
$
|
33
|
|
|
$
|
—
|
|
|
—
|
|
|
Forfeited
|
|
3.02
|
|
|
(214,474
|
)
|
|
|
|
|
$
|
1.36
|
|
|
(175,000
|
)
|
|
Unvested and outstanding at December 31, 2019
|
|
$
|
2.41
|
|
|
638,383
|
|
|
|
|
|
$
|
1.36
|
|
|
390,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liability-classified RSUs
|
|
|
|
|
Weighted
average
grant date
fair value
|
|
Restricted
units
|
|
Vest date
fair value
|
|
|
|
|
($ per unit)
|
|
|
|
|
|
|
Unvested and outstanding at January 1, 2018
|
|
$
|
—
|
|
|
—
|
|
|
|
|
|
Granted
|
|
17.66
|
|
|
37,991
|
|
|
|
|
|
Forfeited
|
|
17.66
|
|
|
(795
|
)
|
|
|
|
|
Unvested and outstanding at December 31, 2018
|
|
$
|
17.66
|
|
|
37,196
|
|
|
|
|
|
Granted
|
|
1.44
|
|
|
71,570
|
|
|
|
|
|
Vested
|
|
9.33
|
|
|
(20,302
|
)
|
|
$
|
25
|
|
|
|
Forfeited
|
|
17.66
|
|
|
(12,685
|
)
|
|
|
|
|
Unvested and outstanding at December 31, 2019
|
|
$
|
4.57
|
|
|
75,779
|
|
|
|
|
Companywide stock award
In the past, we have made grants of 100 shares to each new employee subsequent to being employed for a certain period of time which resulted in a total of 1,100, 600 and 20,100 shares being granted in 2019, 2018 and 2017, respectively. There were no vesting requirements for these awards and thus compensation was recognized in full on the award date based on the closing price of our common stock on that date. The compensation cost is included in the table below.
Stock-based compensation cost
Compensation cost is calculated net of forfeitures. As allowed by recent accounting guidance, we will recognize the impact of forfeitures on expense due to employee terminations as they 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.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
|
|
|
|
|
Period from
|
|
|
Period from
|
|
|
|
|
|
|
|
March 22, 2017
|
|
|
January 1, 2017
|
|
|
|
For the Year Ended December 31,
|
|
through
|
|
|
through
|
|
|
|
2019
|
|
2018
|
|
December 31, 2017
|
|
|
March 21, 2017
|
|
Stock-based compensation expense
|
|
$
|
2,303
|
|
|
$
|
13,444
|
|
|
$
|
12,606
|
|
|
|
$
|
194
|
|
|
Less: stock-based compensation cost capitalized
|
|
(722
|
)
|
|
(2,543
|
)
|
|
(2,773
|
)
|
|
|
(39
|
)
|
|
Total stock-based compensation expense, net
|
|
$
|
1,581
|
|
|
$
|
10,901
|
|
|
$
|
9,833
|
|
|
|
$
|
155
|
|
|
Payments for stock-based compensation
|
|
$
|
1,198
|
|
|
$
|
4,936
|
|
|
$
|
—
|
|
|
|
$
|
—
|
|
|
Recognized tax expense associated with stock-based compensation
|
|
$
|
—
|
|
|
$
|
22
|
|
|
$
|
—
|
|
|
|
$
|
—
|
|
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 December 31, 2019, and 2018, accrued payroll and benefits payable included $52 and $17, respectively, for stock-based compensation costs expected to be settled within the next twelve months. Unrecognized stock-based compensation cost of approximately $3,386 as of December 31, 2019 is expected to be recognized over a weighted-average period of 1.4 years. This amount does not include market-condition RSAs and RSUs scheduled to vest in 2020 and 2021 since requisite service for those shares had not commenced as of December 31, 2019. We expect to repurchase or settle in cash approximately 476,000 shares/units in 2020. Based on the market price of $1.76 per share, the aggregate intrinsic value of unvested RSAs and RSUs outstanding was $5,743 as of December 31, 2019.
Valuation of Awards
Compensation cost is generally recognized and measured according to the grant date fair value of the awards. For awards with service and performance conditions, the fair value is based on the market price of our Class A common stock on the grant date. For awards with a market condition, expense is based on a grant date fair value that incorporates the probability of vesting and the potential value of the award at vesting. We utilize Monte Carlo simulations to estimate the fair value our market based awards. The fair value and associated assumptions, which are considered to be Level 3 inputs within the fair value hierarchy, for our market condition RSAs and RSUs granted in 2019 are follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
Valuation assumptions of market awards
|
|
Low
|
|
High
|
|
Risk free rate
|
|
1.75
|
%
|
|
2.52
|
%
|
|
Volatility (1)
|
|
64.1
|
%
|
|
90.0
|
%
|
|
Fair value per share/unit
|
|
$
|
0.94
|
|
|
$
|
8.59
|
|
_____________________________
(1) Based on daily log returns over a lookback period commensurate with the remaining term until vesting.
Note 14: Stockholders’ equity
Predecessor Common Stock
Our Amended and Restated Certificate of Incorporation filed April 12, 2010, created seven classes of $0.01 par value per share common stock, classes A through G, with the rights and preferences summarized below. The Class A common stock carries standard voting, dividend and liquidation rights. The class B, C and D common stock was issued to our former stockholders, with a separate class issued to each stockholder. The class E and class F common stock was issued to CCMP. One share of class G common stock was issued to two former stockholders.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
On the Effective Date, all existing common stock of the Predecessor was canceled and each holder of such stock did not receive any distribution or retain any property on account of their stock interest.
Successor Common Stock
On the Effective Date, we issued a total of 44,982,142 shares of Successor common stock consisting of 37,110,630 shares of Class A common stock and 7,871,512 shares Class B common stock pursuant to our Reorganization Plan and our new organizational documents. The new Class A shares and Class B shares had identical economic and voting rights. However, Class B shares were subject to certain redemption provisions upon demand to the Company by certain stockholders undertaking an initial public offering, as described in our Third Amended and Restated Certificate of Organization. On December 19, 2018, all outstanding shares of Class B common stock converted into the same number of shares of Class A common stock. Each share of Class B Common Stock that was converted has been retired by the Company and is not available for reissuance. The conversion had no impact on the voting power of the holders of shares of Class B Common Stock. The conversion had no impact on the total number of the Company’s issued and outstanding shares of capital stock.
Summary of changes in common stock
The following is a summary of the changes in our common shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common Stock
|
|
|
|
Class A
|
|
Class B
|
|
Class C
|
|
Class E
|
|
Class F
|
|
Class G
|
|
Total
|
|
Shares outstanding at January 1, 2017 - Predecessor
|
|
333,686
|
|
|
344,859
|
|
|
209,882
|
|
|
504,276
|
|
|
1
|
|
|
2
|
|
|
1,392,706
|
|
|
Restricted stock forfeited
|
|
(1,454
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,454
|
)
|
|
Restricted stock canceled
|
|
(8,964
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(8,964
|
)
|
|
Shares outstanding at March 21, 2017 - Predecessor
|
|
323,268
|
|
|
344,859
|
|
|
209,882
|
|
|
504,276
|
|
|
1
|
|
|
2
|
|
|
1,382,288
|
|
|
Cancellation of Predecessor equity
|
|
(323,268
|
)
|
|
(344,859
|
)
|
|
(209,882
|
)
|
|
(504,276
|
)
|
|
(1
|
)
|
|
(2
|
)
|
|
(1,382,288
|
)
|
|
Shares outstanding at March 21, 2017 - Predecessor
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of Successor common stock - rights offering
|
|
4,197,210
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4,197,210
|
|
|
Issuance of Successor common stock - backstop premium
|
|
367,030
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
367,030
|
|
|
Issuance of Successor common stock - settlement of claims
|
|
32,546,390
|
|
|
7,871,512
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
40,417,902
|
|
|
Shares outstanding at March 21, 2017 - Successor
|
|
37,110,630
|
|
|
7,871,512
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
44,982,142
|
|
|
Stock-based compensation
|
|
1,853,236
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,853,236
|
|
|
Restricted stock canceled
|
|
(7,616
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(7,616
|
)
|
|
Shares outstanding at December 31, 2017 - Successor
|
|
38,956,250
|
|
|
7,871,512
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
46,827,762
|
|
|
Issuance of restricted stock
|
|
55,600
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
55,600
|
|
|
Conversion of Class B shares
|
|
7,871,512
|
|
|
(7,871,512
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Repurchase of common stock
|
|
(261,103
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(261,103
|
)
|
|
Restricted stock forfeited
|
|
(231,746
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(231,746
|
)
|
|
Shares outstanding at December 31, 2018 - Successor
|
|
46,390,513
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
46,390,513
|
|
|
Stock-based compensation
|
|
2,002,173
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,002,173
|
|
|
Restricted stock forfeited
|
|
(316,821
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(316,821
|
)
|
|
Repurchase of common stock
|
|
(209,852
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(209,852
|
)
|
|
Issuance of common stock - litigation settlement
|
|
76,217
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
76,217
|
|
|
Shares outstanding at December 31, 2019 - Successor
|
|
47,942,230
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
47,942,230
|
|
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
Note 15: Retirement benefits
We provide a 401(k) retirement plan for all employees and matched 100% of employee contributions up to 7% of each employee’s gross wages during 2019, 2018 and 2017. At December 31, 2019, 2018, and 2017, there were 122, 173, and 210 employees, respectively, participating in the plan. Our contribution expense was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
|
|
|
|
|
Period from
|
|
|
Period from
|
|
|
|
|
|
|
|
March 22, 2017
|
|
|
January 1, 2017
|
|
|
|
For the Year Ended December 31,
|
|
through
|
|
|
through
|
|
|
|
2019
|
|
2018
|
|
December 31, 2017
|
|
|
March 21, 2017
|
|
401(k) contribution expense
|
|
$
|
1,509
|
|
|
$
|
1,543
|
|
|
$
|
1,267
|
|
|
|
$
|
396
|
|
Note 16: Revenue recognition
In May 2014, the 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”). 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.
Description of products and revenue disaggregation
Our revenue is predominantly derived from the production and sale of oil, natural gas and NGLs which, prior to January 1, 2018, was reported in the aggregate as “Commodity sales” on our statement of operations. Substantially all our oil and natural gas properties are located in Oklahoma and Texas and are sold to midstream gas processing plants or crude oil refineries in the vicinity. We have disaggregated revenue based on the separate commodities being sold: crude oil, natural gas and NGLs. In selecting the disaggregation categories, we considered a number of factors such as those affecting supply and demand and thus market prices, storage and the ability to transport the product, industry specific disclosures required by the SEC and FASB, other external disclosures we typically make, and information we have historically presented in the management discussion and analysis section of our annual and quarterly reports. As such, we believe that disaggregating revenue by commodity type appropriately depicts how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors.
The following table displays the revenue disaggregated and reconciles the disaggregated revenue to the revenue reported:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
|
|
2019
|
|
2018
|
|
Revenues:
|
|
|
|
|
|
|
Oil
|
|
$
|
173,555
|
|
|
$
|
171,749
|
|
|
Natural gas
|
|
40,543
|
|
|
41,506
|
|
|
Natural gas liquids
|
|
42,101
|
|
|
45,590
|
|
|
Gross commodity sales
|
|
256,199
|
|
|
258,845
|
|
|
Transportation and processing
|
|
(23,049
|
)
|
|
(16,276
|
)
|
|
Net commodity sales
|
|
$
|
233,150
|
|
|
$
|
242,569
|
|
Performance Obligations
Our oil, natural gas and natural gas liquids contracts typically contain only one type of performance obligation, which is for the delivery of the underlying commodity, and which is satisfied at the point in time the commodity is transferred to the customer. We consider each commodity (ex. barrel of oil or MMBtu of natural gas) to be a separate performance obligation. For natural gas and natural gas liquids, all our sales are to midstream processing entities engaged in the processing of gas and marketing the resulting residue gas and NGLs to third party customers. We transfer control of the product to the midstream processing customer at the wellhead and recognize revenue upon such delivery.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
Under our oil sales contracts, we generally sell oil to the purchaser from storage tanks near the wellhead and collect a contractually agreed upon index price, net of pricing differentials. We transfer control of the product from the storage tanks to the purchaser and recognize revenue based on the contract price.
We do not engage in activities to purchase and sell third party natural gas and NGLs. As a result, the commodity revenues we recognize are only for our working interest share of the production.
Pricing and measurement
All of our contracts use market or index-based pricing resulting in the entire transaction price being variable. Since our sales transactions meet the variable allocation criteria in the standard, all consideration is allocated entirely to performance obligations satisfied by distinct commodity units delivered. We record revenue in the month production is delivered to the purchaser. However, settlement statements for our commodity sales are received one to three months after the date production is delivered, and as a result, we are required to estimate the amount of production that was delivered to the purchaser and the price that will be received for the sale of the product. We record the differences between our estimates and the actual amounts for product sales in the month that payment is received from the purchaser. Historically, differences between our revenue estimates and actual revenue received have not been significant. We receive payment for a majority of our sales receivables in the month following delivery and substantially all within three months following delivery. For the year ended December 31, 2019, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.
Transaction Price Allocated to Remaining Performance Obligations
For our product sales that have a contract term greater than one year, we have utilized the practical expedient in ASC 606, which states that a company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Each unit of product delivered to the customer represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. For our product sales that have a contract term of one year or less, we have utilized the practical expedient in ASC 606, which states that a company is not required to disclose the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.
Nature of gas contracts
All our natural gas and NGL production is sold to midstream processing entities and we do not elect to take our residue gas and/or NGLs in-kind at the tailgate of the processing plant. The midstream customer provides us with services such as compressing the gas, transporting the gas to the processing plant and processing it into the separate commodity streams for fees which are deducted from the revenue we receive. We previously reported fees for these services as “Transportation and processing” expenses in our statement of operations. Under ASC 606, since control and possession of the gas is transferred to the customer at the wellhead prior to the receipt of the aforementioned services, the customer is not deemed to be providing a distinct service and any fees paid to the customer are accounted for as a reduction in revenue. We have presented transportation and processing fees as a revenue deduction for the fiscal period beginning January 1, 2018, while our presentation for prior periods remains unchanged.
Contract assets and liabilities
We recognize a receivable for the unconditional right to receive consideration when the commodity is transferred to the customer, at which point the performance obligation is satisfied. All our contract assets are in the form of receivables which are presented as “Accrued commodity sales” in our tabular disclosure of accounts receivable in “Note 1: Nature of operations and summary of significant accounting policies.” Since we are not entitled to advance payments from our customers prior to the transfer of our commodities nor do we receive such payments, we do not have contract liabilities.
Method of adoption
We adopted ASC 606 effective January 1, 2018, using the modified retrospective approach. Based on an assessment of our contracts, the new guidance did not have a material impact on prior net income and therefore we did not record a cumulative effect adjustment to the opening balance of accumulated deficit.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
Reconciliation of Income Statement
In accordance with ASC 606, the disclosure of the impact of adoption on our income statement is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31, 2018
|
|
|
|
As reported
|
|
Balances without adoption of ASC 606
|
|
Effect of change
|
|
Revenues
|
|
|
|
|
|
|
|
|
|
|
Net commodity sales
|
|
$
|
242,569
|
|
|
$
|
258,845
|
|
|
$
|
16,276
|
|
|
Costs and expenses
|
|
|
|
|
|
|
|
Transportation and processing
|
|
$
|
—
|
|
|
$
|
(16,276
|
)
|
|
$
|
(16,276
|
)
|
Note 17: Leases
In February 2016, the FASB established ASC 842, which requires lessees to recognize leases on-balance sheet and disclose key information about leasing arrangements. ASC 842 was subsequently amended by ASU No. 2018-01, Land Easement Practical Expedient for Transition to Topic 842; ASU No. 2018-10, Codification Improvements to Topic 842, Leases, ASU No. 2018-11, Targeted Improvements and ASU No 2019-01, Codification Improvements. The new standard establishes a right-of-use (“ROU”) model that requires a lessee to recognize a ROU asset and lease liability on the balance sheet for all leases except those with a term of 12 months or less. Leases will be classified as finance or operating, with classification affecting the pattern and classification of expense recognition in the income statement. We adopted the new standard on its effective date of January 1, 2019, which is also our date of initial application. Consequently, we have not updated financial information nor provided disclosures required under the new standard for dates and periods before January 1, 2019. Our disclosures for dates and periods before January 1, 2019, are provided in accordance with the requirements of ASC Topic 840, Leases (“ASC 840”).
We have elected the package of transition practical expedients, which permits us not to reassess under the new standard our prior conclusions about lease identification, lease classification and initial direct costs. Additionally, we have elected not to apply the recognition requirements of ASC Topic 842 to leases with durations of 12 months or less. Upon adoption of ASC 842, we carried over our existing capital lease obligations (now “financing leases” under ASC 842) and capital lease asset (now “right of use asset” under ASC 842) at their previous carrying value. In recognizing right of use assets and corresponding lease liabilities, the Company considers whether the lease agreements contain options to renew or purchase, and the likelihood that those options will be exercised.
Financing leases
We previously had lease financing agreements which were entered into during 2013 with U.S. Bank for $24,500 through the sale and subsequent leaseback of existing CO2 compressors owned by us. The lease financing obligations were for terms of 84 months and included the option to purchase the equipment for a specified price at 72 months as well as an option to purchase the equipment at the end of the lease term for its then-current fair market value. There were no residual value guarantees and nonlease components under these leases. At the inception of the lease, our measurement of the lease liability assumed that the mid-term purchase option would be exercised. Since the lease contract had not been modified and there were no triggering events subsequent to our adoption of ASC 842, we did not perform any reassessment of the lease prior to its termination discussed below. Lease payments related to the equipment were recognized as principal and interest expense based on a weighted average implicit interest rate of 3.8%. Minimum lease payments were approximately $3,181 annually. In conjunction with the sale of our EOR assets in November 2017, these compressors were subleased to the buyer of those assets while we remained the primary obligor in relation to U.S. Bank. In September 2019, U.S. Bank entered into agreements with the Sublessee that resulted in the discharge of the remaining obligations with respect to these compressor leases in the amount of $9,832.
During 2019, we entered into lease financing agreements for our fleet trucks and office copiers for $1,911. The fleet truck financing obligations are for 48-month terms with the option for us to purchase the vehicle at any time during the lease term by paying the lessor’s remaining unamortized cost in the vehicle. At the end of the lease term, the lessor’s remaining unamortized cost in the vehicle will be a de minimis amount and hence ownership of the vehicle can be transferred to us at minimal cost. There are no residual value guarantees or nonlease components under these leases. We also entered into a lease financing arrangement for a limited number of office copiers in 2019.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
Operating leases
We previously also had operating leases for CO2 compressors deployed in our former EOR operations. The operating lease obligations, which we entered into in 2014 and 2016, were for terms of 84 months without any specified purchase options. There were no residual value guarantees or nonlease components under these leases. In conjunction with the sale of our EOR assets in November 2017, these compressors were subleased to the buyer of those assets although we remained the primary obligor in relation to U.S. Bank. Similar to the financing leases discussed above, all our obligations under these compressor leases were discharged by U.S. Bank in September 2019.
During the fourth quarter of 2018, we entered into 15-month leasing arrangements for two drilling rigs. These agreements specify a minimum daily rate on the rigs that we utilize to measure the lease liability upon adoption of ASC 842. The actual daily rate may vary from the minimum rate depending on whether the rig is being mobilized, demobilized, engaged in drilling or on standby. The daily rate includes a non-lease labor component that we have elected not to separate from the lease component for this asset class. Our fixed commitment under those lease agreements terminated on December 31, 2019. Each of the two drilling rigs operating on our behalf during the first quarter of 2020 are contracted on a well-by-well basis.
On August 30, 2019, in conjunction with the sale of the building housing our headquarters, we entered into a leaseback agreement with the buyer for a portion of the office space in the building for a period of two years with a renewal option that includes one-year extensions for up to two years. The office space lease includes typical non-lease components such as utilities, maintenance and janitorial services for that we have elected not to separate from the lease component.
Short term leases
Our short term leases are those with lease terms of 12 months or less and generally consist of wellhead compressors, generators and drilling rigs with terms ranging from one month to six months. As discussed above, we have elected not to recognize right of use assets or lease liabilities for leases with durations of 12 months or less.
Subleases
As discussed above, we previously had subleases consisting 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 (the “Sublessee”). Minimum payments under the subleases were equal to the original leases and as such we did not record any losses upon initiation of the subleases. All the subleases were classified as operating leases from a lessor’s standpoint. 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, amortized the asset on a straight line basis prospectively while continuing to incur interest expense. In September 2019, U.S. Bank entered into agreements with the Sublessee that resulted in the discharge of all our obligations with respect to the originating leases and to the subleases.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
Lease assets and liabilities
Our operating and financing lease assets and liabilities are recorded on our balance sheet as of December 31, 2019 as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2019
|
|
|
|
Operating leases
|
|
Financing leases
|
|
Right of use asset:
|
|
|
|
|
|
|
|
Right of use assets from operating leases (1)
|
|
$
|
2,444
|
|
|
$
|
—
|
|
|
Plant, property and equipment, net (2)
|
|
—
|
|
|
1,659
|
|
|
Total lease assets
|
|
$
|
2,444
|
|
|
$
|
1,659
|
|
|
Lease liability:
|
|
|
|
|
|
Account payable and accrued liabilities
|
|
$
|
1,259
|
|
|
$
|
—
|
|
|
Long-term debt and financing leases, classified as current
|
|
—
|
|
|
432
|
|
|
Long-term debt and financing leases, less current maturities
|
|
—
|
|
|
1,221
|
|
|
Noncurrent operating lease obligations
|
|
917
|
|
|
—
|
|
|
Total lease liabilities
|
|
$
|
2,176
|
|
|
$
|
1,653
|
|
________________________________
(1) Consisted of a lease of office space.
(2) Consisted of leased fleet vehicles and office equipment.
Our income, expenses and cash flows related to our leases is as follows for the year ended December 31, 2019:
|
|
|
|
|
|
|
|
|
|
|
Year ended
|
|
|
|
December 31, 2019
|
|
Lease cost
|
|
|
|
Finance lease cost:
|
|
|
|
Amortization of right-of-use assets
|
|
$
|
2,073
|
|
|
Interest on lease liabilities
|
|
344
|
|
|
Operating lease cost
|
|
1,342
|
|
|
Short-term lease cost
|
|
780
|
|
|
Variable lease cost
|
|
253
|
|
|
Sublease income
|
|
(3,195
|
)
|
|
Total lease cost
|
|
$
|
1,597
|
|
|
|
|
|
|
Capitalized operating lease cost (1)
|
|
$
|
13,523
|
|
|
|
|
|
|
Other information
|
|
|
|
Cash paid for amounts included in the measurement of lease liabilities
|
|
|
|
Operating cash flows for finance leases
|
|
$
|
(344
|
)
|
|
Operating cash flows for operating leases
|
|
(1,610
|
)
|
|
Investing cash flows for operating leases
|
|
(9,448
|
)
|
|
Financing cash flows for finance leases
|
|
(2,102
|
)
|
|
Right-of-use assets obtained in exchange for new finance lease liabilities
|
|
1,911
|
|
________________________________
|
|
|
|
(1)
|
The operating lease cost are related to drilling rigs and are capitalized as part of oil and natural gas properties on our balance sheets.
|
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
|
|
|
|
|
|
|
|
|
|
As of
|
|
|
|
December 31, 2019
|
|
Weighted-average remaining lease term - finance leases
|
|
3.6 years
|
|
|
Weighted-average remaining lease term - operating leases
|
|
1.7 years
|
|
|
Weighted-average discount rate - finance leases
|
|
6.67
|
%
|
|
Weighted-average discount rate - operating leases
|
|
8.72
|
%
|
Our rent expense for the years ended December 31, 2019, 2018 and 2017 was $5,542, $3,684 and $4,971, respectively.
Discount rate
Whenever possible, we utilize the implied rate in our lease agreements to measure our lease liabilities. In the absence of a readily available implied rate, we utilize our incremental borrowing rate. The incremental borrowing rate is the rate of interest that a lessee would have to pay to borrow on a collateralized basis over a similar term an amount equal to the lease payments in a similar economic environment. The lease liabilities we recorded on our balance sheet on the effective date of ASC 842 were measured utilizing an incremental borrowing rate derived from the yield and/or credit rating on our unsecured Senior Notes and adjusted to a collateralized basis utilizing a recovery rate model that uses observed recovery rates on defaulted debt instruments.
Lease maturities
Our lease payments for each of the next five years and thereafter are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2019
|
|
As of December 31, 2018 (1)
|
|
|
|
Operating leases
|
Financing leases
|
|
Operating leases
|
Financing leases
|
|
2019
|
|
$
|
1,389
|
|
$
|
530
|
|
|
$
|
13,890
|
|
$
|
12,332
|
|
|
2020
|
|
941
|
|
530
|
|
|
1,330
|
|
—
|
|
|
2021
|
|
—
|
|
531
|
|
|
1,297
|
|
—
|
|
|
2022
|
|
—
|
|
226
|
|
|
278
|
|
—
|
|
|
2023
|
|
—
|
|
55
|
|
|
205
|
|
—
|
|
|
Thereafter
|
|
—
|
|
—
|
|
|
—
|
|
—
|
|
|
Total minimum lease payments
|
|
2,330
|
|
1,872
|
|
|
17,000
|
|
12,332
|
|
|
Less: imputed interest
|
|
154
|
|
219
|
|
|
*
|
*
|
|
Total lease liability
|
|
2,176
|
|
1,653
|
|
|
*
|
*
|
|
Less: current maturities of lease obligations
|
|
1,259
|
|
432
|
|
|
*
|
*
|
|
Noncurrent lease obligations
|
|
$
|
917
|
|
$
|
1,221
|
|
|
*
|
*
|
________________________________
|
|
|
|
(1)
|
Represents undiscounted firm commitments as of December 31, 2018
|
* Disclosure not required under ASC 840.
Method of adoption
We adopted ASC 842 effective January 1, 2019, using the modified retrospective approach. Based on an assessment of our leasing contracts, we did not record a cumulative effect adjustment to the opening balance of accumulated deficit.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
Reconciliation of Balance Sheet Statement
In accordance with ASC 842, the disclosure of the impact of adoption on our balance statement is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of January 1, 2019
|
|
|
|
Balances upon adoption
|
|
Balances without adoption of ASC 842
|
|
Effect of change
|
|
Assets
|
|
|
|
|
|
|
|
Right of use asset from operating leases, net
|
|
$
|
14,999
|
|
|
$
|
—
|
|
|
$
|
14,999
|
|
|
Liabilities
|
|
|
|
|
|
|
|
Accounts payable and accrued liabilities
|
|
12,467
|
|
|
—
|
|
|
12,467
|
|
|
Noncurrent operating lease obligation
|
|
2,532
|
|
|
—
|
|
|
2,532
|
|
Note 18: Commitments and contingencies
Letters of Credit. Standby letters of credit (“Letters”) available under our Credit Agreement are used in lieu of surety bonds with various organizations for liabilities relating to the operation of oil and natural gas properties. Our outstanding Letters, as of December 31, 2019 and 2018, totaled $0 and $869, respectively. Interest on each Letter accrues at the lender’s prime rate for all amounts paid by the lenders under the Letters. No amounts were paid by the lenders under the Letters; therefore, we paid no interest on the Letters during the years ended December 31, 2019, 2018, or 2017.
Leases. Our leases currently consist of an operating lease for the office space housing our headquarters and financing leases for fleet vehicles and office equipment. Please see “Note 17: Leases” for a detailed discussion of these contracts.
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.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
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 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.
Note 19: Oil and natural gas activities (unaudited)
Our oil and natural gas activities are conducted entirely in the United States. Costs incurred in oil and natural gas producing activities are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
|
|
|
|
|
Period from
|
|
|
Period from
|
|
|
|
|
|
|
|
March 22, 2017
|
|
|
January 1, 2017
|
|
|
|
For the Year Ended December 31,
|
|
through
|
|
|
through
|
|
|
|
2019
|
|
2018
|
|
December 31, 2017
|
|
|
March 21, 2017
|
|
Property acquisition costs
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved properties
|
|
$
|
179
|
|
|
$
|
1,699
|
|
|
$
|
179
|
|
|
|
$
|
527
|
|
|
Unproved properties
|
|
22,928
|
|
|
120,610
|
|
|
33,901
|
|
|
|
2,904
|
|
|
Total acquisition costs
|
|
23,107
|
|
|
122,309
|
|
|
34,080
|
|
|
|
3,431
|
|
|
Development costs
|
|
238,664
|
|
|
199,833
|
|
|
140,180
|
|
|
|
32,657
|
|
|
Exploration costs
|
|
8,055
|
|
|
18,876
|
|
|
916
|
|
|
|
1,241
|
|
|
Total
|
|
$
|
269,826
|
|
|
$
|
341,018
|
|
|
$
|
175,176
|
|
|
|
$
|
37,329
|
|
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
Depreciation, depletion, and amortization expense of oil and natural gas properties was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
|
|
|
|
|
Period from
|
|
|
Period from
|
|
|
|
|
|
|
|
March 22, 2017
|
|
|
January 1, 2017
|
|
|
|
For the Year Ended December 31,
|
|
through
|
|
|
through
|
|
|
|
2019
|
|
2018
|
|
December 31, 2017
|
|
|
March 21, 2017
|
|
DD&A (1)
|
|
$
|
103,732
|
|
|
$
|
79,070
|
|
|
$
|
84,899
|
|
|
|
$
|
23,442
|
|
|
DD&A per BOE:
|
|
$
|
10.81
|
|
|
$
|
10.56
|
|
|
$
|
12.86
|
|
|
|
$
|
13.05
|
|
________________________________
|
|
|
|
(1)
|
Includes accretion of asset retirement obligations.
|
Oil and natural gas properties not subject to amortization consists of unevaluated leasehold acquisition costs, capitalized interest related to the leasehold costs and wells or facilities for which reserve volumes are not classified as proved until completed. The costs of unevaluated oil and natural gas properties, by year incurred, consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Cost Incurred
|
|
Total as of
|
|
|
|
2019
|
|
2018
|
|
2017
|
|
December 31, 2019
|
|
Leasehold acreage (1)
|
|
$
|
5,223
|
|
|
$
|
70,017
|
|
|
$
|
258,843
|
|
|
$
|
334,083
|
|
|
Capitalized interest (2)
|
|
7,091
|
|
|
9,694
|
|
|
—
|
|
|
16,785
|
|
|
Wells in progress of completion
|
|
20,361
|
|
|
—
|
|
|
—
|
|
|
20,361
|
|
|
Total unevaluated oil and natural gas properties excluded from amortization
|
|
$
|
32,675
|
|
|
$
|
79,711
|
|
|
$
|
258,843
|
|
|
$
|
371,229
|
|
________________________________
|
|
|
|
(1)
|
In the past, the costs associated with unevaluated properties typically related to historical acquisition costs of leasehold acreage. However, the total balance as December 31, 2019 includes an increase in carrying value to fair value of $235,723 as a result of the application of fresh start accounting upon emergence from bankruptcy. See “Note 4: Fresh start accounting.”
|
|
|
|
|
(2)
|
As of December 31, 2019, this amount reflects the cumulative interest capitalized on the historical acquisition cost of leasehold acreage subsequent to our establishing opening balances under fresh start accounting. Interest is not capitalized on amounts related to the fair value gross up discussed above.
|
The carrying value of wells in progress of completion will be transferred to the amortization base upon completion in 2020. With respect to leasehold acreage, the carrying value of undeveloped leasehold acreage will be evaluated and transferred to the amortization base within the next two to five years. Leasehold acreage also includes value assigned to held-by-production leasehold upon adoption of fresh start accounting; the carrying value of such leasehold will be transferred to the amortization base as those locations are evaluated.
Note 20: Disclosures about oil and natural gas activities (unaudited)
The estimate of proved reserves and related valuations at the end of each period presented were based upon the reports of Cawley, Gillespie & Associates, Inc., an independent petroleum and geological engineering firm, and our engineering staff. Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” crude oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
Our oil and natural gas reserves are attributable solely to properties within the United States. A summary of the changes in our quantities of proved oil and natural gas reserves for the three years ended December 31, 2019 are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
(MBbls)
|
|
Natural gas (MMcf)
|
|
Natural gas liquids
(MBbls)
|
|
Total
(MBoe)
|
|
Proved developed and undeveloped reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of January 1, 2017
|
|
96,621
|
|
|
135,449
|
|
|
12,105
|
|
|
131,301
|
|
|
Sales of minerals in place
|
|
(74,918
|
)
|
|
(1,663
|
)
|
|
(46
|
)
|
|
(75,241
|
)
|
|
Extensions and discoveries
|
|
8,957
|
|
|
39,843
|
|
|
5,442
|
|
|
21,040
|
|
|
Revisions (1)
|
|
3,515
|
|
|
11,135
|
|
|
2,216
|
|
|
7,586
|
|
|
Production
|
|
(4,571
|
)
|
|
(14,598
|
)
|
|
(1,395
|
)
|
|
(8,399
|
)
|
|
Balance at December 31, 2017
|
|
29,604
|
|
|
170,166
|
|
|
18,322
|
|
|
76,287
|
|
|
Sales of minerals in place
|
|
(2,422
|
)
|
|
(14,184
|
)
|
|
(1,374
|
)
|
|
(6,160
|
)
|
|
Extensions and discoveries
|
|
6,545
|
|
|
69,189
|
|
|
9,329
|
|
|
27,406
|
|
|
Revisions (1)
|
|
1,254
|
|
|
12,596
|
|
|
1,411
|
|
|
4,764
|
|
|
Production
|
|
(2,684
|
)
|
|
(17,549
|
)
|
|
(1,881
|
)
|
|
(7,490
|
)
|
|
Balance at December 31, 2018
|
|
32,297
|
|
|
220,218
|
|
|
25,807
|
|
|
94,807
|
|
|
Sales of minerals in place
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Extensions and discoveries
|
|
4,766
|
|
|
48,967
|
|
|
8,343
|
|
|
21,271
|
|
|
Revisions (1)
|
|
(6,703
|
)
|
|
(26,340
|
)
|
|
1,166
|
|
|
(9,927
|
)
|
|
Production
|
|
(3,111
|
)
|
|
(22,095
|
)
|
|
(2,799
|
)
|
|
(9,593
|
)
|
|
Balance at December 31, 2019
|
|
27,249
|
|
|
220,750
|
|
|
32,517
|
|
|
96,558
|
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
|
|
January 1, 2017
|
|
28,590
|
|
|
108,800
|
|
|
9,352
|
|
|
56,076
|
|
|
December 31, 2017
|
|
18,301
|
|
|
123,451
|
|
|
11,858
|
|
|
50,734
|
|
|
December 31, 2018
|
|
18,051
|
|
|
135,425
|
|
|
14,846
|
|
|
55,468
|
|
|
December 31, 2019
|
|
18,447
|
|
|
152,187
|
|
|
20,949
|
|
|
64,761
|
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
January 1, 2017
|
|
68,031
|
|
|
26,649
|
|
|
2,753
|
|
|
75,225
|
|
|
December 31, 2017
|
|
11,303
|
|
|
46,715
|
|
|
6,464
|
|
|
25,553
|
|
|
December 31, 2018
|
|
14,246
|
|
|
84,793
|
|
|
10,961
|
|
|
39,339
|
|
|
December 31, 2019
|
|
8,802
|
|
|
68,563
|
|
|
11,568
|
|
|
31,797
|
|
|
|
|
|
(1)
|
The revisions in 2019 and 2018 were primarily due to changes in pricing during the respective periods. The upward revision in 2017 was primarily due to changes in pricing and costs.
|
The following information was developed using procedures prescribed by U.S. GAAP. The standardized measure of discounted future net cash flows should not be viewed as representative of our current value. It and the other information contained in the following tables may be useful for certain comparative purposes, but should not be solely relied upon in evaluating us or our performance.
We believe that, in reviewing the information that follows, the following factors should be taken into account:
|
|
|
|
•
|
future costs and sales prices will probably differ from those required to be used in these calculations;
|
|
|
|
|
•
|
actual rates of production achieved in future years may vary significantly from the rates of production assumed in the calculations;
|
|
|
|
|
•
|
a 10% discount rate may not be reasonable as a measure of the relative risk inherent in realizing future net oil and natural gas revenues; and
|
|
|
|
|
•
|
future net revenues may be subject to different rates of income taxation.
|
Future cash inflows used in the standardized measure calculation were estimated by applying a twelve-month average price for oil, gas and natural gas liquids, adjusted for location and quality differences, to the estimated future production of year-end proved
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
reserves. Future cash inflows do not reflect the impact of future production that is subject to open derivative positions (see “Note 9: Derivative instruments”). Future cash inflows were reduced by estimated future development, abandonment and production costs based on year-end costs in order to arrive at net cash flows before tax. Future income tax expense has been computed by applying year-end statutory tax rates to aggregate future pre-tax net cash flows reduced by the tax basis of the properties involved and tax carryforwards. GAAP requires the use of a 10% discount rate and prices and costs excluding escalations based upon future conditions.
In general, management does not rely on the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable and possible as well as proved reserves and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.
The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2019
|
|
2018
|
|
2017
|
|
Future cash flows
|
|
$
|
2,424,620
|
|
|
$
|
3,255,771
|
|
|
$
|
2,331,940
|
|
|
Future production costs
|
|
(1,040,314
|
)
|
|
(1,187,071
|
)
|
|
(899,380
|
)
|
|
Future development and abandonment costs
|
|
(304,229
|
)
|
|
(450,220
|
)
|
|
(336,828
|
)
|
|
Future income tax provisions
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Net future cash flows
|
|
1,080,077
|
|
|
1,618,480
|
|
|
1,095,732
|
|
|
Less effect of 10% discount factor
|
|
(565,874
|
)
|
|
(932,114
|
)
|
|
(597,859
|
)
|
|
Standardized measure of discounted future net cash flows
|
|
$
|
514,203
|
|
|
$
|
686,366
|
|
|
$
|
497,873
|
|
The changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the year ended December 31,
|
|
|
|
2019
|
|
2018
|
|
2017
|
|
Beginning of year
|
|
$
|
686,366
|
|
|
$
|
497,873
|
|
|
$
|
528,781
|
|
|
Sale of oil and natural gas produced, net of production costs
|
|
(170,255
|
)
|
|
(175,199
|
)
|
|
(175,246
|
)
|
|
Net changes in prices and production costs
|
|
(332,546
|
)
|
|
95,430
|
|
|
125,795
|
|
|
Extensions and discoveries
|
|
114,199
|
|
|
192,105
|
|
|
136,887
|
|
|
Improved recoveries
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Changes in future development costs
|
|
116,677
|
|
|
(2,424
|
)
|
|
(4,879
|
)
|
|
Development costs incurred during the period that reduced future development costs
|
|
38,270
|
|
|
6,277
|
|
|
37,912
|
|
|
Revisions of previous quantity estimates (1)
|
|
(8,152
|
)
|
|
79,192
|
|
|
68,428
|
|
|
Purchases and sales of reserves in place, net
|
|
—
|
|
|
(45,222
|
)
|
|
(238,445
|
)
|
|
Accretion of discount
|
|
58,668
|
|
|
36,386
|
|
|
24,267
|
|
|
Net change in income taxes
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Changes in production rates and other
|
|
10,976
|
|
|
1,948
|
|
|
(5,627
|
)
|
|
End of year
|
|
$
|
514,203
|
|
|
$
|
686,366
|
|
|
$
|
497,873
|
|
|
|
|
|
(1)
|
Amounts in 2019 and 2018 are primarily the result of changes in pricing. Amounts in 2017 are primarily the result of increased volumes due to changes in pricing and costs.
|
The following prices for oil, natural gas, and natural gas liquids before field differentials were used in determining future net revenues related to the standardized measure calculation.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2019
|
|
2018
|
|
2017
|
|
Oil (per Bbl)
|
|
$
|
55.69
|
|
|
$
|
65.56
|
|
|
$
|
51.34
|
|
|
Natural gas (per Mcf)
|
|
$
|
2.58
|
|
|
$
|
3.10
|
|
|
$
|
2.98
|
|
|
Natural gas liquids (per Bbl)
|
|
$
|
16.21
|
|
|
$
|
25.56
|
|
|
$
|
24.17
|
|
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
Note 21: Supplemental quarterly financial information (unaudited)
The following tables present a summary of our unaudited interim results of operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First
Quarter
|
|
Second
Quarter
|
|
Third
Quarter
|
|
Fourth
Quarter
|
|
2019
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
49,817
|
|
|
$
|
67,905
|
|
|
$
|
52,637
|
|
|
$
|
65,986
|
|
|
Operating loss
|
|
$
|
(47,510
|
)
|
|
$
|
(57,268
|
)
|
|
$
|
(146,445
|
)
|
|
$
|
(158,128
|
)
|
|
Net loss
|
|
$
|
(103,540
|
)
|
|
$
|
(45,229
|
)
|
|
$
|
(130,935
|
)
|
|
$
|
(189,244
|
)
|
|
Earnings per share:
|
|
|
|
|
|
|
|
|
|
Basic for Class A and Class B
|
|
(2.28
|
)
|
|
$
|
(0.99
|
)
|
|
$
|
(2.86
|
)
|
|
$
|
(4.14
|
)
|
|
Diluted for Class A and Class B
|
|
(2.28
|
)
|
|
$
|
(0.99
|
)
|
|
$
|
(2.86
|
)
|
|
$
|
(4.14
|
)
|
____________________________________________________________
|
|
|
|
(1)
|
Includes loss on impairment of oil and natural gas properties of $49,722, $63,593, $147,686 and $169,694 for the first, second, third and fourth quarter of 2019, respectively.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First
Quarter
|
|
Second
Quarter
|
|
Third
Quarter
|
|
Fourth
Quarter
|
|
2018
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
59,087
|
|
|
$
|
59,625
|
|
|
$
|
66,718
|
|
|
$
|
61,932
|
|
|
Operating income (loss) (1)
|
|
$
|
8,426
|
|
|
$
|
12,024
|
|
|
$
|
18,312
|
|
|
$
|
(8,585
|
)
|
|
Net (loss) income
|
|
$
|
(11,442
|
)
|
|
$
|
(21,993
|
)
|
|
$
|
(12,068
|
)
|
|
$
|
78,945
|
|
|
Earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic for Class A and Class B (2)
|
|
(0.25
|
)
|
|
$
|
(0.49
|
)
|
|
$
|
(0.27
|
)
|
|
$
|
1.74
|
|
|
Diluted for Class A and Class B (2)
|
|
(0.25
|
)
|
|
$
|
(0.49
|
)
|
|
$
|
(0.27
|
)
|
|
$
|
1.73
|
|
____________________________________________________________
|
|
|
|
(1)
|
Includes loss on impairment of oil and natural gas properties of $20,065 for the fourth quarter.
|
|
|
|
|
(2)
|
On December 19, 2018, all outstanding shares of Class B common stock converted into the same number of shares of Class A common stock.
|