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.

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:



	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		)	(1,240		)
	$	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:



	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 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.



	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
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.

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.

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.

Other expense

Other expense consisted of the following:



	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.

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:



	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 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.