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.

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, 2018, cash with a recorded balance totaling $36,719 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, 2018			December 31, 2017
Joint interests	$	31,573		$	29,032
Accrued commodity sales	30,287			26,516
Derivative settlements	2,092			157
Other	3,375			5,326
Allowance for doubtful accounts	(1,240		)	(668		)
	$	66,087		$	60,363

Inventories

Inventories are comprised 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, 2018			December 31, 2017
Equipment inventory	$	3,663		$	4,163
Commodities	574			1,154
Inventory valuation allowance	(178		)	(179		)
	$	4,059		$	5,138

We recorded lower of cost or net realizable value adjustments, for the periods disclosed below, due to depressed industry conditions which resulted in lower demand for such equipment and hence lower market prices, as well as due to obsolescence. These adjustments are reflected in “Loss on impairment of other assets” in our consolidated statements of operations.

Successor

Predecessor

Period from

January 1, 2018

March 22, 2017

January 1, 2017

January 1, 2016

through

December 31, 2018

December 31, 2017

March 21, 2017

December 31, 2016

Inventory - valuation adjustment

—

179

—

1,393

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, drilling and completing and equipping oil and natural gas wells, including salaries, benefits, and other internal costs directly attributable to these activities.

Costs associated with unevaluated oil and natural gas properties are excluded from the amortizable base until a determination has been made as to the existence of proved reserves. Unevaluated leasehold costs are transferred to the amortization base with the costs of drilling the related well upon proving up reserves of a successful well or upon determination of a dry or uneconomic well under a process that is conducted each quarter. Furthermore, unevaluated oil and natural gas properties are reviewed for impairment if events and circumstances exist that indicate a possible decline in the recoverability of the carrying amount of such property. The impairment assessment is conducted at least once annually and whenever there are indicators that impairment has occurred. In assessing whether impairment has occurred, we consider factors such as intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; assignment of proved reserves; and economic viability of development if proved reserves are assigned. Upon determination of impairment, all or a portion of the associated leasehold costs are transferred to the full cost pool and become subject to amortization. The processes above are applied to unevaluated oil and natural gas properties on an individual basis or as a group if properties are individually insignificant. Our future depreciation, depletion and amortization rate would increase 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 18—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, 2018, 2017 and 2016 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.

We recorded adjustments to the oil and natural gas properties, for the periods disclosed below. The loss is reflected in “Loss on impairment of oil and gas assets” in our consolidated statements of operations.

Successor

Predecessor

Period from

January 1, 2018

March 22, 2017

January 1, 2017

January 1, 2016

through

December 31, 2018

December 31, 2017

March 21, 2017

December 31, 2016

Ceiling test impairment

20,065

42,146

—

281,079

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.

Our bankruptcy filing on May 9, 2016, (see “Note 3—Chapter 11 reorganization”) was an event that required an assessment whether the carrying amounts of our long-lived assets would be recoverable. Our evaluation indicated that no additional impairment was necessary as a direct result of the bankruptcy. 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 assets being restated based on their fair value.

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, 2018, or December 31, 2017.

We file income tax returns in the U.S. federal jurisdiction and in various states, each with varying statutes of limitations. The 2010 through 2018 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 and natural gas 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 “Non-hedge derivative (losses) gains” in the consolidated statements of operations. Cash flows associated with non-hedge 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. As discussed in “Note 4—Fresh start accounting,” the application of fresh start accounting to our balance sheet on March 21, 2017, resulted in our asset retirement obligations being restated based on their fair value. 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, 2018 and 2017, we have not accrued for or been fined or cited for any environmental violations which 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

Pre-emergence stock compensation

Prior to our emergence from bankruptcy, our stock-based compensation programs consisted of phantom stock, restricted stock units (“RSUs”), and restricted stock awards issued to employees. We considered the measurement of fair value of our phantom stock, RSUs and restricted stock awards, discussed below, to be a Level 3 measurement within the fair value hierarchy.

The estimated fair value of the phantom stock and RSU awards were remeasured at the end of each reporting period based on our total asset value less total liabilities, in accordance with the provisions of the Phantom Stock Plan and the Non-Officer Restricted Stock Unit Plan. A crucial input to the measurement was the value of oil and natural gas properties priced on NYMEX forward strips. Compensation cost associated with the phantom stock awards and RSU awards was recognized over the vesting period using the straight-line method and the accelerated method, respectively.

Our previous restricted stock awards included those with a service condition and those with both performance and market conditions. The fair value of our restricted stock awards that included a service condition was based upon the estimated fair market value of our common equity per share on a minority, non-marketable basis on the date of grant, and was remeasured at the end of each reporting period until settlement. We recognized compensation cost over the requisite service period using the accelerated method for awards with graded vesting.

The grant date fair value of restricted stock awards that included a market condition was measured using a Monte Carlo model. Compensation cost associated with restricted stock awards that include a market condition was recognized over the requisite service period using the straight-line method.

Post-emergence stock compensation

Our post-emergence management incentive plan consists of restricted stock awards that are subject to service vesting conditions (the “Time Shares”) and shares that are subject to performance and/or market vesting conditions (the “Performance Shares”). Both Time and Performance Shares are classified as equity-based awards. Compensation cost is recognized and measured based on fair value as determined by the market price of our publicly traded common stock or, in the case of awards subject to a market-based vesting conditions, fair value that incorporates the probability of vesting.

The Time Shares are subject to a graded vesting schedule over three annual installments and expense is recognized under the accelerated method. The Performance Shares vest in three tranches over three calendar years according to performance and/or market conditions established each year. The 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 Performance Shares relate to the individual year for which performance is measured and do not overlap. Performance Shares with performance conditions are expensed based on the number of awards expected to vest in that year. Performance Shares with market conditions 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. Performance and/or market conditions have not been established for Performance Shares scheduled to vest in 2019, 2020 and 2021, hence a grant date for purposes of determining a measurement value had not been established and expense recognition has not commenced. Certain Performance Shares may vest according to performance conditions that are not formulaic but instead depend on subjective evaluation by our board of directors (the “Board”); expense on such awards is based on the fair value of our common stock at the end the reporting period. 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.

In 2018, we began granting RSUs to our employees. These awards, which are service-based, will vest in equal installments over a three-year period and expense is recognized under the accelerated method. Compensation cost is recognized and measured based on fair value as determined by the market price of our publicly traded common stock. Certain RSUs are to be settled only in cash while others are to be settled only in stock. The cash-settled RSUs are classified as liability based awards while the stock-settled RSUs are classified as equity based awards.

See “Note 13—Deferred compensation” for additional information relating to stock-based compensation.

Other expense

Other expense consisted of the following:



	Successor
	Period from		Period from
	January 1, 2018		March 22, 2017
	through		through
	December 31, 2018		December 31, 2017
Restructuring	$	425	$	3,531
Subleases	1,611		197
Total other expense	$	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 has materially changed the scope and manner in which our business is conducted. The restructuring expense related to the divestiture is predominantly comprised 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 are comprised of CO₂ compressors that were previously utilized in our EOR operations and leased as both capital and operating leases from U.S. Bank but are now subleased to the purchaser of our EOR assets (the “Sublessee”). Minimum payments under the subleases are equal to the original leases and hence we did not record any losses upon initiation of the subleases. Prior to the asset sale, the capital 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. Based on the facts and circumstances relating to our original leases and the current subleases, we determined that all the subleases are to be classified as operating leases from a lessor’s standpoint. Subsequent to the execution of the subleases, all payments received from the Sublessee are reflected as “Sublease revenue” on our statement of operations. Minimum payments we make to U.S. Bank on the original operating leases are reflected as “Other” expense on our statement of operations. With respect to the capital leases, we have reclassified the amount associated with these leases from the full cost amortization base to “Property and equipment, net” on our balance sheet and will amortize the asset on a straight line basis prospectively. We will continue incurring interest expense on the capital leases. Please see “Note 1— Nature of operations and summary of significant accounting policies”,” Note 8— Debt”, and “Note 17— Commitments and contingencies”, which contains additional information about our leases.

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 will fund 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 and $4,000 per gross well. The JDA wells, which will be drilled and operated by us, include 17 wells in Canadian County and 13 wells in Garfield County, with the ability to expand the JDA to drill additional wells in the future. The JDA provides us with a means to accelerate the delineation of our position within our Garfield and Canadian County acreage, realizing further efficiencies and holding additional acreage by production, and potentially adding reserves. In exchange, BCE will receive wellbore-only interest in each well totaling an 85% carve-out working interest from our original working interest (and we retain 15%) until the program reaches a 14% internal rate of return. Once achieved, ownership interest in all wells will revert such that we will own a 75% working interest and BCE will retain a 25% working interest. We will retain all acreage and reserves outside of the wellbore, with both parties paying their working interest share of lease operating expenses. We will record revenues and operating costs associated with our JDA wells according to our working interest share as specified above.

Our drilling and completion costs to date have been exceeding well cost caps specified under the JDA primarily due to inflation in the cost of oilfield services as a result of the rebound in industry conditions. In our negotiation with BCE to cover the inflationary cost increases, BCE had indicated willingness to increase the per well cost caps on remaining wells in exchange for adding more wells to the current program. Since we have achieved our goals to utilize the JDA as a means to delineate our acreage in Garfield and Canadian counties, Oklahoma, we do not currently plan for any expansion of the JDA. We have therefore recorded additions to oil and natural gas properties of $13,212 during the year ended December 31, 2018, in cumulative drilling and completion costs on JDA wells that have exceeded the well cost caps specified under the JDA.

Liability management

Liability management expenses, which were incurred in 2016, include third party legal and professional service fees incurred from our activities to restructure our debt and in preparation for our bankruptcy petition. As a result of our Chapter 11 petition, such expenses, to the extent that they were incremental and directly related to our bankruptcy reorganization, are reflected in “Reorganization items” in our consolidated statements of operations.

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		Period from		Period from
	January 1, 2018		March 22, 2017		January 1, 2017		January 1, 2016
	through		through		through		through
	December 31, 2018		December 31, 2017		March 21, 2017		December 31, 2016
One-time severance and termination benefits	$	1,034	$	678	$	608	$	2,772
Professional fees	—		13		21		107
Total cost reduction initiatives expense	$	1,034	$	691	$	629	$	2,879

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 5—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 which 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 which 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 in, 2017, 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 Accounting Standards Codification (“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 August 2014, the FASB issued authoritative guidance that required entities to evaluate whether there is substantial doubt about their ability to continue as a going concern and required additional disclosures if certain criteria were met. The guidance was adopted on December 31, 2016, and other than discussions regarding our emergence from bankruptcy and the related exit financing in “Note 3—Chapter 11 reorganization” and “Note 8—Debt”, there were no additional required disclosures as contemplated by this guidance.

Recently issued accounting pronouncements

In February 2016, the FASB established ASC Topic 842, Leases (“ASC 842”) which 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. The new standard establishes a right-of-use model (ROU) 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. The new standard is effective for us on January 1, 2019, with early adoption permitted. We expect to adopt the new standard on its effective date. A modified retrospective transition approach is required, applying the new standard to all leases existing at the date of initial application. An entity may choose to use either (1) its effective date or (2) the beginning of the earliest comparative period presented in the financial statements as its date of initial application. We expect to adopt the new standard on January 1, 2019 and use the effective date as our date of initial application. Consequently, financial information will not be updated and the disclosures required under the new standard will not be provided for dates and periods before January 1, 2019. The new standard provides a number of optional practical expedients in transition. We expect to elect the ‘package of practical expedients’, which permits us not to reassess under the new standard our prior conclusions about lease identification, lease classification and initial direct costs. While we continue to assess all of the effects of adoption, we currently believe the most significant effects relate to (1) the recognition of new ROU assets and lease liabilities on our balance sheet with a range of approximately $15,000 to $18,000 primarily for our drilling rig and CO₂ compressor operating leases and (2) providing significant new disclosures about our leasing activities. The new standard also provides practical expedients for an entity’s ongoing accounting. We currently expect to elect the short-term lease recognition exemption for all classes of assets. This means, for those leases that qualify, we will not recognize ROU assets or lease liabilities, and this includes not recognizing ROU assets or lease liabilities for existing short-term leases of those assets in transition. We also currently expect to elect the practical expedient to not separate lease and non-lease components for our drilling rig leases.

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